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As filed with the Securities and Exchange Commission on October 31, 2007

Registration No. 333-144716

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 5

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

QUEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


Delaware	1311	26-0518546
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

9520 North May Avenue, Suite 300

Oklahoma City, Oklahoma 73120

(405) 488-1304

(Address, including zip code, and telephone number,

including area code, of registrant’s principal executive offices)

David E. Grose

Chief Financial Officer

9520 North May Avenue, Suite 300

Oklahoma City, Oklahoma 73120

(405) 488-1304

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:


Patrick Respeliers James Swenson Stinson Morrison Hecker LLP 1201 Walnut Kansas City, Missouri 64106 (816) 842-8600		Joshua Davidson Douglass M. Rayburn Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

PRELIMINARY PROSPECTUS

SUBJECT TO COMPLETION, DATED OCTOBER 31, 2007


		8,750,000 Common Units Quest Energy Partners, L.P. Representing Limited Partner Interests

Quest Energy Partners, L.P. is a limited partnership recently formed by Quest Resource Corporation. We are offering 8,750,000 common units representing limited partner interests. This is the initial public offering of our common units. We expect the initial public offering price to be between $19.00 and $21.00 per common unit. Our common units have been approved for listing on the NASDAQ Global Market under the symbol “QELP.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

These risks include the following:


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

	•	On a pro forma basis, we would have had sufficient cash available for distribution to pay only 4.4% and 9.8% of the initial quarterly distribution on our common units for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively.

	•	Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flows from operations and impair our ability to make distributions.

	•	We will not be able to sustain distributions at the level of our estimated initial quarterly distribution without making capital expenditures or accretive acquisitions that maintain or grow our asset base.

	•	Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

	•	We will have substantial debt and will likely incur substantial additional debt in the future. This debt may restrict our ability to make distributions and/or to execute our drilling program.

	•	Natural gas prices are at relatively high levels and are very volatile. A decline in commodity prices will cause a decline in our cash flow from operations and reduce our cash available for distribution.

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

	•	Holders of our common units have limited voting rights, are not entitled to elect the directors of our general partner and face significant difficulties in removing our general partner.

	•	You will experience immediate and substantial dilution of $10.09 in tangible net book value per common unit.

	•	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 Internal Revenue Service 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 you would be substantially reduced.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

PRICE $ PER COMMON UNIT


	Per Common Unit	Total

Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to us (before expenses)	$	$


(1)		Excludes a structuring fee of 0.5% of the gross proceeds of this offering, or $ , payable to Wachovia Capital Markets, LLC for evaluation, analysis and structuring of our partnership and this offering. Please read “Underwriting” beginning on page 196 for more information.

We have granted the underwriters a 30-day option to purchase up to an additional 1,312,500 common units on the same terms and conditions set forth above to cover over-allotments. Wachovia Capital Markets, LLC, on behalf of the underwriters, expects to deliver the common units on or about , 2007.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


Wachovia Securities	RBC Capital Markets

Friedman Billings Ramsey

Oppenheimer & Co. Stifel Nicolaus Wells Fargo Securities

The date of this prospectus is , 2007


Tax Treatment of Operations			184
Disposition of Common Units			187
Uniformity of Units			189
Tax-Exempt Organizations and Other Investors			190
Administrative Matters			190
State, Local, Foreign and Other Tax Considerations			192
SELLING UNITHOLDER			194
INVESTMENT IN QUEST ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS			195
UNDERWRITING			196
VALIDITY OF THE COMMON UNITS			200
EXPERTS			200
WHERE YOU CAN FIND MORE INFORMATION			200
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A — FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF QUEST ENERGY PARTNERS, L.P.			A-1
APPENDIX B — GLOSSARY OF SELECTED TERMS			B-1
APPENDIX C — RESERVE REPORT SUMMARY			C-1
Form of Underwriting Agreement
Form of Credit Agreement
Form of Restricted Unit Award Agreement
Consent of Murrell, Hall, McIntosh & Co., PLLP
Consent of Cawley, Gillespie & Associates, Inc.

As used in this prospectus, unless we indicate otherwise, the terms: (1) “our”, “we”, “us” and similar terms refer to Quest Energy Partners, L.P. and its subsidiaries, after giving effect to the formation transactions described on page 8 of this prospectus, (2) “Quest Energy GP” or “our general partner” refers to Quest Energy GP, LLC, our general partner, (3) “our Parent” refers to Quest Resource Corporation (Nasdaq: QRCP), the owner of our general partner, and its subsidiaries (other than us) and (4) “Quest Midstream” refers to Quest Midstream Partners, L.P. and its subsidiaries. References in this prospectus to the “Partnership Properties” or “our properties” refer to the gas and oil properties to be contributed to us by our Parent in connection with this offering.

As used in this prospectus, “standardized measure” is 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 United States Securities and Exchange Commission, or 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 income taxes. Our standardized measure differs from the standardized measure presented in the historical audited financial statements of our predecessor included in this prospectus due to the exclusion of future income tax expense. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.” Standardized measure is an accounting term that should not be confused with fair market value. Our proved reserve information is based on reports prepared by Cawley, Gillespie & Associates, Inc., an independent engineering firm. A summary of our reserve report as of June 30, 2007 is included in this prospectus in Appendix C.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. You should read “Risk Factors” beginning on page 22 for information about important risks that you should consider carefully before deciding to buy our common units. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per unit and (2) no exercise of the underwriters’ over-allotment option. We include a glossary of some of the gas and oil terms used in this prospectus as Appendix B.

Quest Energy Partners, L.P.

Overview

We are a Delaware limited partnership formed in July 2007 by our Parent, Quest Resource Corporation, to acquire, exploit and develop oil and natural gas properties. 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. We intend to pay holders of our common units distributions of available cash of $0.40 per unit for each quarter, or $1.60 per unit annually, before we pay any distributions to holders of our subordinated units. Our operations are currently focused on the development of coal bed methane, or CBM, in a 13-county region in southeastern Kansas and northeastern Oklahoma, referred to in this prospectus 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.

As of June 30, 2007, we had 205.5 Bcfe of estimated net proved reserves, of which approximately 99% were CBM and 66% 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 CBM producer in the Cherokee Basin with an average net daily production of 43.5 MMcfe for the six months ended June 30, 2007. Our reserves are long-lived, with an average reserve-to-production ratio of 13.1 years (8.7 years for our proved developed properties) as of June 30, 2007, which we define as estimated net proved reserves (or proved developed reserves) as of June 30, 2007 divided by our annualized net production for the six months ended June 30, 2007. Our typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years. Our estimated net proved reserves at June 30, 2007 had estimated future net revenues discounted at 10%, which we refer to as the “standardized measure”, of $353.1 million.

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. We also intend to diversify our operations by pursuing accretive acquisitions of conventional and unconventional gas and oil assets outside the Cherokee Basin. Even if we do not make additional acquisitions, we believe that our multi-year inventory of additional development drilling locations on our undeveloped acreage gives us the opportunity to maintain and increase our proved reserves and average net daily production.

In connection with this offering, our Parent will contribute all of its Cherokee Basin CBM properties to us. Upon completion of this offering, our Parent will directly own our general partner, which will have a 2.0% general partner interest in us as well as incentive distribution rights. Our Parent will also directly own 3,551,521 common units and 8,857,981 subordinated units, representing an aggregate 57.5% limited partner interest in us.

Partnership Properties

All of our gas and oil properties are located in the Cherokee Basin and substantially all of our reserves are CBM reserves. CBM is comprised almost entirely of methane gas, which is a primary component of natural gas. Unlike conventional natural gas hydrocarbon production, CBM gas is “dry”, or without the presence of other naturally occurring hydrocarbon liquids such as ethane, propane and butane. Accordingly, CBM gas is suitable for gathering and delivery into end-user sales pipelines without the necessity to process or remove any liquids. CBM is produced when large volumes of water are pumped from a coal seam in a process known as dewatering or depressuring. As pressure within the coalbed formation is reduced, CBM is released through a process called desorption. CBM then moves into naturally occurring cracks, or cleats, in the coal, and then to the production wells. Cleats are natural fractures which have formed in the coals, usually as a result of the coalification process and geological stresses. Because the cleats are generally filled with water, the static water level above the coal must be reduced, which then lowers the reservoir pressure allowing desorption to occur. Thus, unlike producing from a conventional natural gas reservoir, reservoir pressure in a coalbed formation must generally be reduced to allow for production of CBM. 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.

There are three well defined coal seams underlying our current acreage position. These coal seams are found at relatively shallow depths (300 to 1,400 feet), making wells easier to drill and less expensive to complete compared to conventional wells. Our wells generally reach total depth in one and one half days and our estimated average cost for drilling and completing a well for the six months ended June 30, 2007 was approximately $135,000. Our Cherokee Basin multi-seam CBM wells have an average net proved reserves of 130 MMcf.

As of June 30, 2007, we were operating approximately 1,904 gross gas wells, of which over 90% were multi-seam wells, and 29 gross oil wells. As of June 30, 2007, we owned the development rights to approximately 523,000 net acres throughout the Cherokee Basin and had only developed approximately 48% of our acreage. For 2007, we have budgeted approximately $76.0 million to drill and complete an estimated 558 gross wells and recomplete an estimated 60 gross wells, as well as an additional $37.0 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. For the six months ended June 30, 2007, we had total capital expenditures of approximately $45.5 million, including $34.3 million to connect 251 gross wells and recomplete 34 gross wells. We expect to drill and connect 325 wells in 2008. At this time, we have not identified our drilling locations for 2008 and some or all of these wells may be drilled on locations that were not classified as containing proved reserves in our June 30, 2007 reserve report. As of June 30, 2007, our undeveloped acreage contained approximately 2,295 gross CBM drilling locations, of which 756 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.

The following table summarizes information about our reserves as of December 31, 2004, 2005 and 2006 and June 30, 2007 and our new well development activity for the twelve months ended December 31, 2004, 2005 and 2006 and the six months ended June 30, 2007:


										Six Months
	Twelve Months Ended									Ended
	December 31,									June 30,
	2004			2005			2006			2007

Estimated net proved reserves (Bcfe)(1)		150.1			134.5			198.2			205.5
Percent proved developed(1)		54.5	%		53.4	%		61.8	%		66.4	%
Wells drilled (gross)		466			99	(3)		622			260
Wells recompleted (gross)		38			205			125			34
Wells connected (gross)		164			233			638			251
Well completion %		98	%		98	%		99	%		99	%
Total well drilling and completion capital expenditures (in thousands)(2)	$	35,582		$	45,070		$	104,884		$	41,804


(1)		At period end.

(2)		Capital expenditures represent actual cash expenditures and do not reflect allocated costs or amounts.

(3)		Covenants in a prior credit facility restricted us from drilling during most of 2005. Please read “Risk Factors — Our new credit facility will have substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.”

Gas Hedging

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. We have 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. As of October 15, 2007, we have fixed price swaps covering 13% of our estimated net gas production from proved developed producing reserves and collars covering 45% of our estimated net gas production from proved developed producing reserves for the remainder of 2007. We also have fixed price swaps and collars covering 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, we have fixed price swaps covering 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 Central TX/KS/OK (“Southern Star”) first of month index, with the remainder sold on the daily price on the Southern Star index. All of our derivative contracts are based on the Southern Star first of month index, except for some of our older collar agreements covering approximately 1.8 Bcf of gas in the second half of 2007 (19% of our estimated net gas production from proved developed producing reserves for the second half of 2007) and 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, we are not exposed to basis differential risk, except for the NYMEX collars and swaps. We have 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, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

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:


	•	increase reserves and production through executing what we believe to be a low-risk development and exploitation drilling program;

	•	make accretive acquisitions of conventional and unconventional gas and oil properties characterized by a high percentage of proved developed producing reserves with long-lived, stable production and development opportunities whereby we can apply our management’s knowledge and expertise;

	•	reduce the volatility in our revenues resulting from changes in gas and oil commodity prices through our hedging program;

	•	maintain low cost and efficient operations; and

	•	control our operations and limit our reliance on third party contractors with respect to the completion, stimulation and connection of our wells.

For a more detailed description of our business strategies, please read “Business — Business Strategies.”

Competitive Strengths

We believe that the following competitive strengths will allow us to achieve our objectives of generating and growing available cash for distribution:


	•	high quality asset base characterized by stable, long-lived production with an average reserve-to-production ratio of 13.1 years (8.7 years for our proved developed properties) as of June 30, 2007, low geological risk and predictable production profiles;

	•	an extensive drilling inventory of approximately 2,295 gross CBM drilling locations, of which 756 were classified as proved undeveloped, and approximately 266,070 net undeveloped acres as of June 30, 2007;

	•	operational, acquisition evaluation, risk management and technical support from our Parent; and

	•	experienced and knowledgeable management team with extensive experience in developing conventional and unconventional reserves.

For a more detailed description of our competitive strengths, please read “Business — Competitive Strengths.”

Our Relationship with Our Parent and Quest Midstream

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. Upon completion of this offering, our Parent will control us through its ownership of our general partner, which owns a 2.0% general partner interest in us as well as incentive distribution rights. Please read “How We Make Cash Distributions — Incentive Distribution Rights.” Our Parent will also directly own 3,551,521 common units and 8,857,981 subordinated units representing an aggregate 57.5% limited partner interest in us.

While our relationship with our Parent may benefit us, it is also a source of potential conflicts of interest. At the closing of this offering, we and our Parent will enter into an omnibus agreement. The omnibus agreement contains limited non-compete, expense reimbursement and indemnification provisions. Please read “Conflicts of Interest and Fiduciary Duties.”

Exploitation and Exploration Activities

Upon completion of the formation transactions described in this prospectus, substantially all of our Parent’s existing gas and oil properties will be contributed to us. Our Parent will continue to own approximately 16,500 net undeveloped acres located in the States of Texas, 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. On October 15, 2007, our Parent entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Pinnacle Gas Resources, Inc. (“Pinnacle”), which provides for the acquisition of Pinnacle by our Parent in a stock-for-stock transaction. Pinnacle currently conducts its operations in the Powder River Basin and Green River Basin located in Montana and Wyoming. As of June 30, 2007, Pinnacle owned natural gas and oil leasehold interests in approximately 478,000 gross (332,000 net) acres, approximately 94% of which were undeveloped. The consummation of the Pinnacle acquisition is subject to a number of conditions, including the approval of the merger by the stockholders of both our Parent and Pinnacle and obtaining certain regulatory approvals. Accordingly, we cannot assure you that our Parent will consummate the Pinnacle acquisition on the terms set forth in the Merger Agreement or at all. For more information about the Pinnacle acquisition, please read “Business — Our Relationship with Our Parent.”

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; however, in the event the Pinnacle acquisition is consummated, our Parent does not anticipate that it will offer to us any of the properties acquired in the Pinnacle acquisition in the near term. 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. Although our Parent and its subsidiaries are prohibited from competing with us inside the Cherokee Basin, our Parent and its subsidiaries are not prohibited from competing with us outside the Cherokee Basin.

Midstream Services

Our Parent also controls Quest Midstream through its 85% ownership of Quest Midstream’s general partner and its ownership of approximately 49% of Quest Midstream’s limited partner interests. Our Parent intends for Quest Midstream to be the primary entity for conducting its midstream operations. Quest Midstream owns and operates an over 1,800 mile gas gathering pipeline system in the Cherokee Basin. Pursuant to a midstream services and gas dedication agreement to which we will become a party at the closing of the offering, Quest Midstream will gather and provide certain midstream services 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 renewal periods that may be exercised by either party upon 180 days’ notice. Under the midstream services agreement, we will 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 based on changes in gas prices and the producer price index. Such fees will never be reduced below the initial rates described above and are subject to renegotiation upon the exercise of each five-year extension period. Under the terms of some of our gas leases, we may not be able to charge the full amount of these fees to royalty owners, which would increase the average fees per MMBtu that we effectively pay under the midstream services agreement.

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. 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, 260 of which have been drilled in the Cherokee Basin through June 30, 2007. We expect to drill 298 additional wells in the second half of 2007 and 325 wells in 2008. At this time, we have not identified our drilling locations for 2008 and some or all of these wells may be drilled on locations that were not classified as containing proved reserves in our June 30, 2007 reserve report. For more information about the midstream services agreement, please read “Business — Gas Gathering — Midstream Services Agreement.”

In addition, so long as we are an affiliate of our Parent and a change of control of Quest Midstream or its general partner has not occurred, we will be subject to a midstream omnibus agreement with Quest Midstream and our Parent. The midstream omnibus agreement governs:


	•	the obligations of us and our affiliates to refrain from engaging in certain business opportunities that compete with Quest Midstream;

	•	a right of first offer allowing Quest Midstream to acquire certain of our assets in the event of a sale or transfer of such assets; and

	•	an option allowing Quest Midstream to provide midstream services for any acreage located outside the Cherokee Basin that we or any of our affiliates may acquire in the future.

For more information about the midstream omnibus agreement, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Midstream Omnibus Agreement.”

Summary of Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. Please read carefully these and other risks described under “Risk Factors.”

Risks Related to Our Business


	•	We may not have sufficient cash from operations to pay the initial quarterly distribution 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.


	•	On a pro forma basis, we would have had sufficient cash available for distribution to pay only 4.4% and 9.8% of the initial quarterly distribution on our common units for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively.


	•	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.

	•	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.

	•	We will not be able to sustain distributions at the level of our estimated initial quarterly distribution 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.


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

	•	Our new credit facility will have substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

	•	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.

	•	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.

	•	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.

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.

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

	•	Our Parent may engage in competition with us.

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

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

	•	You will experience immediate and substantial dilution of $10.09 in tangible net book value per common unit.

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

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 Internal Revenue Service (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 you would be substantially reduced.

	•	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.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

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

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


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

	•	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.

	•	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.

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

Formation Transactions and Partnership Structure

Formation Transactions

At the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:


	•	our Parent will transfer the Partnership Properties to us;

	•	we will issue to our general partner 431,827 general partner units representing its initial 2.0% general partner interest in us, and all of the incentive distribution rights, which incentive distribution rights will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.46 per unit per quarter;

	•	we will issue to our Parent 3,551,521 common units and 8,857,981 subordinated units, representing an aggregate 57.5% limited partner interest in us;

	•	we will issue 8,750,000 common units to the public in this offering, representing a 40.5% limited partner interest in us;

	•	we will borrow $75.0 million under our new credit facility;

	•	we will enter into the omnibus agreement with our Parent and our general partner, which will address, among other things, the provision of, and the reimbursement for, general and administrative and operating services and indemnification matters;

	•	we will enter into the management services agreement with Quest Energy Service, LLC (a wholly-owned subsidiary of our Parent) which will provide for the provision of, and the reimbursement for, general and administrative, operating and acquisition services; and

	•	we will become a party to the midstream services agreement pursuant to which Quest Midstream will provide gathering, dehydration, treating and compression services to us in exchange for contracted fees.

We will use the net proceeds of this offering, together with $75.0 million in borrowings under our new credit facility, to repay indebtedness under existing credit facilities of our Parent that are secured by the Partnership Properties. Quest Cherokee, LLC, our principal operating subsidiary, is currently a co-borrower on these credit facilities. Any remaining amounts under the existing credit facilities of our Parent not refinanced with the net proceeds of this offering or borrowings under our new credit facility will be repaid with borrowings under a new credit facility of our Parent to be entered into at the closing of this offering.

We will use any net proceeds from the exercise of the underwriters’ over-allotment option to redeem from our Parent the number of common units equal to the number of common units issued upon the exercise of the underwriters’ option. If the underwriters’ over-allotment option is exercised in full, our Parent’s ownership will be reduced to 2,239,021 common units and 8,857,981 subordinated units, representing an aggregate 51.4% limited partner interest in us, and the ownership interest of the public unitholders will increase to 10,062,500 common units, representing an aggregate 46.6% limited partner interest in us.

Management of Quest Energy Partners, L.P.

Quest Energy GP, LLC, our general partner, will conduct our business and manage our operations, and Quest Energy Service, through its affiliates and employees, will carry out the directions of our general partner pursuant to a management services agreement. Pursuant to this agreement, Quest Energy Service will provide us with legal, accounting, finance, tax, property management, engineering, risk management and acquisition services in respect of opportunities for us to acquire long-lived, stable and proved gas and oil reserves. This agreement is not terminable by us so long as our Parent controls our general partner. Thereafter, the management services agreement is terminable by either us or Quest Energy Service upon six months’ notice. Quest Energy Service will be reimbursed for its reasonable costs in providing services to us and will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. For a description of the services that Quest Energy Service will provide to us and our obligation to reimburse Quest Energy Service for the costs it incurs in providing those services, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Management Services Agreement.”

Some of the executive officers and directors of our Parent also serve as executive officers and directors of our general partner. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or its directors. Our Parent will elect all of the directors of our general partner, with at least three directors meeting the independence standards established by the NASDAQ Global Market. Our general partner will not receive any management fee or other compensation in connection with the management of our business or this offering, but it will be entitled to reimbursement of all direct and indirect expenses incurred on our behalf.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 9520 North May Avenue, Suite 300, Oklahoma City, Oklahoma 73120 and our telephone number is (405) 488-1304. Our website will be located at www.qelp.net. We will make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

Quest Energy GP, LLC, our general partner, has a legal duty to manage us in a manner beneficial to holders of our units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by our Parent, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to our Parent. As a result of this relationship, conflicts of interest may arise in the future between us and holders of our units, on the one hand, and our general partner and its affiliates, on the other hand. For example, our general partner will be entitled to make determinations that affect our ability to make cash distributions, including, but not limited to, determinations related to the operation of our business, such as those related to capital expenditures, asset purchases and sales and other acquisitions and dispositions, borrowings, and the amount of cash reserves necessary or appropriate to satisfy general, administrative and other expenses and debt service requirements, and otherwise provide for the proper conduct of our business. These determinations will have an effect on the amount of cash distributions we make to the holders of units, and that amount in turn has an effect on whether the subordinated units can convert into common units and whether our general partner receives incentive distribution payments as discussed below. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to holders of our common units. Our partnership agreement also restricts the remedies available to holders of our common units and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to holders of our common units and subordinated units. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

The Offering


Common units offered to the public		8,750,000 common units or 10,062,500 common units if the underwriters exercise their over-allotment option in full.

Units outstanding after this offering		12,301,521 common units and 8,857,981 subordinated units, representing a 57.0% and 41.0%, respectively, limited partner interest in us.

Use of proceeds		We intend to use the estimated net proceeds of approximately $161.3 million from this offering, after deducting underwriting discounts, a structuring fee and offering expenses, together with $75.0 million in borrowings under our new credit facility, to repay indebtedness under existing credit facilities of our Parent that are secured by the Partnership Properties.

		Any remaining amounts under the existing credit facilities of our Parent not refinanced with the net proceeds of this offering or borrowings under our new credit facility will be repaid with borrowings under a new credit facility that our Parent will enter into at the closing of this offering.

		If the underwriters exercise their over-allotment option, then we will use the net proceeds to redeem a number of common units from our Parent equal to the number of common units issued upon the exercise of the underwriters’ option.

Cash distributions		We expect to make an initial quarterly distribution of $0.40 per common unit ($1.60 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Our ability to pay distributions at this initial quarterly distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

		Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this distributable cash as “available cash”, and we define its meaning in our partnership agreement and in “How We Make Cash Distributions — Distributions of Available Cash — Definition of Available Cash.” Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner:

		first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.40 plus any arrearages from prior quarters;

		second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.40;

		third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.46;


		fourth, 85% to all unitholders, pro rata, and 15% to our general partner, until each unit has received a distribution of $0.50; and

		thereafter, 75% to all unitholders, pro rata, and 25% to our general partner.

		We refer to the distributions to our general partner in excess of 2% as “incentive distributions.” Please read “How We Make Cash Distributions.”

		We will adjust the quarterly distribution for the period from the closing of this offering through December 31, 2007 based on the actual length of the period. We expect to pay this cash distribution on or about February 14, 2008.


		On a pro forma basis, we would have had sufficient cash available for distribution to pay only 4.4% and 9.8% of the initial quarterly distribution on our common units for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations.”


		We believe that we will have sufficient cash available for distribution to pay the full quarterly distributions at the minimum distribution rate of $0.40 per unit ($1.60 per unit on an annualized basis) on all the outstanding common units, subordinated units and general partner interests for each quarter for the twelve months ending December 31, 2008. Please read “Our Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations.”

Subordinated units		Following this offering, our Parent will own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.40 per unit only after the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid from operating surplus at least $1.60 on each outstanding common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2012. The subordination period will also end 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.

		When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

Early conversion of subordinated units		If we meet the tests for ending the subordination period as set forth above for any quarter ending on or after December 31, 2010, 25% of the subordinated units will convert into common units on a one-for-one basis. If we meet those tests for any quarter ending on or after December 31, 2011, an additional 25% of the subordinated units will convert into common units on a one-for-one basis. The


		early conversion of the second 25% of the subordinated units may not occur until at least one year after the early conversion of the first 25% of the subordinated units.

		In addition to the early conversion described above, if we have earned and paid from operating surplus at least $2.00 (125% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any two consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please read “How We Make Cash Distributions — Subordination Period.”

General partner’s right to reset the target distribution levels		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 the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.

		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 after one year 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. For a more detailed description of our general partner’s right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our general partner to receive Class B units in connection with this reset, please read “How We Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

Issuance of additional units		We can issue an unlimited number of units, including units senior to the common units, without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”

Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except


		by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 58.6% of our common and subordinated units (52.4% if the underwriters exercise their over-allotment option in full) (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program). This will give our general partner the ability to prevent its involuntary removal. Please read “The Partnership Agreement — Voting Rights.”

Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units. Please read “The Partnership Agreement — Limited Call Right.”


Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.60 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.32 per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”


Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Agreement to be bound by the Partnership Agreement		By purchasing a common unit, you will be admitted as a unitholder of our partnership and will be deemed to have agreed to be bound by all of the terms of our partnership agreement.


Exchange listing		Our common units have been approved for listing on the NASDAQ Global Market under the symbol “QELP.”

Summary Historical and Pro Forma Financial Data

Set forth below is summary historical financial data of Quest Energy Partners Predecessor, the predecessor to Quest Energy Partners, L.P., and pro forma financial data of Quest Energy Partners, L.P. as of and for the periods indicated. As used in this prospectus, “Quest Energy Partners Predecessor” means the assets, liabilities and operations of our Parent located in the Cherokee Basin (other than its midstream assets), which our Parent will contribute to us at the completion of this offering. The summary historical financial data as of May 31, 2004 and December 31, 2004, 2005 and 2006 and for the fiscal year ended May 31, 2004, the seven months ended December 31, 2004 and the fiscal years ended December 31, 2005 and 2006 are derived from the audited financial statements of Quest Energy Partners Predecessor. The summary historical financial data as of and for the six months ended June 30, 2006 and 2007 are derived from the unaudited financial statements of Quest Energy Partners Predecessor. The historical financial statements of Quest Energy Partners Predecessor are comprised of our Parent’s assets, liabilities and operations located in the Cherokee Basin (other than its midstream assets), which our Parent will contribute to us at the completion of this offering.

The summary pro forma financial data for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007 are derived from the unaudited pro forma financial statements of Quest Energy Partners, L.P. included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on June 30, 2007, in the case of the pro forma balance sheet, or as of January 1, 2006, in the case of the pro forma statement of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007. These transactions include:


	•	our Parent’s transfer of the Partnership Properties to us;

	•	our issuance of 431,827 general partner units and the incentive distribution rights to our general partner and 3,551,521 common units and 8,857,981 subordinated units to our Parent;

	•	the sale by us of 8,750,000 common units to the public in this offering;

	•	the payment by us of the underwriting discounts, structuring fee and other offering and transaction expenses;

	•	the repayment of existing indebtedness of our Parent and Quest Cherokee that is secured by the Partnership Properties with the proceeds of this offering, $75.0 million of borrowings under our new credit facility and borrowings under a new credit facility of our Parent; and

	•	the execution by us of the midstream services agreement, management services agreement and omnibus agreement.

Quest Energy Partners Predecessor’s historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of our future results, due to its rapid growth through acquisitions and development of its properties and its entering into the midstream services agreement in December 2006.

You should read the following table in conjunction with “— Formation Transactions and Partnership Structure”, “Use of Proceeds”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, the historical carve out financial statements of Quest Energy Partners Predecessor and the unaudited pro forma financial statements of Quest Energy Partners, L.P. included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

The following table includes Adjusted EBITDA, which is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to net income, its most directly comparable financial measure calculated and presented in accordance with generally accepted accounting principles, which we refer to as GAAP, please read “— Non-GAAP Financial Measures.”


																			Quest Energy Partners, L.P.
	Quest Energy Partners Predecessor																		Pro Forma
				Seven
				Months			Year
				Ended			Ended
																						Six
	Year																		Year			Months
	Ended												Six Months Ended						Ended			Ended
	May 31,			December 31,									June 30,						December 31,			June 30,
	2004(1)			2004(1)			2005			2006			2006			2007			2006			2007
										(Restated)(2)			(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)

Statement of Operations Data:
Revenues:
Oil and gas sales	$	28,147		$	24,201		$	44,565		$	65,551		$	33,785		$	53,416		$	65,551		$	53,416
Other revenue/expense		(904	)		37			387			(83	)		(67	)		(32	)		(83	)		(32	)

Total revenues		27,243			24,238			44,952			65,468			33,718			53,384			65,468			53,384
Costs and expenses:
Oil and gas production		5,003			5,389			14,388			21,208			8,572			14,967			21,208			14,967
Transportation expense		1,869			3,196			7,038			17,278			5,167			13,170			19,884			13,170
General and administrative expenses		2,264			2,328			4,068			8,149			3,214			5,846			8,149			5,846
Provision for impairment of gas and oil properties(3)		—			—			—			30,719			—			—			30,719			—
Depreciation, depletion and amortization		6,698			6,954			20,121			25,521			11,680			14,063			25,521			14,063

Total costs and expenses		15,834			17,867			45,615			102,875			28,633			48,046			105,481			48,046

Operating income (loss)		11,409			6,371			(663	)		(37,407	)		5,085			5,338			(40,013	)		5,338

Other income (expense):
Change in derivative fair value(4)		(2,013	)		(1,487	)		(4,668	)		6,410			6,631			(185	)		6,410			(185	)
Gain (loss) on sale of assets		(6	)		—			12			(7	)		43			(197	)		(7	)		(197	)
Interest expense, net		(6,403	)		(7,702	)		(19,873	)		(16,545	)		(6,185	)		(13,880	)		(5,673	)		(2,742	)

Total other expense		(8,422	)		(9,189	)		(24,529	)		(10,142	)		489			(14,262	)		730			(3,124	)

Net income (loss) before cumulative effect of accounting change		2,987			(2,818	)		(25,192	)		(47,549	)		5,574			(8,924	)		(39,283	)		2,214
Cumulative effect of accounting change, net of tax		(28	)		—			—			—			—			—			—			—

Net income (loss)	$	2,959		$	(2,818	)	$	(25,192	)	$	(47,549	)	$	5,574		$	(8,924	)	$	(39,283	)	$	2,214

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	137,621		$	159,096		$	191,290		$	249,549		$	245,309		$	283,599					$	283,599
Total assets		149,651			178,332			217,650			311,718			303,812			334,058						320,205
Long-term debt		126,766			148,747			76,296			225,569			163,104			235,270						75,270
Partners’ capital		(1,730	)		(3,877	)		69,547			51,091			97,128			62,847						208,994
Other Financial Data:
Adjusted EBITDA	$	18,322		$	13,387		$	20,095		$	20,469		$	17,686		$	21,719		$	17,863		$	21,719
Capital expenditures		125,482			28,075			51,682			117,387			67,610			45,466
Net cash provided by (used in):
Operating activities		15,701			18,778			584			11,183			13,546			2,539
Investing activities		(125,482	)		(28,075	)		(51,645	)		(117,194	)		(67,448	)		(45,496	)
Financing activities		111,060			12,285			47,141			124,818			86,698			31,603


(1)		Quest Energy Partners Predecessor changed its fiscal year end from May 31 to December 31 effective as of January 1, 2005.

(2)		Certain changes were made to carve out assumptions resulting in the understatement of previously recorded cash and partners’ capital as of December 31, 2006. Please read Note 19 to the carve out financial statements.


(3)		As of December 31, 2006, Quest Energy Partners Predecessor’s net book value of gas and oil properties exceeded the ceiling (defined as estimated after-tax future net revenues discounted at 10% per annum from proved gas and oil reserves, plus the cost of properties not subject to amortization, as adjusted for the present value of all future gas and oil hedges) under the full cost method of accounting. Accordingly, a provision for impairment was recognized in the fourth quarter of 2006 of $30.7 million. The provision for impairment is primarily attributable to declines in the prevailing market prices of gas and oil at the measurement date.


(4)		Gas derivative contracts are used to reduce our exposure to changes in gas prices. Change in the fair value of these gas derivative contracts are marked to market in our earnings each period. Further, these amounts represent non-cash charges.

Non-GAAP Financial Measures

Adjusted EBITDA

In this prospectus, we include Adjusted EBITDA, which is a non-GAAP financial measure. We provide a reconciliation of Adjusted EBITDA to net income and net cash provided by operations, its most directly comparable financial measures calculated and presented in accordance with GAAP.

We defined Adjusted EBITDA as net income (loss) plus:


	•	net interest expense;

	•	depreciation, depletion and amortization expense;

	•	gain (loss) on sale of assets;

	•	provision for impairment of gas and oil properties;

	•	cumulative effect of accounting change, net of tax;

	•	change in derivative fair value; and

	•	non-cash compensation expense.

Adjusted EBITDA is a significant performance metric used by our management, and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess (prior to the establishment of any cash reserves by our general partner) the cash distributions we expect to pay our unitholders. Specifically, this financial measure indicates whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates without regard to the impact of financing methods, capital structure or historical cost basis of our assets.

Adjusted EBITDA is also used as a supplemental liquidity measure by our management, and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions to our unitholders.

Our new revolving credit agreement will require us to maintain a minimum ratio of consolidated EBITDA plus distribution equivalents paid on unvested equity incentive compensation awards, if any, to consolidated interest expense (as defined in our new credit facility) and a maximum ratio of total debt (as defined in our new credit facility) to consolidated EBITDA plus distribution equivalents paid on unvested equity incentive compensation awards, if any. Consolidated EBITDA under our new revolving credit agreement will be computed in the same manner as the way Adjusted EBITDA is presented in this prospectus. We believe it is important to maintain consistency between the way we report Adjusted EBITDA and the way we are required to calculate consolidated EBITDA for purposes of our revolving credit agreement.

amortization are also necessary elements of our costs. Because Quest Energy Partners Predecessor has used, and we intend to use, derivative contracts to hedge our exposure to commodity prices, changes in the fair value of those contracts is also a necessary element of our costs. Because Quest Energy Partners Predecessor has used, and we intend to use, non-cash equity awards as part of our overall compensation package for our executive officers and employees, non-cash compensation expense is a necessary element of our costs. Therefore, any measures that excludes these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management’s decision-making processes.

The following table presents a reconciliation of Adjusted EBITDA to its most directly comparable financial measures as calculated and presented in accordance with GAAP.


																			Quest Energy Partners, L.P.
	Quest Energy Partners Predecessor																		Pro Forma
				Seven
				Months			Year
				Ended			Ended
																						Six
	Year																		Year			Months
	Ended												Six Months Ended						Ended			Ended
	May 31,			December 31,									June 30,						December 31,			June 30,
	2004			2004			2005			2006			2006			2007			2006			2007
													(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)

Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	15,701		$	18,778		$	584		$	11,183		$	13,546		$	2,539
Add:
Change in operating assets and liabilities		3,571			(7,778	)		11,784			(13,839	)		(10,089	)		7,745
Cash interest expense, net		1,740			2,836			12,108			16,545			6,185			13,880
Other non-cash expense		(2,690	)		(449	)		(4,381	)		6,580			8,044			(2,445	)

Adjusted EBITDA	$	18,322		$	13,387		$	20,095		$	20,469		$	17,686		$	21,719

Reconciliation of Adjusted EBITDA to net income:
Net income (loss)	$	2,959		$	(2,818	)	$	(25,192	)	$	(47,549	)	$	5,574		$	(8,924	)	$	(39,283	)	$	2,214
Add:
Interest expense, net		6,403			7,702			19,873			16,545			6,185			13,880			5,673			2,742
Depreciation, depletion and amortization expense		6,698			6,954			20,121			25,521			11,680			14,063			25,521			14,063
(Gain) loss on sale of assets		6			—			(12	)		7			(43	)		197			7			197
Provision for impairment of gas and oil properties		—			—			—			30,719			—			—			30,719			—
Cumulative effect of accounting change, net of tax		28			—			—			—			—			—			—			—
Change in derivative fair value(1)		2,013			1,487			4,668			(6,410	)		(6,631	)		185			(6,410	)		185
Non-cash compensation expense		215			62			637			1,636			921			2,318			1,636			2,318

Adjusted EBITDA	$	18,322		$	13,387		$	20,095		$	20,469		$	17,686		$	21,719		$	17,863		$	21,719


(1)		Gas derivative contracts are used to reduce our exposure to changes in gas prices. Change in the fair value of these gas derivative contracts are marked to market in our earnings each period. Further, these amounts represent non-cash charges.

Summary Reserve and Operating Data

The following table shows estimated net proved reserves for the Partnership Properties, based on reserve reports prepared by our independent petroleum engineers, Cawley, Gillespie & Associates, Inc., and certain summary unaudited information with respect to production and sales of gas and oil with respect to such properties. A summary prepared by Cawley, Gillespie & Associates of its reserve report relating to the Partnership Properties as of June 30, 2007 is provided in Appendix C and is referred to in this prospectus as the “reserve report.” You should refer to “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Gas and Oil Data” in evaluating the material presented below.


													Six
	Year												Months
	Ended			Year Ended									Ended
	May 31,			December 31,									June 30,
	2004(1)			2004			2005			2006			2007

Reserve Data (at period end):
Proved developed gas (MMcf)		62,559			81,467			71,638			122,390			136,313
Proved undeveloped gas (MMcf)		71,017			68,377			62,681			75,650			68,981

Total proved gas (MMcf)		133,576			149,844			134,319			198,040			205,294
Proved developed oil (MBbl)(2)		57			48			32			32			27
Total proved reserves (MMcfe)		133,919			150,131			134,513			198,234			205,457
Proved developed reserves as a percentage of total proved reserves		47.1	%		54.5	%		53.4	%		61.8	%		66.4	%
Standardized measure (in thousands)(3)	$	318,356		$	401,101		$	482,545		$	264,327		$	353,051
Net Production:
Total production (MMcfe)(4)		5,580			8,664			9,620			12,341			7,864
Average daily production (MMcfe per day)(4)		15.3			23.7			26.4			33.8			43.5
Average Sales Prices ($ per Mcfe):
Average sales prices (including hedges)	$	5.04		$	4.93		$	4.63		$	5.31		$	6.79
Average sales prices (excluding hedges)		5.02			5.63			7.45			5.95			6.60
Average Unit Costs ($ per Mcfe):
Production costs(5)	$	1.23		$	1.53		$	2.23		$	3.12		$	3.58
General and administrative expenses		0.41			0.46			0.42			0.66			0.74
Depreciation, depletion and amortization		1.20			1.38			2.09			2.07			1.79


(1)		The gas production volumes for the 2004 fiscal year include two asset acquisitions: one in December 2003 and one in June 2003.

(2)		We have not estimated our proved undeveloped oil reserves because they are insignificant.

(3)		Standardized measure is 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 differs from the standardized measure presented in the historical audited financial statements of Quest Energy Partners Predecessor included in this prospectus due to the exclusion of future income tax expense. Our standardized measure does not reflect any future income tax expenses because we are not subject to income taxes. Our estimated net proved reserves and standardized measure as of June 30, 2007 were determined using Southern Star prices of $6.806 per Mcf of gas and $66.69 per Bbl of oil. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”


(4)		As of the date hereof, based on preliminary information, we expect that our total production for the third quarter of 2007 will be approximately 4.5 Bcfe or 48.9 MMcfe per day.


(5)		Production costs include oil and gas production and transportation expenses.

RISK FACTORS

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. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, then our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash from operations to pay the initial quarterly distribution 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, we anticipate that our new credit facility will contain 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:


	•	the amount of gas and oil we produce;

	•	the demand for and the price at which we are able to sell our gas and oil production;

	•	the results of our hedging activity;

	•	the costs incurred for continued development of gas wells and proved undeveloped properties;

	•	the level of our operating costs, including reimbursements of expenses to our general partner and its affiliates;

	•	timing and collectability of receivables;

	•	prevailing economic conditions;

	•	our ability to acquire additional gas and oil properties at economically attractive prices;

	•	our ability to continue our exploitation activities at economically attractive costs;

	•	the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon; and

	•	the level of our capital expenditures.

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 “Our Cash Distribution Policy and Restrictions on Distributions.”

On a pro forma basis, we would have had sufficient cash available for distribution to pay only 4.4% and 9.8% of the initial quarterly distribution on our common units for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively.

The amount of available cash we will need to pay the minimum quarterly distribution for four quarters on the common units, subordinated units and the 2% general partner interest to be outstanding immediately after this offering is approximately $8.6 million per quarter, or $34.5 million per year. If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma available cash generated during the year ended December 31, 2006 and the twelve months ended June 30, 2007 would have been approximately $1.0 million and $2.0 million, respectively. As a result, we would have been able to pay only 4.4% and 9.8% of the initial quarterly distribution on our common units during the year ended December 31, 2006 and the twelve months ended June 30, 2007, respectively. We would not have been able to pay any distributions on our subordinated units during the year ended December 31, 2006 or for the twelve months ended June 30, 2007. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the initial distribution rate for each of the four quarters ending December 31, 2008 is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of the minimum Adjusted EBITDA necessary for us to make a distribution on all units at the initial distribution rate for each of the four quarters ending December 31, 2008, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions”, is based on our management’s calculations, and we have not received an opinion or report on it from any independent accountants. This estimate is based on assumptions about drilling, production, gas and oil prices, hedging activities, capital expenditures, expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If any of these assumptions proves to have been inaccurate, our actual results may differ materially from those set forth in our estimates, and we may be unable to pay all or part of the minimum quarterly distribution on our common units or subordinated units.

None of the proceeds of this offering will be used to maintain or grow our asset base.

None of the proceeds of this offering will be used to maintain or grow our asset base, which may be necessary to cover future distributions. The proceeds of the offering will be used to repay debt and associated prepayment penalties and to pay transaction expenses associated with our formation and this offering.

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:


	•	the domestic and foreign supply of and demand for gas;

	•	the price and level of foreign imports of gas and oil;

	•	the level of consumer product demand;

	•	weather conditions;


	•	overall domestic and global economic conditions;

	•	political and economic conditions in gas and oil producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;

	•	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

	•	the impact of the U.S. dollar exchange rates on gas and oil prices;

	•	technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations and taxation;

	•	the impact of energy conservation efforts;

	•	the costs, proximity and capacity of gas pipelines and other transportation facilities; and

	•	the price and availability of alternative fuels.

In the past, the prices of gas have been extremely volatile, and we expect this volatility to continue. For example, during the five years 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 six month period ended June 30, 2007, the NYMEX spot price ranged from a high of $9.07 per MMBtu to a low of $5.40 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, due to the decrease in gas prices between December 31, 2005 and December 31, 2006. Based on the September 30, 2007 prices for natural gas, our predecessor incurred an impairment loss of approximately $90 million at that date. However, in reliance on the SEC Staff Accounting Bulletin No. 102: Topic 12:D.3b — “Full Cost Ceiling Test”, we believe that an impairment loss may not be recognized due to the fact that subsequent improvements in the price of natural gas prior to the release of third quarter earnings may increase the present value of future net reserves sufficiently to eliminate the need for an impairment write down. 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 new 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 June 30, 2007, our reserve-to-production ratio was 13.1 years (8.7 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 June 30, 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 level of our estimated initial quarterly distribution 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 level of our estimated initial quarterly distribution 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 level of our estimated initial quarterly distribution 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.

Because we do not have any officers or employees, we will 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:


	•	our Parent chooses to acquire oil and natural gas properties for itself instead of allowing us to acquire them;

	•	the board of directors of our general partner or its conflicts committee is unable to agree with our Parent and its affiliates on a purchase price or on acceptable purchase terms for our Parent’s properties that are attractive to all parties;

	•	our Parent is unable or unwilling to identify attractive properties for us or is unable to negotiate acceptable purchase contracts;

	•	we are unable to obtain financing for acquisitions on economically acceptable terms; or

	•	we are outbid by competitors.

In the event the Pinnacle acquisition is consummated, our Parent does not anticipate that it will offer to us any of the properties acquired in the Pinnacle acquisition in the near term. 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 $76.0 million and $49.5 million to drill and complete an estimated 558 gross wells and 325 gross wells for 2007 and 2008, respectively, and recomplete an estimated 60 gross wells in 2007. Management also currently estimates that it will require capital investments of approximately $37.0 million and

$29.0 million for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities for 2007 and 2008, respectively. These expenditures could increase as a result of:


	•	changes in our reserves;

	•	changes in gas and oil prices;

	•	changes in labor and drilling costs;

	•	our ability to acquire, locate and produce reserves;

	•	changes in leasehold acquisition costs; and

	•	government regulations relating to safety and the environment.

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


	•	our proved reserves;

	•	the level of gas and oil we are able to produce from existing wells;

	•	the prices at which our gas and oil is sold; and

	•	our ability to acquire, locate and produce new reserves.

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.

Our new credit facility will have 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 our new credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our new credit facility and any future credit facility may restrict our ability to:


	•	incur indebtedness;

	•	grant liens;

	•	make certain acquisitions and investments;

	•	lease equipment;

	•	make capital expenditures above specified amounts;

	•	redeem or prepay other debt;

	•	make distributions to unitholders or repurchase units;

	•	enter into transactions with affiliates; and

	•	enter into a merger, consolidation or sale of assets.

We also will be required to comply with certain financial covenants and ratios. Our new credit facility will require us to maintain a leverage ratio (the ratio of our total debt to our consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any, in each case as will be defined by our new 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. Our new credit facility will require us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any, to our consolidated interest expense, in each case as

will be defined by our new 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. Our new credit facility will require us to maintain a current ratio (the ratio of our current assets plus unused availability under our borrowing base to our current liabilities excluding the current portion of the borrowing base, in each case as defined in our credit agreement) 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’s total debt to EBITDA ratio was 4.77 to 1.0, which exceeded the permitted maximum total debt to EBITDA ratio of 4.5 to 1.0 in its credit facilities. Our Parent obtained a waiver of this default from its lenders and amended its credit facilities to increase the permitted maximum total debt to EBITDA ratio for the remainder of 2007. Our new credit facility will generally permit us to pay distributions of available cash so long as we are in compliance with the provisions of our new credit facility. A default under our new 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 our new 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 our new credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under our new credit facility, the lenders could seek to foreclose on our assets.

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 our new 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 our new credit facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our new 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.

After giving effect to this offering and the related transactions, we estimate that we will have $75.3 million of debt. Following this offering, we will have the ability to incur debt, including under our new credit facility,

subject to borrowing base limitations in our credit facility. Our future indebtedness could have important consequences to us, including:


	•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisition or other purposes may be impaired or such financing may not be available on favorable terms;

	•	covenants contained in our existing and future debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

	•	we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

	•	our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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:


	•	mistaken assumptions about reserves, future production, volumes, revenues and costs, including synergies;

	•	an inability to integrate successfully the businesses we acquire;

	•	a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

	•	a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;

	•	dilution to our unitholders and a decrease in available cash per unit if we issue additional units to finance acquisitions;


	•	the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

	•	an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

	•	limitations on rights to indemnity from the seller;

	•	mistaken assumptions about the overall costs of equity or debt;

	•	the diversion of management’s and employees’ attention from other business concerns;

	•	the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

	•	unforeseen difficulties operating in new product areas or new geographic areas; and

	•	customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and 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 our current operations solely 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:


	•	geology;

	•	well economics;

	•	availability of third party services;

	•	transportation charges;

	•	content, quantity and quality of gas and oil produced;

	•	volume of waste water produced;

	•	state and local regulations and permit requirements; and

	•	production, severance, ad valorem and other taxes.

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:


	•	a constant level of future gas and oil prices;

	•	geological conditions;

	•	production levels;

	•	capital expenditures;

	•	operating and development costs;

	•	the effects of regulation; and

	•	availability of funds.

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 June 30, 2007 had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of June 30, 2007 would have decreased by $118.1 million, from $353.1 million to $235.0 million and our proved reserves would have decreased by 8.4 Bcfe from 205.5 Bcfe to 197.1 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 actual prices we receive for gas;

	•	our actual operating costs in producing gas;

	•	the amount and timing of actual production;

	•	the amount and timing of our capital expenditures;

	•	supply of and demand for gas; and

	•	changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of 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:


	•	high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

	•	reductions in gas prices;

	•	limitations in the market for gas;

	•	adverse weather conditions;

	•	facility or equipment malfunctions;

	•	difficulty disposing of water produced as part of the CBM production process;

	•	equipment failures or accidents;

	•	title problems;

	•	pipe or cement failures or casing collapses;

	•	compliance with environmental and other governmental requirements;

	•	environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

	•	lost or damaged oilfield drilling and service tools;

	•	loss of drilling fluid circulation;

	•	unexpected operational events and drilling conditions;

	•	unusual or unexpected geological formations;

	•	formations with abnormal pressures;

	•	natural disasters, such as fires;

	•	blowouts, surface craterings and explosions; and

	•	uncontrollable flows of gas or well fluids.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

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


	•	a counterparty may not perform its obligation under the applicable derivative instrument;

	•	there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

	•	the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

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

All 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 will pay Quest Midstream, which is a party related to us, a fee of $0.50 per MMBtu for gathering, dehydration and treating services and a compression fee of $1.10 per MMBtu. 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.

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, 260 of which have been drilled in the Cherokee Basin through June 30, 2007. We expect to drill 298 additional wells in the second half of 2007 and 325 wells in 2008. At this time, we have not identified our drilling locations for 2008 and some or all of these wells may be drilled on locations that were not classified as containing proved reserves in our June 30, 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 “Business — Gas Gathering.”

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 agreements. However, on August 3, 2007, certain mineral interest owners filed a putative class action lawsuit against Quest Cherokee, our operating company, 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 you.

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:


	•	damage to wells, pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

	•	inadvertent damage from construction, farm and utility equipment;

	•	leaks of gas or losses of gas as a result of the malfunction of equipment or facilities;

	•	fires and explosions; and

	•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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

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 you.

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 “Business — Legal Proceedings” 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 and Restrictions on Distributions,” 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 “Business — Environmental Matters and Regulation” 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 you could be adversely affected. Please read “Business — Environmental Matters and Regulation” 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.

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, has recently issued a Show Cause Order requiring our operating company, Quest Cherokee, LLC, 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:


	•	we cannot obtain future permits from applicable regulatory agencies;

	•	water of lesser quality or requiring additional treatment is produced;

	•	our wells produce excess water;

	•	new laws and regulations require water to be disposed in a different manner; or

	•	costs to transport the produced water to the disposal wells increase.

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, 2006 and the six months ended June 30, 2007, we sold approximately 95% and 72%, respectively, of our gas to ONEOK Energy Marketing and Trading Company (“ONEOK”) and 5% and 28%, respectively, of our gas to Tenaska Marketing Ventures (“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. Please read “Business — Marketing and Major Customers.” If either of these customers were to reduce the volume of gas it purchases from us, our revenue and cash available for distribution will 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 September 30, 2007, we held gas leases on approximately 143,074 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 7,573 net acres are scheduled to expire between October 1, 2007 and December 31, 2007 and an additional 10,152 net acres are scheduled to expire before December 31, 2008. 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 June 30, 2007, 756 gross proved undeveloped drilling locations and approximately 1,539 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 1,539 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 “Business — Environmental Matters and Regulation” and “Business — Legal Proceedings”.

We rely on our general partner and Quest Energy Service, LLC for our management. If our general partner or Quest Energy Service, LLC 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, LLC, a wholly-owned subsidiary of our Parent, 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 Chief Executive Officer Jerry Cash and Chief Financial Officer David Grose. We maintain no key person insurance for either Messrs. Cash or Grose. The loss of any member of our management or other key employees could negatively impact our ability to execute our strategy.

We may have assumed unknown liabilities in connection with the formation transactions.

As part of the formation transactions, our properties may be subject to existing liabilities, some of which may have been unknown at the closing of this offering. Unknown liabilities might include liabilities for cleanup or remediation of undisclosed or unknown environmental conditions, claims of vendors or other persons (that had not been asserted or threatened prior to this offering), tax liabilities and accrued but unpaid liabilities incurred in the ordinary course of business.

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. Our predecessor’s financial results for the fiscal year ended December 31, 2006 have been restated since the initial filing of the registration statement in connection with this offering. Please read Note 19 in the audited financial statements included elsewhere in this prospectus. The restatement related to the decision to initially not include the Parent’s cash balance on Quest Energy Partners Predecessor’s carve-out financial statements. Under the standards of the Public Company Accounting Oversight Board, a restatement of previously issued financial statements is a strong indicator of the existence of a “material weakness” in internal control over financial reporting. Under the relevant SEC rules, management will not be permitted to conclude that internal control over financial reporting is effective if it has identified one or more material weaknesses in those internal controls. The events surrounding the restatement may be an indication that our general partner has insufficient personnel resources and technical accounting expertise within its internal accounting function to resolve non-routine or complex accounting issues on our behalf. Management believes that the restatement was the result of a change in the assumptions being used to prepare Quest Energy Partners Predecessor’s carve-out financial statements and not the result of a lack of personnel or technical expertise. The change in the assumption was made as part of the due diligence review process in preparation for the filing of an amendment to the registration statement. As such, management does not believe that the restatement by itself is a “material weakness.” 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.

Following this offering, our Parent will own and control 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:


	•	neither our partnership agreement nor any other agreement requires our Parent to pursue a business strategy that favors us. Our Parent’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of our Parent, who include public shareholders. These decisions may be contrary to our interests;

	•	our general partner is allowed to take into account the interests of parties other than us, such as our Parent, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

	•	our general partner determines the amount and timing of operating expenditures, asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders and the general partner, including with respect to its incentive distribution rights, and the ability of the subordinated units to convert to common units;

	•	our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;

	•	subject to the limitations in our omnibus agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

	•	our general partner has the ability in certain circumstances to cause us to borrow funds to pay distributions on its subordinated units and incentive distribution rights; and

	•	our general partner controls the interpretation and enforcement of obligations owed to us by our general partner and its affiliates, including our omnibus agreement with our Parent, the midstream services agreement between us and Quest Midstream and the midstream omnibus agreement.

Please read “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest” for a further discussion of conflicts.

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:


	•	permits our general partner to make a number of decisions either in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and


		reasonable”, our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;


	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner or its conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions, unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

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 intend to enter into a management services agreement with Quest Energy Service, pursuant to which Quest Energy Service will operate our assets and perform 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 58.6% of our aggregate outstanding common and subordinated units (52.4% if the underwriters exercise their over-allotment option in full) (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program), 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 will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% 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. Following

the closing of this offering, our general partner and its affiliates will own 58.6% of our aggregate outstanding common and subordinated units (52.4% if the underwriters exercise their over-allotment option in full) (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program). 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 will agree 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.”

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 will restrict us from engaging in the following businesses (each of which is referred to in this prospectus as a “Restricted Business”):


	•	the gathering, treating, processing and transporting of gas in North America;

	•	the transporting and fractionating of gas liquids in North America;

	•	any other midstream activities, including but not limited to crude oil storage, transportation, gathering and terminaling;

	•	constructing, buying or selling any assets related to the foregoing businesses; and

	•	any line of business other than those described in the preceding bullet points that generates “qualifying income”, within the meaning of Section 7704(d) of the Code, other than any business that is primarily


		engaged in the exploration for and production of oil or gas and the sale and marketing of gas and oil derived from such exploration and production activities.

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 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.”

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 your approval, which would dilute your existing ownership interests.

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 unitholders’ proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	because a lower percentage of total outstanding units will be subordinated units, the risks that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•	the ratio of taxable income to distributions may increase;

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.

Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, our Parent will hold 3,551,521 common units (2,239,021 common units if the underwriters exercise their over-allotment option) (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program) and 8,857,981 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some or all may convert earlier. In addition, our general partner has agreed to provide registration rights to these holders, subject to certain limitations. Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any common units that they hold, subject to certain limitations. All of our common units that were outstanding prior to our initial public offering will be subject to resale restrictions under 180-day lock-up agreements with the underwriters. Each of the lock-up arrangements with the underwriters may be waived in the discretion of Wachovia Capital Markets, LLC. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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.

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. Please read “How We Make Cash Distributions — Distributions of Available Cash — General Partner Interest and 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.

You will experience immediate and substantial dilution of $10.09 in tangible net book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $9.91 per unit. Based on the assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $10.09 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

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:


	•	general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

	•	conditions in the gas and oil industry;


	•	the market price of, and demand for, our common units;

	•	our results of operations and financial condition; and

	•	prices for gas and oil.

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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters’ over-allotment option, our general partner and its affiliates will own approximately 28.9% of our outstanding common units (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program). At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 58.6% of our aggregate outstanding common units (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program). For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

Your liability 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency determined that:


	•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•	your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”

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 you 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.

Unitholders may have limited liquidity for their common units, a trading market may not develop for the common units and you may not be able to resell your common units at or above the initial public offering price.

Prior to the offering, there has been no public market for the common units. After the offering, there will be 8,750,000 publicly traded common units, assuming no exercise of the underwriters’ over-allotment option. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

If our common unit price declines after the initial public offering, you could lose a significant part of your investment.

The initial public offering price for the common units was determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including:


	•	the level of our distributions and our earnings or those of other companies in our industry;

	•	announcements by us or our competitors of significant contracts, acquisitions or other business developments;

	•	changes in market valuations of similar companies;

	•	changes in accounting standards, policies, guidance, interpretations or principles;

	•	changes in general economic conditions, financial markets and the gas and oil industry;

	•	departure of key personnel;

	•	commencement or involvement in litigation;

	•	future issuances and sales of our common units;

	•	the failure of securities analysts to cover our common units after this offering or changes in financial estimates and recommendations by analysts; and

	•	the other factors described in these “Risk Factors.”

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

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. Please read “Description of the Common

Units — Transfer of Common Units” and “The Partnership Agreement — Non-Eligible Holders; Redemption.” 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. Please read “How We Make Cash Distributions — Operating Surplus and Capital Surplus.”

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

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

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 you 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 you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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 you. 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 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. Please read “Material Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

You may be required to pay taxes on your share of our income even if you 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, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your 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 you.

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 prospectus 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 you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. If you sell your units, you may incur a tax liability in excess of the amount of cash you 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 you. 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, your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election.”

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. Please read “Material Tax Consequences — Disposition of Common Units —

Constructive Termination” and “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”

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.

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

In addition to federal income taxes, you 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 you do not live in any of those jurisdictions. You 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, you may be subject to penalties for failure to comply with those requirements. We will initially 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 your 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.

The ratio of our allocable taxable income to cash distributions to a purchaser of common units could be higher than our estimate.

We estimate that a purchaser of common units in this offering who holds those common units through the record date for distributions for the period ending December 31, 2010, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. This estimate is based upon certain assumptions with respect to our gross income from operations, capital expenditures, cash flow and anticipated cash distributions. Our estimate and assumptions are subject to numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Our estimate is also based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, the actual percentage of our distributions that will constitute taxable income could be higher or lower than our estimate, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions will be higher than our estimate if our gross income exceeds the amount required to make our minimum quarterly distributions, yet we only distribute the minimum quarterly distribution amount. The ratio of allocable taxable income to cash distributions will also be higher than our estimate if we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions, such as to repay outstanding indebtedness or to acquire property that is not eligible for depletion, depreciation or amortization for federal tax purposes or that is depletable, depreciable or amortizable

at a rate significantly slower than the rate applicable to our existing assets. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”

Our tax counsel is unable to opine as to certain federal income tax issues. The IRS may challenge our treatment of such tax issues.

Our tax counsel has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations; (3) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder; (4) whether the deduction related to U.S. production activities will be available to a unitholder or the extent of any such deduction to any unitholder and (5) whether our method for depreciating Section 743 adjustments is sustainable in certain cases. Please read “Material Tax Consequences.”

An adverse determination by the IRS regarding any of these issues could increase the amount of taxable income or loss being allocated to our unitholders or otherwise adversely affect the amount of tax benefits available to our unitholders. It could also result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

CAUTIONARY NOTE REGARDING
FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:


	•	the volatility of gas and oil prices;

	•	discovery, estimation, development and replacement of gas and oil reserves;

	•	cash flow, liquidity and financial condition;

	•	business and financial strategy;

	•	amount, nature and timing of capital expenditures, including future development costs;

	•	availability and terms of capital;

	•	timing and amount of future production of gas and oil;

	•	availability of drilling and production equipment, labor and other services;

	•	operating costs and other expenses;

	•	prospect development and property acquisitions;

	•	marketing of gas and oil;

	•	competition in the gas and oil industry;

	•	the impact of weather and the occurrence of natural disasters such as fires;

	•	governmental regulation of the gas and oil industry;

	•	developments in oil-producing and gas-producing countries; and

	•	strategic plans, expectations and objectives for future operations.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Summary”, “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Our Cash Distribution Policy and Restrictions on Distributions”, “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may”, “will”, “could”, “should”, “expect”, “plan”, “project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target”, “continue”, the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

USE OF PROCEEDS

We expect to receive net proceeds of approximately $161.3 million from the sale of 8,750,000 common units offered by this prospectus, after deducting underwriting discounts, a structuring fee and offering expenses totaling approximately $13.7 million. We base this amount on the assumed initial public offering price of $20.00 per common unit and assume no exercise of the underwriters’ over-allotment option. We anticipate using the aggregate net proceeds of this offering, together with $75.0 million in borrowings under our new credit facility, to repay indebtedness under existing credit facilities of our Parent that are secured by the Partnership Properties. Quest Cherokee, our principal operating subsidiary, is a co-borrower on our Parent’s existing credit facilities.

We will use any net proceeds from the exercise of the underwriters’ over-allotment option to redeem the number of common units from our Parent equal to the number of common units issued upon the exercise of the underwriters’ option. If the underwriters exercise their over-allotment option in full, our Parent’s ownership of common units will be reduced from 3,551,521 common units to 2,239,021 common units, representing, together with its subordinated units, an aggregate 51.4% limited partner interest in us, and the ownership interest of the public unitholders will increase to 10,062,500 representing an aggregate 46.6% limited partner interest in us.

The indebtedness to be repaid consists of:


	•	$50.0 million first lien term loan under a Senior Credit Agreement among our Parent and Quest Cherokee, as co-borrowers, Guggenheim Corporate Funding, LLC (“Guggenheim”), as administrative agent and syndication agent, and the lenders party thereto. The Senior Credit Agreement also includes a $50.0 million revolving credit facility, which had $10.0 million outstanding thereunder as of June 30, 2007;

	•	$100.0 million under a Second Lien Term Loan Agreement among our Parent and Quest Cherokee, as co-borrowers, Guggenheim, as Administrative Agent, and the lenders party thereto; and

	•	$75.0 million under a Third Lien Term Loan Agreement among our Parent and Quest Cherokee, Guggenheim, as Administrative Agent, and the lenders party thereto.

The following table sets forth our expected net proceeds from this offering, together with borrowings under our new credit facility and our Parent’s new credit facility and the use of proceeds:


	Total

Sources of Funds (in millions):
Estimated proceeds, net of estimated underwriting discounts, a structuring fee and offering expenses(1)	$	161.3
New credit facility		75.0
Parent’s new credit facility(2)		7.6

Total Sources	$	243.9

Uses of Funds (in millions):
Repayment of Parent’s first lien term loan	$	50.0
Repayment of Parent’s second lien term loan(3)		103.5
Repayment of Parent’s third lien term loan(4)		76.9
Repayment of Parent’s revolving credit facility(2)		10.0
Loan origination costs for new credit facility		3.5

Total Uses	$	243.9


(1)		An increase or decrease in the assumed public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions and offering expenses payable by us, to increase or decrease by $8.1 million. If the initial public offering price were to vary from $20.00 per common unit or if we were to change the number of common units in this offering (other than through the underwriters’ exercise of their over-allotment option), the effect would be to


		decrease or increase the amount of outstanding indebtedness of our Parent after the closing of this offering, but would have no effect on the anticipated amount of our outstanding debt at the closing of this offering.

(2)		Our Parent’s Senior Credit Agreement has a $50.0 million revolving credit facility that matures on November 14, 2010. As of June 30, 2007, $10.0 million was borrowed under this facility. If on the closing date of this offering, the amount outstanding under our Parent’s revolving credit facility exceeds $10.0 million, the additional amount will be repaid with additional borrowings under our Parent’s new credit facility. Our Parent’s new credit facility will not be guaranteed by us or secured by the Partnership Properties.

(3)		Includes an assumed 3.5% prepayment premium of $3.5 million. The prepayment premium decreases to 2.25% if the second lien term loan is prepaid after November 15, 2007 and prior to November 15, 2008.

(4)		Includes a 2.5% prepayment premium of $1.9 million.

Interest accrues on our Parent’s revolving credit facility at LIBOR plus 1.75% or the base rate plus 0.75%, at our Parent’s option. Interest accrues on our Parent’s first lien term loan at LIBOR plus 3.25% or the base rate plus 2.50%, at our Parent’s option. Interest accrues on our Parent’s second lien term loan at LIBOR plus 5.50%. Interest accrues on our Parent’s third lien term loan at LIBOR plus 8.00%. The base rate is the greater of the prime rate or the federal funds effective rate plus 0.5%. Our Parent’s revolving credit facility and first lien term loan mature on November 14, 2010, our Parent’s second lien term loan matures on November 14, 2011 and our Parent’s third lien term loan matures on June 9, 2012.

The borrowings incurred under our Parent’s credit facilities within the past twelve months were used for capital expenditures and working capital.

CAPITALIZATION

The following table shows:


	•	the historical capitalization of Quest Energy Partners Predecessor as of June 30, 2007; and

	•	our pro forma capitalization as of June 30, 2007, adjusted to reflect the transactions described under “Summary — Formation Transactions and Partnership Structure.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	As of June 30, 2007
	Historical			Pro Forma(1)
	(In thousands)

Total long-term debt	$	235,270		$	75,270
Partners’ capital/net parent equity:
Net parent equity	$	67,987		$	—
Common units — public		—			155,159
Common units — Quest Resource Corporation		—			16,311
Subordinated units — Quest Resource Corporation		—			40,681
General partner interest — Quest Energy GP, LLC		—			1,983
Other comprehensive income (losses)		(5,140	)		(5,140	)

Total partners’ capital		62,847			208,994

Total capitalization	$	298,117		$	284,264


(1)		Assumes an initial public offering price of our common units of $20.00 per unit and the net proceeds from this offering after deducting underwriting discounts, a structuring fee and offering expenses payable by us and the application of the proceeds as described in “Use of Proceeds.” A $1.00 increase (decrease) in the assumed public offering price per common unit would increase (decrease) our pro forma total partners’ capital by $8.1 million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts, commissions and estimated offering expenses payable by us. The pro forma information discussed above is illustrative only and following the completion of this offering will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.

This table does not reflect the issuance of up to 1,312,500 common units that may be sold to the underwriters upon exercise of their over-allotment option.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of June 30, 2007, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ over-allotment option is not exercised, our net tangible book value was $213.9 million, or $9.91 per common unit. Net tangible book value excludes $0.2 million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit			$	20.00
Net tangible book value per common unit before the offering(1)	$	5.28
Increase (decrease) in net tangible book value per common unit attributable to purchasers in the offering		4.63

Less: Pro forma net tangible book value per common unit after the offering(2)				9.91

Immediate dilution in tangible net book value per common unit to new investors(3)			$	10.09


(1)		Determined by dividing the net tangible book value of our properties by the number of units (3,551,521 common units and 8,857,981 subordinated units) and general partner units (431,827 general partner units) to be issued to our Parent and Quest Energy GP, LLC, respectively, for their contribution of the Partnership Properties to us.

(2)		Determined by dividing the total number of common units, subordinated units and general partner units to be outstanding after the offering (12,301,521 common units, 8,857,981 subordinated units and 431,827 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

(3)		If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $9.72 or $10.47, respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner, its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:


						Total
	Units Acquired					Consideration
	Number		Percent			Amount		Percent
	(In thousands)

General partner and affiliates(1)(2)		12,841		59.5	%	$	67,987		28.0	%
Purchasers in this offering		8,750		40.5			175,000		72.0

Total		21,591		100.0	%	$	242,987		100.0	%


(1)		The units acquired by our general partner and its affiliates consist of 3,551,521 common units, 8,857,981 subordinated units and 431,827 general partner units.

(2)		The assets contributed by our general partner and its affiliates were recorded at their net book value in accordance with GAAP.

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Assumptions and Considerations” below. In addition, you should read “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to the audited historical financial statements of our predecessor for the fiscal year ended May 31, 2004, the seven months ended December 31, 2004, and for the years ended December 31, 2005 and 2006 and our unaudited pro forma financial statements for the year ended December 31, 2006 and the six months ended June 30, 2007 included elsewhere in this prospectus.

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. We intend to fund a portion of our expansion capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash, after expenses and reserves, rather than retaining it. It is the board’s current policy that we will pay an initial quarterly distribution of $0.40 per unit for each complete quarter, and that we should increase our level of quarterly cash distributions per unit only when, in the board’s judgment, it believes that (i) we have sufficient reserves and liquidity for the conduct of our business, including to fund the level of maintenance capital expenditures required to maintain our production levels and asset base, and (ii) we can maintain that increased distribution level over the long term. Also, because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to federal income tax.

Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:


	•	Our cash distribution policy will be subject to restrictions on distributions under our new credit facility. Our new credit facility will contain material financial tests and covenants that we must satisfy. These financial tests and covenants include a requirement that our ratio of consolidated indebtedness to consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any, be less than 3.50 to 1.0, a requirement that our ratio of consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any, to consolidated interest expense be not less than 2.50 to 1.0 and a requirement that our ratio of current assets plus unused availability under our borrowing base to current liabilities excluding the current portion of the borrowing base be not less than 1.00 to 1.00. These financial ratios and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility.” Should we be unable to satisfy these restrictions under our new credit facility or if we are otherwise in default under our new credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. Any future indebtedness may contain similar or more stringent restrictions.


	•	Our general partner will have the authority to establish reserves for the conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish reserves made by our general partner in good faith will be binding on the unitholders. We intend to reserve a substantial portion of our cash generated from operations to fund our capital expenditures required to maintain the current production levels over the long term. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain or grow 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. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. Decreases in commodity prices from current levels will also adversely affect our ability to pay distributions. 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.

	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. During the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders. After the subordination period has ended, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a single class (including common units and Class B units held by our Parent and its affiliates). At the closing of this offering, our Parent will own our general partner and approximately 28.9% of our outstanding common units and 100% of our subordinated units.

	•	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

	•	We have assumed that our operations will not be subject to material entity level taxation. Several states (e.g., Texas) have adopted taxes on the income of limited partnerships. Since we will not initially own properties in such states, we do not believe that such state entity level tax will materially affect our distributions. In addition, we believe that limited partnerships are not taxed at the entity level in the states in which we initially will own properties. In the future, we may acquire properties in states that tax the income of limited partnerships.

	•	Under Sections 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

	•	We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, some of which are beyond our control, including (1) reduced demand for gas and oil; (2) increases in our operating expenses or general and administrative expenses, including expenses we will incur as a result of being a public company; (3) our ability to make working capital borrowings under our new credit facility to pay distributions; (4) principal and interest payments on our outstanding debt; (5) fluctuations in our working capital and anticipated cash needs; (6) the level of competition we face; (7) the amount of our estimated maintenance capital expenditures; (8) tax expenses and (9) declines in commodity prices.

Our Ability to Grow Depends on Our Ability to Access External Growth Capital

We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of

our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement or our new credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a cash distribution policy that will require us to pay distributions at an initial distribution rate of $0.40 per unit per complete quarter, or $1.60 per unit per year, on all common units, subordinated units and general partner units no later than 45 days after the end of each fiscal quarter to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. This equates to an aggregate cash distribution of $8.6 million per quarter or $34.5 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. If the underwriters exercise their over-allotment option, a number of common units equal to the additional common units issued will be redeemed from our Parent and there will be no effect on the number of common units outstanding or our aggregate cash distributions. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “— Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate of $0.40 per common unit per quarter ($1.60 per common unit on an annualized basis).


			Estimated
	Number of		Distributions
	Units		One Quarter		Four Quarters

Publicly held common units		8,750,000	$	3,500,000	$	14,000,000
Common units held by our Parent(1)		3,551,521		1,420,608		5,682,434

Total common units		12,301,521		4,920,608		19,682,434
Subordinated units held by our Parent		8,857,981		3,543,192		14,172,770
General partner units held by Quest Energy GP, LLC		431,827		172,731		690,923

Total units		21,591,329	$	8,636,531	$	34,546,127


(1)		If the underwriters’ over-allotment option is exercised, a number of common units equal to the additional common units issued will be redeemed proportionately from our Parent. Accordingly, the exercise of the underwriters’ over-allotment option will not affect the total amount of common units outstanding or the amount of cash needed to pay the initial distribution rate on all units.

The subordination period generally will end if we have earned and paid at least $1.60 on each outstanding common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2012. If we meet the tests for ending the subordination period as set forth above for any quarter ending on or after December 31, 2010, 25% of the subordinated units will convert into common units on a one-for-one basis. If we meet those tests for any quarter ending on or after December 31, 2011, an additional 25% of the subordinated units will convert into common units on a one-for-

one basis. In addition, if we have earned and paid at least $2.00 (125% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any two consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please read “How We Make Cash Distributions — Subordination Period.”

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

If distributions on our common units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future except that, during the subordination period to the extent we have available cash in any future quarter in excess of the amount necessary to make cash distributions to holders of our common units at the initial distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “How We Make Cash Distributions — Subordination Period.”

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith”, our general partner must believe that the determination is in our best interests.

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.

We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. Assuming that we become a publicly traded partnership before December 31, 2007, we will pay unitholders a prorated distribution for the period from the first day our common units are publicly traded to and including December 31, 2007.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.40 per unit each quarter through the quarter ending December 31, 2008. In those sections, we present two tables, consisting of:


	•	Our “Unaudited Pro Forma Available Cash”, in which we present the amount of cash we would have had available for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, based on our unaudited pro forma financial statements. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.


	•	Our “Estimated Cash Available for Distribution”, in which we present how we calculate the estimated minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the full initial quarterly distribution on all the outstanding units for each quarter through December 31, 2008. In “— Assumptions and Considerations” below, we also present our assumptions underlying our belief that we will generate sufficient Adjusted EBITDA to pay the initial quarterly distribution on all units for each quarter through December 31, 2008.

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and the Twelve Months Ended June 30, 2007

If we had completed the transactions contemplated in this prospectus on January 1, 2006, our pro forma cash for the year ended December 31, 2006 would have been approximately $1.0 million. As a result, we would have been able to pay only 4.4% of the initial quarterly distribution on our common units for the year ended December 31, 2006. We would not have had sufficient cash to make any cash distributions on our subordinated units for the year ended December 31, 2006.

If we had completed the transactions contemplated in this prospectus on July 1, 2006, our pro forma cash for the twelve months ended June 30, 2007 would have been approximately $2.0 million. As a result, we would have been able to pay only 9.8% of the initial quarterly distribution on our common units for the twelve months ended June 30, 2007. We would not have had sufficient cash to make any cash distributions on our subordinated units for the twelve months ended June 30, 2007.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our unaudited pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, the amount of available cash that would have been available for distributions to our unitholders, assuming that the formation transactions and this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

Quest Energy Partners, L.P.

Unaudited Pro Forma Available Cash


	Year Ended			Twelve Months
	December 31,			Ended
	2006			June 30, 2007
	(In thousands, except
	per unit data)

Pro forma net income (loss)(1)	$	(39,283	)	$	(48,533	)
Plus:
Pro forma interest expense, net(2)		5,673			6,063
Depreciation, depletion and amortization expense		25,521			27,904
Gain (loss) on sale of assets		7			247
Provision for impairment of gas and oil properties		30,719			30,719
Change in derivative fair value		(6,410	)		406
Non-cash compensation expense		1,636			3,033

Pro forma adjusted EBITDA(3)	$	17,863		$	19,839
Less:
Cash interest expense, net(4)		5,637			5,729
Estimated maintenance capital expenditures(5)		11,340			12,150
Expansion capital expenditures(5)		100,363			78,631
Plus:
Capital contributions to fund expansion capital expenditures(5)		100,363			78,631

Pro forma cash	$	886		$	1,960

Distributions per unit	$	1.60		$	1.60

Pro forma cash distributions:
Distribution to common unitholders	$	19,682		$	19,682
Distribution to subordinated units held by our Parent		14,173			14,173
Distribution to our general partner		691			691

Total distributions	$	34,546		$	34,546

Shortfall	$	(33,660	)	$	(32,586	)


(1)		Reflects net income of Quest Energy Partners Predecessor derived from its historical financial statements for the period indicated, giving pro forma effect to the formation transactions and this offering.


(2)		Pro forma interest expense, net for the year ended December 31, 2006, consists of $6.1 million of interest expense and $390,000 of interest income. Pro forma interest expense, net for the twelve months ended June 30, 2007, consists of $6.0 million of interest expense and $280,000 of interest income.


(3)		Please read “Summary — Non-GAAP Financial Measures.”


(4)		Reflects (a) interest expense related to $75.0 million in borrowings under our new credit facility at an assumed annual interest rate of 8.0%, (b) other interest expense of $63,000 for the year ended December 31, 2006 and $34,000 for the twelve months ended June 30, 2007, (c) other interest income of $390,000 for the year ended December 31, 2006 and $280,000 for the twelve months ended June 30, 2007, and (d) the exclusion of $3.5 million in amortization of debt issuance costs. If the interest rate used to calculate the interest on our credit facility borrowings were 1% higher or lower, our annual cash interest cost would increase or decrease, respectively, by approximately $750,000. We will incur debt issuance costs of approximately $3.5 million under our new credit facility (consisting of bank commitment fees, mortgage registration taxes, filing fees, legal fees and expenses). We have excluded the amortization of debt issuance costs because these amounts will be paid in connection with the origination of the credit facility from the net proceeds of this offering and borrowings under our new credit facility and do not represent ongoing cash interest expense.


(5)		Maintenance capital expenditures are those capital expenditures required to maintain our production levels and asset base over the long term. Historically, we did not characterize capital expenditures as maintenance or expansion and did not plan capital expenditures in a manner intended to maintain or expand our production or asset base. We have estimated what our maintenance capital expenditures would have been during each period based on the number of wells that we would have needed to drill and complete to maintain our level of production and asset base as of the beginning of the period.

		In addition, we estimate that we made expansion capital expenditures of $100.4 million for the year ended December 31, 2006 and $78.6 million for the twelve months ended June 30, 2007. Expansion capital expenditures are those capital expenditures that we expect will increase our production of our gas and oil properties or asset base over the long term. These expenditures were assumed to be funded by contributions from our Parent and are not included in our pro forma cash available for distribution calculation.

Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2008

In order to pay the initial quarterly distribution on all our common units, subordinated units and general partner units of $0.40 per unit per complete quarter for four quarters, we estimate that our Adjusted EBITDA for the twelve months ending December 31, 2008 must be at least $65.2 million. For the twelve months ended June 30, 2007, our pro forma Adjusted EBITDA was $19.8 million. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure our operating performance, liquidity or ability to service debt obligations. Please read “Summary — Summary Historical and Pro Forma Financial Data” and “Summary — Non-GAAP Financial Measures” for an explanation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to net income, its most directly comparable financial performance measure calculated in and presented in accordance with GAAP.

We also anticipate that if our Adjusted EBITDA for such period is $65.2 million, we would be permitted to make the quarterly distributions on all the common units, subordinated units and general partner units at the initial distribution rate under the anticipated applicable covenants under our new credit facility.

We believe that we will be able to generate the estimated minimum Adjusted EBITDA of $65.2 million for the twelve months ending December 31, 2008. You should read “— Assumptions and Considerations” below for a discussion of the material assumptions underlying this belief, which reflect our judgment of conditions we expect to exist and the course of action we expect to take. If our estimate is not achieved, we may not be able to pay the initial quarterly distribution on all of our units. We can give you no assurance that our assumptions will be realized or that we will generate the $65.2 million in Adjusted EBITDA required to pay the initial quarterly distribution on all our common units, subordinated units and general partner units. There will likely be differences between our estimates and the actual results we will achieve and those differences could be material. If we do not generate the estimated minimum Adjusted EBITDA or if our capital expenditures or interest expense are higher than estimated, we may not be able to pay the initial quarterly distribution on all units.

When considering our ability to generate the estimated minimum Adjusted EBITDA of $65.2 million, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our results of operations and cash available for distribution to our unitholders to vary significantly from those set forth below.

We do not as a matter of course make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below to present the estimated cash available for distribution for the twelve months ending December 31, 2008. The accompanying prospective financial information was not prepared with a view toward public disclosure or with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents, to the best of our management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the date in this prospectus except to the extent required by law. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to make the full initial quarterly distribution on all of our outstanding common units, subordinated units and general partner units for each quarter through December 31, 2008 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate the estimated Adjusted EBITDA necessary to pay the initial quarterly distribution on all our common units, subordinated units and general partner units for each quarter in the twelve months ending December 31, 2008. Our estimated Adjusted EBITDA is based on our projected results of operations for the twelve months ending December 31, 2008. The assumptions that we have made that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes set forth in “— Assumptions and Considerations.”

Quest Energy Partners, L.P.

Estimated Cash Available for Distribution


													Twelve Months
	Quarter Ending												Ending
	March 31,			June 30,			September 30,			December 31,			December 31,
	2008			2008			2008			2008			2008

Revenues:
Oil and gas sales	$	37,415		$	41,048		$	44,411		$	46,928		$	169,801
Costs and expenses:
Oil and gas production		8,512			9,538			10,349			10,955			39,354
Transportation expense		8,788			9,651			10,419			11,042			39,899
General and administrative expenses		2,107			2,403			2,696			2,986			10,193
Depreciation, depletion and amortization expense		9,819			10,763			11,638			12,292			44,512

Total costs and expenses		29,226			32,356			35,102			37,275			133,959

Operating income (loss)	$	8,189		$	8,692		$	9,309		$	9,653		$	35,842
Other income (expense)		(2,138	)		(2,499	)		(2,846	)		(3,050	)		(10,531	)

Net income (loss)	$	6,051		$	6,194		$	6,463		$	6,603		$	25,311

Adjustments to reconcile net income to estimated Adjusted EBITDA:
Add:
Interest expense		1,674			2,035			2,382			2,586			8,675
Depreciation, depletion and amortization expense		9,819			10,763			11,638			12,292			44,512
Change in derivative fair value		464			464			464			464			1,856

Estimated Adjusted EBITDA(1)	$	18,007		$	19,456		$	20,946		$	21,945		$	80,354

Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense		1,674			2,035			2,382			2,586			8,675
Estimated maintenance capital expenditures		5,500			5,500			5,500			5,500			22,000
Expansion capital expenditures		17,350			18,768			15,933			4,451			56,501
Plus:
Borrowings to fund expansion capital expenditures		17,350			18,768			15,933			4,451			56,501

Estimated cash available for distribution	$	10,834		$	11,921		$	13,065		$	13,860		$	49,679

Per unit cash distribution	$	0.4000		$	0.4000		$	0.4000		$	0.4000		$	1.60

Distribution to common unitholders	$	4,921		$	4,921		$	4,921		$	4,921		$	19,682
Distribution to subordinated units		3,543			3,543			3,543			3,543			14,173
Distribution to our general partner		173			173			173			173			691

Total cash distributions	$	8,637		$	8,637		$	8,637		$	8,637		$	34,546

Excess (shortage) of cash available for distribution over cash distributions	$	2,197		$	3,284		$	4,428		$	5,223		$	15,133

Estimated Adjusted EBITDA	$	18,007		$	19,456		$	20,946		$	21,945		$	80,354
Less:
Excess (shortage) of cash available for distribution over cash distributions	$	2,197		$	3,284		$	4,428		$	5,223		$	15,133

Minimum estimated Adjusted EBITDA necessary to pay cash distributions	$	15,810		$	16,171		$	16,518		$	16,722		$	65,222

Interest coverage ratio(2)		6.85			7.40			7.84			8.09			8.09
Leverage ratio(2)		1.82			1.78			1.77			1.78			1.78
Current ratio(2)		2.19			1.84			1.53			1.30			1.30


(1)		Please read “Summary — Non-GAAP Financial Measures.”

(2)		At the closing of this offering, we will enter into a new credit facility that will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens and engage in transactions with affiliates. Furthermore, our credit facility will contain covenants requiring us to maintain an interest coverage ratio (the ratio of consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any, to consolidated interest expense) of not less than 2.50 to 1.00, a leverage


		ratio (the ratio of consolidated indebtedness to consolidated adjusted EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any) of less than 3.50 to 1.00 and a current ratio (ratio of current assets plus unused availability under our borrowing base to current liabilities excluding the current portion of the borrowing base) of not less than 1.00 to 1.00. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the twelve months ending December 31, 2008, we expect to generate cash flow from operations in an amount sufficient to fund our budgeted maintenance capital expenditures and pay the initial quarterly distribution on all units through December 31, 2008.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full initial quarterly distribution (absent borrowings under our new credit facility), or any amount, on all units, in which event the market price of our common units may decline substantially. We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient capital expenditures to maintain or grow 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. Decreases in commodity prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, 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. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors”, and “Cautionary Note Regarding Forward-Looking Statements.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Operations and Revenue

Production. The following table sets forth information regarding net production of gas and oil for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008:


					Forecasted for
			Twelve Months		Twelve Months
	Year Ended		Ended		Ending
	December 31,		June 30,		December 31,
	2006		2007		2008

Gas (MMcf)		12,282		14,739		24,457
Oil (Bbl)		9,737		8,035		5,318
Combined (MMcfe)		12,341		14,787		24,489
Gas (MMcf/d)		33.6		40.4		66.8
Oil (Bbl/d)		26.7		22.0		14.5
Combined (MMcfe/d)		33.8		40.5		66.9

Our forecasted net production volumes for the twelve months ending December 31, 2008 represents a 66% increase in forecasted production from our pro forma production for the twelve months ended June 30, 2007. Approximately 92% of our forecasted net production volumes for the twelve months ending

December 31, 2008 is expected to come from our proved reserves as of June 30, 2007. The forecast is based on the following assumptions:


	•	for wells that were producing in commercial quantities as of June 30, 2007, we have used the production estimated for the twelve months ending December 31, 2008 in our reserve report as of the same date prepared by Cawley, Gillespie & Associates, Inc., our independent reserve engineers, and

	•	for the 632 additional gross wells that we forecast connecting between July 1, 2007 and December 31, 2008, we have assumed that each of these wells will produce an amount of gas based on the average production profile for our Cherokee Basin wells.

Our production profile for a Cherokee Basin 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. Over 99% of the wells that we have drilled and completed in the Cherokee Basin were economically productive wells. We have assumed that we will be successful in producing gas in commercial quantities from all additional wells based on past drilling experience in the Cherokee Basin.

Prices. The table below illustrates the relationship between gas and oil wellhead prices as a percentage of average NYMEX prices for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 as compared to our forecast for the twelve months ending December 31, 2008:


							Forecasted for
				Twelve Months			Twelve Months
	Year Ended			Ended			Ending
	December 31,			June 30,			December 31,
	2006			2007			2008

Gas:
Average NYMEX gas ($/Mcf)(1)	$	7.13		$	6.86		$	7.75
Differential to NYMEX		(1.20	)(2)		(0.72	)		(0.75	)

Wellhead price	$	5.93		$	6.14		$	7.00

Differential percentage to NYMEX		(16.8	)%(2)		(10.5	)%		(9.7	)%
Oil:
Average NYMEX oil ($/Bbl)	$	66.23		$	64.98		$	67.00
Differential to NYMEX		(5.33	)		(6.43	)		(6.75	)

Wellhead price	$	60.90		$	55.34		$	60.25

Differential percentage to NYMEX		(8.0	)%		(9.9	)%		(10.1	)%
Total combined wellhead price ($/Mcfe)	$	5.95		$	5.92		$	7.26


(1)		We have estimated average NYMEX gas prices of $7.75 per Mcf for the twelve months ending December 31, 2008 based on NYMEX future prices as of October 19, 2007 that averaged $8.02 per Mcf for the twelve months ending December 31, 2008. Recent NYMEX spot prices have been below the forecasted price (for instance, the NYMEX spot price on October 15, 2007 was $7.08 per Mcf) and could limit our ability to make distributions if they remain at recent levels. Please read “— Gas and Oil Revenues” for an analysis of how Adjusted EBITDA may be influenced by changes in NYMEX prices.

(2)		Differential to NYMEX for the year ended December 31, 2006 was adversely affected by the hurricanes in the summer and fall of 2005.

Hedging. The following table summarizes our realized gas prices for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008:


							Forecasted for
				Twelve Months			Twelve Months
	Year Ended			Ended			Ending
	December 31,			June 30,			December 31,
	2006			2007			2008

Gas wellhead price ($/Mcf)	$	5.93		$	6.14		$	7.00
Gas hedges gain (loss) ($/Mcf)		(0.64	)		(0.39	)		(0.06	)

Gas realized price ($/Mcf)	$	5.29		$	5.75		$	6.94

We do not have any hedges with respect to our oil production. We have entered into derivative arrangements for a portion of our gas production. For a discussion of our hedges with respect to our gas production, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

The following table summarizes our gas derivative contracts covering forecasted production for the twelve months ending December 31, 2008:


	Swaps				Collars
							Weighted		Weighted
			Weighted				Average		Average
			Average				Floor		Ceiling
	MMBtu/d		Price		MMBtu/d		Price		Price

Gas derivative contracts for January 2008 — December 2008:
Southern star contracts		6,373	$	7.35		11,232	$	8.00	$	8.97
NYMEX contracts(1)		13,145	$	7.88		8,000	$	4.50	$	5.52


(1)		We have entered into derivative contracts locking the basis differential on 4,000 MMBtu/d at $1.03 per MMBtu.

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 38,750 MMBtu/d gas derivative swaps and collars described in the table above cover 40% and 40%, respectively, of our forecasted net gas production from proved developed producing reserves and 29% and 29%, respectively, of our forecasted total net gas production for the twelve months ending December 31, 2008.

Gas and Oil Revenues. The following table illustrates the primary components of revenues for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively, and on a forecasted basis for the twelve months ending December 31, 2008 (in thousands):


							Forecasted for
				Twelve Months			Twelve Months
	Year Ended			Ended			Ending
	December 31,			June 30,			December 31,
	2006			2007			2008

Gas:
Gas wellhead revenues	$	72,865		$	90,539		$	170,880
Gas hedges (loss)		(7,888	)		(5,802	)		(1,399	)

Total gas revenues	$	64,977		$	84,737		$	169,481

Oil:
Total oil revenues	$	574		$	445		$	320

Gas comprises 99% of our total estimated production for the twelve months ending December 31, 2008. As a consequence, our revenues are primarily affected by changes in gas prices rather than changes in oil prices. The following table shows estimated Adjusted EBITDA sensitivities under various assumed NYMEX gas prices for the twelve months ending December 31, 2008. Total revenues consists of oil and gas sales, including the effects of hedges. In addition, the estimated Adjusted EBITDA amounts shown below are based on realized gas prices that take into account our average gas price differential assumption of 90.3% of NYMEX for our production. We have assumed no changes in our production based on changes in prices and that our hedging counterparties will perform as expected. However, over the long-term, a sustained decline in gas prices would likely lead to a decline in production as well as a reduction in our realized gas prices. Therefore, the following table is not illustrative of the effects of changes in commodity prices for periods subsequent to December 31, 2008 (dollars in thousands, except per unit data).


	Twelve Months Ending
	December 31, 2008
NYMEX gas price ($/Mcf)	$	5.00		$	5.84		$	7.00		$	8.00		$	9.00
NYMEX oil price ($/Bbl)	$	67.00		$	67.00		$	67.00		$	67.00		$	67.00
Combined daily production (MMcfe/d)		66.9			66.9			66.9			66.9			66.9
Percentage gas		99	%		99	%		99	%		99	%		99	%
Total revenues	$	144,368		$	153,213		$	163,280		$	171,975		$	184,620
Oil and gas production expense		37,123			37,889			38,782			39,545			40,654
Transportation expense		39,899			39,899			39,899			39,899			39,899
General and administrative expenses		10,193			10,193			10,193			10,193			10,193

Adjusted EBITDA	$	57,152		$	65,222		$	74,405		$	82,337		$	93,873
Less:
Minimum adjusted EBITDA necessary to pay cash distributions		65,222			65,222			65,222			65,222			65,222

Excess (shortage)	$	(8,069	)	$	0		$	9,184		$	17,116		$	28,651

The following table shows estimated Adjusted EBITDA under various assumed production levels for the twelve months ending December 31, 2008. The estimated Adjusted EBITDA amounts shown below are based on realized commodity prices that take into account our average NYMEX commodity price differential assumption of 90.3% of NYMEX for our production and applicable hedges.


Percentage of Forecasted Net Production	90%		100%		110%

Gas (MMcf)		22,012		24,457		26,903
Oil (MBbl)		5		5		6

Total (MMcfe)		22,040		24,489		26,938

Gas (Mcf/d)		60.1		66.8		73.5
Oil (Bbl/d)		13.1		14.5		16.0

Total (MMcfe/d)		60.2		66.9		73.6

Adjusted EBITDA (in thousands):
Total revenues	$	152,681	$	169,801	$	186,921
Oil and gas production expense		37,851		39,354		40,857
Transportation expense		35,910		39,899		43,889
General and administrative expenses		9,249		10,193		11,138

Adjusted EBITDA	$	69,671	$	80,354	$	91,037
Less:
Minimum adjusted EBITDA necessary to pay cash distributions		65,222		65,222		65,222

Excess	$	4,450	$	15,133	$	25,816

Capital Expenditures and Expenses

Capital Expenditures. We estimate that our capital expenditures for the twelve months ending December 31, 2008 will be approximately $78.5 million as compared to $117.4 million and $95.2 million for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. We expect that our capital expenditures will average approximately $80.8 million over the three-year period ending December 31, 2010. The capital expenditures for the twelve months ending December 31, 2008 are expected to consist of the following:


	•	approximately $49.5 million to drill and complete 325 gross wells;

	•	approximately $3.2 million for recompletions;

	•	approximately $11.8 million for equipment and facilities; and

	•	approximately $14.0 million for potential costs that we may incur for acquiring leases and similar expenditures that will enable us to maintain our capital asset base.

The estimated capital expenditures for the twelve months ending December 31, 2008 consists of $22.0 million of maintenance capital expenditures and $56.5 million of expansion capital expenditures.

We expect to finance our maintenance capital expenditures with cash flow from operations and our expansion capital expenditures from a combination of available borrowings under our new credit facility, cash flow from operations and the proceeds from additional debt and equity issuances.

Oil and Gas Production Expense. The following table summarizes oil and gas production expense on an aggregate basis and on a per Mcfe basis for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008 (in thousands, except per Mcfe amounts):


					Forecasted for
			Twelve Months		Twelve Months
	Year Ended		Ended		Ending
	December 31,		June 30,		December 31,
	2006		2007		2008

Lease operations expenses	$	15,795	$	20,256	$	24,449
Ad valorem taxes		2,160		3,258		7,264
Production taxes		3,253		4,181		7,641

Total oil and gas production expense	$	21,208	$	27,695	$	39,354

Lease operations expenses ($/Mcfe)	$	1.28	$	1.37	$	1.00
Ad valorem taxes ($/Mcfe)		0.18		0.22		0.30
Production taxes ($/Mcfe)		0.26		0.28		0.31

Total oil and gas production expense ($/Mcfe)	$	1.72	$	1.87	$	1.61

Lease operations expenses consist of the labor, field office rent, vehicle expenses, supervision, minor maintenance, tools and supplies and other customary charges. We estimate that our lease operations expenses for the twelve months ending December 31, 2008 will be approximately $24.5 million as compared to $15.8 million and $20.3 million for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. The $8.7 million increase and $4.2 million increase in forecasted lease operations expenses are primarily attributable to the following:


	•	expected increases in prices paid to oilfield service companies and suppliers due to a current higher price environment; and

	•	increased operational activity due to increased production.

The estimated decrease in lease operations expense on a per Mcfe basis is the result of estimated cost reductions that we began to implement in August 2007 and the estimated increase in production.

We estimate that our ad valorem taxes projected for the twelve months ending December 31, 2008 will be approximately $7.3 million as compared to $2.2 million and $3.3 million of ad valorem taxes for the year ended December 31, 2006 and for the twelve months and June 30, 2007, respectively. The $5.1 million increase and $4.0 million increase in forecasted ad valorem taxes is primarily attributable to our increased level of forecasted activity and higher valuations being assessed by the states in which we conduct operations.

We estimate that our production taxes projected for the twelve months ending December 31, 2008 will be approximately $7.6 million as compared to $3.3 million and $4.2 million of production taxes for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. The $4.3 million increase and $3.5 million increase in forecasted production taxes is primarily due to higher levels of forecasted production.

The following table summarizes production taxes on an aggregate basis and as a percentage of wellhead revenues for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively and for the twelve months ending December 31, 2008 (dollars in thousands):


							Forecasted for
	Year			Twelve Months			Twelve Months
	Ended			Ended			Ending
	December 31,			June 30,			December 31,
	2006			2007			2008

Oil and gas wellhead revenues	$	73,439		$	90,984		$	171,201
Production taxes		3,253			4,181			7,641
Production taxes as a percentage of oil and gas wellhead revenues		4.4	%		4.6	%		4.5	%

Our production taxes are calculated as a percentage of our oil and gas wellhead revenues. In general, as prices and volumes increase, our production taxes increase and as prices and volumes decrease, our production taxes decrease. Additionally, production tax percentages vary by state and as revenues by state vary, it can cause increases or decreases in our overall rate.

Transportation Expense. The following table summarizes transportation expense on an aggregate basis and on a per Mcf basis for the year ended December 31, 2006 and for the twelve months ended June 30, 2007 and on a forecasted basis for the twelve months ending December 31, 2008 (in thousands, except per Mcf amounts):


					Forecasted for
	Year		Twelve Months		Twelve Months
	Ended		Ended		Ending
	December 31,		June 30,		December 31,
	2006		2007		2008
Transportation expense	$	19,884	$	24,824	$	39,899
Transportation expense ($/Mcf)	$	1.61	$	1.68	$	1.63

We estimate that our transportation expense projected for the twelve months ending December 31, 2008 will be approximately $39.9 million as compared to $19.9 million and $24.8 million of expenses for the year ended December 31, 2006 and for the twelve months ended June 30, 2007, respectively. The $20.0 million increase and $15.1 million increase in forecasted transportation expense is primarily due to a higher level of production. The increase in transportation expense per Mcf is due to higher operating costs, compression rentals and a fixed transportation fee.

General and Administrative Expenses. We estimate that our general and administrative expenses projected for the twelve months ending December 31, 2008 will be approximately $10.2 million as compared to approximately $8.1 million and $10.8 million for the year ended December 31, 2006 and the twelve months ended June 30, 2007, respectively. The $2.1 million increase and $0.6 million decrease in forecasted general and administrative expenses is primarily attributable to increased costs associated with the costs of being a public company and the increased size of our operations and the expense recorded for certain equity issuances during the twelve months ended June 30, 2007. At the closing of this offering, we expect to enter into a management services agreement with Quest Energy Service, LLC whereby it will perform administrative services for us and be reimbursed for its expenses incurred on our behalf. Our Predecessor’s carve-out financial statements include non-cash compensation expenses of our Predecessor. However, to the extent that these non-cash compensation expenses are allocated to us under the management services agreement, we will reimburse Quest Energy Service for these expenses. Our general partner intends to establish a long term incentive plan and grant incentive equity compensation awards to our general partner’s management and non-employee directors. At this time, no decision has been made with respect to any equity incentive awards. As a result no non-cash compensation expense is included in our forecast of general and administrative expenses.

Interest Expense. We estimate that our interest expense projected for the twelve months ending December 31, 2008 will be approximately $8.7 million as compared to $6.1 million and $6.0 million on a pro forma basis for the year ended December 31, 2006 and the twelve months ended June 30, 2007, respectively. During the twelve months ending December 31, 2008, we expect to have approximately $103.3 million in debt outstanding, on average, under our new credit facility, consisting of the $75.0 million to be outstanding at the closing of this offering and additional amounts borrowed to fund our expansion capital expenditures.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending December 31, 2008 is based on the following significant assumptions related to regulatory, industry and economic factors:


	•	there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

	•	there will not be any major adverse change in the portions of the energy industry or in general economic conditions; and

	•	market, insurance and overall economic conditions will not change substantially.

Distributions

Distributions on the common units, subordinated units and general partner units for the twelve months ending December 31, 2008 are forecasted to be $34.5 million in the aggregate. Quarterly distributions will be paid within 45 days after the close of each quarter.

HOW WE MAKE CASH DISTRIBUTIONS

Our Parent holds all of the member interests in our general partner, and consequently is indirectly entitled to all of the distributions that we make to our general partner, subject to the terms of the limited liability company agreement of our general partner and relevant legal restrictions.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General. Within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2007 we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the quarterly distribution for the period from the closing of this offering through December 31, 2007 based on the actual length of the period.

Definition of Available Cash. Available cash, for any quarter, consists of all cash on hand at the end of that quarter:


	•	less the amount of cash reserves established by our general partner to:


	•	provide for the proper conduct of our business, including the payment of fees payable to our general partner;

	•	comply with applicable law, any of our debt instruments or other agreements; or

	•	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;


	•	plus, all additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months other than from additional working capital borrowings.

Minimum Quarterly Distribution. We will distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.40 per unit, or $1.60 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our new credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility” for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, our general partner will be entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will initially be represented by 431,827 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions may 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 below) in

excess of $0.46 per unit per quarter. The maximum distribution of 25% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 25% does not include any distributions that our general partner may receive on units that it owns.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus. Operating surplus consists of:


	•	$25.9 million (as described below); plus

	•	all of our cash receipts after the closing of this offering, excluding cash from (i) borrowings that are not working capital borrowings, (ii) sales of equity securities and debt securities, (iii) sales or other dispositions of assets outside the ordinary course of business, (iv) the termination of commodity hedge contracts prior to the termination date specified therein, (v) capital contributions received, (vi) corporate reorganizations or restructurings and (vii) sales in connection with plugging and abandoning and other reclamation activities for our wells; plus

	•	working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for the quarter; less

	•	all of our operating expenditures (as defined below) after the closing of this offering; less

	•	the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures; less

	•	all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings.

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Part of our business strategy is to limit our exposure to volatility in commodity prices by entering into derivative contracts. In general, all of the payments we make or receive under derivative contracts, including periodic settlement payments, the purchase price of put contracts and payments made or received in connection with the termination of derivative contracts, will be added or deducted in the determination of operating surplus on the date the payment is received or made. Our partnership agreement allows our general partner, with the approval of the conflicts committee of our board of directors, to allocate payments made or received under derivative contracts over multiple periods, or to exclude such payments or receipts from the calculation of operating surplus if it determines such treatment to be appropriate.

Operating Expenditures. We define operating expenditures in the partnership agreement, and it generally means all of our expenditures, including, but not limited to, lease operating expenses, taxes, reimbursements of expenses to our general partner, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures, provided that operating expenditures will not include:


	•	repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus when such repayment actually occurs;

	•	payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;

	•	actual maintenance capital expenditures;


	•	expansion capital expenditures;

	•	payment of transaction expenses relating to interim capital transactions; or

	•	distributions to partners.

Maintenance Capital Expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our production levels and asset base over the long term. Examples of maintenance capital expenditures include capital expenditures to bring our non-producing reserves into production, such as drilling and completion costs, enhanced recovery costs and other construction costs, and costs to acquire reserves that replace the reserves we expect to produce in the future. Well plugging and abandonment, site restoration and similar costs will also be considered maintenance capital expenditures.

Expansion Capital Expenditures. Expansion capital expenditures are those capital expenditures that we expect will increase our production of our gas and oil properties or our asset base over the long term. Examples of expansion capital expenditures include the acquisition of gas and oil properties or equipment or new exploitation or development prospects, to the extent we expect that such expenditures will increase current production of our oil and gas properties over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is put into service or the date that it is disposed of or abandoned.

Estimated Average Maintenance Capital Expenditures. Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus (as described below) and available cash for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus each quarter. Accordingly, to eliminate the effect of these fluctuations on operating surplus, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our production levels and asset base over the long term be subtracted in calculating operating surplus each quarter as opposed to the actual amounts we spend. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only.

The deduction of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:


	•	it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter and subsequent quarters;

	•	it will reduce the need to borrow under our new credit facility to pay distributions;

	•	it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our general partner; and

	•	it will reduce the likelihood that a large maintenance capital expenditure in a period will prevent the conversion of some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Characterization of Cash Distributions. Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available

cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an amount equal to $25.9 million. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $25.9 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General. Our partnership agreement provides that, 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.

Subordination Period. Except as described below under “— Early Conversion of Subordinated 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:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period. 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:


	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units. 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:


	•	distributions of available cash from operating surplus on each outstanding common unit, subordinated unit and the 2% general partner interest equaled or exceeded $2.00 (125% of the annualized minimum quarterly distribution) for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $2.00 per common unit (125% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Adjusted Operating Surplus. Adjusted operating surplus consists of:


	•	operating surplus generated with respect to that period; less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus is calculated using estimated maintenance capital expenditures, rather than actual maintenance capital expenditures and, to the extent the estimated amount for a period is less than the actual amount, the cash generated from operations during that period would be less than adjusted operating surplus.

Distributions of Available Cash from Operating Surplus during the Subordination Period

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


	•	first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “— Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “— Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage (13% and 23%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that the general partner maintains its 2% general partner interest and continues to own the incentive distribution rights.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.46 per unit for that quarter (the “first target distribution”);

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.50 per unit for that quarter (the “second target distribution”); and

	•	thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed adjusted operating surplus for such quarter. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be

sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period.

The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units. We will also issue an additional amount of general partner units in order to maintain the general partner’s ownership interest in us relative to the issuance of the Class B units.

The following discussion assumes that the general partner maintains its 2% general partner interest and continues to own the incentive distribution rights.

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 be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter;

	•	thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.


	Quarterly	Marginal Percentage						Quarterly
	Distribution	Interest in Distributions						Distribution per
	per Unit				General			Unit Following
	Prior to Reset	Unitholders			Partner			Hypothetical Reset

Minimum Quarterly Distribution	$0.40		98	%		2	%	$0.60
First Target Distribution	up to $0.46		98	%		2	%	up to $0.69(1)
Second Target Distribution	above $0.46 up to $0.50		85	%		15	%	above $0.69(1) up to $0.75(2)
Thereafter	above $0.50		75	%		25	%	above $0.75(2)


(1)		This amount is 115% of the hypothetical reset minimum quarterly distribution


(2)		This amount is 125% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that there are 21,159,502 common units and 431,827 general partner units, representing a 2% general partner interest, outstanding, and that the average distribution to each common unit is $0.60 for the two quarters prior to the reset. The assumed number of outstanding units assumes the conversion of all subordinated units into common units and no additional unit issuances.


				General Partner Cash Distribution
	Quarterly	Common		Prior to Reset
	Distribution	Unitholders Cash				2% General		Incentive
	per Unit	Distributions		Class B		Partner		Distribution				Total
	Prior to Reset	Prior to Reset		Units		Interest		Rights		Total		Distributions

Minimum Quarterly Distribution	$0.40	$	8,463,801		—	$	172,731	$	—	$	172,731	$	8,636,531
First Target Distribution	up to $0.46		1,269,570		—		25,910		—		25,910		1,295,480
Second Target Distribution	above $0.46		846,380		—		19,915		129,446		149,361		995,741
	up to $0.50
Thereafter	above $0.50		2,115,950		—		56,425		648,891		705,317		2,821,267

		$	12,695,701		—	$	274,980	$	778,338	$	1,053,318	$	13,749,019

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 21,159,502 common units, 1,297,230 Class B units and 463,358 general partner units, representing a 2% general partner interest, outstanding, and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) the $778,338 received by the general partner in respect of its incentive distribution rights as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above by (y) the $0.60 of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.


	Quarterly	Common		General Partner Cash Distribution After Reset
	Distribution	Unitholders Cash				2% General		Incentive
	per Unit	Distributions				Partner		Distribution				Total
	After Reset	After Reset		Class B Units		Interest		Rights		Total		Distributions

Minimum Quarterly Distribution	$0.60	$	12,695,701	$	778,338	$	274,980		—	$	1,053,318	$	13,749,019
First Target Distribution	up to $0.69		—		—		—		—		—		—
Second Target Distribution	above $0.69 up to $0.75		—		—		—		—		—		—
Thereafter	above $0.75		—		—		—		—		—		—

		$	12,695,701	$	778,338	$	274,980		—	$	1,053,318	$	13,749,019

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount”, until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.


	Total Quarterly	Marginal Percentage
	Distribution per	Interest in Distributions
	Unit Target Amount	Unitholders			General Partner

Minimum Quarterly Distribution	$0.40		98	%		2	%
First Target Distribution	up to $0.46		98	%		2	%
Second Target Distribution	above $0.46 up to $0.50		85	%		15	%
Thereafter	above $0.50		75	%		25	%

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 75% being paid to the holders of units and 25% to the general partner. The

percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:


	•	the minimum quarterly distribution;

	•	target distribution levels;

	•	the unrecovered initial unit price; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter will be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the


		amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;


	•	third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

	•	fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;

	•	fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;

	•	thereafter, 75% to all unitholders, pro rata, and 25% to our general partner.

The percentage interests set forth above for our general partner assumed that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we did not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:


	•	first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts. Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table shows selected historical financial data of Quest Energy Partners Predecessor and pro forma financial data of Quest Energy Partners, L.P. as of and for the periods indicated. The selected historical financial data as of May 31, 2003 and 2004 and December 31, 2004, 2005 and 2006 and for the fiscal years ended May 31, 2003 and 2004, the seven months ended December 31, 2004 and the fiscal years ended December 31, 2005 and 2006 are derived from the audited financial statements of Quest Energy Partners Predecessor. The selected historical financial data as of May 31, 2002 and June 30, 2006 and 2007 and for the fiscal year ended May 31, 2002 and for the six months ended June 30, 2006 and 2007 are derived from the unaudited financial statements of Quest Energy Partners Predecessor. The historical financial statements of Quest Energy Partners Predecessor are comprised of our Parent’s assets, liabilities and operations located in the Cherokee Basin (other than its midstream assets), which our Parent will contribute to us at the completion of this offering.

The selected pro forma financial data for the year ended December 31, 2006 and as of and for the six months ended June 30, 2007 are derived from the unaudited pro forma financial statements of Quest Energy Partners, L.P. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on June 30, 2007, in the case of the pro forma balance sheet, or as of January 1, 2006, in the case of the pro forma statement of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007. These transactions include:


	•	our Parent’s transfer of the Partnership Properties to us;

	•	our issuance of 431,827 general partner units and the incentive distribution rights to our general partner and 3,551,521 common units and 8,857,981 subordinated units to our Parent;

	•	the sale by us of 8,750,000 common units to the public in this offering;

	•	the payment by us of the underwriting discounts, structuring fee and other offering and transaction expenses;

	•	the repayment of existing indebtedness of our Parent that is secured by the Partnership Properties with the proceeds of this offering, $75.0 million of borrowings under our new credit facility and borrowings under a new credit facility of our Parent; and

	•	the execution by us of the midstream services agreement, management services agreement and omnibus agreement.

You should read the following table in conjunction with “Summary — Formation Transactions and Partnership Structure”, “Use of Proceeds”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, the historical carve out financial statements of Quest Energy Partners Predecessor and the unaudited pro forma financial statements of Quest Energy Partners, L.P. included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.

The following table includes Adjusted EBITDA, which is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Summary — Non-GAAP Financial Measures.”


																									Quest Energy
																									Partners, L.P.
	Quest Energy Partners Predecessor																								Pro Forma
										Seven
										Months			Year
										Ended			Ended
																			Six									Six
																			Months						Year			Months
																			Ended						Ended			Ended
	Year Ended May 31,									December 31,									June 30,						December 31,			June 30,
	2002			2003			2004(1)			2004(1)			2005			2006			2006			2007			2006			2007
	(Unaudited)															(Restated)(2)			(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)
	(In thousands)

Statement of Operations Data:
Revenues:
Oil and gas sales	$	1,699		$	8,345		$	28,147		$	24,201		$	44,565		$	65,551		$	33,785		$	53,416		$	65,551		$	53,416
Other revenue/(expense)		144			(908	)		(904	)		37			387			(83	)		(67	)		(32	)		(83	)		(32	)

Total revenues		1,843			7,437			27,243			24,238			44,952			65,468			33,718			53,384			65,468			53,384
Costs and expenses:
Oil and gas production		593			1,979			5,003			5,389			14,388			21,208			8,572			14,967			21,208			14,967
Transportation expense		441			644			1,869			3,196			7,038			17,278			5,167			13,170			19,884			13,170
General and administrative expenses		259			711			2,264			2,328			4,068			8,149			3,214			5,846			8,149			5,846
Provision for impairment of gas and oil properties(3)		—			—			—			—			—			30,719			—			—			30,719			—
Depreciation, depletion and amortization		184			1,578			6,698			6,954			20,121			25,521			11,680			14,063			25,521			14,063

Total costs and expenses		1,477			4,912			15,834			17,867			45,615			102,875			28,633			48,046			105,481			48,046

Operating income (loss)		366			2,525			11,409			6,371			(663	)		(37,407	)		5,085			5,338			(40,013	)		5,338

Other income (expense):
Change in derivative fair value(4)		—			(4,867	)		(2,013	)		(1,487	)		(4,668	)		6,410			6,631			(185	)		6,410			(185	)
Gain (loss) on sale of assets		—			(3	)		(6	)		—			12			(7	)		43			(197	)		(7	)		(197	)
Interest expense, net		(106	)		(438	)		(6,403	)		(7,702	)		(19,873	)		(16,545	)		(6,185	)		(13,880	)		(5,673	)		(2,742	)

Total other expense		(106	)		(5,308	)		(8,422	)		(9,189	)		(24,529	)		(10,142	)		489			(14,262	)		730			(3,124	)

Net income (loss) before cumulative effect of accounting change		260			(2,783	)		2,987			(2,818	)		(25,192	)		(47,549	)		5,574			(8,924	)		(39,283	)		2,214
Cumulative effect of accounting change, net of tax		—			—			(28	)		—			—			—			—			—			—			—

Net income (loss)	$	260		$	(2,783	)	$	2,959		$	(2,818	)	$	(25,192	)	$	(47,549	)	$	5,574		$	(8,924	)	$	(39,283	)	$	2,214

Balance Sheet Data (at period end):
Property, plant and equipment, net	$	3,183		$	18,397		$	137,621		$	159,096		$	191,290		$	249,549		$	245,309		$	283,599					$	283,599
Total assets		3,987			23,264			149,651			178,332			217,650			311,718			303,812			334,058						320,205
Long-term debt		1,717			10,575			126,766			148,747			76,296			225,569			163,104			235,270						75,270
Partners’ capital		1,983			6,521			(1,730	)		(3,877	)		69,547			51,091			97,128			62,847						208,994
Other Financial Data:
Adjusted EBITDA							$	18,322		$	13,387		$	20,095		$	20,469		$	17,686		$	21,719		$	17,863		$	21,719
Capital expenditures		2,114			8,000			125,482			28,075			51,682			117,387			67,610			45,466
Net cash provided by (used in):
Operating activities		795			3,306			15,701			18,778			584			11,183			13,546			2,539
Investing activities		(2,114	)		(8,397	)		(125,482	)		(28,075	)		(51,645	)		(117,194	)		(67,448	)		(45,496	)
Financing activities		1,319			7,203			111,060			12,285			47,141			124,818			86,698			31,603


(1)		Quest Energy Partners Predecessor changed its fiscal year end from May 31 to December 31 effective as of January 1, 2005.

(2)		Certain changes were made to carve out assumptions resulting in the understatement of previously recorded cash and partners’ capital as of December 31, 2006. Please read Note 19 to the carve out financial statements.

(3)		As of December 31, 2006, Quest Energy Partners Predecessor’s net book value of gas and oil properties exceeded the ceiling (defined as estimated after-tax future net revenues discounted at 10% per annum from proved gas and oil reserves, plus the cost of properties not subject to amortization, as adjusted for the present value of all future gas and oil hedges) under the full cost method of accounting. Accordingly, a provision for impairment was recognized in the fourth quarter of 2006 of $30.7 million. The provision for impairment is primarily attributable to declines in the prevailing market prices of gas and oil at the measurement date.

(4)		Gas derivative contracts were used to reduce our exposure to changes in gas prices. Change in the fair value of these gas derivative contracts are marked to market in our earnings each period. Further, these amounts represent non-cash charges.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included elsewhere in this prospectus reflect the assets, liabilities and operations of Quest Energy Partners Predecessor, which is our predecessor. At the closing of the offering, the assets of our predecessor will be contributed to us by our Parent. The following discussion analyzes the financial condition and results of operations of Quest Energy Partners Predecessor. You should read the following discussion of the financial condition and results of operations for Quest Energy Partners Predecessor in conjunction with the historical financial statements and notes of Quest Energy Partners Predecessor and the unaudited pro forma financial statements for Quest Energy Partners, L.P. included elsewhere in this prospectus.

Overview

Our Cherokee Basin properties had estimated net proved reserves at June 30, 2007 of 205.5 Bcfe, and we had a standardized measure of $353.1 million. At June 30, 2007, our estimated net proved reserves were approximately 99% CBM and 66% proved developed. We believe we are the largest CBM producer in the Cherokee Basin with an average net daily production of 43.5 MMcfe for the six months ended June 30, 2007. Our reserves are long-lived, with an average reserve-to-production ratio of 13.1 years (8.7 years for our proved developed properties) as of June 30, 2007. Our typical Cherokee Basin CBM well has a predictable production profile and a standard economic life of approximately 15 years.

As of June 30, 2007, we were operating approximately 1,904 gross gas wells, of which over 90% were multi-seam wells, and 29 gross oil wells. As of June 30, 2007, we owned the development rights to approximately 523,000 net acres throughout the Cherokee Basin and had only developed approximately 48% of our acreage. For 2007, we have budgeted approximately $76.0 million to drill and complete an estimated 558 gross wells and recomplete an estimated 60 gross wells, as well as an additional $37.0 million for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities. For the six months ended June 30, 2007, we had total capital expenditures of approximately $45.5 million, including $34.3 million to connect 251 gross wells and recomplete 34 gross wells. We expect to drill and connect 325 wells in 2008. At this time, we have not identified our drilling locations for 2008 and some or all of these wells may be drilled on locations that were not classified as containing proved reserves in our June 30, 2007 reserve report. As of June 30, 2007, our undeveloped acreage contained approximately 2,295 gross CBM drilling locations, of which 756 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.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are the following:


	•	volumes of gas and oil produced;

	•	realized prices;


	•	production and general and administrative expenses; and

	•	Adjusted EBITDA.

Volumes of gas and oil produced — the Partnership Properties

The following table sets forth information regarding the Partnership Properties. 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.


	Year		Seven Months
	Ended		Ended		Year Ended				Six Months Ended
	May 31,		December 31,						June 30,
	2004		2004		2005		2006		2006		2007

Net Production:
Gas (MMcf)		5,530		5,010		9,565		12,282		5,387		7,842
Oil (Bbls)		8,549		5,551		9,241		9,737		5,657		3,674
Gas equivalent (MMcfe)		5,580		5,050		9,620		12,341		5,421		7,864
Number of Producing Wells (at period end)		688		802		1,027		1,638		1,372		1,865

Production volumes for the Partnership Properties increased by 45.1% for the six months ended June 30, 2007 as compared to the six months ended June 30, 2006. Production volumes for the Partnership Properties increased by 28.3% for the year ended December 31, 2006 as compared to the year ended December 31, 2005. These increases were primarily due to the number of additional wells that have been connected over the past two years.

We face the challenge of gas production declines. As a given well produces gas, our total gas reserves are reduced. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. Our ability to add reserves through drilling is dependent on our capital resources. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact the rate of our production, which may have an adverse effect on our revenues and as a result, cash available for distribution. In accordance with our business plan, we intend to invest the capital necessary to maintain our production or operating capacity and our asset base over the long-term. As of December 31, 2006, we had identified 756 additional proved undeveloped drilling locations and approximately 1,539 other drilling locations on our leasehold acreage.

Realized prices — the Partnership Properties

Factors Affecting the Price of Gas and Oil. Gas and oil prices historically have been volatile and may fluctuate widely in the future. During the five year period ended December 31, 2006, gas prices have been extremely volatile with NYMEX spot prices ranging from a low of $1.92 per MMBtu to a high of $18.41 per MMBtu. During the six month period ended June 30, 2007, the NYMEX spot price ranged from a low of $5.40 per MMBtu to a high of $9.07 per MMBtu. We believe that this volatility has been significantly impacted by the level of hurricane activity in the summer and fall of each year, threats and existence of wars and terrorism in the Middle East, Africa and elsewhere, OPEC’s management of oil reserves (given the correlation between natural gas and oil) and growth in domestic natural gas demand. The currently high levels of natural gas in storage, resulting at least in part from relatively mild winters in 2005 and 2006 in the United States, have caused natural gas prices to decline from the higher levels prevailing during the later part of 2005. Sustained periods of low prices for gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of gas and oil reserves that we can economically produce and our access to capital.

Derivative Transactions. 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. We have entered into additional hedges with respect to approximately 80% of our total estimated net production from proved developed producing reserves through the fourth quarter of 2010. As of October 15, 2007, we have fixed price swaps covering 13% of our estimated net gas production from proved developed producing reserves and collars covering 45% of our estimated net gas production from proved developed producing reserves for the remainder of 2007. We also have fixed price swaps and collars covering 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, we have fixed price swaps covering 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 Central TX/KS/OK (“Southern Star”) first of month index, with the remainder sold on the daily price on the Southern Star index. All of our derivative contracts are based on the Southern Star first of month index, except for some of our older collar agreements covering approximately 1.8 Bcf of gas in the second half of 2007 (19% of our estimated net gas production from proved developed producing reserves for the second half of 2007) and 2.9 Bcf of gas in 2008 (17% of our estimated net gas production from proved developed producing reserves for the second half of 2007) 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, we are not exposed to basis differential risk, except for the NYMEX collars and swaps. We have entered into derivative contracts locking in 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, please read “— Quantitative and Qualitative Disclosures about Market Risk.”

Oil and gas production and general and administrative expenses

In evaluating our production operations, we frequently monitor and assess our oil and gas production and general and administrative expenses per Mcfe produced. This measure allows us to better evaluate our operating efficiency and is used by us in reviewing the economic feasibility of a potential acquisition or development project.

Oil and Gas Production. These expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, dewatering and water disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. Production expenses do not include general and administrative expenses. We monitor our production expenses per well to determine if any of our wells or properties should be shut-in, recompleted or sold. A majority of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons increases or decreases. For example, we incur power costs in connection with various production related activities such as pumping to recover gas and oil and removing and disposing of water from coal seams to permit the recovery of gas. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed.

Production taxes vary by state. Our production taxes are calculated as a percentage of our gas and oil wellhead revenues. In general, as prices and volumes increase, our production taxes increase, and as prices and volumes decrease, our production taxes decrease.

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.

General and Administrative Expenses. We intend to enter into a management services agreement with Quest Energy Service, LLC (a wholly-owned subsidiary of our Parent), which will carry out the directions of our general partner. Pursuant to this agreement, Quest Energy Service will provide us with legal, accounting, finance, tax, property management, engineering, risk management and acquisition services in respect of potential opportunities for us to acquire long-lived, stable and proved gas and oil reserves. Quest Energy Service will be reimbursed for its reasonable costs in providing services to us and will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. For a description of the services that Quest Energy Service will provide to us and our obligation to reimburse Quest Energy Service for the costs it incurs in providing those services, please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Management Services Agreement.”

Adjusted EBITDA

We defined Adjusted EBITDA as net income (loss) plus:


	•	net interest expense;

	•	depreciation, depletion and amortization expense;

	•	gain (loss) on sale of assets;

	•	provision for impairment of gas and oil properties;

	•	cumulative effect of accounting change, net of tax;

	•	change in derivative fair value; and

	•	non-cash compensation expense.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Adjusted EBITDA does not include interest expense, income taxes, depreciation and amortization expense, change in derivative fair value or non-cash compensation expense. Because Quest Energy Partners Predecessor has borrowed, and we intend to borrow, money to finance the Partnership Properties’ operations, interest expense is a necessary element of our costs. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Because Quest Energy Partners Predecessor has used, and we intend to use, derivative contracts to hedge our exposure to commodity prices, changes in the fair value of those contracts is also a necessary element of our costs. Because Quest Energy Partners Predecessor has used, and we intend to use, non-cash equity awards as part of our overall compensation package for our executive officers and employees, non-cash compensation expense is a necessary element of our costs. Therefore, any measures that excludes these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity.

Outlook

Gas prices have been volatile over the last three years. Rising prices contributed to an increase in our gas and oil sales in both 2004 compared to 2003 and 2005 compared to 2004. Gas prices spiked sharply in the fall of 2005 following the hurricanes in the United States in the fourth quarter of 2005 (peaking in November 2005 at $10.61 per Mcf) and thereafter declined to a low of $3.49 per Mcf in October 2006. Our average sales price in July 2007 was $6.11 per Mcfe. We anticipate a continued favorable commodity price environment for the remainder of 2007 and for 2008. Significant factors that will impact near-term gas prices include the following:


	•	the domestic and foreign supply of gas;

	•	the price and quantity of imports of foreign natural gas;

	•	overall domestic and global economic conditions;

	•	the consumption pattern of industrial consumers, electricity generators and residential users;

	•	weather conditions;

	•	the level of domestic natural gas inventories;

	•	technological advances affecting energy consumption;

	•	domestic and foreign governmental regulations;

	•	proximity and capacity of gas pipelines and other transportation facilities; and

	•	the price and availability of alternative fuels.

A substantial portion of our estimated gas production from our proved developed producing reserves is currently hedged through December 2009, and we intend to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on our gas and oil revenues.

We believe that current gas prices will continue to cause relatively high levels of gas-related drilling in the United States as producers seek to increase their level of gas production. Although the number of gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the gas industry to meet the expected increased demand for, and to compensate for the slowing production of, gas in the United States.

Due to the expected continued high commodity price environment and related demand pressures, we anticipate drilling service and labor costs, as well as costs of equipment and raw materials, to remain at or exceed the levels experienced in 2006.

We expect to fund our 2007 and 2008 capital expenditures utilizing a combination of cash flow from operations, additional borrowings and/or the issuance of debt or equity. We also estimate that we will have sufficient cash flow from operations after funding maintenance capital expenditures, but not including expansion capital expenditures, to enable us to make our initial quarterly distribution to unitholders for each quarter for the twelve months ending December 31, 2008. Please read “— Liquidity and Capital Resources” below and “Our Cash Distribution Policy and Restrictions on Distributions.”

We intend to pursue acquisition opportunities, but expect to confront intense competition for these assets. We believe that our structure as a pass-through vehicle for tax purposes will allow us to have a lower cost of capital for acquisition opportunities than many of our taxable competitors.

Factors That Significantly Affect Comparability of Our Results

Our future results of operations and cash flows could differ materially from the historical results of Quest Energy Partners Predecessor due to a variety of factors, including the following:

Outstanding Indebtedness. Quest Energy Partners Predecessor had significantly more indebtedness ($235.3 million as of June 30, 2007) than the $75.3 million of indebtedness that we will have at the closing of this offering. In addition, the average interest rate on the indebtedness of Quest Energy Partners Predecessor for the six months ended June 30, 2007 was 11.2% as compared to the anticipated interest rate at the closing of this offering under our new credit facility of LIBOR plus 1.5%.

Purchase of Derivatives. For the fiscal year ended May 31, 2004, the seven months ended December 31, 2004 and the years ended December 31, 2005 and 2006, fixed-price contracts hedged approximately 83.0%, 85.0%, 89.0% and 61.0%, respectively, of our Parent’s gas production. We have entered into derivative contracts with respect to approximately 80% of our estimated proved developed producing production through the fourth quarter of 2010 in order to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in gas prices and interest rates. As of October 15, 2007, we have fixed price swaps covering 13% of our estimated net gas production from proved developed producing reserves and collars covering 45% of our estimated net gas production from proved developed producing reserves for the remainder of 2007. We also have fixed price swaps and collars covering 40% and 40%, respectively, of our estimated net gas production from proved developed producing reserves in 2008. In addition, for 2009 and 2010, we have fixed price swaps covering 80% and 80%, respectively, of our estimated net gas production from proved developed producing reserves. 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. 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.

Midstream Services Agreement. Prior to the formation of Quest Midstream in December 2006, a wholly-owned subsidiary of our Parent provided us with gas gathering, treating, dehydration and compression services pursuant to a gas transportation agreement that was entered into in December 2003. Since these services were being provided by one wholly owned subsidiary of our Parent to another wholly-owned subsidiary, no amendments were made to this prior contract to reflect increases in the costs of providing these services. As part of the formation of Quest Midstream, our Parent and Quest Midstream entered into the midstream services agreement, which provided for negotiated fees for these services that were significantly higher than those that had been previously paid.

Under the midstream services agreement, Quest Midstream is paid $0.50 per MMBtu of gas for gathering, dehydration and treating services and $1.10 per MMBtu of gas for compression services, subject to annual adjustment based on changes in gas prices and the producer price index. Such fees will never be reduced

below these initial rates and are subject to renegotiation upon the exercise of each five-year extension period. Under the terms of some of our gas leases, we may not be able to charge the full amount of these fees to royalty owners, which would increase the average fees per MMBtu that we effectively pay under the midstream services agreement. For more information about the midstream services agreement, please read “Business — Gas Gathering — Midstream Services Agreement.”

Results of Operations for Quest Energy Partners Predecessor

The discussion of the results of operations and period-to-period comparisons presented below covers the historical results of Quest Energy Partners Predecessor. As discussed above under “— Factors That Significantly Affect Comparability of Our Results”, Quest Energy Partners Predecessor’s historical results of operations and period-to-period comparisons of its results may not be indicative of our future results.

Six Months Ended June 30, 2006 and June 30, 2007

Overview. The following table summarizes Quest Energy Partners Predecessor’s results of operations for the six months ended June 30, 2006 and 2007.


	Six Months
	Ended
	June 30,						Increase/
	2006			2007			(Decrease)
	($ in thousands)

Oil and gas sales	$	33,785		$	53,416		$	19,631		58.1	%
Other revenue/(expense)		(67	)		(32	)		35		52.2	%
Operating expenses		13,739			28,137			14,398		104.8	%
Depreciation, depletion and amortization		11,680			14,063			2,383		20.4	%
General and administrative expenses		3,214			5,846			2,632		81.9	%
Interest expense		6,434			14,160			7,726		120.1	%
Change in derivative fair value		6,631			(185	)		(6,816	)	(102.8	)%

Production. The following table presents the primary components of revenues of Quest Energy Partners Predecessor (gas and oil production and average gas and oil prices), as well as the average costs per Mcfe, for the six months ended June 30, 2006 and 2007.


	Six Months
	Ended
	June 30,				Increase/
	2006		2007		(Decrease)

Production Data:
Total production (MMcfe)		5,421		7,864		2,443		45.1	%
Average daily production (MMcfe/d)		30.0		43.5		13.5		45.1	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	6.40		6.60	$	0.20		3.1	%
Including hedges		4.37		6.79		2.42		55.4	%
Average Unit Costs per Mcfe:
Production costs	$	2.53	$	3.58	$	1.04		41.2	%
Depreciation, depletion and amortization		2.15		1.79		(0.37	)	(17.0	)%
General and administrative expenses		0.59		0.74		0.15		25.4	%

Oil and gas sales. Oil and gas sales were $53.4 million for the six months ended June 30, 2007 compared to $33.8 million for the six months ended June 30, 2006, an increase of $19.6 million, or 58.1%. Oil and gas sales for the six months ended June 30, 2007 include a $1.4 million gain on settlements of gas hedges. The quarter ended June 30, 2006 includes a $10.2 million loss on settlement of gas hedges. The increase in oil and gas sales for the six months ended June 30, 2007 was the result of a 45.1% increase in sales volumes that was achieved by the addition of more producing wells, which was partially offset by the natural decline in production from older gas wells and an increase in gas prices between periods.

The additional wells contributed to the production of 7,842,000 Mcf of net gas for the six months ended June 30, 2007, as compared to 5,387,000 net Mcf produced for the six months ended June 30, 2006. Our product prices on an equivalent basis (Mcfe) increased from $6.40 per Mcfe on average for the six months ended June 30, 2006 to $6.60 per Mcfe on average for the six months ended June 30, 2007. For the six months ended June 30, 2007, the net product price, after accounting for the gain on hedging settlements of $1.4 million, averaged $6.79 per Mcfe. For the six months ended June 30, 2006, the net product price, after accounting for the loss on hedge settlements of $10.9 million recorded in the change in derivative fair value, averaged $4.37 per Mcfe.

Other Expense. Other expense for the six months ended June 30, 2007 was $32,000 as compared to other expense of $67,000 for the six months ended June 30, 2006.

Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, were $28.1 million for the six months ended June 30, 2007 as compared to $13.7 million for the six months ended June 30, 2006, an increase of $14.4 million, or 104.8%. Oil and gas production costs were $15.0 million for the six months ended June 30, 2007 as compared to $8.6 million for the six months ended June 30, 2006, an increase of $6.4 million, or 74.6%. This increase was partially due to increased lease operating costs per Mcfe, inclusive of gross production and ad valorem taxes, which were $1.90 per Mcfe, for the six months ended June 30, 2007 as compared to $1.58 per Mcfe for the six months ended June 30, 2006. Production costs, excluding gross production and ad valorem taxes, were $1.39 per Mcfe for 2007 compared to $1.18 per Mcfe for the 2006 period. This increase was due to a number of factors, including: winter weather conditions resulting in a larger percentage of the field labor force being charged to operating expense as compared to capital expenditures, our increased development program, an increase in wage rates due to a tight labor market for skilled workers in the Cherokee Basin, an increase in well repairs, utilities and fuel costs due to the increase in the number of wells being operated, an increase in energy and raw material costs and an increase in property taxes due to both the increase in the number of properties that we own and an increase in property tax rates.

Transportation expense increased by approximately 154.9% from $5.2 million for the six months ended June 30, 2006 to $13.2 million for the six months ended June 30, 2007. Transportation expense per Mcf for the six months ended June 30, 2007 increased to $1.67 per Mcf as compared to $0.95 per Mcf for the six months ended June 30, 2006. This increase resulted from the midstream services agreement with Quest Midstream that became effective December 1, 2006, which provided for a fixed transportation fee that was higher than the fees in the year earlier period.

Depreciation, Depletion and Amortization. For the six months ended June 30, 2007, depreciation, depletion and amortization increased to $14.1 million as compared to $11.7 million for the six months ended June 30, 2006. The increase in depreciation, depletion and amortization is a result of the increased number of producing wells developed and the higher volumes of gas and oil produced.

General and Administrative Expenses. General and administrative expenses increased from $3.2 million for the six months ended June 30, 2006 to $5.8 million for the six months ended June 30, 2007, an increase of $2.6 million, or 81.9%. This increase resulted from a non-cash charge of approximately $2.3 million for amortization of stock awards. The remainder of the increase is due to an increase in staff personnel, as well as increased legal, accounting and professional fees related to the increased size and complexity of our operations.

Interest Expense. Interest expense was $14.2 million for the six months ended June 30, 2007 compared to $6.4 million for the six months ended June 30, 2006, an increase of $7.7 million, or 120.1%. This increase was due to an increase in our outstanding borrowings related to equipment, development and leasehold expenditures and higher average interest rates.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash loss of $185,000 for the six months ended June 30, 2007, which included a $1.3 million loss attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $1.1 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash gain of $6.6 million for the six months ended June 30, 2006, which included a $14.6 million gain attributable to the change in fair value for certain derivatives that did not qualify as cash flow hedges pursuant to SFAS 133, a $10.2 million loss due to settlement of ineffective cash flow hedges and a gain of $2.2 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

Years Ended December 31, 2005 and 2006

Overview. The following table summarizes Quest Energy Partners Predecessor’s results of operations for the fiscal years ended December 31, 2005 and 2006.


	Year Ended
	December 31,						Increase/
	2005			2006			(Decrease)
				($ in thousands)

Oil and gas sales	$	44,565		$	65,551		$	20,986		47.1	%
Other revenue/(expense)		387			(83	)		(470	)	(121.4	)%
Operating expenses		21,426			38,486			17,060		79.6	%
Depreciation, depletion and amortization		20,121			25,521			5,400		26.8	%
General and administrative expenses		4,068			8,149			4,081		100.3	%
Interest expense		19,919			16,935			(2,984	)	(15.0	)%
Change in derivative fair value		(4,668	)		6,410			11,078		237.3	%
Impairment charge		—			30,719			30,719		—


	Year Ended
	December 31,				Increase/
	2005		2006		(Decrease)

Production Data:
Total production (MMcfe)		9,620		12,341		2,720		28.3	%
Average daily production (MMcfe/d)		26.4		33.8		7.5		28.3	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	7.45	$	5.95	$	(1.50	)	(20.1	)%
Including hedges		4.63		5.31		0.68		14.7	%
Average Unit Costs per Mcfe:
Production costs	$	2.23	$	3.12	$	0.89		40.0	%
Depreciation, depletion and amortization		2.09		2.07		(0.02	)	(1.0	)%
General and administrative expenses		0.42		0.66		0.24		57.1	%

Oil and gas sales. Oil and gas sales were $65.6 million for the year ended December 31, 2006 as compared to $44.6 million for the year ended December 31, 2005, an increase of $21.0 million, or 47.1%. The increase resulted from the additional wells completed during 2006. The additional wells completed contributed to the production of 12,282,142 Mcf of net gas for the year ended December 31, 2006, as compared to 9,565,000 net Mcf produced for the year ended December 31, 2005. Our product prices before hedge settlements on an equivalent basis (Mcfe) decreased from $7.45 Mcfe on average for the 2005 period to $5.95 Mcfe on average for the 2006 period. Accounting for hedge settlements, the product prices increased from $4.63 Mcfe on average for the 2005 period to $5.31 Mcfe on average for the 2006 period.

Other Revenue/(Expense). Other expense for the year ended December 31, 2006 was $83,000 that resulted from an adjustment of overhead fees and pumper fees as compared to other revenue of $387,000 for the year ended December 31, 2005, that was primarily the result of an adjustment of overhead fees.

Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, were $38.5 million for the year ended December 31, 2006 as compared to $21.4 million for the year ended December 31, 2005, an increase of $17.1 million, or 79.6%. Oil and gas production costs for the year ended December 31, 2006 were $21.2 million as compared to $14.4 million for the year ended December 31, 2005, an increase of $6.8 million, or 47.2%. Production costs, excluding gross production and ad valorem taxes, were $1.28 per Mcfe for 2006 compared to $0.98 for the year ended December 31, 2005. Production costs, inclusive of gross production and ad valorem taxes, were $1.72 per Mcfe for the 2006 period as compared to $1.50 per Mcfe for the year ended December 31, 2005 period, representing a 15% increase. This increase was a result of increased property taxes on wells in the State of Kansas, increased gross production taxes from increased production volumes, decreased field payroll allocated to capital expenditures and an increase in our treating program to reduce pump failures.

Transportation expense increased from $0.73 per Mcf for 2005 to $1.40 per Mcf for 2006. This increase resulted from increases in compression rental and property taxes assessed on pipelines and related equipment.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization costs increased to $25.5 million in 2006 from $20.1 million in 2005 as a result of the increased number of producing wells developed, the higher volumes of gas and oil produced and the resulting increased depletion rate.

General and Administrative Expenses. General and administrative expenses increased by $4.1 million, or 100.3%, to $8.1 million for the year ended December 31, 2006 from $4.1 million in the year ended December 31, 2005 due to an increase in professional fees, travel expenses, increased staffing to support the higher levels of development and operational activity and the added resources to enhance our internal controls and financial reporting.

Interest Expense. Interest expense decreased by $3.0 million, or 15.0%, to $16.9 million for the year ended December 31, 2006 from $19.9 million for the year ended December 31, 2005 (inclusive of a $4.3 million write-off of debt issue costs realized in connection with the refinancing of our credit facilities in 2005). Excluding the write-off of debt issue costs in 2005, the approximate $3.0 million increase in interest expense in 2006 was due to higher average outstanding borrowings, partially offset by lower average interest rates under our credit facilities that were entered into in November 2005.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash gain of $6.4 million for the year ended December 31, 2006, which included a net $2.0 million gain attributable to the change in fair value for certain derivative contracts that did not qualify as cash flow hedges pursuant to SFAS 133 and a gain of $4.4 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net loss of $4.7 million for the year ended December 31, 2005, which included a $0.9 million net gain attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period, a $103,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $5.7 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

Impairment Charge. In the year ended December 31, 2006 we recognized a $30.7 million provision for impairment of oil and gas properties from a full cost pool ceiling write-down, primarily as a result of declines in estimated reserves due to the prevailing market prices of oil and gas at the measurement date.

Years Ended December 31, 2004 and 2005

Quest Energy Partners Predecessor changed its fiscal year-end from May 31 to December 31 in 2004. As a result of this change, Quest Energy Partners Predecessor prepared financial statements for the calendar year ended December 31, 2005. The following tables and discussion compares the audited results of operations for the year ended December 31, 2005 to the unaudited results of operations for the year ended December 31, 2004.

Overview. The following table summarizes Quest Energy Partners Predecessor’s results of operations for the fiscal years ended December 31, 2004 and 2005.


	Year Ended
	December 31,						Increase/
	2004			2005			(Decrease)
	($ in thousands)

Oil and gas sales	$	43,593		$	44,565		$	972		2.2	%
Other revenue/(expense)		995			387			(608	)	(61.1	)%
Operating expenses		11,993			21,426			9,433		78.7	%
Depreciation, depletion and amortization		11,879			20,121			8,242		69.3	%
General and administrative expenses		3,989			4,068			79		2.0	%
Interest expense		13,233			19,919			6,686		50.5	%
Change in derivative fair value		(6,812	)		(4,668	)		2,144		31.5	%


	Year Ended
	December 31,				Increase/
	2004		2005		(Decrease)

Production Data:
Total production (MMcfe)		8,664		9,620		956		11.0	%
Average daily production (MMcfe/d)		23.7		26.4		2.6		11.0	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	5.63	$	7.45	$	1.82		32.3	%
Including hedges		4.93		4.63		(0.30	)	(6.1	)%
Average Unit Costs per Mcfe:
Production costs	$	1.53	$	2.23	$	0.70		45.8	%
Depreciation, depletion and amortization		1.38		2.09		0.71		51.4	%
General and administrative expenses		0.46		0.42		(0.04	)	(8.7	)%

Oil and gas sales. Oil and gas sales were $44.6 million for the year ended December 31, 2005 as compared to $43.6 million for the year ended December 31, 2004, an increase of $1.0 million, or 2.2%. The increase resulted from the additional wells acquired or completed during 2005. The additional wells completed contributed to the production of 9,565,000 Mcf of net gas for the year ended December 31, 2005, as compared to 8,607,000 net Mcf produced for the year ended December 31, 2004. Our product prices before hedge settlements on an equivalent basis (Mcfe) increased from $5.63 Mcfe on average for the year ended

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December 31, 2004 to $7.45 Mcfe on average for the year ended December 31, 2005. Accounting for hedge settlements, the product prices decreased from $4.93 Mcfe on average for the 2004 period to $4.63 Mcfe on average for the 2005 period, due to the significant basis differential that occurred in the market during our fourth quarter, resulting from the hurricanes in the United States.

Other Revenue. Other revenue for the year ended December 31, 2005 was $0.4 million as compared to $1.0 million for the year ended December 31, 2004. Other revenue consists of the gain or loss on hedge settlements.

Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, were $21.4 million for the year ended December 31, 2005 as compared to $12.0 million for the year ended December 31, 2004, an increase of $9.4 million, or 78.7%. Oil and gas production costs for the year ended December 31, 2005 were $14.4 million as compared to $8.0 million for the year ended December 31, 2004, an increase of $6.4 million, or 80.0%. Production costs, excluding gross production and ad valorem taxes, were $0.98 per Mcfe for the year ended December 31, 2005 compared to $0.78 for the year ended December 31, 2004. Production costs, inclusive of gross production and ad valorem taxes, were $1.50 per Mcfe for the year ended December 31, 2005 as compared to $0.92 per Mcfe for the year ended December 31, 2004, representing a 63% increase. This increase was primarily due to increased property taxes on wells in the State of Kansas, increased gross production taxes from product price increases and decreased field payroll allocated to capital expenditures due to the limited amount of capital expenditures that we could incur under our prior credit facility during the last half of year 2005.

Transportation costs increased from $0.47 per Mcf for the year ended December 31, 2004 to $0.73 per Mcf for the year ended December 31, 2005 due to higher operating costs in 2005, primarily resulting from an increase in compressor rental costs and additional personnel to maintain the pipeline equipment.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expenses increased to $20.1 million for the year ended December 31, 2005 from $11.9 million for the year ended December 31, 2004 as a result of the increased number of producing wells acquired and developed, the higher volumes of natural gas and oil produced and the resulting increased depletion rate and development costs.

General and Administrative Expenses. General and administrative expenses increased $0.1 million, or 2.0%, to $4.1 million for the year ended December 31, 2005 from $4.0 million for the year ended December 31, 2004 due primarily to increased staffing in the fourth quarter to support higher levels of development and operational activity and the added resources to enhance our internal controls and financial reporting in anticipation of our having to comply with the requirement for an audit of our Parent’s internal control over financial reporting for the year ended December 31, 2006 required under the Sarbanes-Oxley Act of 2002.

Interest Expense. Interest expense increased by $6.7 million, or 50.5%, to $19.9 million (inclusive of a $4.3 million write off of amortizing bank fees realized in connection with the refinancing of our credit facilities) for the year ended December 31, 2005 from $13.2 million for the year ended December 31, 2004. This increase was due to an increase in interest rates and in our outstanding borrowings.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash net loss of $4.7 million for the year ended December 31, 2005, which included a $879,000 net gain attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period, a $103,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $5.7 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net loss of $6.8 million for the year ended December 31, 2004, which included a $5.0 million net loss attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period, a $1.4 million net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $3.2 million relating to hedge ineffectiveness. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

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Seven Months Ended December 31, 2003 and 2004

Quest Energy Partners Predecessor changed its fiscal year-end from May 31 to December 31 in 2004. As a result of this change, Quest Energy Partners Predecessor prepared financial statements for the seven-month transition period ended December 31, 2004. The following tables and discussion compares the audited results of operations for the seven months ended December 31, 2004 to the unaudited results of operations for the seven months ended December 31, 2003.

Overview. The following table summarizes Quest Energy Partners Predecessor’s results of operations for the seven months ended December 31, 2003 and 2004.


	Seven Months
	Ended
	December 31,						Increase/
	2003			2004			(Decrease)
	($ in thousands)

Oil and gas sales	$	8,755		$	24,201		$	15,446		176.4	%
Other revenue/(expense)		(1,862	)		37			1,899		102.0	%
Operating expenses		3,465			8,585			5,120		147.8	%
Depreciation, depletion and amortization		1,773			6,954			5,181		292.2	%
General and administrative expenses		603			2,328			1,725		286.1	%
Interest expense		882			7,711			6,829		774.3	%
Change in derivative fair value		3,312			(1,487	)		(4,799	)	(144.9	)%


	Seven Months
	Ended
	December 31,				Increase/
	2003		2004		(Decrease)

Production Data:
Total production (MMcfe)		1,830		5,050		3,220		176.0	%
Average daily production (MMcfe/d)		8.6		23.7		15.1		176.0	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	4.82	$	5.77	$	0.95		19.7	%
Including hedges		4.08		4.79		0.71		17.4	%
Average Unit Costs per Mcfe:
Production costs	$	1.89	$	1.71	$	(0.18	)	(9.5	)%
Depreciation, depletion and amortization		0.97		1.38		0.41		42.3	%
General and administrative expenses		0.33		0.46		0.13		39.4	%

Oil and gas sales. Oil and gas sales were $24.2 million for the seven months ended December 31, 2004 compared to $8.8 million for the seven months ended December 31, 2003, an increase of $15.4 million, or 176.4%. This increase was achieved by a combination of the additional producing wells from the Devon acquisition in December 2003 and the aggressive new well development program that was in effect during the 2003 and 2004 fiscal years. The Devon asset acquisition and the additional wells acquired or completed contributed to the production of 5,010,000 Mcf of net gas for the seven months ended December 31, 2004, as compared to 1,815,000 net Mcf produced for the seven months ended December 31, 2003. Our product prices before hedge settlements on an equivalent basis (Mcfe) increased from $4.82 Mcfe on average for the seven

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months ended December 31, 2003 to $5.77 Mcfe on average for the seven months ended December 31, 2004. Accounting for hedge settlements, the product prices increased from $4.08 Mcfe on average for the seven months ended December 31, 2003 to $4.79 Mcfe on average for the seven months ended December 31, 2004.

Other Revenue/(Expense). Other revenue for the seven months ended December 31, 2004 was $37,000 as compared to other expense of $1.9 million for the seven months ended December 31, 2003, resulting from recording the gain or loss on hedge settlements for the two comparative periods.

Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, were $8.6 million for the seven months ended December 31, 2004 as compared to $3.5 million for the seven months ended December 31, 2003, an increase of $5.1 million, or 147.8%. Oil and gas production costs for the seven months ended December 31, 2004 were $5.4 million as compared to $2.4 million for the seven months ended December 31, 2003, an increase of $3.0 million, or 125%. This increase was partially due to increased oil and gas production costs per Mcfe, which were $1.07 per Mcfe for the seven months ended December 31, 2004 period as compared to $0.61 per Mcfe for the seven months ended December 31, 2003, a 75.4% increase. The increase in operating costs are due to the acquisition of assets from Devon and the number of wells acquired, completed and operated during the year.

Transportation expense for the seven months ended December 31, 2004 was $3.2 million ($0.63 per Mcf) as compared to $1.0 million ($0.65 per Mcf) for the seven months ended December 31, 2003, an increase of $2.2 million, or 220%. The increase in transportation expense was due to the increased size of our operations as a result of the acquisition of assets from Devon in December 2003. See “Business — Overview.”

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expenses was $7.0 million for the seven months ended December 31, 2004 as compared to $1.8 million for the prior period, an increase of 292%, due to the increased number of producing wells acquired and developed, the higher volumes of natural gas and oil produced and the higher cost of properties recorded by application of the purchase method of accounting to record the Devon asset acquisition.

General and Administrative Expenses. General and administrative expenses increased by $1.7 million, or 286%, to $2.3 million for the seven months ended December 31, 2004 from $0.6 million for the seven months ended December 31, 2003 due primarily to the Devon asset acquisition, the increased staffing to support the higher levels of development and operational activity and the added resources to enhance our internal controls and financial reporting.

Interest Expense. Interest expense increased by $6.8 million, or 774%, to $7.7 million for the seven months ended December 31, 2004 from $0.9 million for the seven months ended December 31, 2003. The increase was due to an increase in our outstanding borrowings related to the Devon acquisition and equipment, development and leasehold expenditures from our aggressive drilling and development program during the transition period.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash net loss of $1.5 million for the seven months ended December 1, 2004, which included a $269,000 net loss attributable to the change in fair value for certain cash flow hedges which did not meet the effectiveness guidelines of SFAS 133 for the period, a $565,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $1.8 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net gain of $3.3 million for the seven months ended December 31, 2003, which was attributable to the change in fair value of cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the period. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives that are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

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Fiscal Years Ended May 31, 2003 and 2004

Overview. The following table summarizes Quest Energy Partners Predecessor’s results of operations for the fiscal years ended May 31, 2003 and 2004.


	Year Ended
	May 31,						Increase/
	2003			2004			(Decrease)
	($ in thousands)

Oil and gas sales	$	8,345		$	28,147		$	19,802	237.3	%
Other revenue/(expense)		(908	)		(904	)		4	0.4	%
Operating expenses		2,623			6,872			4,249	162.0	%
Depreciation, depletion and amortization		1,578			6,698			5,120	324.5	%
General and administrative expenses		711			2,264			1,553	218.4	%
Interest expense		470			6,404			5,934	1,262.6	%
Change in derivative fair value		(4,867	)		(2,013	)		2,854	58.6	%


	Year Ended
	May 31,				Increase/
	2003		2004		(Decrease)

Production Data:
Total production (MMcfe)		1,500		5,580		4,080		272.0	%
Average daily production (MMcfe/d)		4.1		15.3		11.2		272.0	%
Average Sales Price per Unit (Mcfe):
Excluding hedges	$	5.33	$	5.02	$	(0.31	)	(5.8	)%
Including hedges		5.30		5.04		(0.26	)	(4.9	)%
Average Unit Costs per Mcfe:
Production costs	$	1.75	$	1.23	$	(0.52	)	(29.7	)%
Depreciation, depletion and amortization		1.05		1.20		0.15		14.3	%
General and administrative expenses		0.47		0.41		(0.06	)	(12.8	)%

Oil and gas sales. Oil and gas sales were $28.1 million for the fiscal year ended May 31, 2004 compared to $8.3 million for the fiscal year ended May 31, 2003, an increase of $19.8 million, or 237.3%. This increase was achieved by a combination of the additional producing wells from the Devon acquisition in December 2003, the Perkins/Willhite acquisition in June 2003, the STP Cherokee acquisition in November 2002 and our aggressive new well development program during both periods. The Devon, STP Cherokee and Perkins/Willhite acquisitions and the additional wells acquired or completed contributed to the production of 5,530,208 Mcf of net gas in the fiscal year ended May 31, 2004, as compared to 1,488,679 net Mcf produced in the fiscal year ended May 31, 2003. Our product prices on an equivalent basis (Mcfe) decreased from $5.30 Mcfe on average for the fiscal year ended May 31, 2003 to $5.04 Mcfe on average for the fiscal year ended May 31, 2004.

Other Expense. Other expense for the fiscal year ended May 31, 2004 was $904,000 as compared to other expense of $908,000 for the fiscal year ended May 31, 2003, resulting from recording the loss on hedge settlements for the two comparative periods.

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Operating Expenses. Operating expenses, which consist of oil and gas production costs and transportation expense, were $6.9 million for the fiscal year ended May 31, 2004 as compared to $2.6 million for the fiscal year ended May 31, 2003, an increase of $4.2 million, or 162.0%. Oil and gas production costs for the fiscal year ended May 31, 2004 were $5.0 million as compared to $2.0 million for the fiscal year ended May 31, 2003, an increase of $3.0 million, or 153%. Oil and gas production costs per Mcfe for the fiscal year ended May 31, 2004 were $0.99 per Mcfe as compared to $1.32 per Mcfe for the fiscal year ended May 31, 2003. This decrease was caused by increased production volumes due to the Devon acquisition initially accompanied by lower production costs for the same period. The increase in operating costs was due to the Devon, STP Cherokee and Perkins/Willhite acquisitions and the number of wells acquired, completed and operated during the year.

Transportation expense for the fiscal year ended May 31, 2004 totaled $1.9 million ($0.34 per Mcf) as compared to $0.6 million ($0.43 per Mcf) for the fiscal year ended May 31, 2003. The increase in transportation expense was due to the increased size of our operations as a result of the acquisition of assets from Devon in December 2003. See “Business — Overview.”

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expenses increased to $6.7 million from $1.6 million as a result of the increased number of producing wells acquired and developed, the higher volumes of natural gas and oil produced and the higher cost of properties recorded by application of the purchase method of accounting to record the Devon, STP Cherokee and Perkins/Willhite acquisitions.

General and Administrative Expenses. General and administrative expenses increased by $1.6 million, or 218.4%, to $2.3 million in the fiscal year ended May 31, 2004 from $0.7 million in the fiscal year ended May 31, 2003 due primarily to the Devon, STP and Perkins/Willhite acquisitions, increased staffing to support the higher levels of development and operational activity and the added resources to enhance our internal controls and financial reporting.

Interest Expense. Interest expense increased by $6.0 million to $6.4 million for the fiscal year ended May 31, 2004 from $0.5 million for the fiscal year May 31, 2003. The increase was due to the increase in our outstanding borrowings related to the Devon, STP and Perkins/Willhite acquisitions and equipment, development and leasehold expenditures and the expense of $1 million related to the refinancing of our credit facilities that were in place at the time of the Devon acquisition.

Change in Derivative Fair Value. Change in derivative fair value was a non-cash net loss of $2.0 million for the fiscal year ended May 31, 2004, which included a $1.7 million net loss attributable to the change in fair value for certain cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the fiscal year, a $888,000 net gain attributable to the reversal of contract fair value gains and losses recognized in earnings prior to actual settlement, and a loss of $1.2 million relating to hedge ineffectiveness. Change in derivative fair value was a non-cash net loss of $4.9 million for the year ended May 31, 2003, which was attributable to the change in fair value of cash flow hedges that did not meet the effectiveness guidelines of SFAS 133 for the year. Amounts recorded in this caption represent non-cash gains and losses created by valuation changes in derivatives which are not entitled to receive hedge accounting. All amounts recorded in this caption are ultimately reversed in this caption over the respective contract term.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity are expected to be cash generated from our operations, amounts available under our anticipated credit facility described below and funds from future private and public equity and debt offerings.

Our partnership agreement requires that we distribute our available cash. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be

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used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

Because of the seasonal nature of gas and oil, we may make short-term working capital borrowings in order to level out our distributions during the year. In addition, a substantial portion of our production is hedged. We are generally required to settle our commodity hedges on either the 5^th or 25^th day of each month. As is typical in the gas and oil and gas business, we do not generally receive the proceeds from the sale of the hedged production around the 25^th day of the following month. As a result, when gas and oil prices increase and are above the prices fixed in our derivative contracts, we will be required to pay the hedge counterparty the difference between the fixed price in the hedge and the market price before we receive the proceeds from the sale of the hedged production. If this were to occur, we may make working capital borrowings to fund our distributions. Because we will distribute our available cash, we will not have those amounts available to reinvest in our business to increase our reserves and production. Because we will distribute a substantial amount of our cash flows (after making principal and interest payments on our indebtedness) rather than reinvest those cash flows in our business, we may not grow as quickly as other companies or at all.

Future Capital Expenditures

We plan to make substantial capital expenditures in the future for the acquisition, exploitation and development of gas and oil properties. During 2007, we intend to focus on drilling and completing an estimated 558 gross wells. We also currently intend to drill and complete approximately 325 gross wells during 2008. At this time, we have not identified our drilling locations for 2008 and some or all of these wells may be drilled on locations that were not classified as containing proved reserves in our June 30, 2007 reserve report. Management currently estimates that it will require for 2007 and 2008 capital investments of approximately $76.0 million and $49.5 million, respectively, to drill and complete these wells and recomplete an estimated 60 gross wells and $37.0 million and $29.0 million, respectively, for acreage, equipment and vehicle replacement and purchases and salt water disposal facilities.

Our predecessor’s capital expenditures have consisted primarily of, and we anticipate that our capital requirements will continue to consist of, the following:


	•	maintenance capital expenditures, which are those capital expenditures required to maintain our production levels and asset base over the long term; and

	•	expansion capital expenditures, which are those capital expenditures that we expect will increase our production of our gas and oil properties or our asset base over the long term.

In estimating the minimum amount of Adjusted EBITDA that we must generate to pay our minimum quarterly distribution to our unitholders for the twelve months ending December 31, 2008, we have assumed that our capital expenditure budget for the twelve months ending December 31, 2008 will be approximately $78.5 million, consisting of approximately $22.0 million in maintenance capital expenditures and $56.5 million in expansion capital expenditures. We intend to finance future maintenance capital expenditures generally from cash flow from operations and expansion capital expenditures generally with borrowings under our new credit facility and/or the issuance of debt or equity.

In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we would reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt or equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness will be limited by covenants in our anticipated credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

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Cash flows

Cash Flows from Operating Activities. Net cash provided by operating activities totaled $2.5 million for the six months ended June 30, 2007 as compared to net cash provided by operations of $13.5 million for the six months ended June 30, 2006. This decrease resulted from a net loss of $8.9 million, a change in derivative fair value, an increase in accounts receivable and accounts payable and an increase in revenue payable and other receivables. Net cash provided by operating activities increased from $0.6 million for the year ended December 31, 2005 to $11.2 million for the year ended December 31, 2006 due primarily to an increase in sales volumes during 2006.

Cash Flows Used in Investing Activities. Net cash used in investing activities totaled $45.5 million for the six months ended June 30, 2007 as compared to $67.4 million for the six months ended June 30, 2006. During the six months ended June 30, 2007, a total of approximately $45.5 million of capital expenditures was invested as follows: $34.3 million was invested in new natural gas wells and properties, $7.5 million in acquiring leasehold and $3.6 million in other additional capital items. Net cash used in investing activities totaled $117.2 million for the year ended December 31, 2006 as compared to $51.6 million for the year ended December 31, 2005.

Cash Flows from Financing Activities. Net cash provided by financing activities totaled $31.6 million for the six months ended June 30, 2007 as compared to $86.7 million for the six months ended June 30, 2006. Net cash provided by financing activities totaled $124.8 million for the year ended December 31, 2006, which was an increase from $47.1 million for the year ended December 31, 2005, and related to the financing of capital expenditures.

Credit Facility

Description of Credit Facility. At the closing of this offering, Quest Cherokee, our operating subsidiary, will enter into a new 5-year $250 million revolving credit agreement, with an initial borrowing base of $160.0 million, with a syndicate of financial institutions. We will guarantee Quest Cherokee’s obligations under the credit facility.

The credit facility will be available for general partnership purposes, including working capital, capital expenditures, distributions and repayment of indebtedness of our Parent. We will borrow $75.0 million under the credit facility at the closing of this offering and, as a result, we will have approximately $85.0 million of remaining borrowing capacity under the credit facility immediately after the closing. Please read “Use of Proceeds.”

Our obligations under the credit facility will be secured at all times by substantially all of our assets and all of the assets of our subsidiaries. We may prepay all advances at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of LIBOR borrowings. Indebtedness under the credit facility will initially bear interest at LIBOR plus 1.5% per annum.

The credit agreement will prohibit us from making distributions of available cash to unitholders if any default or event of default (as defined in the credit agreement) exists. The credit agreement will require us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards, if any, in each case as will be defined by the credit agreement) 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 agreement will require us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA plus any distribution equivalents paid on unvested equity incentive compensation awards if any, to our consolidated interest expense, in each case as will be defined by the credit agreement) 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. Our new credit facility will also require us to maintain a current ratio (the ratio of our current assets plus unused availability under our borrowing base to our current liabilities excluding the current portion of the borrowing base, in each case as defined in our credit agreement) of not less than 1.00 to 1.00.

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In addition, the credit agreement will contain various covenants that may limit, among other things, our ability to:


	•	grant liens;

	•	incur additional indebtedness;

	•	engage in a merger, consolidation or dissolution;

	•	enter into transactions with affiliates;

	•	sell or otherwise dispose of our assets, businesses and operations;

	•	materially alter the character of our business; and

	•	make acquisitions, investments and capital expenditures.

If an event of default exists under our credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following could be an event of default under the credit agreement:


	•	failure to pay any principal when due or any interest or fees within five business days of the due date;

	•	failure to perform or otherwise comply with the covenants in the credit agreement;

	•	failure of any representation or warranty to be true and correct in any material respect;

	•	failure to pay debt;

	•	a change of control; and

	•	other customary defaults, including specified bankruptcy or insolvency events, the Employee Retirement Income Security Act of 1974, or ERISA, violations, and material judgment defaults.

Contractual Obligations

Future payments due on our contractual obligations as of June 30, 2007 are as follows:


	Total		2007		2008-2009		2010-2011		Thereafter
					(In thousands)

Quest Resource Corporation Term Notes(1)	$	225,000	$	—	$	—	$	150,000	$	75,000
Revolver — Quest Resource Corporation(1)(2)		10,000		—		—		—		10,000
Asset retirement obligation		1,546		—		—		—		1,546
Drilling contractor		7,663		3,422		4,241		—		—
Notes payable		270		179		69		13		9
Lease obligations		274		73		201		—		—
Derivatives		11,012		6,814		4,198		—		—

Total	$	255,765	$	10,488	$	8,709	$	150,013	$	86,555


(1)		Existing indebtedness will be repaid at closing with our new credit facility, the net proceeds of this offering and borrowings under our Parent’s new credit facility.

(2)		$50.0 million revolving credit facility of our Parent that matures on November 14, 2010. As of June 30, 2007, $10.0 million was borrowed under this facility.

In addition, we will enter into a management services agreement with Quest Energy Service upon completion of this offering, pursuant to which Quest Energy Service, through its affiliates and employees, will carry out the directions of our general partner and provide us with legal, accounting, finance, tax, property

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management, engineering and risk management services. Quest Energy Service may additionally provide us with acquisition services in respect of opportunities for us to acquire long-lived, stable and proved gas and oil reserves.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Other Long-Term Indebtedness

At June 30, 2007, $270,000 of notes payable to banks and finance companies were outstanding and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 1.9% to 11.5% per annum.

Critical Accounting Policies and Estimates

Readers of this prospectus and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The two policies we consider to be the most significant are discussed below.

The selection and application of accounting policies is an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business.

The sensitivity analyses used below are not intended to provide a reader with our predictions of the variability of the estimates used. Rather, the sensitivities used are included to allow the reader to understand a general cause and effect of changes in estimates.

Accounting for Derivative Instruments and Hedging Activities

We use commodity price and financial risk management instruments to mitigate our exposure to price fluctuations in gas and oil and changes in interest rates. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of gas and oil derivative transactions are reflected in oil and gas sales, and results of interest rate hedging transactions are reflected in interest expense. The changes in the fair value of derivative instruments not qualifying for designation as either cash flow or fair value hedges that occur prior to maturity are reported currently in the statement of operations as unrealized gains (losses) within oil and gas sales or interest expense. Cash flows from derivative instruments are classified in the same category within the statement of cash flows as the items being hedged, or on a basis consistent with the nature of the instruments.

Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in oil and gas sales. For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over

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time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently confirmed the fair values internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

Due to the volatility of gas and oil prices and, to a lesser extent, interest rates, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2005 and 2006 and June 30, 2007, the net market value of our derivatives was a liability of $61.7 million, an asset of $2.9 million and a liability of $2.9 million, respectively. With respect to our derivative contracts relating to periods after December 31, 2007, an increase or decrease in natural gas prices of $0.10 per MMBtu would decrease or increase the estimated fair value of our derivative contracts by approximately $1.8 million.

Gas and Oil Properties

The accounting for our business is subject to special accounting rules that are unique to the gas and oil industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full-cost method. We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of gas and oil properties are generally calculated on a well by well or lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of gas and oil properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher gas and oil depreciation, depletion and amortization rate, and we will not have exploration expenses that successful efforts companies frequently have.

Under the full-cost method, capitalized costs are amortized on a composite unit-of-production method based on proved gas and oil reserves. Depreciation, depletion and amortization expense is also based on the amount of estimated reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

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We review the carrying value of our gas and oil properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, gas and oil prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

The process of estimating gas and oil reserves is very complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates.

As of June 30, 2007, approximately 100% of our proved reserves were evaluated by independent petroleum engineers. All reserve estimates are prepared based upon a review of production histories and other geologic, economic, ownership and engineering data.

In addition, the prices of gas and oil are volatile and change from period to period. Price changes directly impact the estimated revenues from our properties and the associated present value of future net revenues. Such changes also impact the economic life of our properties and thereby affect the quantity of reserves that can be assigned to a property.

For example, if gas prices at June 30, 2007 had been $1.00 less per Mcf, then the standardized measure of our proved reserves as of June 30, 2007 would have decreased by $118.1 million, from $353.1 million to $235.0 million and our proved reserves would have decreased by 8.4 Bcfe from 205.5 Bcfe to 197.1 Bcfe.

Recent Accounting Pronouncements

The Financial Accounting Standards Board (“FASB”) recently issued the following standards which we reviewed to determine the potential impact on our financial statements upon adoption.

In June 2006, the FASB issued Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), an interpretation of FASB Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. FIN 48 clarifies the accounting and reporting for income taxes where interpretation of the law is uncertain. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of income tax uncertainties with respect to positions taken or expected to be taken in income tax returns. FIN 48 is effective for fiscal years beginning after December 15, 2006 and has no current applicability to our financial statements.

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expands the required disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 157.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS No. 158”), an amendment of FASB Statements No. 87, 88, 106 and 132(R). SFAS No. 158 requires (a) recognition of the funded status (measured as the difference between the fair value of the plan assets and the benefit obligation) of a benefit plan as an asset or liability in the employer’s statement of financial position, (b) measurement of the funded status as of the employer’s fiscal year-end with limited exceptions, and (c) recognition of changes in the funded status in the year in which the changes occur through comprehensive income. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure the plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SFAS No. 158 has no current applicability to our financial statements.

In September 2006, the Securities Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB No. 108”). SAB No. 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), an amendment of FASB Statement No. 115. SFAS No. 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 159.

Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. For additional information regarding our hedging activities, please read “Note 14 — Derivatives” to the audited financial statements included elsewhere in this prospectus.

Gas Hedging Activities

We seek to reduce our exposure to unfavorable changes in gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow us to predict with greater certainty the effective gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the six months ended June 30, 2006 and 2007, fixed-price contracts hedged approximately 68.5% and 68.2%, respectively, of our gas production. As of June 30, 2007, fixed-price contracts are in place to hedge 24.8 Bcf

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of estimated future gas production. Of this total volume, 5.4 Bcf are hedged for 2007 and 19.4 Bcf thereafter. We do not have any hedges with respect to our oil production.

For energy swap contracts, we receive a fixed price for the respective commodity and pay a floating market price, as defined in each contract (generally a regional spot market index or in some cases, NYMEX future prices), to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Natural gas collars contain a fixed floor price (put) and ceiling price (call) (generally a regional spot market index or in some cases, NYMEX future prices). If the market price of natural gas exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price of natural gas is between the call and the put strike price, then no payments are due from either party. The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of June 30, 2007.


	Six Months
	Ending			Year Ending			Year Ending
	December 31,			December 31,			December 31,
	2007			2008			2009		Total
	(In thousands, except MMBtu data)

Natural Gas Swaps:
Contract volumes (MMBtu)		1,187,000			2,332,000			9,999,000		13,518,000
Weighted-average fixed price per MMBtu(1)	$	7.20		$	7.35		$	7.85	$	7.70
Fixed-price sales	$	8,544		$	17,141		$	78,451	$	104,136
Fair value, net	$	884		$	35		$	25	$	944
Natural Gas Collars:
Contract volumes (MMBtu):
Floor		4,251,000			7,028,000			—		11,279,000
Ceiling		4,251,000			7,028,000			—		11,279,000
Weighted-average fixed price per MMBtu(1):
Floor	$	6.63		$	6.54			—	$	6.57
Ceiling	$	7.54		$	7.54			—	$	7.54
Fixed-price sales(2)	$	28,174		$	45,973			—	$	74,147
Fair value, net	$	(1,418	)	$	(2,447	)		—	$	(3,865	)
Total Natural Gas Contracts:(3)
Contract volumes (MMBtu)		5,438,000			9,360,000			9,999,000		24,797,000
Weighted-average fixed price per MMBtu(1)	$	6.75		$	6.74		$	7.85	$	7.19
Fixed-price sales(2)	$	36,718		$	63,114		$	78,451	$	178,283
Fair value, net	$	(534	)	$	(2,412	)	$	25	$	(2,921	)


(1)		The prices to be realized for hedged production are expected to vary from the prices shown due to basis.

(2)		Assumes floor prices for gas collar volumes.

(3)		Does not include basis swaps with notional volumes by year, as follows: 2007: 920,000 MMBtu; 2008: 1,464,000 MMBtu.

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and are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change.

All fixed-price contracts have been approved by our board of directors. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the six months ended June 30, 2006 and 2007, oil and gas sales included a loss of $663,000 and a gain of $1.4 million, respectively, of net losses associated with realized losses under fixed-price contracts.

For fixed-price contracts qualifying as cash flow hedges, changes in fair value for volumes not yet settled are shown as adjustments to other comprehensive income. For those contracts not qualifying as cash flow hedges, changes in fair value for volumes not yet settled are recognized in change in derivative fair value in the statement of operations. The fair value of all fixed-price contracts are recorded as assets or liabilities in the balance sheet.

Based upon market prices at June 30, 2007, the estimated amount of unrealized gains for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $8.2 million.

Interest Rate Risk

We will be exposed to market risk due to variable interest rates under the credit facility that we will enter into prior to the closing of this offering. Prior to the closing of this offering, we will enter into a $250.0 million credit facility, with an initial borrowing base of $160.0 million, and borrow $75.0 million under that facility. All such borrowings will bear interest at floating rates. Changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. Additionally, if domestic interest rates continue to increase, the interest rates on any of our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Credit Risk

Energy swaps and collars and interest rate swaps and caps provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are a financial institution and a major energy corporation. Should a counterparty default on a contract, there can be no assurance that we would be able to enter into a new contract with a third party on terms comparable to the original contract. We have not experienced non-performance by its counterparties.

Cancellation or termination of a fixed-price contract would subject a greater portion of our gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. Cancellation or termination of an interest rate swap or cap would subject a greater portion of our long-term debt to market interest rates, which, in an inflationary environment, could have an adverse effect on its future net income. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet.

Market Risk

The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for our production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For instance, some of our fixed price contracts are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”), that is, we receive the fixed price amount stated in the contract and pay to our counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of our gas assets and the cost of transporting the gas to another market, the amount that we receive when we actually sell our gas is based on the Southern Star first

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of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between gas prices on the NYMEX and the price actually received by us is referred to as a basis differential. Typically, the price for gas on the Southern Star first of month index is less than the price on the NYMEX due to the more limited demand for gas on the Southern Star first of month index.

The effective price realizations that result from the fixed-price contracts are affected by movements in this basis differential. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of our fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Predecessor receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract.

Changes in future gains and losses to be realized in gas and oil sales upon cash settlements of fixed-price contracts as a result of changes in market prices for gas are expected to be offset by changes in the price received for hedged gas production.

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BUSINESS

Overview

We are a Delaware limited partnership formed in July 2007 by our Parent to acquire, exploit and develop oil and natural gas properties. 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 are currently focused on the development of CBM in 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.

As of June 30, 2007, we had 205.5 Bcfe of estimated net proved reserves, of which approximately 99% were CBM and 66% 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 CBM producer in the Cherokee Basin with an average net daily production of 43.5 MMcfe for the six months ended June 30, 2007. Our estimated net proved reserves at June 30, 2007 had estimated future net revenues discounted at 10%, which we refer to as the “standardized measure”, of $353.1 million. Our reserves are long-lived, with an average reserve-to-production ratio of 13.1 years (8.7 years for our proved developed properties) as of June 30, 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. Even if we do not make additional acquisitions, we believe that our multi-year inventory of additional development and drilling locations on our undeveloped acreage gives us the opportunity to maintain and increase our proved reserves and average net daily production. Our strong presence in the Cherokee Basin is due to Quest Energy Partners Predecessor’s acquisition in December 2003 of approximately 372,000 gross (366,000 net) acres of gas leases, 418 gross (325 net) gas wells and 207 miles of gas gathering pipelines in the Cherokee Basin from Devon Energy Production Company, L.P. and Tall Grass Gas Services, LLC (collectively, “Devon”) in exchange for approximately $126 million total consideration.

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Business Strategies


	•	Increase reserves and production through executing what we believe to be a low-risk development and exploitation drilling program. We plan to grow our proved reserves through internal development and exploitation activities of our Cherokee Basin CBM properties. We have identified approximately 2,295 gross CBM drilling locations on our undeveloped acreage, of which 756 were classified as proved undeveloped as of June 30, 2007. During the period from January 1, 2005 through June 30, 2007, we recompleted over 364 gross wells that were originally completed using single-seam completions into multi-seam completions. We estimate that there are approximately 150 additional single-to-multi seam re-entries which we intend to complete over the next 24 months. Additionally, we are currently conducting a pilot program to test the development of a portion of our acreage using 80-acre spacing. If successful, we potentially could increase significantly the number of CBM drilling locations which are present on our acreage. Based upon current drilling and completion costs and expected increases in the same, we have currently budgeted approximately $76.0 million in calendar year 2007 to drill and complete an estimated 558 gross CBM wells and recomplete an estimated 60 gross wells in the Cherokee Basin.

	•	Make accretive acquisitions of conventional and unconventional gas and oil properties characterized by a high percentage of proved developed producing reserves with long-lived, stable production and development opportunities whereby we can apply our management’s knowledge and expertise. We seek to acquire long-lived properties with a high percentage of proved developed producing reserves, stable production and reserve exploitation potential. Proved developed producing reserves tend to be the lowest risk category for gas and oil production, providing immediate cash flow and more predictable future production. Long-lived reserves typically exhibit more sustainable production profiles, thereby better enabling us to grow reserves and production and increasing the likelihood that acquired assets will benefit from future advances in reservoir science and technology. Although our current assets are located in the Cherokee Basin, we intend to assess our opportunities in other producing basins within the United States.

	•	Reduce the volatility in our revenues resulting from changes in gas and oil commodity prices through hedging. We enter into derivative contracts with unaffiliated third parties to mitigate the impact of gas price volatility on our cash flow from operations. 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

	•	Maintain a low cost and efficient operating and production operation. We believe our significant reserve potential in our Cherokee Basin operating area, our technical expertise with unconventional reserves and high drilling success have allowed us to achieve low finding and development costs. From January 1, 2004 through June 30, 2007, we have invested approximately $207 million to drill and complete over 1,286 gross CBM wells and recomplete 382 gross CBM wells in the Cherokee Basin.

	•	Control our operations and limit our reliance on third party contractors with respect to the completion, stimulation and connection of our wells. We own, on average, a 99% working interest in all of our currently undeveloped leasehold acreage, and an average 99% working interest in all of our leasehold acreage that is held by production, in the Cherokee Basin. We have historically, and it is our intention to continue, to have our employees and those of our general partner and its affiliates control and physically conduct the completion and stimulation operations for wells we drill in the Cherokee Basin. In addition, our affiliate Quest Midstream owns and operates all of the compression, gas gathering and related facilities for our Cherokee Basin properties and is responsible for gas gathering connection

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operations for these properties. We believe that by limiting our reliance on third party contractors with respect to the completion, stimulation and connection of our wells, that we are better able to control costs and decisions with respect to the timing, development and operations of our Cherokee Basin properties.

Competitive Strengths

We believe that the following competitive strengths will allow us to achieve our objectives of generating and growing available cash for distribution:


	•	High quality asset base characterized by stable, long-lived production with an average reserve-to-production ratio of 13.1 years (8.7 years for our proved developed properties) as of June 30, 2007. Our properties have a long reserve-to-production ratio, with predictable decline rates. Based on our estimated net proved reserves (or proved developed reserves) as of June 30, 2007 divided by our annualized net production for the six months ended June 30, 2007, our properties’ average reserve-to-production ratio was 13.1 years (8.7 years for our proved developed properties). In addition, the standard economic life of our typical Cherokee Basin well is approximately 15 years. Over 99% of the CBM wells that have been drilled on our acreage to date have been successful. In addition, the coal seams from which we produce CBM are notable for their consistent thickness and gas content, resulting in a relatively predictable production profile for our wells.


	•	Extensive drilling inventory. As of June 30, 2007, we had approximately 2,295 identified drilling locations, of which 756 were classified as proved undeveloped, and approximately 266,070 net undeveloped acres. As a result, we have a multi-year inventory of drilling and development locations with which to maintain and increase our proved reserves and average net daily production. We use certain data available from the drilling records of the over 100,000 well bores that have penetrated the Cherokee Basin since the 1920s to help us determine the aerial extent, thickness and relative permeability of the coal seams we target for development, which greatly reduces our dry hole risk.

	•	Operational, acquisition evaluation, risk management and technical support from our Parent. Pursuant to the management services agreement, a subsidiary of our Parent will provide us with legal, accounting, finance, tax, property management, engineering, risk management and acquisition services related to identifying, evaluating and completing acquisitions.

	•	Experienced and knowledgeable management team. Key members of our executive management and technical team have been developing CBM in the Cherokee Basin since 1995 and have spent several years conducting technical research on historical data related to the development of the Cherokee Basin. Using our extensive expertise in Cherokee Basin geology, we believe we have determined where the most attractive opportunities for CBM development exist within the basin. In addition, our general partner’s executive officers have an average of over 20 years of experience in the oil and natural gas industry, with extensive experience working with a wide variety of oil and gas assets outside the Cherokee Basin. Our general partner’s executive officers have worked with conventional gas assets in areas including Texas, Louisiana, the Rocky Mountains, the Mid-continent region, the Gulf Coast region and offshore in the Gulf of Mexico and with unconventional assets in areas including the Arkoma, Black Warrior, Raton, Puget and Powder River basins.

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. Upon completion of this offering, our Parent will control us through its ownership of our general partner, which owns a 2% general partner interest in us as well as incentive distribution rights. Our Parent will also own 3,551,521 common units and 8,857,981 subordinated units representing an aggregate 57.5% limited partner interest in us.

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Exploitation and Exploration Activities. Upon completion of the formation transactions described in this prospectus, substantially all of our Parent’s existing gas and oil properties will be contributed to us. Our Parent will continue to own approximately 16,500 net undeveloped acres located in the States of Texas, 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 October 15, 2007, our Parent entered into a Merger Agreement with 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 June 30, 2007, Pinnacle owned natural gas and oil leasehold interests in approximately 478,000 gross (332,000 net) acres, approximately 94% of which were undeveloped. At December 31, 2006, Pinnacle had estimated net proved reserves of 20.3 Bcf based on a year-end Colorado Interstate Gas index price of $4.46 per Mcf, with a standardized measure of $22.4 million. These net proved reserves were located on approximately 8% of Pinnacle’s net acreage.

Under the Merger Agreement, our Parent would acquire Pinnacle in a stock-for-stock transaction. Following the merger, Jerry Cash, Chief Executive Officer, Chairman and a director of our general partner, will continue to serve as Chairman, President and Chief Executive Officer and as a director of our Parent. Consummation of the merger is subject to various conditions, including approval of the stockholders of both our Parent and Pinnacle, the closing of this offering and other customary conditions. In addition, the merger agreement contains certain termination rights for both our Parent and Pinnacle, and further provides that, upon termination of the merger agreement under specified circumstances (including an adverse change by either party’s board of directors of its recommendation to stockholders to vote for the merger) a party may be required to pay the other party a termination fee of $3.0 million. It is anticipated that the closing of the merger will occur in the first or 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; however, in the event the Pinnacle acquisition is consummated, our Parent does not anticipate that it will offer to us any of the properties acquired in the Pinnacle acquisition in the near term. 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

We produce CBM gas out of our properties located in the Cherokee Basin.

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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.

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.

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 2006 to drill and complete a well, excluding the related pipeline infrastructure was approximately $114,000. For the six months ended June 30, 2007, our average cost for drilling and completing a well was approximately $135,000. 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.

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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, 2006, we recompleted approximately 120 wellbores in Kansas and an additional five wellbores in Oklahoma and we had an additional 150 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 the Partnership Properties as of the dates presented based on our Parent’s 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. Our Parent filed estimates of its gas and oil reserves for the calendar years 2004, 2005 and 2006 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.


	May 31,			December 31,									June 30,
	2004			2004			2005			2006			2007

Proved reserves:
Gas (Mcf)		133,576,200			149,843,900			134,319,000			198,040,000			205,293,672
Oil (Bbls)		57,105			47,834			32,269			32,272			27,176
Total (Mcfe)		133,918,830			150,130,904			134,512,614			198,233,632			205,456,728
Proved developed gas reserves (Mcf)		62,558,900			81,467,300			71,638,215			122,390,360			136,313,070
Proved undeveloped gas reserves (Mcf)		71,017,300			68,376,600			62,681,000			75,649,640			68,980,602
Proved developed oil reserves (Bbls)(1)		57,105			47,834			32,269			32,272			27,176
Proved developed reserves as a percentage of total proved reserves		47.0	%		54.5	%		53.4	%		61.8	%		66.4	%
Standardized measure (in thousands)(2)	$	318,356		$	401,101		$	482,545		$	264,327		$	353,051


(1)		Although we have proved undeveloped oil reserves, they are insignificant, so no effort was made to calculate such reserves.

(2)		Standardized measure is 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

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		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 revenues. Our standardized measure differs from the standardized measure presented in the historical audited financial statements of Quest Energy Partners Predecessor included in this prospectus due to the exclusion of future income tax expense. Our standardized measure does not reflect any future income tax expenses because we are not subject to income taxes. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.” The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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. Please read “Risk Factors.”

Production Volumes, Sales Prices and Production Costs. The following table sets forth information regarding the Partnership Properties. 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.


	Year		Seven Months			Year						Six Months
	Ended		Ended			Ended						Ended
	May 31,		December 31,									June 30,
	2004		2004			2005			2006			2007

Net Production:
Gas (MMcf)		5,530		5,010			9,565			12,282			7,842
Oil (Bbls)		8,549		5,551			9,241			9,737			3,674
Gas equivalent (MMcfe)		5,580		5,050			9,620			12,341			7,864
Gas and Oil Sales ($ in thousands):
Gas sales	$	27,694	$	28,864		$	71,137		$	72,865		$	51,799
Gas derivatives — gains (loss)		102		(4,908	)		(27,066	)		(7,888	)		1,423

Total gas sales		27,796		23,956			44,071			64,977			53,222
Oil sales		351		245			494			574			194

Total gas and oil sales	$	28,147	$	24,201		$	44,565		$	65,551		$	53,416

Average Sales Price (excluding effects of hedging):
Gas ($ per Mcf)	$	5.19	$	5.74		$	7.44		$	5.93		$	6.60
Oil ($ per Bbl)		41.06		44.14			53.46			60.90			52.80
Gas equivalent ($ per Mcfe)		5.02		5.77			7.45			5.95			6.60
Average Sales Price (including effects of hedging):
Gas ($ per Mcf)	$	5.04	$	4.83		$	4.61		$	5.29		$	6.79
Oil ($ per Bbl)		41.06		44.14			53.46			60.90			52.80
Gas equivalent ($ per Mcfe)		5.04		4.79			4.63			5.31			6.79
Expenses ($ per Mcfe):
Oil and gas production	$	0.90	$	1.07		$	1.50		$	1.72		$	1.90
Transportation expense		0.33		0.63			0.73			1.40			1.68

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Producing Wells and Acreage. The following tables set forth information for the Partnership Properties as of December 31, 2004, 2005 and 2006 and June 30, 2007. For purposes of the table below, productive wells consist of producing wells and wells capable of production.


	Productive Wells
	Gas(1)				Oil				Total
	Gross		Net		Gross		Net		Gross		Net

December 31, 2004		795		774.3		29		27.9		824		802.2
December 31, 2005		1,026		999.3		29		27.9		1,055		1,027.2
December 31, 2006		1,653		1,609.9		29		27.9		1,682		1,637.8
June 30, 2007		1,904		1,860.9		29		27.9		1,933		1,888.8


(1)		At December 31, 2006 and June 30, 2007, the Partnership Properties had approximately 1,480 and 1,750, respectively, gross wells that were producing from multiple seams.

During the year ended December 31, 2006 and the six months ended June 30, 2007, we drilled 622 gross (605.8 net) and 260 gross (260 net) new wells, respectively, 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. Please read “— Drilling Activities.” During the year ended December 31, 2006, we continued to lease additional acreage in certain core development areas of the Cherokee Basin.


	Leasehold Acreage(1)
	Producing(2)				Nonproducing				Total Leased
	Gross		Net		Gross		Net		Gross		Net

December 31, 2004		311,941		291,318		205,230		187,884		517,171		479,202
December 31, 2005		334,676		310,663		198,569		184,322		533,245		494,985
December 31, 2006		394,795		385,148		132,189		124,774		526,984		509,923
June 30, 2007		401,928		391,304		141,436		131,914		543,364		523,218


(1)		Approximately 90,000 net acres that were included in the 2005 leasehold acreage amounts expired and are not included in the December 31, 2006 data.

(2)		Includes acreage held by production under the terms of the lease.

As of June 30, 2007, we had 266,230 gross (257,148 net) developed 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.

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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:


											Seven Months
											Ended						Year Ended								Six Months
	Year Ended										December 31,														Ended
	May 31, 2004										2004(1)						2005(1)				2006(1)				June 30, 2007(1)
	Oil						Gas				Gas						Gas				Gas				Gas
	Gross			Net			Gross		Net		Gross			Net			Gross		Net		Gross		Net		Gross		Net

Exploratory Wells:
Capable of Production		—			—			—		—		—			—			—		—		—		—		—		—
Dry		—			—			—		—		—			—			—		—		—		—		—		—
Development Wells:
Capable of Production		—			—			138		132		117			114			233		227		638		621		251		251
Dry		—			—			2		2		—			—			—		—		—		—		—		—
Wells Abandoned		(2	)		(2	)		—		—		(11	)		(11	)		—		—		—		—		—		—
Acquired Wells		—			—			337		337		11			11			—		—		—		—		—		—

Net Increase in Capable Wells		(2	)		(2	)		475		469		117			114			233		227		638		621		251		251

Recompletion of Single-seam Wells:
Capable of Production		—			—			—		—		38			38			205		200		125		122		34		34


(1)		There was no change to oil wells for the seven months ended December 31, 2004, for the years ended December 31, 2005 and 2006 or for the six months ended June 30, 2007.

The 251 gross new gas wells drilled and completed for the six months ended June 30, 2007 reflect an average activity level of approximately 42 gross wells per month. We plan to drill and complete an average of approximately 47 gross wells per month for year 2007, subject to capital being available for such expenditures.

During the period from January 1, 2007 through June 30, 2007, we drilled 260 gross wells and connected 251 gross wells. As of August 28, 2007, we were drilling 5 gross wells and approximately 100 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 will manage all of our properties and employs production and reservoir engineers, geologists and other specialists. Quest Cherokee Oilfield Service, LLC, a wholly-owned subsidiary of our operating company, Quest Cherokee, will employ our 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.

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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 June 30, 2007, we had over 4,500 leases covering approximately 523,000 net acres in the Cherokee Basin. The typical Cherokee Basin 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 a 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

Midstream Services Agreement. In connection with the closing of the offering, we will become 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 will gather and provide 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 will 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. 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.

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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 will 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.

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, 260 of which have been drilled in the Cherokee Basin through June 30, 2007. We expect to drill 298 additional wells in the second half of 2007 and 325 wells in 2008. At this time, we have not identified our drilling locations for 2008 and some or all of these wells may be drilled on locations that were not classified as containing proved reserves in our June 30, 2007 reserve report.

Marketing and Major Customers

We market our own gas and for the fiscal year ended May 31, 2004, approximately 90% of our gas was sold to ONEOK. More than 95% of our gas was sold to ONEOK for the seven months ended December 31, 2004 and for the years ended December 31, 2005 and 2006. No other customer accounted for more than 10% of revenues for the fiscal year ended May 31, 2004, the seven months ended December 31, 2004 or the years ended December 31, 2005 and 2006. In December 2006, we began selling gas to Tenaska. For the six months ended June 30, 2007, approximately 72% of our gas was sold to ONEOK and 28% was sold to Tenaska. 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 Activity

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. We have 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. As of October 15, 2007, we have fixed price swaps covering 13% of our estimated net gas production from proved developed producing reserves and collars covering 45% of our estimated net gas production from proved developed producing reserves for the remainder of 2007. We also have fixed price swaps and collars covering 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, we have fixed price swaps covering 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 our derivative contracts are based on the Southern Star first of month index, except for some of our older collar agreements covering approximately 1.8 Bcf of gas in the second half of 2007 (40% of our estimated net gas production from proved developed producing reserves for the second half of 2007) and 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

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pricing. As a result, our derivative contracts do not expose us to basis differential risk, except for the NYMEX collars and swaps. We have 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, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

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 prospectus.

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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 “Business — Legal Proceedings”.

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:


	•	require the acquisition of various permits before drilling commences;

	•	enjoin some or all of the operations of facilities deemed in non-compliance with permits;

	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with gas and oil drilling, production and transportation activities;

	•	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas; and

	•	require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

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

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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 (“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 Clean Water Act and analogous state laws and regulations.

Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act (“SDWA”) and analogous state and local laws. The underground injection well program under the SDWA classifies produced wastewaters and imposes controls relating to the drilling and operation of the wells as well as the quality of the injected wastewaters. This program is designed to protect drinking water sources and requires a permit from the EPA or the designated state agency — 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.

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The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which addresses three principal areas of oil pollution: prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Air Emissions. The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations or utilize specific emission control technologies to limit emissions. In addition, EPA has developed, and continues to develop, stringent regulations governing emissions of 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.

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.

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.

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Endangered Species Act. The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Although we believe that our current operations do not affect endangered or threatened species or their habitats, the existence of endangered or threatened species in areas of future operations and development could cause us to incur additional mitigation costs or become subject to construction or operating restrictions or bans in the affected areas.

OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act, or 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, 2006. Additionally, as of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2007. 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:


	•	the location of wells;

	•	the method of drilling and casing wells;

	•	the surface use and restoration of properties upon which wells are drilled;

	•	the plugging and abandoning of wells; and

	•	notice to surface owners and other third parties.

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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, has recently issued a Show Cause Order 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.

Gas Regulation. 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 (“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 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, 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.

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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.

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.

Employees

We employ approximately 250 field employees that perform development and maintenance services on our wells. Upon the consummation of this offering, we will enter into a management services agreement with Quest Energy Service, LLC pursuant to which it will perform administrative services for us such as accounting, finance, land, legal and engineering. We will 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 50 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.

Offices

Our Parent currently leases approximately 11,000 square feet of office space in Oklahoma City, Oklahoma at 9520 North May Ave., Suite 300, Oklahoma City, Oklahoma 73120, where our principal offices are located. The lease expires in May 2009. On May 31, 2007, our Parent entered into a ten-year office lease for a new corporate headquarters location at Suite 2750, 210 Park Avenue, Oklahoma City, Oklahoma, 73102. The lease is for approximately 35,000 square feet, with a monthly rental expense of $52,590. The lease term is currently anticipated to commence in November 2007.

Legal Proceedings

Our operating subsidiary, Quest Cherokee, LLC is currently a party 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, Quest Energy Service, LLC, STP, Inc., Quest Midstream Partners, L.P., Quest Midstream GP LLC, Quest Cherokee, STP Cherokee, Inc. (now STP Cherokee, LLC), and Bluestem Pipeline, LLC, Quest Midstream’s operating subsidiary (“Bluestem”), have been named Defendants in a lawsuit (Case #CJ-2003-30) filed by Plaintiffs Eddie R. Hill, et al, in the District Court for Craig County, Oklahoma. Plaintiffs are royalty owners who are alleging underpayment of royalties owed them. Plaintiffs also allege, among other things, that Defendants have engaged in self-dealing, have breached their fiduciary duties owed to Plaintiffs and have acted fraudulently towards 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

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Kansas. Plaintiffs are seeking unspecified actual and punitive damages. Discovery is ongoing and Defendants intend to defend vigorously against Plaintiffs’ claims.

STP, Inc., STP Cherokee, Inc. (now STP Cherokee, LLC), Bluestem, Quest Cherokee, and Quest Energy Service 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 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 (approximately 1,100 acres). 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. 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 conversion of the gas and seeks an accounting for all gas produced 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. Quest Cherokee has asserted third party claims against the persons who entered into the gas leases with Quest Cherokee for breach of the warranty of title contained in their leases in the event that the court finds that Plaintiff owns the coal bed methane gas. The District Court granted Quest Cherokee’s motion for summary judgment, ruling that coal bed methane gas is owned by the owners of the gas rights. That ruling was appealed to the Kansas Supreme Court, which has set the matter for oral argument on December 4, 2007.

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 2,500 acres of land in Craig County, Oklahoma. These leases, together with the leases involved in the Kansas lawsuit discussed above, comprise approximately 0.5% of our total acreage. 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 intend to defend vigorously against Plaintiff’s claims.

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by Quest Cherokee. Plaintiffs in those cases are generally seeking statutory damages of $100 per lease, attorneys fees, and a judicial declaration that Quest Cherokee’s leases have terminated. As of August 7, 2007, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,300 acres. Quest Cherokee contends that it has complied with the terms of these oil and gas leases and that they remain in full force and effect. Quest Cherokee intends to vigorously defend against the 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 and unplugged 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. See “Risk Factors — Risks Related to Our Business — 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.’’

On August 3, 2007, certain mineral and overriding royalty interest owners in land located in the Kansas portion of the Cherokee Basin filed a putative class action lawsuit against Quest Cherokee. Hugo Spieker, et al. v. Quest Cherokee, LLC, United States District Court for the District of Kansas, Case No. 07-1225-MLB. The named plaintiffs allege that Quest Cherokee has 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 of gas measured at the wellheads, and by allocating certain expenses to plaintiffs’ interests. Plaintiffs also allege that Quest Cherokee is improperly charging the royalty owners costs in excess of the actual costs of the services provided. Plaintiffs allege that the amount in controversy exceeds $5 million. Quest Cherokee is in the process of investigating and evaluating the claims. Quest Cherokee denies any wrongdoing and intends to vigorously defend against the 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 our 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.

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MANAGEMENT

Management of Quest Energy Partners, L.P.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business. Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please see “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Quest Energy GP, LLC, our general partner, will manage our operations and activities on our behalf. Quest Energy GP is wholly owned by our Parent. We intend to enter into a management services agreement with Quest Energy Service, LLC, a wholly-owned subsidiary of our Parent, pursuant to which Quest Energy Service will provide us with legal, accounting, finance, tax, property management, engineering, risk management and acquisition services in respect of opportunities for us to acquire long-lived, stable and proved gas and oil reserves. The management services agreement will provide that employees of Quest Energy Service (including the persons who are executive officers of our general partner) will devote such portion of their time as may be needed to conduct our business and affairs.

Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. As owner of our general partner, our Parent will have the ability to elect all the members of the board of directors of our general partner. Our general partner owes a fiduciary duty to our unitholders, although our partnership agreement limits such duties and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except as described in “The Partnership Agreement — Voting Rights” and subject to its fiduciary duty to act in good faith, our general partner will have exclusive management power over our business and affairs.

Quest Energy GP has a board of directors that oversees its management, operations and activities. We refer to the board of directors of Quest Energy GP as the “board of directors of our general partner.” The board of directors of our general partner will have at least three members who are not officers or employees, and are otherwise independent, of our Parent and its affiliates, including our general partner. These directors, to whom we refer as independent directors, must meet the independence standards established by the NASDAQ Global Market and SEC rules. The board of directors of our general partner will have at least one independent director to serve on the audit committee prior to our common units being listed for trading on the NASDAQ Global Market, at least one additional independent director to serve on the audit committee within 90 days after listing of our common units on the NASDAQ Global Market and a third independent director to serve on the audit committee not later than one year following the listing of our common units on the NASDAQ Global Market. The NASDAQ Global Market does not require a listed limited partnership like 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.

All three independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board of directors believes may involve conflicts of interest. At the request of the board of directors of our general partner, the conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us (in light of the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial

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to us). The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including our Parent, and must meet the independence and experience standards established by the NASDAQ Global Market and SEC rules, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the NASDAQ Global Market and SEC rules. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

The independent members of the board of directors of our general partner will serve as the initial members of the audit and conflicts committees of the board of directors of our general partner.

Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and our general partner is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under the Delaware Act or any other law. Examples include the exercise of its limited call rights, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment of the partnership agreement.

All of the executive officers of our general partner will be employees of Quest Energy Service and will allocate their time between managing our business and affairs and the business and affairs of our Parent and its affiliates, including Quest Midstream. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of our Parent and its affiliates. The board of directors of our general partner intends to cause the executive officers of our general partner to devote as much time to the management of our business and affairs as is necessary for the proper conduct thereof. It is anticipated that the executive officers of our general partner will devote a majority of their time to our business for the foreseeable future. We will also utilize a significant number of other employees of Quest Energy Service to provide us with general and administrative services. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Management Services Agreement.” We will reimburse Quest Energy Service for allocated general and administrative expenses. Please read “— Reimbursement of Expenses of Our General Partner.”

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Directors and Executive Officers

The following table shows information regarding the current directors and executive officers of our general partner. Directors are elected for one-year terms by our Parent, the owner of our general partner.


Name	Age		Position

Jerry D. Cash		45	Chairman of the Board, Chief Executive Officer, Director
David E. Grose		55	Chief Financial Officer
David Lawler		39	Chief Operating Officer and Director
David Bolton		39	Executive Vice President — Land
Steve Hochstein		49	Executive Vice President — Exploration/A&D
Richard Marlin		55	Executive Vice President — Engineering
Gary Pittman		44	Director Nominee
Mark Stansberry		51	Director Nominee

Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

Jerry D. Cash serves as the Chairman of the Board of Directors and Chief Executive Officer of our general partner. Mr. Cash is Chief Executive Officer and a Director of our Parent. Mr. Cash has been active in the gas and oil exploration and development business for over 25 years. Mr. Cash has been the Chairman of the Board of our Parent since November 2002, when our Parent acquired STP Cherokee, Inc. Mr. Cash has been Chief Executive Officer since September 2004. From November 2002 until September 2004, he was Co-Chief Executive Officer of our Parent. From November 2002 until June 2004, he was Chief Financial Officer of our Parent. In 1987, Mr. Cash formed STP, Inc. and as President directed that company in the identification and realization of numerous oil, gas and CBM exploration projects. In November 2002, Mr. Cash transferred substantially all of the assets of STP, Inc. to STP Cherokee and sold STP Cherokee to our Parent in November 2002. From 1980 to 1986, Mr. Cash worked for Bodard & Hale Drilling Company while pursuing a petroleum engineering degree at Oklahoma State University. During this period, Mr. Cash drilled several hundred wells throughout Oklahoma. A long-time resident of Oklahoma, Mr. Cash maintains an active role in several charitable organizations.

David E. Grose serves as the Chief Financial Officer of our general partner. Mr. Grose is Chief Financial Officer of our Parent, and has held that position since June 2004. Mr. Grose has 25 years of financial experience, primarily in the exploration, production, and drilling sectors of the gas and oil industry. Mr. Grose also has significant knowledge and expertise in capital development and in the acquisition of oil & gas companies. From January 2004 to June 2004, Mr. Grose was Chief Financial Officer for Avalon Corrections, Inc., a corrections company. From June 2002 until December 2003, Mr. Grose was Chief Financial Officer for Oxley Petroleum Company. From April 1999 to December 2001, Mr. Grose was Chief Financial Officer for a telecommunications company. From July 1997 to April 1999, Mr. Grose was Chief Financial Officer for Bayard Drilling Technologies, Inc. Prior to that, Mr. Grose was employed by Alexander Energy Corporation from March 1980 to February 1997, in various positions, most recently as Chief Financial Officer. Mr. Grose earned a B.A. in Political Science from Oklahoma State University in 1974 and an MBA from the University of Central Oklahoma in 1977.

David Lawler serves as a Director and the Chief Operating Officer of our general partner. Mr. Lawler has served as Chief Operating Officer of our Parent since May 2007. Mr. Lawler has worked in the oil and gas industry for more than 16 years in various management and engineering positions including production, drilling, project management and facilities. Prior to joining our Parent, Mr. Lawler was employed by Shell Exploration & Production Company from May 1997 to May 2007 and in his most recent assignment, served as Engineering and Operations Manager for multiple assets along the U.S. Gulf Coast from January 2005 to May 2007. These assets included Shell’s prolific gas producing assets located in South Texas as well as offshore sour gas production facilities near Mobile Bay, Alabama and the Yellowhammer Sulfur Recovery Plan

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located in Coden, Alabama. Prior to his role as Operations Manager, Mr. Lawler progressed through technical and leadership assignments at Shell, including Executive Support/Staff Business Analyst (March 2003 to December 2004) and drilling engineering team leader (May 1997 to February 2003). Prior to joining Shell, Mr. Lawler was employed by Conoco, Inc. and Burlington Resources in various domestic engineering and operations positions. Mr. Lawler graduated from the Colorado School of Mines in 1990 with a bachelor’s of science degree in petroleum engineering and earned his Masters in Business Administration from Tulane University in 2003.

David Bolton serves as Executive Vice President — Land of our general partner. Mr. Bolton has served as Executive Vice President — Land of our Parent since May 2006. Prior to that, Mr. Bolton was a Land Manager for Continental Land Resources LLC, an Oklahoma based gas and oil lease broker from May 2004 to May 2006. Prior to that, Mr. Bolton was a landman for Continental Land Resources from April 2001 to May 2004. Mr. Bolton was an independent landman from 1995 to April 2001. Mr. Bolton is a Certified Professional Landman with over 15 years of experience in various aspects of the gas and oil industry, and has worked extensively throughout Oklahoma, Texas, and Kansas. Mr. Bolton holds a Bachelor of Liberal Studies degree from the University of Oklahoma, attended the Oklahoma City University School of Law, and is a member of American Association of Petroleum Landmen, Oklahoma City Association of Petroleum Landmen, the American Bar Association, and the Energy Bar Association.

Steve Hochstein serves as Executive Vice President — Exploration/A&D of our general partner. Mr. Hochstein joined our Parent in January of 2006 as Manager of New Ventures. Mr. Hochstein assumed the Executive Vice President — Exploration/A&D position at our Parent effective March 16, 2007. While serving as Manager of New Ventures, Mr. Hochstein led resource assessment efforts for several acquisition projects and was responsible for generating two new resource plays for our Parent. In his new role, Mr. Hochstein will continue to develop new opportunities for our Parent, lead the A&D efforts, and oversee all geologic and reservoir engineering functions. Before joining our Parent, Mr. Hochstein served for two years as a partner in Rockport Energy, a small E&P company. Prior to that, Mr. Hochstein worked for El Paso Corporation in its coalbed methane division, serving as technical manager (January 2001 to August 2001), Director of Coalbed Methane (August 2001 to February 2003) and Vice President of CBM/Mid Continent and Rockies (February 2003 to April 2004). Prior to that, Mr. Hochstein worked for Sonat Exploration Co. from August 1981 to January 2001 in various positions, most recently as Manager of Geoscience. Mr. Hochstein has more than 25 years of industry experience and more than 10 years of unconventional resource experience. Mr. Hochstein holds a Bachelor of Science in Geologic Sciences from the University of Texas, Austin, and is a member of the American Association of Petroleum Geologists.

Richard Marlin serves as Executive Vice President — Engineering of our general partner. Mr. Marlin has served as Executive Vice President — Engineering of our Parent since September 2004. Mr. Marlin also was our Parent’s Chief Operations Officer from February 2005 through July 2006. Mr. Marlin was our Parent’s engineering manager from November 2002 to September 2004. Prior to that, Mr. Marlin was the engineering manager for STP from 1999 until STP’s acquisition by our Parent in November 2002. Prior to that, Mr. Marlin was employed by Parker and Parsley Petroleum as the Mid-Continent Operations Manager for 12 years. Mr. Marlin has more than 28 years industry experience involving all phases of drilling and production in more than 14 states. His experience also involved primary and secondary operations along with the design and oversight of gathering systems that move as much as 175 MMcf/d. Mr. Marlin is a registered Professional Engineer holding licenses in Oklahoma and Colorado. Mr. Marlin earned a B.S. in Industrial Engineering and Management from Oklahoma State University in 1974. Mr. Marlin is a Director of the Mid-Continent Coal Bed Methane Forum.

Gary Pittman will become a director of our general partner prior to the effectiveness of the registration statement of which this prospectus is a part. Mr. Pittman is currently an active private investor who began his career in private equity and investment banking. From 1987 to 1995, Mr. Pittman was Vice President of The Energy Recovery Fund, a $180 million private equity fund focused on the energy industry. Mr. Pittman has served as a director of various oil and natural gas companies, including Flotek Industries, Inc., a specialty chemical oil service company; Geokinetics, Inc., a seismic acquisition and processing company; Czar Resources, Ltd, a Canadian E&P company; Triton Imaging International, a developer of sea floor imaging

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software; and Sub Sea International, an offshore robotics and diving company. He owned and operated an oil and gas production and gas gathering company in Montana from 1992 to 1998. Mr. Pittman currently chairs the compensation committee and serves on the audit committee for Flotek, and chairs the audit committee and serves on the compensation and governance committees for Geokinetics. Mr. Pittman holds a B.A. degree in Economics/Business from Wheaton College and an MBA from Georgetown University.

Mark Stansberry will become a director of our general partner prior to the effectiveness of the registration statement of which this prospectus is a part. Mr. Stansberry currently serves as the Chairman of The GTD Group, which owns and invests in companies including those specializing in energy consulting and management, environmental, governmental relations, international trade development and commercial construction. He has served as Chairman of The GTD Group since 1998. Currently, he serves as Chairman of The Governor’s International Team and State Chamber’s Energy Council in Oklahoma. He also serves on a number of other boards, including the Board of Directors of People to People International, and serves as President of the International Society of The Energy Advocates. Mr. Stansberry has testified before the U.S. Senate Energy and Natural Resources Committee and is the author of the book: The Braking Point: America’s Energy Dreams and Global Economic Realities. Mr. Stansberry is a 1977 Bachelor’s of Arts graduate from Oklahoma Christian University, a graduate of the Fund for American Studies/Georgetown University, and a graduate of the Intermediate School of Banking, Oklahoma State University.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership. However, our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business including overhead allocated to our general partner by its affiliates, including our Parent. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. We do not expect to incur any additional fees or to make other payments to these entities in connection with operating our business. Our general partner is entitled to determine in good faith the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. We expect that we will reimburse our Parent for at least a majority of the compensation and benefits paid to the executive officers of our general partner. Please read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions” and “The Partnership Agreement — Reimbursement of Expenses.”

We intend to enter into a management services agreement with Quest Energy Service pursuant to which Quest Energy Service will operate our assets and perform other administrative services for us such as accounting, corporate development, finance, land, legal and engineering. We will reimburse Quest Energy Services for its costs in performing these services, plus related expenses.

Executive Compensation Discussion and Analysis

We do not directly employ any of the persons responsible for managing our business, and we do not have a compensation committee. Quest Energy GP, our general partner, will manage our operations and activities, and its board of directors and officers will make decisions on our behalf. All of the executive officers of our general partner also serve as executive officers of our Parent. The compensation of Quest Energy Service’s employees that perform services on our behalf will be set by the compensation committee of and paid for by our Parent. The officers and employees of our general partner may participate in employee benefit plans and arrangements sponsored by our Parent. Our general partner has not entered into any employment agreements with any of its officers.

We and our general partner were formed in July 2007. As such, our general partner did not accrue any obligations with respect to executive compensation for its directors and executive officers for the fiscal year ended December 31, 2006, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. For 2007, we expect that our general partner’s named executive officers will include Jerry D. Cash (Chief Executive Officer), David E. Grose (Chief Financial Officer), David Lawler (Chief Operating

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Officer), David Bolton (Executive Vice President — Land) and Steve Hochstein (Executive Vice President — Exploration/A&D). Compensation paid or awarded by us in 2007 with respect to such named officers (collectively, the “named executive officers”) will reflect only the portion of compensation paid by our Parent that is allocated to us pursuant to our Parent’s allocation methodology and subject to the terms of the management services agreement and the omnibus agreement. Compensation of our executive officers, including awards under our long term incentive plan, will be approved by the compensation committee of the board of directors of our Parent or its delegate.

Our Parent’s Compensation Methodology. Our Parent has the ultimate decision-making authority with respect to the total compensation of our named executive officers. The elements of compensation discussed below, and our Parent’s decisions with respect to the levels of such compensation, will not be subject to approval by the board of directors of our general partner, including the audit and conflicts committees thereof. Awards under our general partner’s long-term incentive plan will be made by the board of directors of our general partner or a committee thereof.

Purpose of our Parent’s Executive Compensation Program. Our Parent’s executive compensation program has been designed to accomplish the following three primary objectives:


	•	attract and retain well-qualified executives who will lead our Parent and achieve superior performance;

	•	tie annual incentives to achievement of specific, measurable short-term corporate goals; and

	•	align the interests of management of our Parent with those of the stockholders of our Parent to encourage achievement of increases in stockholder value.

Role of our Parent’s Compensation Committee. Our Parent’s compensation committee has overall responsibility for the compensation of the named executive officers. The compensation payable to the Chief Executive Officer is set by our Parent’s compensation committee following an annual performance review. All aspects of compensation payable to the other named executive officers is reviewed and recommended to the board of directors of our Parent or determined by our Parent’s compensation committee. Beginning with the 2007 fiscal year, each year our Parent’s compensation committee will ask the Chief Executive Officer and Chief Financial Officer to present a proposed compensation plan for the fiscal year beginning January 1 and ending December 31 (each, a “Plan Year”), along with supporting and competitive market data.

The compensation philosophy of our Parent’s compensation committee is to manage total compensation of the named executive officers at the median level (50^th percentile) relative to companies with which our Parent competes for talent (which are primarily the peer group companies). Our Parent’s compensation committee compares compensation levels with a selected cross-industry group of other gas and oil exploration and production companies of similar size to establish a competitive compensation package. All compensation determinations are discretionary and, as noted above, subject to our Parent’s decision-making authority.

Our Parent’s compensation committee monitors the performance of the named executive officers throughout the Plan Year against the targets set for each performance measure. At the end of the Plan Year, our Parent’s compensation committee meets with the Chief Executive Officer and Chief Financial Officer to review the final results compared to the established performance goals before determining compensation levels of the named executive officers for the Plan Year. During this meeting, our Parent’s compensation committee also establishes the named executive officer compensation plan for the upcoming Plan Year, based on the Chief Executive Officer’s recommendations.

Performance Peer Group. Our Parent and its compensation committee retained the independent compensation consulting firm of Towers Perrin (“T-P”) to conduct a comprehensive benchmarking survey and to evaluate our Parent’s overall compensation program. With the assistance of T-P, our Parent’s compensation committee selected a peer group consisting of the following thirteen publicly traded U.S. exploration and production companies: ATP Oil & Gas Corp., Brigham Exploration, Carrizo Oil & Gas Inc., Edge Petroleum, Gastar Exploration, GMX Resources, Goodrich Petroleum, Linn Energy, McMoRan Exploration, Parallel Petroleum, Toreador Resources Corp. and Warren Resources. In general, peer group companies were

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U.S. energy companies in the exploration and production sector which had annual revenues ranging from $30 million to $175 million.

Elements of our Parent’s Executive Compensation Program. Our Parent’s compensation program for the named executive officers consists of the following components:

Base Salary: Base salaries for the named executive officers are established base on their scope of responsibilities, taking into account competitive market compensation paid by other companies in our Parent’s peer group. Our Parent’s compensation committee considers the median salary range for each named executive officer’s counterpart, but makes adjustments to reflect differences in job descriptions and scope of responsibilities for each named executive officer and to reflect the compensation committee’s philosophy that each named executive officer’s total compensation should be at the median level (50th percentile) relative to our Parent’s peer group. Our Parent’s compensation committee annually reviews base salaries for the named executive officers and makes adjustments from time to time to realign their salaries, after taking into account individual performance, responsibilities, experience, autonomy, strategic perspectives and marketability, as well as the recommendations of the Chief Executive Officer.

Management Annual Incentive Plan: Our Parent’s Management Annual Incentive Plan (the “Bonus Plan”) is intended to recognize value creation by providing competitive incentives for meeting and exceeding annual financial and operating performance measurement targets. By providing market-competitive bonus awards, our Parent’s compensation committee believes the Bonus Plan will support the attraction and retention of the named executive officers which are critical to achieving the strategic business objectives of our Parent. The Bonus Plan puts a significant portion of total compensation at risk by linking potential annual compensation to the our Parent’s achievement of specific performance goals during the year, which creates a direct connection between the executive’s pay and our Parent’s financial performance.

Each year our Parent’s compensation committee establishes goals at the beginning of each calendar year. Our Parent’s compensation committee increased the 2007 performance targets from the 2006 levels. Our Parent’s compensation committee believes the named executive officers must continue to improve our financial and operating performance in order to achieve the targets, and that it will be difficult for the named executive officers to reach the target levels. The compensation committee established the 2007 performance targets and percentages of goals achieved for each of the five corporate financial goals described below:

Percentage of Goal Achieved

50%

100%

150%

Performance Measure

EBITDA (earnings before interest, taxes, depreciation and amortization)

34,000,000

54,000,000

74,000,000

Lease operating expense (excluding gross production taxes and ad valorem taxes)

1.31/Mcf

1.23/Mcf

1.15/Mcf

Finding and development cost

1.67/Mcf

1.50/Mcf

1.33/Mcf

Year end proved reserves

193.5 Bcfe

215 Bcfe

236.5 Bcfe

Production

16.2 Bcfe

18.0 Bcfe

19.8 Bcfe

Each of the five corporate financial goals are equally weighted. The amount of the incentive bonus varies depending upon the average percentage of the financial goals achieved. For amounts between 50% and 100% and between 100% and 150%, linear interpolation is used to determine the “Percentage of Goal Achieved”. For amounts below 50%, the “Percentage of Goal Achieved” is determined using the same scale as between 50% and 100%. For amounts in excess of 150%, the “Percentage of Goal Achieved” is determined using the same scale as between 100% and 150%. For 2007, no incentive awards will be paid under the Bonus Plan if the average percentage of the financial goals achieved is less than 60%. Additionally, no additional incentive awards will be paid if the average percentage of the financial goals achieved exceeds 150%.

For 2007, awards under the Bonus Plan will be payable solely in cash. Our Parent’s compensation committee anticipates that future annual bonus awards will also be paid only in the form of cash awards. Our Parent’s compensation committee made this change because of the roll out of our Parent’s long-term incentive

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plan, as described below, so that the compensation committee could preserve the number of shares remaining under our Parent’s 2005 Omnibus Stock Award Plan (the “Omnibus Stock Award Plan”) for the long-term incentive plan.

After the end of the Plan Year, our Parent’s compensation committee determines to what extent our Parent and the participants have achieved the performance measurement goals. Our Parent’s compensation committee calculates and certifies in writing the amount of each participant’s bonus based upon the actual achievements and computation formulae set forth in the Bonus Plan. Our Parent’s compensation committee has no discretion to increase the amount of any named executive officer’s bonus as so determined, but may reduce the amount of or totally eliminate such bonus, if it determines, in its absolute and sole discretion that such reduction or elimination is appropriate in order to reflect the named executive officer’s performance or unanticipated factors. The performance period (“Incentive Period”) with respect to which target awards and bonuses may be payable under the Bonus Plan will generally be the fiscal year beginning on January 1 and ending on December 31, but our Parent’s compensation committee has the authority to designate different Incentive Periods.

Productivity Gain Sharing Payments: A one-time cash payment equal to 10% of an individual’s monthly base salary is earned during each month that our Parent’s CBM production rate increases by 1,000 Mcf/day over the prior record. In general, employees of our Parent are eligible to receive productivity gain sharing payments. The purpose of these payments is to incentivize all employees, including named executive officers, to continually and immediately focus on production.

Discretionary Bonus Plan: Beginning in 2007, our Parent established a bonus plan for all of its full time employees that have been employed for 90 days as of the end of a year (other than those employed by Quest Midstream GP). Under the plan, participating employees are eligible to receive a cash bonus of up to 15% of their base compensation (excluding bonuses and other extraordinary compensation) that is earned in the year for which the bonus is paid. The determination as to whether a bonus payment will be made under the bonus plan for any given year, and the amount of that payment, is solely within the discretion of our Parent’s compensation committee. Bonuses under the plan may be paid in either cash, stock of our Parent or a combination thereof. It is currently anticipated that bonuses under the plan would be paid in the form of stock (with such amounts being awarded under the Omnibus Stock Award Plan). Our Parent anticipates that the amount of the bonus paid to an employee would depend upon the employee’s performance during the prior year.

Equity Awards

Omnibus Stock Award Plan. The total number of shares of our Parent’s stock that may be issued under the Omnibus Stock Award Plan is 2,200,000 shares. The Omnibus Stock Award Plan also permits the grant of incentive stock options for our Parent’s shares. The objectives of the Omnibus Stock Award Plan are to strengthen key employees’ and non-employee directors’ commitment to the success of our Parent, to stimulate key employees’ and non-employee directors’ efforts on its behalf and to help our Parent attract new employees with the education, skills and experience it needs and retain existing key employees. All of our Parent’s equity awards are issued under the Omnibus Stock Award Plan.

Management Annual Incentive Awards. In 2007, no stock awards will be made under the Bonus Plan because our Parent’s compensation committee will use the long-term incentive plan described below for equity awards.

Restricted Stock Awards. In addition to the equity component of the management annual incentive plan described above, our Parent’s compensation committee granted certain restricted stock awards to certain named executive officers in connection with their acceptance of employment with our Parent.

Our Parent’s Long-Term Incentive Plan. For 2007, our Parent’s compensation committee added a new long-term incentive plan for the named executive officers under our Parent’s Omnibus Stock Award Plan. The new plan is intended to encourage participants to focus on long-term performance of our Parent and provide an opportunity for the named executive officers to increase their stake in our Parent through grants of

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restricted stock pursuant to the terms of the Omnibus Stock Award Plan. Our Parent’s compensation committee designed the long-term incentive plan to:


	•	enhance the link between the creation of stockholder value and long-term named executive officers incentive compensation;

	•	provide an opportunity for increased equity ownership by named executive officers; and

	•	maintain a competitive level of total compensation.

Our Parent’s compensation committee determined the level of awards based on market data provided by T-P and the recommendations of the Chief Executive Officer (which in some cases were based on negotiations with named executive officers). Award levels vary among participants based on their position within our Parent. The awards are subject to the terms of an award agreement which outlines a vesting schedule (at the conclusion of each year of service, one-third of the award amount vests with the entire award vested at the end of three years) which is expected to help retain named executive officers as any unvested awards are forfeited if that individual terminates his employment without good reason. There are no additional performance criteria that must be met in order for the award to be earned. The vesting schedule for the awards accelerates if a named executive officer is terminated without cause by our Parent, or for good reason by the named executive officer.

We plan to issue our executive officers long-term equity based awards intended to compensate the officers based on the performance of our common units and their continued employment during the vesting period. These awards will be made pursuant to a long-term incentive plan that will be adopted by us and administered by our Parent; provided, however, that awards under the long-term incentive plan will be recommended by the compensation committee of our Parent and approved by the board of directors of Quest Energy GP, LLC. Please see “— Long-Term Incentive Plan.” The cost of such awards will be allocated to us pursuant to our Parent’s allocation methodology and subject to the terms of the omnibus agreement. The Quest Energy Partners equity-based awards that we intend to make to both our named executive officers and the directors of our general partner are intended to align their long-term interests with those of our unitholders.

The terms and amount of Quest Energy Partners equity awards that we intend to make to each of our directors under our long-term incentive plan will be recommended by our Parent’s compensation committee or its delegate and approved by our general partner.

Benefits. Our Parent’s employees, including the named executive officers, who meet minimum service requirements are entitled to receive medical, dental, life and long-term disability insurance benefits for themselves (and after 12 months’ employment, 50% coverage for their dependents). Named executive officers also participate along with other employees in our Parent’s 401(k) plan and other standard benefits. Our Parent’s 401(k) plan provides for matching contributions by our Parent. Such benefits are provided equally to all our Parent employees, other than where benefits are provided pro rata based on the respective named executive officer’s salary (such as the level of disability insurance coverage).

Perquisites. Our Parent believes its executive compensation program described above is generally sufficient for attracting talented executives and that providing large perquisites is neither necessary nor in our Parent’s stockholders’ best interests. Certain perquisites are provided to provide job satisfaction and enhance productivity. For example, our Parent provides an automobile for certain named executive officers, and on occasion family members and acquaintances have accompanied the Chief Executive Officer on business trips made on private charter flights. Named executive officers also are eligible to receive gym club memberships.

Long-Term Incentive Plan

Our general partner intends to adopt the Quest Energy GP, LLC Long-Term Incentive Plan for employees, consultants and directors of our general partner and any of its affiliates who perform services for us. The long-term incentive plan will consist of the following of our securities: options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to employees providing services to us, and to align the economic interests of such employees with the interests of our

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unitholders. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 10% of the outstanding common and subordinated units on the effective date of the initial public offering of common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the compensation committee of our Parent’s board of directors, provided that administration may be delegated to such other committee as appointed by our general partner’s board of directors.

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest of (1) the date units are no longer available under the plan for grants, (2) termination of the plan by the plan administrator or (3) the date 10 years following its date of adoption.

Restricted Units. A restricted unit is a common unit that vests over a specified period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the plan administrator, cash equivalent to the value of a common unit. The plan administrator may make grants of phantom units under the plan containing such terms as the plan administrator shall determine, including the period over which phantom units granted will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial objectives.

Unit Options. The long-term incentive plan will permit the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights. The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

Distribution Equivalent Rights. The plan administrator may, in its discretion, grant distribution equivalent rights, or DERs, as a stand-alone award or with respect to phantom unit awards or other award under the long-term incentive plan. DERs entitle the participant to receive cash or additional awards equal to the amount of any cash distributions made by us during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

Other Unit-Based Awards. The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

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Unit Awards. The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service. Awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Source of Units. Common units to be delivered pursuant to awards under the long-term incentive plan may be common units acquired by us in the open market, common units acquired by us from any other person or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that each director who is not an officer or employee of our general partner or its affiliates will receive compensation for attending meetings of the board of directors and committees thereof. The amount of such compensation has not yet been determined.

In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:


	•	each person who then will beneficially own 5% or more of the then outstanding units;

	•	each director or director nominee of our general partner;

	•	each named executive officer of our general partner; and

	•	all directors and officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power”, which includes the power to vote or to direct the voting of such security, or “investment power”, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.


											Percentage of
											Total
			Percentage of					Percentage of			Common and
	Common		Common			Subordinated		Subordinated			Subordinated
	Units to be		Units to be			Units to be		Units to be			Units to be
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner(1)	Owned		Owned			Owned		Owned			Owned

Quest Resource Corporation		3,551,521		28.9	%		8,857,981		100	%		58.6	%
Jerry D. Cash(2)		—		—			—		—			—
David E. Grose(2)		—		—			—		—			—
David Lawler(2)		—		—			—		—			—
David Bolton(2)		—		—			—		—			—
Steve Hochstein(2)		—		—			—		—			—
Richard Marlin(2)		—		—			—		—			—
Gary Pittman(2)		—		—			—		—			—
Mark Stansberry(2)		—		—			—		—			—
All directors and executive officers as a group (8 persons)		—		—			—		—			—


(1)		Unless otherwise indicated, the address for all beneficial owners in this table is 9520 North May Avenue, Suite 300, Oklahoma City, Oklahoma 73120.

(2)		Does not include up to 437,500 common units that may be purchased in the directed unit program.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, our general partner and its affiliates will own 3,551,521 common units and 8,857,981 subordinated units representing an aggregate 57.5% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Quest Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.


Formation Stage
The consideration received by Quest Resource Corporation and its subsidiaries for the contribution of the assets and liabilities to us		• 3,551,521 common units;
		• 8,857,981 subordinated units;
		• 431,827 general partner units; and
		• the incentive distribution rights.
Payments at or prior to closing		We intend to use the net proceeds of this offering to repay $161.3 million of indebtedness under existing credit facilities of our Parent that are secured by the Partnership Properties. Quest Cherokee, LLC, our principal operating subsidiary, is currently a co-borrower on these credit facilities.
Operational Stage
Distributions of available cash to our general partner and its affiliates		We will generally distribute 98% of our available cash to all unitholders, including affiliates of our general partner (as the holders of an aggregate of 3,551,521 common units and 8,857,981 subordinated units) and 2% of our available cash to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 23% of the distributions above the highest target distribution level.
		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our common units for four quarters, our general partner and its affiliates will receive an annual distribution of approximately $690,923 on their 2% general partner interest and $19.9 million on their common units and subordinated units.

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Payments to our general partner and its affiliates		Our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business, including overhead allocated to our general partner by its affiliates. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. We do not expect to incur any additional fees or to make other payments to these entities in connection with operating our business. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Our Management Services Agreement requires us to reimburse Quest Energy Service for its expenses incurred on our behalf. Please read ‘‘— Agreements Governing the Transactions — Management Services Agreement” below.
Withdrawal or removal of the general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of that interest. Please read ‘‘The Partnership Agreement — Withdrawal or Removal of the General Partner.”
Liquidation Stage
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement. Upon the closing of this offering, we will enter into an omnibus agreement with our Parent that will govern our relationship with it and its subsidiaries with respect to certain matters not governed by the management services agreement.

Under the omnibus agreement, our Parent and its subsidiaries will agree 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. Except as provided

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above, our Parent will not be restricted, under either our partnership agreement or the omnibus agreement, from competing with us and may acquire, construct or dispose of additional gas and oil properties or other assets in the future without any obligation to offer us the opportunity to acquire those assets.

Under the omnibus agreement, our Parent will indemnify us for three years after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of the assets occurring before the closing date of this offering. Additionally, our Parent will indemnify us for losses attributable to title defects (for three years after the closing of this offering), retained assets and income taxes attributable to pre-closing operations (for the applicable statute of limitations). Our Parent’s maximum liability for the environmental indemnification obligations will not exceed $5.0 million and our Parent will not have any indemnification obligation for environmental claims or title defects until our aggregate losses exceed $500,000. Our Parent will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of this offering. We have agreed to indemnify our Parent against environmental liabilities related to our assets to the extent our Parent is not required to indemnify us. We also will indemnify our Parent for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to our Parent’s indemnification obligations.

Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described above, will be terminable by our Parent at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of us or our general partner.

Midstream Services Agreement. Upon completion of this offering, we will become a party to an existing midstream services and gas dedication agreement between our Parent and Quest Midstream pursuant to which Quest Midstream will gather substantially all of the gas from wells operated by us in the Cherokee Basin. Please read “Business — Gas Gathering — Midstream Services Agreement.” The gathering fees payable to Quest Midstream under the midstream services agreement in some cases exceed the amount we are able to charge to royalty owners under our gas leases for gathering and compression. For the six months ended June 30, 2007, we paid approximately $13.2 million to Quest Midstream under the midstream services agreement.

Management Services Agreement. We intend to enter into a management services agreement with Quest Energy Service pursuant to which Quest Energy Service will provide us with legal, information technology, accounting, finance, insurance, tax, property management, engineering, administrative, risk management, corporate development, commercial and marketing, treasury, human resources, audit, investor relations and acquisition services in respect of opportunities for us to acquire long-lived, stable and proved gas and oil reserves.

We will reimburse Quest Energy Service for the reasonable costs of the services it provides to us. The employees of Quest Energy Service will also manage the operations of our Parent and Quest Midstream and will be reimbursed by our Parent and Quest Midstream for general and administrative services incurred on their respective behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to Quest Energy Service by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Our general partner has the right and the duty to review the services provided, and the costs charged, by Quest Energy Service under the management services agreement. Our general partner may in the future cause us to hire additional personnel to supplement or replace some or all of the services provided by Quest Energy Service, as well as employ third-party service providers. If we were to take such actions, they could increase the overall costs of our operations.

The management services agreement is not terminable by us without cause so long as our Parent controls our general partner. Thereafter, the agreement is terminable by either us or Quest Energy Service upon six months’ notice. The management services agreement is terminable by us or our Parent upon a material breach

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of the agreement by the other party and failure to remedy such breach for 60 days (or 30 days in the event of nonpayment) after receiving notice of the breach.

Quest Energy Service will not be liable to us for its performance of, or failure to perform, services under the management services agreement unless its acts or omissions constitute gross negligence or willful misconduct. Please read “Management — Reimbursement of Expenses of Our General Partner.”

Midstream Omnibus Agreement. In addition, as of the closing of the offering, we will be subject to the midstream omnibus agreement dated as of December 22, 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.

The midstream omnibus agreement will restrict us from engaging in the following businesses (each of which is referred to in this prospectus as a “Restricted Business”):


	•	the gathering, treating, processing and transporting of gas in North America;

	•	the transporting and fractionating of gas liquids in North America;

	•	any other midstream activities, including but not limited to crude oil storage, transportation, gathering and terminaling;

	•	constructing, buying or selling any assets related to the foregoing businesses; and

	•	any line of business other than those described in the preceding bullet points that generates “qualifying income”, within the meaning of Section 7704(d) of the Code, other than any business that is primarily engaged in the exploration for and production of oil or gas and the sale and marketing of gas and oil derived from such exploration and production activities.

If a business described in the last bullet point above has been offered to Quest Midstream and it has declined the opportunity to purchase that business, then that line of business is no longer considered a Restricted Business.

The following are not considered a Restricted Business —


	•	the ownership of a passive investment of less than 5% in an entity engaged in a Restricted Business;

	•	any business in which Quest Midstream permits us to engage;

	•	the ownership or operation of assets used in a Restricted Business if the value of the assets is less than $4 million; and

	•	any business that we have given Quest Midstream the option to acquire and it has elected not to purchase.

Subject to certain exceptions, if we were to acquire any midstream assets in the future pursuant to the above provisions, then Quest Midstream will have a preferential right to acquire those midstream assets in the event of a sale or transfer of those assets by us.

If we acquire any acreage located outside the Cherokee Basin that is not subject to any existing agreement with an unaffiliated party to provide midstream services, Quest Midstream will have a preferential right to offer to provide midstream services to us in connection with wells to be developed by us on that acreage.

Contribution, Conveyance and Assumption Agreement. We intend to enter into a contribution, conveyance and assumption agreement to effect, among other things, the transfer of the assets, liabilities and operations of our Parent located in the Cherokee Basin (other than its midstream assets) to us at the closing of this offering, the issuance of 3,551,521 common units and 8,857,981 subordinated units to our Parent and the issuance to our general partner of 431,827 general partner units and the incentive distribution rights. We will indemnify our Parent for liabilities arising out of or related to existing litigation relating to the assets, liabilities and operations located in the Cherokee Basin transferred to us.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including our Parent and Quest Midstream) on the one hand, and our partnership and our limited partners, on the other hand. In addition, the directors and officers of our general partner serve in similar capacities for our Parent and some of its affiliates. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

As required by our partnership agreement, the board of directors of our general partner will maintain a conflicts committee, comprised of at least two independent directors. Our general partner may, but is not required to, seek the approval of the resolution of the conflict of interest from the conflicts committee of its board of directors.

Our general partner is responsible for identifying any such conflict of interest and our general partner may choose to resolve the conflict of interest by any one of the methods described in the following sentence. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:


	•	approved by the conflicts committee, which approval may be granted in advance of a known conflict, if such approval is contingent upon compliance with pre-approved, documented guidelines and procedures, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates, although our general partner is not obligated to seek such approval;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest with our general partner or its affiliates is fair and reasonable to us. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. If a matter is submitted to the conflicts committee and the conflicts committee does not approve the matter, we will not proceed with the matter unless and until the matter has been modified in such a manner that the conflicts committee determines is fair and reasonable to us. If our general partner does not seek approval from the conflicts committee, the board of directors of our general partner may adopt a resolution with respect to a conflict of interest provided that interested directors have recused themselves from participation. If the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the

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conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he or she is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Our general partner’s affiliates may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Under the omnibus agreement, our Parent and its subsidiaries have agreed not to engage in the businesses described under “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Omnibus Agreement”, subject to certain limitations. Except as provided in our partnership agreement and the omnibus agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Immediately after the closing of this offering, our Parent will have gas and oil leases covering approximately 16,500 net acres in New Mexico, Pennsylvania and Texas. There are currently no proved reserves associated with these properties. As discussed in “Business — Our Relationship with Our Parent,” on October 15, 2007, our Parent entered into a Merger Agreement to acquire Pinnacle. Pinnacle’s assets are in Montana and Wyoming, and as of June 30, 2007, Pinnacle owned natural gas and oil leasehold interests in approximately 478,000 gross (332,000 net) acres, approximately 94% of which were undeveloped. Our Parent may acquire, develop or dispose of additional gas or oil properties or other assets outside of the Cherokee Basin in the future, without any obligation to offer us the opportunity to purchase or develop 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.

Neither our partnership agreement nor any other agreement requires our Parent to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Our Parent’s directors have a fiduciary duty to make these decisions in the best interests of the owners of our Parent, which may be contrary to our interests.

Because certain of the directors of our general partner are also directors and/or officers of our Parent, such directors have fiduciary duties to our Parent that may cause them to pursue business strategies that disproportionately benefit our Parent or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as our Parent, in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its right to make a determination to receive Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

We do not have any officers and rely solely on officers of our general partner and employees of Quest Energy Service, LLC and its affiliates for the management of our business.

We will rely upon officers of our general partner and employees of affiliates of our general partner to manage our business. We intend to enter into a management services agreement with Quest Energy Service, LLC. Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be

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material competition for the time and effort of the officers and employees who provide services to our general partner. The officers and employees of our general partner are not required to work full time on our affairs. In addition, certain of the officers of our general partner, including the chief executive officer and chief financial officer, will also serve as officers of affiliates of the general partner.

Our partnership agreement limits the liability of our general partner, reduces its fiduciary duties, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, our Parent. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:


	•	permits our general partner to make a number of decisions either in its individual capacity, as opposed to in its capacity as our general partner or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner. Examples include:


	•	its right to reset the target distribution levels of its incentive distribution rights at higher levels and receive, in connection with this reset, a number of Class B units that are convertible at any time following the first anniversary of the issuance of these Class B units into common units;

	•	its limited call right;

	•	its rights to vote and transfer the units it owns;

	•	its registration rights; and

	•	its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;


	•	provides that the general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by the general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable”, our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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If you purchase any common units, you will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith”, our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


	•	the manner in which our business is operated;

	•	amount and timing of asset purchases and sales;

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	•	cash expenditures;

	•	borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

In addition, our general partner may use an amount equal to $25.9 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and the general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by the general partner to our unitholders, including borrowings that have the purpose or effect of:


	•	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

	•	hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permit us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “How We Make Cash Distributions — Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, Quest Cherokee, or its operating subsidiaries.

Our general partner determines which costs incurred by our Parent and its affiliates are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing

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with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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 our unitholders. This ability may result in lower distributions to our common unitholders 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 (23%) 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 a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and 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

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per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be 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 specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. 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. Please read “How We Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal

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		action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and nonappealable judgment by a court of competent jurisdiction determining that the general partner or the officers and directors of our general partner acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the indemnitee’s conduct was unlawful.

		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

		If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

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By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and the officers, directors, and managers of our general partner and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and nonappealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to unitholders under our partnership agreement. For a description of the rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section, “How We Make Cash Distributions” and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of unitholders under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. Computershare Trust Company, N.A. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:


	•	represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

	•	gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

If we become subject to U.S. laws with respect to the ownership of 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. In such event, transferees will be required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to certify, that the unitholder is an Eligible Holder. As of the date hereof, an Eligible Holder means a person or entity qualified to hold an interest in gas and oil leases on federal lands. As used herein, an Eligible Holder means: (1) a citizen of the

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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. For the avoidance of doubt, 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.

In such event, if a transferee fails to furnish a transfer application containing the required certification, a certification within 30 days after request or provides a false certification, then such transfer will be void or we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder at the then-current market price of the units. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights. The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 7% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in this prospectus. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “How We Make Cash Distributions”;

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

	•	with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was formed in July 2007 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than acquisition, exploitation and development of oil and gas properties, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Please also read “Certain Relationships and Related Party Transactions — Agreements Governing the Transactions — Midstream Omnibus Agreement” for a description of certain restrictions on our ability to engage in other business activities.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “— Amendment of the Partnership Agreement.”

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Cash Distributions.”

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately 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 will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:


	•	during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and the approval of a majority of the outstanding subordinated units, voting as separate classes; and

	•	after the subordination period, the approval of a majority of the outstanding common units and Class B units, if any, voting as a single class.

In voting their common, Class B and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.


Issuance of additional common units		No approval right. Please read “— Issuance of Additional Securities.”

Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of a majority of our outstanding units. Please read “— Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution.”

Continuation of our business upon dissolution		Unit majority. Please read “— Termination and Dissolution.”

Withdrawal of the general partner		Under most circumstances, the approval of a majority of the units, excluding units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2017 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”

Removal of the general partner		Not less than 662/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”

Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to

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		an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the units, excluding units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2017. Please read “— Transfer of General Partner Units.”

Transfer of incentive distribution rights		Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2017. Please read “— Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in the general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:


	•	to remove or replace our general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

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Our subsidiaries conduct business in Kansas and Oklahoma and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our member interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities that may effectively rank senior to our common units.

Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately 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 will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

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Amendment of the Partnership Agreement

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below under “— No Unitholder Approval”, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:


	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of this offering, our general partner and its affiliates will own approximately 58.6% of our outstanding common and subordinated units.

No Unitholder Approval. Our general partner generally may make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:


	•	a change in our name, the location of our principal place of business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	•	a change that our general partner determines to be necessary or appropriate to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating company nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:


	•	the adjustments of the minimum quarterly distribution, first target distribution and second target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “How We Make Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels;” or

	•	the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and

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	•	any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;


	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	•	a change in our fiscal year or taxable year and related changes;

	•	conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

	•	any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect our limited partners (or any particular class of limited partners) in any material respect;

	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes in connection with any amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to our partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

	•	the entry of a decree of judicial dissolution of our partnership; or

	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither our partnership, our operating company nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

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Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to our partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2017 without obtaining the approval of a majority of our outstanding common units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Units” and “— Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of our outstanding units voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units and Class B units, if any, voting as a separate class, and subordinated units, voting as a separate class, including those held by our general partner and its affiliates. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner, its owners and their affiliates will own approximately 58.6% of the outstanding common and subordinated units (prior to giving effect to any purchases by management or directors of our general partner or our Parent in our directed unit program).

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

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In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for the transfer by our general partner of all, but not less than all, of its general partner units in us to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner units to another person prior to December 31, 2017 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, our Parent, as the sole member of our general partner, may sell or transfer all or part of its ownership interest in the general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to December 31, 2017, other transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2017, the incentive distribution rights will be freely transferable.

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Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group other than our general partner, our Parent and their affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the average of the closing prices for the 20 trading days ending as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

The general partner’s right to purchase common units pursuant to this limited call right will be subject to the general partner’s compliance with applicable securities and other laws.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by

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holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes except such units may be considered to be outstanding for purposes of the withdrawal of our general partner. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and Class B units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability” above, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Eligible Holders; Redemption


	•	a citizen of the United States;

	•	a corporation organized under the laws of the United States or of any state thereof;

	•	a public body, including a municipality; or

	•	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.

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For the avoidance of doubt, 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. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If we become subject to U.S. laws with respect to the ownership interests in oil and gas leases on federal lands, and a transferee or unitholder, as the case may be, fails to furnish:


	•	a transfer application containing the required certification, or

	•	a certification within 30 days after request,

then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder at the then-current market price of the units. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights.

The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 7% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of or owner of an equity interest in a general partner or any departing general partner;

	•	any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in the preceding three bullet points;

	•	any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine the expenses that are allocable to us.

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Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition (our general partner can satisfy this requirement by furnishing to the limited partner upon his request our most recent Form 10-K and any subsequent filings on Form 10-Q and Form 8-K); and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner, our Parent, our officers and directors or any of their respective affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and structuring fees. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, and our Parent will hold 3,551,521 common units and 8,857,891 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

Our Parent, our partnership, our general partner and the directors and executive officers of our general partner and our Parent have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material United States federal income tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Stinson Morrison Hecker LLP, counsel to our general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Quest Energy Partners, L.P. and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or prospective unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (“IRAs”), real estate investment trusts (“REITs”) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Stinson Morrison Hecker LLP and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions and advice of Stinson Morrison Hecker LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this summary may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Stinson Morrison Hecker LLP has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); (3) whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read “— Tax Treatment of Operations — Depletion Deductions”); (4) whether the deduction related to U.S. production activities will be available to a unitholder or the extent of any such deduction to any unitholder (please read “— Tax Treatment of Operations — Deduction for United States Production Activities”); and (5) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception”, exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, production, marketing, transportation, storage and processing of natural resources including gas, crude oil and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Stinson Morrison Hecker LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our classification as a partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Stinson Morrison Hecker LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and the operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Stinson Morrison Hecker LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Stinson Morrison Hecker LLP has relied are:


	•	Neither we, nor the operating company has elected or will elect to be treated as a corporation; and

	•	For each taxable year, more than 90% of our gross income will be income that Stinson Morrison Hecker LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net earnings would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Stinson Morrison Hecker LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

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Limited Partner Status

Unitholders who have become limited partners of Quest Energy Partners, L.P. will be treated as partners of Quest Energy Partners, L.P. for federal income tax purposes. Also:


	•	assignees who are awaiting admission as limited partners, and

	•	unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units

will be treated as partners of Quest Energy Partners, L.P. for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Items of our income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Quest Energy Partners, L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year or years ending with or within his taxable year. Please read “— Tax Treatment of Operations — Taxable Year and Accounting Method.”

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as “nonrecourse liabilities”, will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables”, including depreciation recapture, and/or substantially appreciated “inventory items”, both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ended December 31, 2010, will be allocated, on a cumulative basis, an amount of

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federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2010 the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than our estimate, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distribution on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for federal income tax purposes or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder’s at risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of

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the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the basis of that property.

The at risk limitation applies on an activity-by-activity basis, and in the case of gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer’s interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at risk amount for that property and not the at risk amount for all the taxpayer’s gas and oil properties. It is uncertain how this rule is implemented in the case of multiple gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a unitholder’s at risk limitation with respect to us. If a unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he may not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at risk amount with respect to his units as a whole.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or a unitholder’s salary or active business income. If we dispose of all or only a part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Notwithstanding whether a gas and oil property is a separate activity, passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net earnings may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are

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authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. Gross income may also be allocated to holders of subordinated units after the close of the subordination period to the extent necessary to give them economic rights at liquidation identical to the rights of common units. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

For tax purposes, we are required to adjust the “book” basis of all assets contributed to us by our general partner and its affiliates, referred to below as “Contributed Property”, to their fair market values at the time this offering closes. We are further required to adjust this book basis for each asset in proportion to tax depreciation or amortization we later claim with respect to the asset. Section 704(c) principles set forth in Treasury regulations require that subsequent allocations of depreciation, gain, loss and similar items with respect to the asset take into account, among other things, the difference between the “book” and tax basis of the asset. In this context, we use the term “book” as that term is used in Treasury regulations relating to partnership allocations for tax purposes. The “book” value of our property for this purpose may not be the same as the book value of our property for financial reporting purposes.

For example, a substantial portion of our Contributed Property will be depletable property with a “book” basis in excess of its tax basis. Section 704(c) principles generally will require that depletion with respect to each such property be allocated disproportionately to purchasers of common units in this offering and away from our general partner and its affiliates. To the extent these disproportionate allocations do not produce a result to holders of common units similar to that which would be the case if all of our initial assets had a tax basis equal to their “book” basis on the date this offering closes, purchasers of common units in this offering will be allocated the additional tax deductions needed to produce that result as to any asset with respect to which we elect the “remedial method” of taking into account the difference between the “book” and tax basis of the asset.

In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) allocations”, similar to the Section 704(c) allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis and the fair market value of all property held by us at the time of the future transaction.

In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by unitholders that did not receive the benefit of such deduction. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required under Section 704(c) principles, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic

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effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Stinson Morrison Hecker LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election”, “— Uniformity of Units” and “— Disposition of Common Units — Allocations Between Transferors and Transferees”, allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s (unitholder’s) share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and all of these distributions would appear to be ordinary income.

Stinson Morrison Hecker LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest United States federal income tax rate for individuals is currently 35% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

The timing of deductions attributable to Section 743(b) adjustments to our common basis will depend upon a number of factors, including the nature of the assets to which the adjustment is allocable, the extent to which the adjustment offsets any Section 704(c) type gain or loss with respect to an asset and certain elections we make as to the manner in which we apply Section 704(c) principles with respect to an asset to which the adjustment is applicable. Please read “— Allocation of Income, Gain, Loss and Deduction.” The timing of these deductions may affect the uniformity of our units. Please read “— Uniformity of Units.”

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A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Taxable Year and Accounting Method. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year different from our taxable year and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Depletion Deductions. Subject to the limitations on deductibility of losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our gas and oil interests. Although the Internal Revenue Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s daily production of domestic crude oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between gas and oil production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

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In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for Intangible Drilling and Development Costs. We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

Although we will elect to currently deduct IDCs, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of gas) on average for any day during the taxable year or in the retail marketing of gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon

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the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Deduction for United States Production Activities. Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the “Section 199 deduction”, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 6% for qualified production activities income generated in the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read “— Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders. Moreover, legislation has been proposed that would deny the Section 199 deduction with respect to certain oil and gas production activities income. We are unable to predict whether this proposed legislation or any other changes will ultimately be enacted.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs. The cost of acquiring gas and oil leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “— Tax Treatment of Operations — Depletion Deductions.”

Geophysical Costs. The cost of geophysical exploration incurred in connection with the exploration and development of gas and oil properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.

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Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses which are reasonable in amount.

Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner and its affiliates. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Part or all of the goodwill, going concern value and other intangible assets we acquire in connection with this offering may not produce any amortization deductions, either because of the application of the “anti-churning” restrictions of Section 197 or because our general partner determines not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of such property immediately prior to this offering. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

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Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract

with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

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The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Stinson Morrison Hecker LLP is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Transfer Notification Requirements. A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A unitholder who acquires units generally is required to notify us in writing of that acquisition within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year different from our taxable year, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. Please read “— Tax Treatment of Operations — Taxable Year and Accounting Method.” We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. Any non-uniformity could have a negative impact on the value of the units. The timing of deductions attributable to Section 743(b) adjustments to the common basis of our assets with respect to persons purchasing units after this offering may affect the uniformity of our units. Please read “— Tax Consequences of Unit Ownership — Section 754 election.” For example, we may not elect the remedial allocation method under Section 704(c) principles with respect to certain of our intangible assets (please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction”), and it is possible that we own, or will acquire, certain assets that are not subject to the typical rules governing depreciation (under Section 168 of the Internal Revenue Code) or amortization (under Section 197 of the Internal Revenue Code) of assets. Any or all of these factors could cause the timing of a purchaser’s deductions to differ, depending on when the unit he purchased was issued.

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units even under circumstances like those described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Our counsel, Stinson Morrison Hecker LLP, is unable to opine as to validity of such filing positions. A unitholder’s basis in units is reduced by his or her share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any

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position that we take that understates deductions will overstate the unitholder’s basis in his or her common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, nonresident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from certain permitted sources. Income derived from the ownership of an interest in a “qualified publicly traded partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.

Nonresident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net earnings or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity”, which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that

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those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Stinson Morrison Hecker LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names our Parent as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	•	the name, address and taxpayer identification number of the beneficial owner and the nominee;

	•	whether the beneficial owner is:


	•	a person that is not a United States person;

	•	a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

	•	a tax-exempt entity;


	•	the amount and description of units held, acquired or transferred for the beneficial owner; and

	•	specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an

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underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	•	for which there is, or was, “substantial authority;” or

	•	as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules apply to “tax shelters”, but we believe we are not a tax shelter.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions. If we were to engage in a “reportable transaction”, we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-related Penalties”,

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We initially will own property or conduct business in Kansas and Oklahoma. We may also own property or conduct business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from those jurisdictions falls below the filing and payment requirements, you will be required to file income tax returns and to pay income taxes in many of the jurisdictions in which we do conduct or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses

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may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Stinson Morrison Hecker LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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SELLING UNITHOLDER

If the underwriters exercise all or any portion of their over-allotment option, we will issue up to 1,312,500 additional common units, and we will redeem an equal number of units from our Parent, who may be deemed to be a selling unitholder in this offering. The redemption price per common unit will be equal to the price per common unit (net of underwriting discounts and a structuring fee) sold to the underwriters upon exercise of their option. The structuring fee is equal to 0.5% of the gross proceeds of this offering including any exercise of the underwriters’ over-allotment option and will be paid to Wachovia Capital Markets, LLC for its assistance in the evaluation, analysis and structuring of our partnership and this offering.

The following table sets forth information concerning the ownership of common and subordinated units by our Parent. The numbers in the table are presented assuming:


	•	the underwriters’ over-allotment option is not exercised; and

	•	the underwriters exercise their option to purchase additional units in full.

Units Owned Immediately

Units Owned

After Exercise of

Immediately After

Underwriters’ Option and

this Offering

Related Unit Redemption

Assuming

Underwriters’

Option is

Exercised

Name of Selling Unitholder

Not Exercised

Percent(1)

in Full

Percent(1)

Quest Resource Corporation

Common units

3,551,521

16.5

2,239,021

10.4

Subordinated units

8,857,981

41.0

8,857,981

41.0


(1)		Percentage of total units outstanding, including common units, subordinated units and general partner units.

(2)		Jerry D. Cash, William Damon, John C. Garrison, James B. Kite, Jr., Malone Mitchell and Jon H. Rateau are members of the Board of Directors of our Parent, and the Board of Directors of our Parent approved on behalf of our Parent the agreement pursuant to which we may redeem up to 1,312,500 common units from our Parent.

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INVESTMENT IN QUEST ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities (i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable, and registered under some provisions of the federal securities laws);

(b) the entity is an “operating company”, (i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries); or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Subject to the terms and conditions of the underwriting agreement between us and the underwriters, the underwriters have agreed severally to purchase from us the following number of common units at the offering price less the underwriting discount set forth on the cover page of this prospectus.


	Number of
Underwriters	Common Units

Wachovia Capital Markets, LLC
RBC Capital Markets Corporation
Friedman, Billings, Ramsey & Co., Inc.
Oppenheimer & Co. Inc.
Stifel, Nicolaus & Company, Incorporated
Wells Fargo Securities, LLC

		8,750,000

The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions and that the underwriters will purchase all such common units if any of the common units are purchased. The underwriters are obligated to take and pay for all of the common units offered by this prospectus, other than those covered by the over-allotment option described below, if any are taken.

The underwriters have advised us that they propose to offer the common units to the public at the offering price set forth on the cover page of this prospectus and to certain dealers at such price less a selling concession not in excess of $ per common unit. The underwriters may allow, and such dealers may re-allow, a concession not in excess of $ per common unit to certain other dealers. After the offering, the offering price and other selling terms may be changed by the underwriters, but any such changes will not affect the net proceeds to be received by us in the offering.

Option to Purchase Additional Units. Pursuant to the underwriting agreement, we have granted to the underwriters an option, exercisable in whole or in part for 30 days after the date of this prospectus, to purchase up to 1,312,500 additional common units at the offering price, less the underwriting discount set forth on the cover page of this prospectus, solely to cover over-allotments.

To the extent the underwriters exercise such option, the underwriters will become obligated, subject to certain conditions, to purchase approximately the same percentage of such additional units as the number set forth next to such underwriter’s name in the preceding table bears to the total number of units in the table, and we will be obligated, pursuant to the option, to sell such units to the underwriters.

Lock-Up Agreements. We, our general partner, our Parent, the directors and executive officers of our general partner and our Parent have agreed that during the 180 days after the date of this prospectus, we and they will not, without the prior written consent of Wachovia Capital Markets, LLC, directly or indirectly, offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units within the time period of the lock-up, other than (1) pursuant to employee benefit plans as in existence as of the date of this prospectus, (2) to affiliates, (3) in connection with accretive acquisitions of assets or businesses in which common units are issued as consideration, or (4) in connection with the over-allotment option; provided, however, any such recipient of common units will furnish to Wachovia Capital Markets, LLC a letter agreeing to be bound by these provisions for the remainder of the 180-day period. Notwithstanding the foregoing, if (1) during the last 17 days of the 180-day period, we issue an earnings release or material news or a material event relating to us occurs; or (2) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, the “lock-up” restrictions described above shall continue to apply until the expiration of the 180-day period beginning on the issuance of the earnings release or the occurrence of the

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material news or material event. Wachovia Capital Markets, LLC may, in its sole discretion, allow any of these parties to offer for sale, contract to sell, sell, distribute, grant any option, right or warrant to purchase, pledge, hypothecate, enter into any derivative transaction with similar effect as a sale or otherwise dispose of any common units, any securities convertible into, or exercisable or exchangeable for, common units or any other rights to acquire such common units prior to the expiration of such 180-day period in whole or in part at anytime without notice. Wachovia Capital Markets, LLC has informed us that in the event that consent to a waiver of these restrictions is requested by us or any other person, Wachovia Capital Markets, LLC, in deciding whether to grant its consent, will consider the unitholder’s reasons for requesting the release, the number of units for which the release is being requested and market conditions at the time of the request for such release. However, Wachovia Capital Markets, LLC has informed us that as of the date of this prospectus there are no agreements between Wachovia Capital Markets, LLC and any party that would allow such party to transfer any common units, nor does it have any intention of releasing any of the common units subject to the lock-up agreements prior to the expiration of the lock-up period at this time.

IPO Pricing. Prior to this offering, there has been no public market for the common units. The initial public offering price will be determined by negotiation between us and the underwriters. The principal factors that will be considered in determining the public offering price include the following:


	•	the information set forth in this prospectus and otherwise available to the underwriters;

	•	market conditions for initial public offerings;

	•	the history and the prospects for the industry in which we compete;

	•	the ability of our management;

	•	our prospects for future earnings;

	•	the present state of our development and our current financial condition;

	•	the general condition of the securities markets at the time of this offering; and

	•	the recent market prices of, and the demand for, publicly traded common units of generally comparable entities.

Discounts and Commissions. The following table summarizes the discounts that we will pay to the underwriters in connection with the offering, including a financial advisory fee for evaluation, analysis and structuring of our partnership and this offering. Wachovia Capital Markets, LLC will earn 0.5% of the gross proceeds of the offering, including any exercise of the underwriters’ over-allotment option, for financial advisory services rendered to us. The Financial Industry Regulatory Authority, or the FINRA (formerly known as the National Association of Securities Dealers, Inc., or NASD), considers this fee to represent compensation earned in connection with this offering. The amounts below assume both no exercise and full exercise of the underwriters’ over-allotment option.


	No Exercise	Full Exercise

Per common unit	$	$

Total	$	$

We estimate that total expenses of this offering, other than underwriting discounts and commissions, will be approximately $1.5 million.

Indemnification. We, our general partner and our Parent have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments that may be required with respect to these liabilities.

Stabilization. Until the distribution of the common units is completed, rules of the SEC may limit the ability of the underwriters and certain selling group members to bid for and purchase the common units. As an exception to these rules, the underwriters are permitted to engage in certain transactions that stabilize, maintain or otherwise affect the price of the common units.

197

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate-covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.

	•	Syndicate-covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, resulting in a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate-covering transaction to cover syndicate short positions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Market or otherwise.

The underwriters will deliver a prospectus to all purchasers of common units in the short sales. The purchasers of common units in short sales are entitled to the same remedies under the federal securities laws as any other purchaser of common units covered by this prospectus.

The underwriters are not obligated to engage in any of the transactions described above. If they do engage in any of these transactions, they may discontinue them at any time.

Directed Unit Program. At our request, the underwriters are reserving up to 437,500 common units for sale at the initial public offering price to directors, officers, employees, family members of directors, officers and employees, business associates and other third parties through a directed unit program. We do not know if our directors, officers, employees, family members of directors, officers and employees, business associates and other third parties will choose to purchase all or any portion of the reserved units, but any purchases they do make will reduce the number of common units available to the general public. Any common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered by this prospectus.

Neither we nor the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor the underwriters make any representation that the underwriters will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

198

Because the FINRA views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules (which are part of the FINRA rules). Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

No sales to accounts over which any underwriter exercises discretionary authority may be made without the prior written approval of the customer.

Electronic Prospectuses. A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters participating in this offering. Other than the prospectus in electronic format, the information on any such website, or accessible through such website, is not part of the prospectus.

Conflicts/Affiliates. Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us, our Parent and its affiliates. They have received customary fees and commissions for these transactions. Royal Bank of Canada, an affiliate of RBC Capital Markets Corporation, is the administrative agent and a lender under Quest Midstream’s credit facility and will be the administrative agent and a lender under our new credit facility and the new credit facility of our Parent to be entered into as of the closing of this offering. RBC Capital Markets Corporation acted as the lead arranger and sole bookrunner for Quest Midstream’s credit facility and will act as the lead arranger and sole bookrunner for our new credit facility and the new credit facility of our Parent. Affiliates of Wells Fargo Securities, LLC are lenders under Quest Midstream’s credit facility and our Parent’s credit facilities. Affiliates of the underwriters may become a party to the syndicate of lenders under our new credit facility upon the closing of this offering.

199

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Stinson Morrison Hecker LLP, Kansas City, Missouri. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The carve out financial statements of Quest Energy Partners Predecessor as of December 31, 2005 and 2006 and for the fiscal year ended May 31, 2004, the seven months ended December 31, 2004 and the years ended December 31, 2005 and 2006 included in this prospectus have been audited by Murrell, Hall, McIntosh & Co., PLLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the restatement discussed in Note 19) and elsewhere in the registration statement, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The information included in this prospectus as of May 31, 2004, December 31, 2004, 2005 and 2006 and June 30, 2007, relating to our estimated quantities of gas and oil reserves, is derived from reserve reports prepared by Cawley, Gillespie & Associates, Inc., of Ft. Worth, Texas. This information is included in this prospectus in reliance upon this firm as an expert in matters contained in the reports.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

200

QUEST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Introduction

The following unaudited pro forma financial statements of Quest Energy Partners, L.P. (the “Partnership”) as of June 30, 2007 and for the year ended December 31, 2006 and the six months ended June 30, 2007 are based on the historical balance sheet and results of operations of Quest Energy Partners, L.P. Predecessor (the “Predecessor”). The unaudited pro forma financial statements of the Partnership have been derived from the historical financial statements of the Predecessor included elsewhere in this prospectus and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. The unaudited pro forma financial statements should be read in conjunction with the accompanying notes and with the historical financial statements and related notes of the Predecessor.

The unaudited pro forma financial statements reflect the following transactions:


	•	the contribution by Quest Resource Corporation of its Cherokee Basin gas and oil leases and related equipment to the Partnership (the “Partnership Properties”);

	•	the issuance by the Partnership to Quest Energy GP, LLC (the “General Partner”) of 431,827 general partner units representing its initial 2.0% general partner interest in the Partnership, and all of the incentive distribution rights, which incentive distribution rights will entitle the General Partner to increasing percentages of the cash the Partnership distributes in excess of $0.46 per unit per quarter;

	•	the Partnership’s issuance to Quest Resource Corporation of 3,551,521 common units and 8,857,981 subordinated units, representing an aggregate 57.5% limited partner interest in the Partnership;

	•	the Partnership’s issuance of 8,750,000 common units to the public in a public offering, representing an aggregate 40.5% limited partner interest in the Partnership;

	•	the Partnership’s borrowing of $75.0 million under the Partnership’s new credit facility;

	•	the repayment of indebtedness under existing credit facilities of Quest Resource Corporation that are secured by the Partnership Properties using the net proceeds of the 8,750,000 common unit public offering and the borrowings of $75.0 million under the Partnership’s new credit facility;

	•	the Partnership’s entry into an Omnibus Agreement with Quest Resource Corporation and the General Partner, which will address, among other things, the provision of, and the reimbursement for, general and administrative and operating services and indemnification matters;

	•	the Partnership’s entry into a Management Services Agreement with Quest Energy Service, LLC, which will provide for the provision of, and the reimbursement for, general and administrative, operating and acquisition services; and

	•	the Partnership becoming a party to the Midstream Services and Gas Dedication Agreement dated as of December 22, 2006, but effective as of December 1, 2006, between Bluestem Pipeline, LLC and Quest Resource Corporation, pursuant to which Bluestem Pipeline, LLC will provide gathering, dehydration, treating and compression services to the Partnership in exchange for contracted fees.

The unaudited pro forma balance sheet and results of operations were derived by adjusting the historical financial statements of the Predecessor to reflect the above transactions. The adjustments are based on currently available information and certain estimates and assumptions; therefore, the actual effect of the above transactions will differ from pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma financial information.

F-2

QUEST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA BALANCE SHEET
JUNE 30, 2007


	Predecessor			Pro Forma				Partnership
	Historical			Adjustments				Pro Forma
	(In thousands)

ASSETS
Current assets:
Cash	$	9,980		$	175,000	(a)		$	5,905
					75,000	(b)
					(235,000	)(c	)
					(13,700	)(d	)
					(5,375	)(e	)
Restricted cash		1,160							1,160
Accounts receivable, trade		12,442							12,442
Other receivables		1,509							1,509
Inventory		5,563							5,563
Other current assets		1,644							1,644
Short-term derivative asset		6,302							6,302

Total current assets		38,600			(4,075	)			34,525
Property and equipment, net of accumulated depreciation of $5,340		18,150							18,150
Oil and gas properties:
Properties being amortized		359,705							359,705
Properties not being amortized		12,390							12,390

		372,095							372,095
Less: Accumulated depreciation, depletion, amortization and impairment		(106,646	)						(106,646	)

Net property, plant and equipment		265,449							265,449
Other assets, net		10,016			(9,778	)(e	)		238
Long-term derivative asset		1,843							1,843

Total assets	$	334,058		$	(13,853	)		$	320,205


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	15,182		$				$	15,182
Revenue payable		7,063							7,063
Accrued expenses		1,138							1,138
Current portion of notes payable		179							179
Short-term derivative liability		6,814							6,814

Total current liabilities		30,376							30,376

Non-current liabilities:
Long-term derivative liability		4,198							4,198
Asset retirement obligation		1,546							1,546
Notes payable		235,270			(235,000	)(c	)		75,270
					75,000	(b)
Less: current maturities		(179	)						(179	)

Total non-current liabilities		240,835			(160,000	)			80,835

Total liabilities		271,211			(160,000	)			111,211

Commitments and contingencies		—			—				—
Partners’ capital:
Partners’ capital		67,987			(67,987	)(f	)
Common units — public					175,000	(a)			155,159
					(13,700	)(d	)
					(6,141	)(e	)
Common units — Quest Resource Corporation					(2,492	)(e	)		16,311
					18,803	(f)
Subordinated units — Quest Resource Corporation					(6,217	)(e	)		40,681
					46,898	(f)
General partner interest — Quest Energy GP, LLC					(303	)(e	)		1,983
					2,286	(f)
Accumulated other comprehensive income		(5,140	)		—				(5,140	)

Total partners’ capital		62,847			146,147				208,994

Total liabilities and partners’ capital	$	334,058		$	(13,853	)		$	320,205

See accompanying notes to unaudited pro forma financial statements.

F-3

QUEST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2006


	Predecessor			Pro Forma			Partnership
	Historical			Adjustments			Pro Forma
	(In thousands, except per unit data)

Revenues:
Oil and gas sales	$	65,551		$			$	65,551
Other revenue/(expense)		(83	)					(83	)

Total revenues		65,468						65,468
Costs and expenses:
Oil and gas production		21,208						21,208
Transportation expense		17,278			2,606	(g)		19,884
General and administrative expenses		8,149						8,149
Depreciation, depletion and amortization		25,521						25,521
Provision for impairment of gas and oil properties		30,719						30,719

Total costs and expenses		102,875			2,606			105,481

Operating income (loss)		(37,407	)		(2,606	)		(40,013	)

Other income (expense):
Change in derivative fair value		6,410						6,410
(Loss)/gain on sale of assets		(7	)					(7	)
Interest expense		(16,935	)		16,872	(h)		(6,063	)
					(6,000	)(i)

Interest income		390						390

Total other income (expense)		(10,142	)		10,872			730

Net income (loss)	$	(47,549	)	$	8,266		$	(39,283	)

General partner’s interest in net income (loss)							$	(786	)

Limited partners’ interest in net income (loss)							$	(38,497	)

Net income (loss) per limited partner unit							$	(1.66	)

Weighted average number of limited partner units outstanding								23,160

See accompanying notes to unaudited pro forma financial statements.

F-4

QUEST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2007


	Predecessor			Pro Forma			Partnership
	Historical			Adjustments			Pro Forma
	(In thousands, except per unit data)

Revenues:
Oil and gas sales	$	53,416		$			$	53,416
Other revenue/(expense)		(32	)					(32	)

Total revenues		53,384						53,384
Costs and expenses:
Oil and gas production		14,967						14,967
Transportation expense		13,170						13,170
General and administrative expenses		5,846						5,846
Depreciation, depletion and amortization		14,063						14,063

Total costs and expenses		48,046						48,046

Operating income (loss)		5,338						5,338

Other income (expense):
Change in derivative fair value		(185	)					(185	)
Gain/(loss) on sales of assets		(197	)					(197	)
Interest expense		(14,160	)		14,138	(h)		(3,022	)
					(3,000	)(i)

Interest income		280						280

Total other income (expense)		(14,262	)		11,138			(3,124	)

Net income (loss)	$	(8,924	)	$	11,138		$	2,214

General partner’s interest in net income (loss)							$	44

Limited partners’ interest in net income (loss)							$	2,170

Net income (loss) per limited partner unit							$	0.09

Weighted average number of limited partner units outstanding								23,160

See accompanying notes to unaudited pro forma financial statements.

F-5

QUEST ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS


1.	Basis of Presentation

The unaudited pro forma financial statements have been prepared based upon historical financial information of the Predecessor, giving effect to the transactions described in the Introduction to these unaudited pro forma financial statements and other related adjustments described in these footnotes as if those transactions had taken place on June 30, 2007 in the case of the pro forma balance sheet, or as of January 1, 2006, in the case of the pro forma statement of operations for the twelve months ended December 31, 2006 and the six months ended June 30, 2007. These unaudited pro forma financial statements are not necessarily indicative of the results that would have been achieved had the transactions described in the Introduction to these unaudited pro forma financial statements actually taken place at the dates indicated, and do not purport to be indicative of future financial position or operating results. The unaudited pro forma financial statements should be read in conjunction with the historical financial statements of the Predecessor and the notes thereto.

The historical financial statements were prepared using specific identification of income and expenses and assets and liabilities, where available, and, where not available, include allocations and estimates that management believes are reasonable and appropriate under the circumstances. However, these allocations and estimates may not necessarily reflect the operating results for the periods presented had Quest Energy Partners, L.P. operated as a separate entity.

The Partnership expects to incur $1.5 million of general and administrative expenses per year as a result of being a publicly traded limited partnership separate from Quest Resource Corporation, including costs associated with annual and quarterly reports to unitholders, financial statement audit, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation, which amount approximates the amount included in the Predecessor financial statements related to similar expenses incurred by Quest Resource Corporation. As a result, no adjustment has been made in the pro forma financial statements for incremental general and administrative expenses related to our being a publicly traded limited partnership.

The accounting policies and presentation used in the preparation of these unaudited pro forma financial statements are those set out in the audited historical financial statements of the Predecessor included elsewhere in this Prospectus.


2.	Pro Forma Adjustments and Assumptions

(a) Reflects estimated gross proceeds to the Partnership of $175.0 million from the issuance and sale of 8,750,000 common units at an assumed initial public offering price of $20.00 per common unit.

(b) Reflects $75.0 million of borrowings under the Partnership’s new credit facility.

(c) Reflects repayment of $235.0 million of loan principal indebtedness under the Predecessor’s credit facilities that is secured by the Partnership Properties. Quest Cherokee, LLC, the Partnership’s principal operating subsidiary, is currently a co-borrower on these credit facilities.

(d) Reflects the estimated fees and expenses of $13.7 million related to the issuance and sale of 8,750,000 common units.

(e) Loan costs and related one-time expenses are not reflected in the pro forma income statements; however, the amounts have been reflected in the pro forma balance sheet as of June 30, 2007. As of June 30, 2007, the adjustment reflects the payment of prepayment penalties of $5.4 million and $9.8 million in loan costs associated with loan repayment described in (c) above.

(f) Adjustment to reflect the contribution of net assets by the Predecessor in exchange for its common units, subordinated units and general partner units.

F-6

QUEST ENERGY PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS — (Continued)

(g) Reflects incremental gathering, treating, dehydration and compression fees under the Midstream Services and Gas Dedication Agreement with Quest Midstream at $1.60 per MMBtu.

(h) Adjusts interest expense as a result of loan repayment described in (c) above.

(i) Represents interest expense associated with borrowings under the Partnership’s new credit facility described in (b) above. Interest expense is calculated assuming an estimated annual interest rate of 8.0%. A one percentage point change in the interest rate would change pro forma interest expense by $750,000 for the year ended December 31, 2006 and $375,000 for the six months ended June 30, 2007.


3.	Pro Forma Net Income (Loss) Per Limited Partner Unit

Pro forma net income (loss) per limited partner unit is determined by dividing the pro forma net income (loss) that would have been allocated to the common and subordinated unitholders, which is 98% of the pro forma net income, by the number of common and subordinated units expected to be outstanding 21,159,502. All units were assumed to have been outstanding since January 1, 2006. Basic and diluted pro forma net income (loss) per limited partner unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income (loss) per limited partner unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.


4.	SFAS 69 Supplemental Disclosures

There are no pro forma adjustments to the Predecessor’s historical SFAS 69 supplemental disclosures. Please see Note 15 to the Predecessor’s historical financial statements as of and for the year ended December 31, 2006.

F-7

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Quest Energy Partners, L.P.

We have audited the accompanying carve out balance sheets of Quest Energy Partners, L.P. Predecessor (the “Company”) as of December 31, 2005 and 2006, and the related carve out statements of operations, cash flows and partners’ capital for the year ended May 31, 2004, the seven months ended December 31, 2004 and the years ended December 31, 2005 and 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the carve out financial position of the Company as of December 31, 2005 and 2006, and the carve out results of its operations, cash flows and partners’ capital for the year ended May 31, 2004, the seven months ended December 31, 2004 and the years ended December 31, 2005 and 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 19 to the carve out financial statements, certain changes were made to carve out assumptions resulting in the understatement of previously recorded cash and partners’ capital as of December 31, 2006. Accordingly, the 2006 carve out balance sheet, and statements of cash flow and partners’ capital have been restated to correct the error.

/s/ Murrell Hall McIntosh & Co PLLP

Oklahoma City, Oklahoma

July 19, 2007

(September 5, 2007 as to the effect of the restatement discussed in Note 19)

F-8

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT BALANCE SHEETS


	As of December 31,
	2005			2006
				(Restated)
	($ in thousands)

ASSETS
Current assets:
Cash	$	2,527		$	21,334
Restricted cash		4,318			1,150
Accounts receivable, trade		9,658			9,840
Other receivables		343			371
Inventory		1,407			3,378
Other current assets		1,727			1,053
Short-term derivative asset		95			10,795

Total current assets		20,075			47,921
Property and equipment, net of accumulated depreciation of $2,114 and $5,045		13,490			16,054
Oil and gas properties:
Properties being amortized		194,479			316,783
Properties not being amortized		18,285			9,445

		212,764			326,228
Less: Accumulated depreciation, depletion, amortization and impairment		(34,964	)		(92,733	)

Net property, plant and equipment		177,800			233,495
Other assets, net		6,192			9,466
Long-term derivative asset		93			4,782

Total assets	$	217,650		$	311,718


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	8,090		$	13,929
Revenue payable		—			4,540
Accrued expenses		649			2,486
Current portion of notes payable		407			324
Short-term derivative liability		38,195			5,244

Total current liabilities		47,341			26,523
Non-current liabilities:
Long-term derivative liability		23,723			7,449
Asset retirement obligation		1,150			1,410
Notes payable		76,296			225,569
Less current maturities		(407	)		(324	)

Total non-current liabilities		100,762			234,104

Total liabilities		148,103			260,627

Commitments and contingencies		—			—
Partners’ capital:
Partners’ capital		116,718			50,663
Accumulated other comprehensive income		(47,171	)		428

Total partners’ capital		69,547			51,091

Total liabilities and partners’ capital	$	217,650		$	311,718

The accompanying notes are an integral part of these financial statements.

F-9

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT STATEMENTS OF OPERATIONS


				Seven Months
	Year Ended			Ended			Year Ended
	May 31,			December 31,
	2004			2004			2005			2006
	($ in thousands)

Revenues:
Oil and gas sales	$	28,147		$	24,201		$	44,565		$	65,551
Other revenue/(expense)		(904	)		37			387			(83	)

Total revenues		27,243			24,238			44,952			65,468
Costs and expenses:
Oil and gas production		5,003			5,389			14,388			21,208
Transportation expense		1,869			3,196			7,038			17,278
General and administrative expenses		2,264			2,328			4,068			8,149
Depreciation, depletion and amortization		6,698			6,954			20,121			25,521
Provision for impairment of gas and properties		—			—			—			30,719

Total costs and expenses		15,834			17,867			45,615			102,875

Operating income (loss)		11,409			6,371			(663	)		(37,407	)
Other income (expense):
Change in derivative fair value		(2,013	)		(1,487	)		(4,668	)		6,410
(Loss)/gain on sale of assets		(6	)		—			12			(7	)
Interest expense		(6,404	)		(7,711	)		(19,919	)		(16,935	)
Interest income		1			9			46			390

Total other income (expense)		(8,422	)		(9,189	)		(24,529	)		(10,142	)

Income (loss) before income taxes		2,987			(2,818	)		(25,192	)		(47,549	)
Income tax expense		—			—			—			—

Net income (loss) before cumulative effect of accounting change		2,987			(2,818	)		(25,192	)		(47,549	)
Cumulative effect of accounting change, net of income tax of $19		(28	)		—			—			—

Net income (loss)	$	2,959		$	(2,818	)	$	(25,192	)	$	(47,549	)

The accompanying notes are an integral part of these financial statements.

F-10

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT STATEMENTS OF CASH FLOWS


				Seven Months
	Year Ended			Ended			Year Ended
	May 31,			December 31,
	2004			2004			2005			2006
										(Restated)
	($ in thousands)

Cash flows from operating activities:
Net income (loss)	$	2,959		$	(2,818	)	$	(25,192	)	$	(47,549	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion		6,698			6,954			20,121			28,339
Write-down of oil and gas properties		—			—			—			30,719
Net realized derivative gain (loss)		4,537			1,243			4,580			(16,917	)
Cumulative effect of accounting change		28			—			—			—
Accrued interest subordinated debt		3,459			4,866			7,765			—
Accretion of line of credit		1,204			—			—			—
Capital contributions for Retirement Plan		121			—			266			428
Capital contributions for audit committee fees		—			62			19			—
Capital contributions for directors fees		—			—			—			429
Capital contributions to employees		—			—			352			779
Capital contributed for services		94			—			—			—
Amortization of loan origination fees		172			530			5,108			1,202
Amortization of gas swap fees		—			163			—			208
Amortization of deferred hedging gains		—			—			(831	)		(328	)
Bad debt expense		—			—			192			37
(Gain) loss on sale of assets		—			—			(12	)		(3	)
Change in assets and liabilities:
Restricted cash		—			—			(4,318	)		3,167
Accounts receivable		(5,178	)		893			(3,455	)		(219	)
Other receivables		(582	)		66			(15	)		(28	)
Other current assets		151			14			(1,495	)		—
Deposits		—			—			—			675
Inventory		(197	)		161			(1,124	)		(1,970	)
Accounts payable		1,924			6,454			(1,440	)		5,836
Revenue payable		—			—			—			4,540
Accrued expenses		311			190			63			1,838

Net cash provided by (used in) operating activities		15,701			18,778			584			11,183
Cash flows from investing activities:
Equipment, development and leasehold		(123,335	)		(21,681	)		(46,269	)		(111,703	)
Additions to other property and equipment		(1,898	)		(5,979	)		(5,413	)		(5,684	)
Additions to other assets		(249	)		(415	)		—			—
Proceeds from sale of property and equipment		—			—			37			193

Net cash used in investing activities		(125,482	)		(28,075	)		(51,645	)		(117,194	)
Cash flows from financing activities:
Proceeds from bank borrowings		93,290			121,711			59,584			203,696
Repayments of note borrowings		(21,748	)		(104,732	)		(86,728	)		(54,424	)
Proceeds from subordinated debt		39,920			—			13,297			—
Repayment of subordinated debt		—			—			(66,398	)		—
Capital contributions (distributions)		(1,040	)		887			133,658			(20,142	)
Refinancing costs		—			(4,943	)		(6,272	)		(4,479	)
Change in other long-term liabilities		638			(638	)		—			167

Net cash provided from financing activities		111,060			12,285			47,141			124,818

Net increase (decrease) in cash		1,279			2,988			(3,920	)		18,807
Cash, beginning of period		2,180			3,459			6,447			2,527

Cash, end of period	$	3,459		$	6,447		$	2,527		$	21,334

The accompanying notes are an integral part of these financial statements.

F-11

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT STATEMENTS OF PARTNERS’ CAPITAL


				Seven Months
	Year Ended			Ended			Year Ended
	May 31,			December 31,
	2004			2004			2005			2006
										(Restated)
	($ in thousands)

Beginning Balance	$	6,521		$	8,655		$	7,266		$	116,718
Net income (loss)		2,959			(2,818	)		(25,192	)		(47,549	)
Partner contributions		—			887			133,658			—
Contributions for consideration pursuant
to compensation plan for non-employee directors		—			—			—			429
Contributions for consideration in the acquisition of assets		—			—			—			—
Contributions for consideration for compensation to employees		—			—			427			779
Contributions for retirement plan		121			480			495			428
Contributions for consideration of services		94			62			64			—
Distributions		(1,040	)		—			—			(20,142	)

Ending Balance		8,655			7,266			116,718			50,663

Accumulated other comprehensive income (loss):
Beginning Balance		—			(10,385	)		(11,143	)		(47,171	)
Change in fixed-price contract and other derivative fair value		(10,044	)		(5,258	)		(63,924	)		39,710
Reclassification adjustments-Contract settlements		(341	)		4,500			27,896			7,889

Ending Balance		(10,385	)		(11,143	)		(47,171	)		428

Total Partners’ Capital	$	(1,730	)	$	(3,877	)	$	69,547		$	51,091

The accompanying notes are an integral part of these financial statements.

F-12

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS


1.	Formation of the Partnership and Description of Business

Quest Energy Partners. L.P., a Delaware limited partnership (the “Partnership”), was formed in July 2007 by Quest Resource Corporation (individually, “Quest Resource Corporation”, and together with its subsidiaries, “QRC”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. QRC currently owns all the general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering of its common units representing limited partner interests (the “Offering”). At the closing of the Offering, the Partnership will hold gas and oil properties and related assets in the Cherokee Basin of Kansas and Oklahoma (the “Cherokee Basin Operations”) currently owned by Quest Cherokee, LLC, a wholly owned subsidiary of QRC. At the closing of the Offering, QRC will contribute Quest Cherokee, LLC to the Partnership in exchange for general partner units, the incentive distribution rights, common units and subordinated units in the Partnership.


2.	Basis of Presentation

The accompanying carve out financial statements and related notes thereto represent the carve out financial position, results of operations, cash flows, and changes in partners’ capital of the Cherokee Basin Operations, referred to as Quest Energy Partners, L.P. Predecessor (the “Predecessor”). The carve out financial statements have been prepared in accordance with Regulation S-X, Article 3 “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by QRC are only indirectly attributable to its ownership of the Cherokee Basin Operations as QRC owns interests in midstream assets and other gas and oil properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to the Predecessor, so that the accompanying carve out financial statements reflect substantially all the costs of doing business. The allocations and related estimates and assumptions are described more fully in “Note 3 — Summary of Significant Accounting Policies” and “Note 6 — Related Party Transactions” below.


3.	Summary of Significant Accounting Policies

Use of Estimates

Preparing carve out financial statements in conformity with accounting principles generally accepted in the United States requires the Predecessor to make certain estimations and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities in the financial statements and the reported amounts of revenues and expenses. Also, certain amounts in the accompanying carve out financial statements have been allocated in a way that the Predecessor believes is reasonable and consistent in order to depict the historical financial position, results of operations and cash flows of the Predecessor on a stand-alone basis. Actual results could differ materially from those estimates.

Estimates made in preparing these financial statements include, among other things, estimates of the proved gas and oil reserve volumes used in calculating depletion, depreciation and amortization expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment write-down; and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods.

Basis of Accounting

The Predecessor’s financial statements are prepared using the accrual method of accounting. Revenues are recognized when earned and expenses when incurred.

F-13

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Cash Equivalents

For purposes of the financial statements, the Predecessor considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents.

Uninsured Cash Balances

The Predecessor maintains its cash balances at several financial institutions. Accounts at the institutions are insured by the Federal Deposit Insurance Corporation up to $100,000. The Predecessor’s cash balances typically are in excess of this amount.

Accounts Receivable

The Predecessor conducts its operations in the States of Kansas and Oklahoma and operates exclusively in the natural gas and oil industry. The Predecessor’s joint interest and natural gas and oil sales receivables are generally unsecured; however, the Predecessor has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements.

Management periodically assesses the Predecessor’s accounts receivable and establishes an allowance for estimated uncollectible amounts. Accounts determined to be uncollectible are charged to operations when that determination is made.

Inventory

Inventory, which is included in current assets, includes tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method.

Concentration of Credit Risk

A significant portion of the Predecessor’s liquidity is concentrated in cash and derivative contracts that enable the Predecessor to hedge a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Predecessor to credit risk from its counterparties. The Predecessor’s accounts receivable are primarily from purchasers of natural gas and oil products. Natural gas sales to one purchaser (ONEOK) accounted for more than 90% of total natural gas and oil revenues for the fiscal year ended May 31, 2004 and for more than 95% for the seven month transition period ended December 31, 2004 and for the years ended December 31, 2005 and 2006. The industry concentration has the potential to impact the Predecessor’s overall exposure to credit risk, either positively or negatively, in that the Predecessor’s customers may be similarly affected by changes in economic, industry or other conditions.

Natural Gas and Oil Properties

The Predecessor follows the full cost method of accounting for natural gas and oil properties, prescribed by the Securities and Exchange Commission (“SEC”). Under the full cost method, all acquisition, exploration, and development costs are capitalized. The Predecessor capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of natural gas and oil properties, as well as other directly identifiable general and administrative costs associated with such activities.

F-14

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

unproved properties are excluded from amortization until the properties are evaluated. The Predecessor reviews all of its unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

The Predecessor reviews the carrying value of its oil and natural gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, plus the cost of properties not being amortized, less any related income tax effects. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, oil and natural gas prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

As of December 31, 2006, the Predecessor’s net book value of gas and oil properties exceeded the ceiling. Accordingly, a provision for impairment was recognized in the fourth quarter of 2006 of $30.7 million. The provision for impairment is primarily attributable to declines in the prevailing market prices of oil and gas at the measurement date.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between the capitalized costs and proved reserves of natural gas and oil, in which case the gain or loss is recognized in income.

Other Property and Equipment

Other property and equipment is reviewed on an annual basis for impairment and as of December 31, 2006, the Predecessor had not identified any such impairment. Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized.

Other property and equipment are stated at cost. Depreciation is calculated using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes.

The estimated useful lives are as follows:


	•	Buildings: 25 years

	•	Equipment: 10 years

	•	Vehicles: 7 years

Debt Issue Costs

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at December 31, 2006 and 2005 totaled $9.1 million and $5.8 million, respectively, and are being amortized over the life of the credit facilities.

F-15

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Other Dispositions

Upon disposition or retirement of property and equipment other than natural gas and oil properties, the cost and related accumulated depreciation are removed from the accounts and the gain or loss thereon, if any, is credited or charged to income.

Marketable Securities

In accordance with Statement of Financial Accounting Standards (“SFAS”) 115, Accounting for Certain Investments in Debt and Equity Securities, the Predecessor classifies its investment portfolio according to the provisions of SFAS 115 as either held to maturity, trading, or available for sale. At December 31, 2006 and 2005, the Predecessor did not have any investments in its investment portfolio classified as available for sale and held to maturity.

Income Taxes

The operations of the Predecessor are currently included in the federal income tax return of Quest Cherokee, LLC, which is a limited liability company that is not subject to federal income taxes. Following the initial public offering of the Partnership, our operations will be treated as a partnership with each partner being separately taxed on its share of our taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying carve out financial statements.

Fair Value of Financial Instruments

The Predecessor’s financial instruments consist of cash, receivables, deposits, hedging contracts, accounts payable, accrued expenses and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The hedging contracts are recorded in accordance with the provisions of SFAS 133, Accounting for Derivative Instruments and Hedging Activities. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

Accounting for Derivative Instruments and Hedging Activities

The Predecessor seeks to reduce its exposure to unfavorable changes in natural gas prices by utilizing energy swaps and collars (collectively, “fixed-price contracts”). The Predecessor has adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Instruments and Hedging Activities, which contains accounting and reporting guidelines for derivative instruments and hedging activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.

Pursuant to the provisions of SFAS 133, all hedging designations and the methodology for determining hedge ineffectiveness must be documented at the inception of the hedge, and, upon the initial adoption of the standard, hedging relationships must be designated anew. Based on the interpretation of these guidelines by the Predecessor, the changes in fair value of all of its derivatives during the period from June 1, 2003 to December 22, 2003 were required to be reported in results of operations, rather than in other comprehensive income.

F-16

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Although the Predecessor’s fixed-price contracts may not qualify for special hedge accounting treatment from time to time under the specific guidelines of SFAS 133, the Predecessor has continued to refer to these contracts in this document as hedges inasmuch as this was the intent when such contracts were executed, the characterization is consistent with the actual economic performance of the contracts, and the Predecessor expects the contracts to continue to mitigate its commodity price and interest rate risks in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS 133. Please read “Note 14 — Derivatives” below.

The Predecessor has established the fair value of all derivative instruments using estimates determined by its counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

Asset Retirement Obligations

The Predecessor has adopted SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 requires companies to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

The Predecessor’s asset retirement obligations relate to the plugging and abandonment of natural gas and oil properties.

Allocation of Costs

The accompanying carve out financial statements have been prepared in accordance with SAB Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting, and legal services, and other general and administrative expenses. QRC has allocated general and administrative expenses to the Predecessor based on time and other costs required to properly manage the assets. In management’s estimation, the allocation methodologies used are reasonable and result in an allocation of the cost of doing business borne by QRC on behalf of the Predecessor; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

Audited historical financial statements of the Cherokee Basin Operations as of December 31, 2005 and 2006 and for the fiscal year ended May 31, 2004, the seven months ended December 31, 2004 and the years ended December 31, 2005 and 2006 are presented. The Predecessor had a fiscal year end of May 31 through May 31, 2004, and switched to a calendar year end for December 31, 2004. The historical financial statements were prepared as follows:


	•	Revenues include all revenues earned by the Cherokee Basin Operations, before elimination of intercompany sales with QRC and its subsidiaries. Prior to December 1, 2006, pursuant to a transportation agreement, Bluestem Pipeline, a wholly-owned subsidiary of QRC, generally charged the Cherokee Basin Operations transportation fees ranging from $0.78 per thousand cubic feet (“Mcf”) to $0.87 per Mcf. Effective December 1, 2006, pursuant to the midstream services agreement, the fee for gathering, dehydration and treating services is $0.50 per MMBtu of gas and $1.10 per MMBtu of gas for compression services, subject to annual adjustment. Please read “Note 6 — Related Party Transactions”.

F-17

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


	•	Certain common expenses of QRC’s operations and the Cherokee Basin Operations were treated as follows:


	•	general and administrative expenses associated with the pipeline operations were eliminated;

	•	costs associated with the salt water disposal system, which were previously reported in Bluestem operations prior to the formation of Quest Midstream Partners, L.P. (“Quest Midstream”) in December 2006, were allocated to the Cherokee Basin Operations; and

	•	third party costs incurred at the QRC level that are clearly identifiable as Cherokee Basin Operations costs, such as insurance premiums related to the Cherokee Basin Operations and legal fees of outside counsel related to contracts entered into or claims made by or against the Cherokee Basin Operations and salaries and benefits of Cherokee Basin Operations executives paid by QRC, were allocated to the Cherokee Basin Operations.


	•	Non-producing acreage located outside of the Cherokee Basin and not transferred to the Partnership was eliminated from the balance sheet and related expenses were eliminated.

	•	To the extent that the common expenses described above were charged to the Cherokee Basin Operations in the past, the reduction in expenses was retroactively reflected with the offsetting debit to partner’s equity.

	•	Since the Partnership is not subject to entity level income taxes, no allocation of income taxes or deferred income taxes was reflected in the financial statements.

	•	Derivative transactions remained with the Cherokee Basin Operations.

	•	Management’s estimates of the expenses of the Cherokee Basin Operations on a stand-alone basis were not expected to be significantly different from those reflected in the statements.

Earnings per Share

During the periods presented, the Cherokee Basin Operations were wholly owned by QRC. Accordingly, earnings per share has not been presented.

Reclassifications

Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations or partners’ capital.


4.	Acquisitions

Quest Cherokee acquired certain assets from Faith Well Service on November 30, 2005 in the amount of $1.5 million. The assets consisted of service rigs and related equipment. The acquisition was funded with a portion of the net proceeds from the private placement of common stock that closed on November 14, 2005.

In November 2005, the Predecessor purchased all of the Class A units in Quest Cherokee from ArcLight for approximately $19.1 million, of which $2.1 million was allocated to non-producing leasehold and $17 million was allocated to wells. The $19.1 million purchase price for the Class A units was arrived at through negotiations between the Predecessor and ArcLight.

The Predecessor acquired approximately 10 miles of pipeline and 2,340 acres of leasehold from Venture Independent Petroleum during 2005 for $365,000, which pipeline was contributed to Quest Midstream in December 2006.

F-18

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The Predecessor acquired certain assets from Consolidated Oil Well Services on September 15, 2004 in the amount of $4.1 million. The assets consisted of cementing, acidizing and fracturing equipment and a related office building and storage facility in Chanute, Kansas. The acquisition was funded with a portion of the remaining net proceeds from a $120 million term loan that closed in June 2004.

The Predecessor acquired 8 wells and approximately 8,000 acres in the Cherokee Basin on August 6, 2004 for $750,000. These acquisitions were funded with a portion of the remaining net proceeds from a $120 million term loan that closed in June 2004.

On December 10, 2003, the Predecessor entered into an asset purchase agreement with Devon Energy Production Company, L.P. and Tall Grass Gas Services, LLC (collectively, “Devon”) to acquire certain natural gas properties located in Kansas and Oklahoma for a total consideration of $126 million, subject to certain purchase price adjustments. The acquisition was finalized on December 22, 2003. At the closing, the Predecessor transferred all of its rights and obligations under the asset purchase agreement to Quest Cherokee.

At the time of closing, Devon had not received consents to the assignment of certain of the leases from the lessors on natural gas leases with an allocated value of approximately $12.3 million. As a result, Quest Cherokee and Devon entered into a Holdback Agreement pursuant to the terms of which Quest Cherokee paid approximately $113.4 million of the purchase price at the closing and agreed to pay the allocated value of the remaining properties at such time as Devon received the consents to assignment for those leases. Subsequent to closing, Quest Cherokee paid approximately $9.6 million in February 2004, $2.6 million in May 2004 and $0.6 million in September 2004.

At the time of acquisition, the acquired assets had approximately 95.9 Bcfe of estimated proved reserves. The assets included approximately 372,000 gross (366,000 net) acres of natural gas leases, 418 gross (325 net) natural gas wells and 207 miles of natural gas gathering pipelines, which pipelines have been contributed to Quest Midstream. At the time of acquisition, the Devon assets were producing an average of approximately 19,600 mcf per day.

In accordance with the terms of the asset purchase agreement, the purchase price, including approximately $7.7 million of transaction fees and $1.7 million of assumed hedging liabilities was allocated as follows:


Proved producing properties	$	54,528,000
Proved undeveloped properties		38,649,000
Undeveloped properties		20,422,000
Pipelines — contributed to Quest Midstream		21,964,000
Other		9,000

Total	$	135,572,000

Effective June 1, 2003, certain subsidiaries of QRC consummated a Stock Purchase Agreement with Perkins Oil Enterprises, Inc. and E. Wayne Willhite Energy, L.L.C. pursuant to the terms of which the subsidiaries acquired from Perkins Oil Enterprises and E. Wayne Willhite Energy all of the capital stock of Producers Service Incorporated in exchange for 200,000 shares of the common stock of QRC, which was valued at $1.2 million. At the time of the acquisition, Producers Service Incorporated owned all of the issued and outstanding membership interests of J-W Gas Gathering, L.L.C. and a 5-year contract right to operate a lease on a 78-mile natural gas pipeline and J-W Gas Gathering, L.L.C. owned approximately 200 miles of natural gas gathering lines in southeast Kansas, which lease and gathering lines have been contributed to Quest Midstream. These assets were subsequently transferred to Quest Cherokee as part of the restructuring of the Predecessor’s operations in anticipation of the Devon asset acquisition.

F-19

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Also effective June 1, 2003, another subsidiary of QRC closed on a Purchase and Sale Agreement with James R. Perkins Energy, L.L.C. and E. Wayne Willhite Energy, L.L.C. and J-W Gas Gathering, L.L.C. pursuant to the terms of which such subsidiary acquired 53 natural gas and oil leases and related assets in Chautauqua, Elk, and Montgomery Counties, Kansas for $2,000,000. Both of these June 6, 2003 transactions were completed effective as of June 1, 2003. The cash portion of the purchase price was funded with borrowings under the Predecessor’s then existing credit facilities. These assets were also subsequently transferred to Quest Cherokee as part of the restructuring of the Predecessor’s operations in anticipation of the Devon asset acquisition.

In accordance with the terms of the asset purchase agreement, the purchase price, current assets and certain assumed liabilities were allocated as follows:


Current assets	$	604,000
Property and equipment		1,177,000
Natural gas and oil properties		2,040,000
Current liabilities		(669,000	)
Long-term debt		(112,000	)

Net assets acquired	$	3,040,000

Pro Forma Summary Data (unaudited)

The following pro forma summary data for the fiscal year ending May 31, 2004 presents the consolidated results of operations as if the Devon asset acquisition made on December 22, 2003 and the Perkins/Willhite acquisition made on June 1, 2003 had occurred on June 1, 2003. These pro forma results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisitions been made at June 1, 2003 or of results that may occur in the future.


	Year Ended
	May 31,
	2004

Pro forma revenue	$	45,241,000
Pro forma net income (loss)	$	2,311,000


5.	Long-Term Debt

Long-term debt consists of the following:


	December 31,		December 31,
	2005		2006
	($ in thousands)

Senior credit facilities	$	75,310	$	225,000
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 5.5% to 11.5% per annum		986		569

Total long-term debt		76,296		225,569
Less — current maturities		407		324

Total long term debt, net of current maturities	$	75,889	$	225,245

F-20

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The aggregate scheduled maturities of notes payable and long-term debt for the five years ending December 31, 2011 and thereafter were as follows as of December 31, 2006:


2007	$	324,000
2008		110,000
2009		30,000
2010		50,007,000
2011		100,006,000
Thereafter		75,092,000

	$	225,569,000

Credit Facilities — Guggenheim

As of December 31, 2006, Quest Resource Corporation and Quest Cherokee were co-borrowers under the following credit facilities (which are referred to as the Predecessor credit facilities):


	•	$100 million Senior Credit Agreement with Guggenheim Corporate Funding, LLC (“Guggenheim”), as administrative agent and syndication agent, and the lenders party thereto, which consists of a five-year $50 million revolving credit facility and a five-year $50 million first lien term loan;

	•	$100 million Second Lien Term Loan Agreement with Guggenheim, as Administrative Agent, and the lenders party thereto; and

	•	$75 million Third Lien Term Loan Agreement with Guggenheim, as Administrative Agent, and the lenders party thereto.

The first lien term loan was fully drawn as of February 14, 2006. The Second Lien Term Loan Agreement consists of a six year $100 million second lien term loan that was fully funded at the closing of the Second Lien Term Loan Agreement on November 14, 2005. The Third Lien Term Loan Agreement consists of a six year $75 million third lien term loan that was fully funded at the closing of the Third Lien Term Loan Agreement on June 9, 2006.

Availability under the revolving credit facility is tied to a borrowing base that will be redetermined by the lenders every six months taking into account the value of the Predecessor’s reserves and such other information (including, without limitation, the status of title information with respect to the Predecessor’s natural gas and oil properties and the existence of any other indebtedness) as the administrative agent deems appropriate and consistent with its normal oil and gas lending criteria as it exists at the particular time. The unanimous consent of the lenders is required to increase the borrowing base and the consent of 662/3% of the lenders is required to decrease or maintain the borrowing base. In addition, the Predecessor or the lenders may each request a special redetermination of the borrowing base once every 12 months. The outstanding principal balance of the first lien term loan and any outstanding letters of credit will be reserved against the borrowing base in determining availability under the revolving credit facility. As of December 31, 2006, the borrowing base under the revolving credit facility was $100 million.

The Predecessor pays a commitment fee equal to 0.75% on the difference between $50 million and the outstanding balance of borrowings and letters of credit under the revolving credit facility.

Interest accrues on the revolving credit facility at LIBOR plus 1.75% or the base rate plus 0.75%, at our option. Interest accrues on the first lien term loan at LIBOR plus 3.25% or the base rate plus 2.50%, at our option. Interest accrues on the second lien term loan at LIBOR plus 5.50%. The base rate is the greater of the prime rate or the federal funds effective rate plus 0.5%. Interest accrues on the third lien term loan at LIBOR

F-21

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

plus 8.00%. For the year ended December 31, 2006, the effective interest rates under the credit facilities were as follows.


	•	Revolving credit facility under the Senior Credit Agreement — 9.56%;

	•	First lien term loan under the Senior Credit Agreement — 8.30%;

	•	Second Lien Term Loan — 10.92%; and

	•	Third Lien Term Loan — 13.06%.

The revolving credit facility and the first lien term loan may be prepaid, without any premium or penalty, at any time. The second lien term loan may be repaid at any time, subject to the payment of a prepayment premium described below. The third lien term loan may be repaid at any time, subject to the payment of a prepayment premium described below.

Each of the Predecessor’s subsidiaries has guaranteed all obligations under these credit agreements. The revolving credit facility and the first lien term loan are secured by a first priority lien on substantially all of the assets of the Predecessor and its subsidiaries. The second lien term loan is secured by a second priority lien on substantially all of the assets of the Predecessor and its subsidiaries. The third lien term loan is secured by a third priority lien on substantially all of the assets of the Predecessor and its subsidiaries.

The credit agreements also secure on a pari passu basis derivative contracts entered into with lenders, their affiliates and other approved counterparties if the derivative contracts state that they are secured by the credit facilities. Approved counterparties are generally entities that have an A rating from Standard & Poor’s or an A2 rating from Moody’s, or whose obligations under the derivative contracts are guaranteed by an entity with such a rating. As of December 31, 2006, all of the Predecessor’s natural gas swap and collar derivative contracts were secured on a pari passu basis with the revolving credit facility.

The Predecessor is required to make certain representations and warranties that are customary for credit agreements of this type. The credit agreements also contain affirmative and negative covenants that are customary for credit agreements of this type. The covenants in the credit agreements include, without limitation: performance of obligations; delivery of financial statements, other financial information, production reports and information regarding swap agreements; delivery of notices of default and other material developments; operation of properties in accordance with prudent industry practice and in compliance with applicable laws; maintenance of satisfactory insurance; compliance with laws; inspection of books and properties; continued perfection of security interests in existing and subsequently acquired collateral; further assurances; payment of taxes and other preferred claims; compliance with environmental laws and delivery of notices related thereto; delivery of reserve reports; limitations on dividends and other distributions on, and redemptions and repurchases of, capital stock and other equity interests; limitations on liens; limitations on loans and investments; limitations on debt, guarantees and derivative contracts; limitations on mergers, acquisitions and asset sales; limitations on transactions with affiliates; limitations on dissolution; limitations on changes in business conducted by us and our subsidiaries; limitations on the right to enter into derivative contracts; and prohibitions against agreements limiting any subsidiaries’ right to pay dividends or make distributions; as well as certain financial covenants.

The financial covenants applicable to the credit agreements require that:


	•	the Predecessor’s minimum net sales volumes will not be less than:

1,890 MMcf for the quarter ended March 31, 2006;

2,380 MMcf for the quarter ended June 30, 2006;

3,080 MMcf for the quarter ended September 30, 2006; and

3,430 MMcf for the quarter ended December 31, 2006.

F-22

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


	•	the Predecessor’s ratio of total net debt to EBITDA for each quarter ending on the dates set forth below will not be more than:

4.5 to 1.0 for the quarter ended March 31, 2007;

4.25 to 1.0 for the quarter ended June 30, 2007;

4.00 to 1.0 for the quarter ended September 30, 2007;

3.75 to 1.0 for the quarter ended December 31, 2007;

3.50 to 1.0 for the quarter ended March 31, 2008;

3.25 to 1.0 for the quarter ended June 30, 2008; and

3.00 to 1.0 for any quarter ended on or after September 30, 2008.


	•	for the Senior Credit Agreement, the Predecessor’s ratio of PV-10 value for all of its proved reserves to indebtedness under the Senior Credit Agreement (excluding obligations under hedging agreements secured by the Senior Credit Agreement) must not be less than 2.0 to 1.0.

	•	for the Second and Third Lien Term Loan Agreements, the Predecessor’s ratio of PV-10 value for all of its proved reserves to total net debt must not be less than 1.5 to 1.

Under all credit agreements “PV-10 value” is generally defined as the future cash flows from the Predecessor’s proved reserves (based on the NYMEX three-year pricing strip and taking into account the effects of its hedge agreements) discounted at 10%.

EBITDA is generally defined in all of the credit agreements as consolidated net income plus interest, income taxes, depreciation, depletion, amortization and other non-cash charges (including unrealized losses on derivative contracts), plus costs and expenses directly incurred in connection with the credit agreements, the private equity transaction and the buy-out of ArcLight’s investment in Quest Cherokee and any write-off of prior debt issue costs, minus all non-cash income (including unrealized gains on derivative contracts). The EBITDA for each quarter will be multiplied by four in calculating the above ratios.

Total net debt is generally defined as funded debt, less cash and cash equivalents, reimbursement obligations under letters of credit and certain surety bonds.

Events of default under the credit agreements are customary for transactions of this type and include, without limitation, non-payment of principal when due, non-payment of interest, fees and other amounts for a period of three business days after the due date, representations and warranties not being correct in any material respect when made, non-performance of covenants after any applicable grace period, certain acts of bankruptcy or insolvency, cross defaults to other material indebtedness and change in control. Under the credit agreements, a change in control will generally be deemed to have occurred if any person or group acquires more than 35% of Quest Resource Corporation’s outstanding common stock or a majority of Quest Resource Corporation’s directors have either not been nominated or appointed by its board of directors. If an event of default has occurred and is continuing, the interest rate on the credit agreements will increase by 2.5%.

In connection with the formation of Quest Midstream on December 22, 2006, the Predecessor entered into amendments to the credit agreements. Among other things, the amendments permitted Quest Resource Corporation to transfer the member interests in Bluestem to Quest Midstream, released the security interests of the lenders in the member interests and assets of Bluestem and resulted in the pledge of Quest Resource Corporation’s class A and class B subordinated limited partner interests in Quest Midstream and Quest Resource Corporation’s 85% member interest in Quest Midstream GP as collateral for the credit facilities.

In connection with the amendments, the prepayment provisions of the second and third lien term loans were amended. After giving effect to the amendments, the prepayment provisions are as follows: If the

F-23

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Predecessor prepays second lien term loan during the 12 months beginning on (i) November 15, 2006, the Predecessor will pay a 3.5% premium, (ii) November 15, 2007, the Predecessor will pay a 2.25% premium, and (iii) November 15, 2008, the Predecessor will pay a 1.124% premium. Thereafter, the Predecessor may repay the second lien term loan at any time without any premium or prepayment penalty. The third lien term loan may not be repaid prior to June 10, 2007. If the Predecessor prepays the third lien term loan during the 12 months beginning on (i) June 10, 2007, the Predecessor will pay a 2.5% premium, (ii) June 10, 2008, the Predecessor will pay a 1.25% premium, and (iii) June 10, 2009, the Predecessor will pay a 0.5% premium. Thereafter, the Predecessor may repay the third lien term loan at any time without any premium or prepayment penalty.

Prior Credit Facilities

In January 2005, the Predecessor determined that it was not in compliance with the leverage and interest coverage ratios for the fiscal quarter ended November 30, 2004 under a prior secured credit agreement. On February 22, 2005, the default under this prior credit agreement was waived and the credit agreement was amended to reset the financial covenants, restrict the Predecessor’s capital expenditures and eliminate the Predecessor’s ability to drill any additional wells until its gross daily production reached certain levels. The Predecessor was unable to reach these production goals without the drilling of additional wells and, in the fourth quarter of 2005, Quest Resource Corporation undertook a significant recapitalization that included a private placement of its common stock and the refinancing of this prior secured credit agreement with the current Predecessor credit facilities discussed above.

Other Long-Term Indebtedness

$569,000 of notes payable to banks and finance companies were outstanding at December 31, 2006 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 5.5% to 11.5% per annum.


6.	Related Party Transactions

The Predecessor employs its own field employees and first level supervisor. The management level and general and administrative employees supporting the operations of the Predecessor are employees of Quest Energy Service, Inc. In addition to employee payroll-related expenses, QRC incurred general and administrative expenses related to leasing of office space and other corporate overhead type expenses during the period covered by these carve out financial statements. For purposes of deriving the accompanying carve out financial statements, a portion of the consolidated general and administrative and indirect lease operating overhead expenses reported for QRC has been allocated to the Predecessor and included in the accompanying Carve Out Statements of Operations for each of the periods presented. The portion of QRC’s consolidated general and administrative and indirect lease operating overhead expenses to be included in the accompanying carve out financial statements for each period presented was determined based on time and other costs required to properly manage the assets.

The Predecessor also controls Quest Midstream through its 85% ownership of Quest Midstream’s general partner and its ownership of approximately 49% of Quest Midstream’s limited partner interests. Quest Midstream owns and operates an over 1,700 mile gas gathering pipeline system in the Cherokee Basin. Pursuant to a midstream services and gas dedication agreement, Quest Midstream gathers and provides certain midstream services to the Predecessor for all gas produced from the Predecessor’s 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 renewal periods that may be exercised by either party upon 180 days’ notice. Under the midstream services agreement, the Predecessor pays Quest Midstream $0.50 per MMBtu of gas for gathering, dehydration and treating services and $1.10 per MMBtu of

F-24

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

gas for compression services, subject to annual adjustment based on changes in gas prices and the producer price index. Such fees will never be reduced below the initial rates described above and are subject to renegotiation upon the exercise of each five-year extension period. Under the terms of some of the Cherokee Basin Operations gas leases, the Predecessor may not be able to charge the full amount of these fees to royalty owners, which would increase the average fees per MMBtu that the Predecessor effectively pays under the midstream services agreement.

Quest Midstream has an exclusive option for sixty days to connect to its gathering system all of the gas wells that the Predecessor develops in the Cherokee Basin. In addition, Quest Midstream is required to connect to its gathering system, at its expense, any new gas wells that the Predecessor completes 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. 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.


7.	Supplemental Cash Flow Information


			Seven Months
	Year Ended		Ended		Year Ended
	May 31,		December 31,
	2004		2004		2005		2006
	($ in thousands)

Cash paid for interest	$	2,650	$	3,618	$	7,839	$	14,701
Cash paid for income taxes	$	—	$	—	$	—	$	—

Supplementary Information:

During the year ended December 31, 2006, non-cash investing and financing activities were as follows:


	•	Issued 82,500 shares of QRC common stock for credit agreement waiver fees valued at $904,200.

	•	Issued QRC common stock to the Predecessor’s 401(k) plan valued at $607,000 as an employer contribution.

During the year ended December 31, 2005, non-cash investing and financing activities were as follows:


	•	Issued 3,200 shares of QRC common stock to compensate a director for audit committee service valued at $19,000.

	•	Issued QRC common stock for services rendered valued at $45,000.

	•	Issued QRC common stock to the Predecessor’s 401(k) plan valued at $495,000 as an employer contribution.

	•	Recorded non-cash additions to net natural gas and oil properties of $211,000 pursuant to SFAS 143.

During the seven-month transition period ended December 31, 2004, non-cash investing and financing activities are as follows:


	•	Issued 6,800 QRC common stock shares to compensate a director for audit committee service valued at $62,000.

	•	Recorded non-cash additions to net natural gas and oil properties of $126,000 pursuant to SFAS 143.

F-25

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

During the fiscal year ended May 31, 2004, non-cash investing and financing activities are as follows:


	•	Issued QRC common stock upon conversion of $180,000 of convertible debentures.

	•	Issued QRC common stock to acquire assets valued at $1,200,000.

	•	Issued QRC common stock for services rendered valued at $94,000.

	•	Issued QRC common stock to the Predecessor’s 401(k) plan valued at $121,000 as an employer contribution.

	•	Recorded non-cash additions to net natural gas and oil properties of $624,000 pursuant to SFAS 143.


8.	Contingencies

Quest Cherokee, LLC (“Quest Cherokee”), STP Cherokee, Inc. (“STP”), and Bluestem Pipeline, LLC (“Bluestem”) were originally named defendants in a lawsuit (Case #CJ-2003-30) filed by plaintiffs Eddie R. Hill, et al, on September 27, 2003 in the District Court for Craig County, Oklahoma. Plaintiffs are royalty owners who are alleging underpayment of royalties owed them by STP and Quest Cherokee. Bluestem owns the gathering system that is used to gather gas from the wells in issue. Plaintiffs also allege, among other things, that STP and Quest Cherokee have engaged in self-dealing, have breached their fiduciary duties to Plaintiffs and have acted fraudulently towards Plaintiffs. Plaintiffs also allege that the gathering fees and related charges imposed by Bluestem should not be deducted by STP and Quest Cherokee in paying royalties. In March 2007, Plaintiffs filed an amended petition that added 20 additional plaintiffs and Quest Midstream Partners, L.P., Quest Energy Service, Inc., and Quest Midstream GP, LLC as defendants. Plaintiffs are seeking unspecified actual and punitive damages as a result of the alleged conduct by the defendants. Quest Cherokee intends to defend vigorously against these claims.

STP, Inc., STP Cherokee, Inc., and Bluestem have been named defendants in a lawsuit (Case No. CJ-2005-143) by plaintiffs John C. Kirkpatrick, et ux., in the District Court for Craig County, Oklahoma. Plaintiffs allege that STP, Inc., et al., through Bluestem, sold natural gas from wells owned by Plaintiffs to Quest Cherokee without proper notice to Plaintiffs. Plaintiffs have requested an accounting and stated 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 Quest Cherokee is vigorously contesting 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 (approximately 1,100 acres). 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 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 Plaintiff, with summary judgment being awarded in Quest Cherokee’s favor. Plaintiff has appealed the summary judgment and that appeal is pending. Quest Cherokee intends to defend vigorously against these claims.

F-26

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

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 2,500 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.

Bluestem and Quest Cherokee were named as defendants in a lawsuit (Case No. CJ-2007-325) filed by Devonian Enterprises, Inc. d/b/a Permian Land Company (“Permian”) in the district court of Oklahoma County, Oklahoma. Permian has asserted claims against Quest Cherokee and Bluestem in the amount of $521,252.88 for land services allegedly rendered to Quest Cherokee and Bluestem by Permian and for which no payment has purportedly been received by Permian. Quest Cherokee and Bluestem have asserted counterclaims against Permian for breach of contract and negligence, among other theories, due to Permian’s failure to file acquired instruments of record and deliver such records to Quest Cherokee and Bluestem, which has caused Quest Cherokee and Bluestem to incur unnecessary costs to re-acquire such instruments. In addition, Permian failed to ascertain whether or not minerals were leased or otherwise burdened and acquired oil and gas leases for Quest Cherokee and Bluestem, which were, in fact, burdened, causing Quest Cherokee and Bluestem to incur thousands of dollars in curative costs to acquire title to such minerals. Further, without approval, Permian inserted non-standard construction completion penalty provisions into said rights-of-way and easements, forcing Quest Cherokee and Bluestem to incur thousands of dollars in damages resulting from the unauthorized construction penalty provisions. Finally, Plaintiff has failed to return confidential information to Quest Cherokee and Bluestem pursuant to the parties’ written confidentiality and non-disclosure agreement. Quest Cherokee and Bluestem seek an undetermined amount of damages, injunctive relief, and an accounting to determine whether and to what extent Permian charged excessive fees for purported services it provided. Discovery is ongoing. Quest Cherokee intends to defend vigorously against Permian’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.

F-27

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Predecessor’s business, financial position or results of operations. Like other natural gas and oil producers and marketers, the Predecessor’s 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.


9.	Asset Retirement Obligation

As described in “Note 3 — Summary of Significant Accounting Policies” above, effective June 1, 2003, the Predecessor adopted SFAS 143, Accounting for Asset Retirement Obligations. Upon adoption of SFAS 143, the Predecessor recorded a cumulative effect to net income of ($28,000) net of tax. Additionally, the Predecessor recorded an asset retirement obligation liability of $254,000 and an increase to net properties and equipment of $207,000.

The following table provides a roll forward of the asset retirement obligations for the seven months ended December 31, 2004 and for the years ended December 31, 2005 and 2006 (dollars in thousands):


	Seven
	Months Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
	2004			2005			2006
	($ in thousands)

Asset retirement obligation beginning balance	$	717		$	871		$	1,150
Liabilities incurred		129			217			175
Liabilities settled		(3	)		(6	)		(7	)
Accretion expense		28			68			92
Revisions in estimated cash flows		—			—			—

Asset retirement obligation ending balance	$	871		$	1,150		$	1,410


10.	Company Benefit Plan

The Predecessor has adopted a 401(K) profit sharing plan with an effective date of June 1, 2001. The plan covers all eligible employees. During the years ended December 31, 2006 and 2005, employees contributed $490,880 and $298,937, respectively to the plan and the Predecessor contributed 51,131 and 49,842 shares of its common stock to the plan. The Predecessor valued the 2006 and 2005 common stock contribution at $607,000 and $495,000, respectively, of which $428,000 and $266,000, respectively, was included as an expense in the statement of operations and $179,000 and $229,000, respectively, was included in oil and gas properties. During the seven-month transition period ended December 31, 2004 and the fiscal year ended May 31, 2004, the employee contributions to the plan were $115,231 and $97,631, respectively, and the Predecessor contributed 32,355 shares of its common stock to the plan. The Predecessor valued the 2004 common stock contribution at $121,000 and included this amount as an expense in the statement of operations. There is a graduated vesting schedule with the employee becoming fully vested after six years of service.

Stock-Based Compensation

F-28

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

(“G&A”) expenses and lease operating expenses allocated to the Predecessor was non-cash stock-based compensation recorded on the books of QRC. On January 1, 2006, QRC adopted the provisions of SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) using the “modified prospective” method. SFAS 123R is a revision of SFAS No. 123, “ Accounting for Stock-Based Compensation “ (“SFAS 123”) and supersedes Accounting Principles Board (“APB”) Opinion No. 25, “ Accounting for Stock Issued to Employees “ (“APB 25”). Prior to the adoption of SFAS 123R, employee stock options and restricted stock awards were accounted for under the provisions of APB 25, which resulted in no compensation expense being recorded by QRC for stock options, since all options that were granted to QRC employees or non-employee directors had an exercise price equal to or above the common stock price on the grant date. However, expense was recorded by QRC and allocated to the Predecessor related to restricted stock granted to QRC employees.


11.	Operating Leases

The minimum annual rental commitments as of December 31, 2006 under non-cancellable office space leases are as follows: 2007 — $150,000; 2008 — $142,000 and 2009 — $59,000.


12.	Major Purchasers

The Predecessor’s natural gas and oil production is sold under contracts with various purchasers. Natural gas sales to one purchaser approximated 90% of total natural gas and oil revenues for the fiscal year ended May 31, 2004 and 95% of total natural gas and oil revenues for the seven-month transition period ended December 31, 2004 and for the years ended December 31, 2005 and 2006.


13.	Financial Instruments

The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Predecessor held as of December 31, 2005 and 2006 and the methods and assumptions used to estimate their fair value:


	December 31, 2005						December 31, 2006
	Carrying			Fair			Carrying			Fair
	Amount			Value			Amount			Value
	($ in thousands)

Derivative assets:
Interest rate swaps and caps	$	188		$	188		$	197		$	197
Basis swaps		—			—			62			62
Fixed-price natural gas swaps		—			—			2,207			2,207
Fixed-price natural gas collars		—			—			13,111			13,111
Derivative liabilities:
Basis swaps	$	—		$	—		$	(377	)	$	(377	)
Fixed-price natural gas swaps		(31,185	)		(31,185	)		—			—
Fixed-price natural gas collars		(30,733	)		(30,733	)		(12,316	)		(12,316	)
Credit facilities		(75,310	)		(75,310	)		(225,000	)		(225,000	)
Other financing agreements		(986	)		(986	)		(569	)		(569	)

The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value due to the short maturity of those instruments. The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

F-29

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The fair value of all derivative instruments as of December 31, 2005 and 2006 was based upon estimates determined by the Predecessor’s counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. Please read “Note 14 — Derivatives” below.

Derivative assets and liabilities reflected as current in the December 31, 2006 and 2005 balance sheets represent the estimated fair value of fixed-price contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value of the hedged future production has not been accrued in the accompanying balance sheet, creating the appearance of a working capital deficit from these contracts. The contract settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices and interest rates in effect at the balance sheet date due to option time value. Since the Predecessor expects to hold these contracts to maturity, this time value component has no direct relationship to actual future contract settlements and consequently does not represent a liability that will be settled in cash or realized in any way.


14.	Derivatives

Natural Gas Hedging Activities

The Predecessor seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Predecessor to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Predecessor will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the fiscal year ended May 31, 2004, the seven months ended December 31, 2004 and the years ended December 31, 2005 and 2006, fixed-price contracts hedged approximately 83.0%, 85.0%, 89.0%, and 61.0%, respectively, of the Predecessor’s natural gas production. As of December 31, 2006, fixed-price contracts are in place to hedge 20.1 Bcf of estimated future natural gas production. Of this total volume, 10.8 Bcf are hedged for 2007 and 9.3 Bcf thereafter.

For energy swap contracts, the Predecessor receives a fixed price for the respective commodity and pays a floating market price, as defined in each contract (generally a regional spot market index or in some cases, NYMEX future prices), to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Natural gas collars contain a fixed floor price (put) and ceiling price (call) (generally a regional spot market index or in some cases, NYMEX future prices). If the market price of natural gas exceeds the call strike price or falls below the put strike price, then the Predecessor receives the fixed price and pays the market price. If the market price of natural gas is between the call and the put strike price, then no payments are due from either party.

F-30

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of December 31, 2006. Please read “ — Market Risk.”


	Years Ending December 31,
	2007		2008			Total
	($ in thousands, except per MMBtu data)

Natural Gas Swaps:
Contract volumes (MMBtu)		2,354,000		—			2,354,000
Weighted-average fixed price per MMBtu(1)	$	7.20		—		$	7.20
Fixed-price sales	$	16,948		—		$	16,948
Fair value, net	$	2,207		—		$	2,207
Natural Gas Collars:
Contract volumes (MMBtu):
Floor		8,433,000		7,027,000			15,460,000
Ceiling		8,433,000		7,027,000			15,460,000
Weighted-average fixed price per MMBtu(1):
Floor	$	6.63	$	6.54		$	6.59
Ceiling	$	7.54	$	7.53		$	7.54
Fixed-price sales(2)	$	55,890	$	45,973		$	101,863
Fair value, net	$	3,525	$	(2,729	)	$	796
Total Natural Gas Contracts(3):
Contract volumes (MMBtu)		10,786,000		7,027,000			17,813,000
Weighted-average fixed price per MMBtu(1)	$	6.75	$	6.54		$	6.67
Fixed-price sales(2)	$	72,838	$	45,973		$	118,811
Fair value, net	$	5,732	$	(2,729	)	$	3,003


(1)		The prices to be realized for hedged production are expected to vary from the prices shown due to basis.

(2)		Assumes floor prices for natural gas collar volumes.

(3)		Does not include basis swaps with notional volumes by year, as follows: 2007: 1,825,000 MMBtu; 2008: 1,460,000 MMBtu.

The estimates of fair value of the fixed-price contracts are computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis. Forward market prices for natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change. Please read “Note 13 — Financial Instruments” above.

All fixed-price contracts have been approved by the Predecessor’s board of directors. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the fiscal year ended May 31, 2004, the seven-month transition period ended December 31, 2004 and the years ended December 31, 2005 and 2006, oil and gas sales included $649,000, $4.7 million, $27.9 million and $7.9 million, respectively, of net losses associated with realized losses under fixed-price contracts.

F-31

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

For contracts that did not qualify as cash flow hedges, the realized contract profit and loss is included in other revenue and expense in the period for which the underlying production was hedged. For the fiscal year ended May 31, 2004, the seven-month transition period ended December 31, 2004 and the years ended December 31, 2005 and 2006, other revenue and expense included $1.5 million, $105,000, $0 and $10.2 million, respectively, of net losses associated with realized losses under fixed-price contracts.

Based upon market prices at December 31, 2006, the estimated amount of unrealized gains for fixed-price contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next 12 months is $5.3 million.

Change in Derivative Fair Value

Change in derivative fair value in the statements of operations for the fiscal year ended May 31, 2004, the seven-month transition period ended December 31, 2004 and the years ended December 31, 2005 and 2006, are comprised of the following:


				Seven
	Year Ended			Months Ended			Year Ended			Year Ended
	May 31,			December 31,			December 31,			December 31,
	2004			2004			2005			2006
	($ in thousands)

Change in fair value of derivatives not qualifying as cash flow hedges	$	(1,740	)	$	(269	)	$	879		$	12,233
Amortization of derivative fair value gains and losses recognized in earnings prior to actual cash settlements		888			565			103			—
Settlements due to ineffective cash flow hedges		—			—			—			(10,234	)
Ineffective portion of derivatives qualifying as cash flow hedges		(1,161	)		(1,783	)		(5,650	)		4,411

	$	(2,013	)	$	(1,487	)	$	(4,668	)	$	6,410

The amounts recorded in change in derivative fair value do not represent cash gains or losses. Rather, they are temporary valuation swings in the fair value of the contracts. All amounts initially recorded in this caption are ultimately reversed within this same caption over the respective contract terms.

Credit Risk

Energy swaps and collars provide for a net settlement due to or from the respective party as discussed previously. The counterparties to the derivative contracts are a financial institution and a major energy corporation. Should a counterparty default on a contract, there can be no assurance that we would be able to enter into a new contract with a third party on terms comparable to the original contract. The Predecessor has not experienced non-performance by its counterparties.

F-32

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Cancellation or termination of a fixed-price contract would subject a greater portion of the Predecessor’s natural gas production to market prices, which, in a low price environment, could have an adverse effect on its future operating results. In addition, the associated carrying value of the derivative contract would be removed from the balance sheet.

Market Risk

The differential between the floating price paid under each energy swap or collar contract and the price received at the wellhead for the Predecessor’s production is termed “basis” and is the result of differences in location, quality, contract terms, timing and other variables. For instance, some of the Predecessor’s fixed price contracts are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”), that is, the Predecessor receives the fixed price amount stated in the contract and pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of the Predecessor’s natural gas assets and the cost of transporting the natural gas to another market, the amount that the Predecessor receives when it actually sells its natural gas is based on the Southern Star Central TX/KS/OK (“Southern Star”) first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Predecessor is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of the month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of the month index.

The effective price realizations that result from the fixed-price contracts are affected by movements in this basis differential. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of the Predecessor’s fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Predecessor receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract.

Changes in future gains and losses to be realized in natural gas and oil sales upon cash settlements of fixed-price contracts as a result of changes in market prices for natural gas are expected to be offset by changes in the price received for hedged natural gas production.


15.	SFAS 69 Supplemental Disclosures (Unaudited)

Net Capitalized Costs

The Predecessor’s aggregate capitalized costs related to natural gas and oil producing activities are summarized as follows:


	December 31,
	2005			2006

Natural gas and oil properties and related lease equipment:
Proved	$	201,788,000		$	316,780,000
Unproved		18,285,000			9,545,000

		220,073,000			326,325,000
Accumulated depreciation and depletion		(36,703,000	)		(92,732,000	)

Net capitalized costs	$	183,370,000		$	233,593,000

F-33

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Unproved properties not subject to amortization consisted mainly of leasehold acquired through acquisitions. The Predecessor will continue to evaluate its unproved properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.

Costs Incurred

Costs incurred in natural gas and oil property acquisition, exploration and development activities that have been capitalized are summarized as follows:


	Year Ended December 31,
	2005		2006

Acquisition of properties proved and unproved	$	—	$	—
Development costs		29,283,000		105,917,000	(1)

	$	29,283,000	$	105,917,000


(1)		Development costs for the year ended December 31, 2005 do not include the buy out of the ArcLight units of $19.1 million.

Results of Operations for Natural Gas and Oil Producing Activities

The Predecessor’s results of operations from natural gas and oil producing activities are presented below for the fiscal year ended May 31, 2004, the transition period ended December 31, 2004 and the years ended December 31, 2005 and 2006. The following table includes revenues and expenses associated directly with the Predecessor’s natural gas and oil producing activities. It does not include any interest costs and general and administrative costs and, therefore, is not necessarily indicative of the contribution to net operating results of the Predecessor’s natural gas and oil operations.


				Seven
	Year Ended			Months Ended			Year Ended
	May 31,			December 31,
	2004			2004			2005			2006

Production revenues	$	28,147,000		$	24,201,000		$	44,565,000		$	65,551,000
Production costs		(5,003,000	)		(5,389,000	)		(14,388,000	)		(21,208,000	)
Transportation costs		(1,869,000	)		(3,196,000	)		(7,038,000	)		(17,278,000	)
Depreciation and depletion		(6,698,000	)		(6,954,000	)		(20,121,000	)		(25,521,000	)

		14,577,000			8,662,000			3,018,000			1,544,000
Imputed income tax provision(1)		(5,831,000	)		(3,465,000	)		(1,207,000	)		(618,000	)

Results of operations for natural gas/oil producing activity	$	8,746,000		$	5,197,000		$	1,811,000		$	926,000


(1)		The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to the Predecessor’s deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision will be payable.

F-34

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Natural Gas and Oil Reserve Quantities

The following schedule contains estimates of proved natural gas and oil reserves attributable to the Predecessor. Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in thousand cubic feet (Mcf) of natural gas and barrels (Bbl) of oil. Geological and engineering estimates of proved natural gas and oil reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.


	Gas — Mcf			Oil — Bbls

Proved reserves:
Balance, December 31, 2004		149,843,900			47,834
Purchase of reserves-in-place		—			—
Extensions and discoveries		—			—
Revisions of previous estimates		(5,959,600	)		(6,324	)
Production		(9,565,000	)		(9,241	)

Balance, December 31, 2005		134,319,300			32,269
Purchase of reserves-in-place		—			—
Extensions and discoveries		87,002,842			9,740
Revisions of previous estimates		(11,000,000	)		—
Production		(12,282,142	)		(9,737	)

Balance, December 31, 2006		198,040,000			32,272

Proved developed reserves:
Balance, December 31, 2004		81,467,220			47,834
Balance, December 31, 2005		71,638,250			32,269
Balance, December 31, 2006		122,390,000			32,272

During 2005, the Predecessor drilled 99 gross wells and connected 233 gross wells. Of the wells connected during 2005, approximately 44 were drilled during 2005, with the other 189 having been drilled in 2004. All of these wells did not result in any extensions or discoveries, because the wells were in-field wells located in areas of existing production. The downward revision of 6.0 Bcf of natural gas in 2005 was due to a change in performance of wells on a portion of the Predecessor’s acreage.

During 2006, the Predecessor recorded extensions and discoveries of 87.0 Bcf of natural gas due to the 638 gross (621 net) new natural gas wells that the Predecessor drilled during 2006 and a downward revision of previous estimates of 11.0 Bcf of natural gas caused by lower natural gas prices at December 31, 2006 as compared to December 31, 2005. Lower prices reduce the economic lives of the underlying oil and natural gas properties and thereby decrease the estimated future reserves.

F-35

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Standardized Measure of Discounted Future Net Cash Flows

The following schedule presents the standardized measure of estimated discounted future net cash flows from the Predecessor’s proved reserves for the fiscal year ended May 31, 2004, the seven-month transition period ended December 31, 2004 and for the years ended December 31, 2005 and 2006. Estimated future cash flows are based on independent reserve data. Because the standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at May 31, 2004 and December 31, 2004, 2005 and 2006, it should be emphasized that such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Predecessor’s recoverable reserves or in estimating future results of operations.


				Seven
	Year Ended			Months Ended
	May 31,			December 31,			Year Ended December 31,
	2004			2004			2005			2006

Future production revenues(1)	$	796,329,000		$	959,591,000		$	1,258,579,000		$	1,190,084,000
Future production costs		(264,810,000	)		(274,015,000	)		(366,474,000	)		(636,710,000	)
Future development costs		(48,773,000	)		(74,470,000	)		(122,428,000	)		(126,272,000	)
Future income tax		(128,000,000	)		(160,734,000	)		(205,561,000	)		(66,289,000	)

Future net cash flows		354,746,000			450,372,000			564,116,000			360,813,000
Effect of discounting future annual cash flows at 10%		(120,802,000	)		(154,769,000	)		(210,446,000	)		(136,765,000	)

Standardized measure of discounted net cash flows before hedges		233,944,000			295,603,000			353,670,000			224,048,000
Future hedge settlements		(19,788,000	)		(22,477,000	)		(61,918,000	)		2,687,000

Standardized measure of discounted net cash flows after hedges	$	214,156,000		$	273,126,000		$	291,752,000		$	226,735,000


(1)		The weighted average natural gas and oil wellhead prices used in computing the Predecessor’s reserves were $5.95 per Mcf and $35.25 per Bbl at May 31, 2004; $6.30 per Mcf and $41.07 per Bbl at December 31, 2004; $9.22 per Mcf and $55.69 per Bbl at December 31, 2005 and $6.00 per Mcf and $58.06 per Bbl at December 31, 2006.

F-36

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The principal changes in the standardized measure of discounted future net cash flows relating to proven natural gas and oil properties were as follows:


				Seven
	Year Ended			Months Ended
	May 31,			December 31,			Year Ended December 31,
	2004			2004			2005			2006

Sales and transfers of natural gas and oil, net of production costs	$	(21,312,000	)	$	(18,419,000	)	$	(25,646,000	)	$	(25,796,000	)
Net changes in prices and production costs		7,461,000			45,264,000			171,468,000			(459,199,000	)
Acquisitions of natural gas and oil in place — less related production costs		217,924,000			—			—			—
Extensions and discoveries, less related production costs		19,956,000			46,686,000			—			242,558,000
Revisions of previous quantity estimates less related production costs		22,722,000			5,004,000			(51,760,000	)(1)		(33,510,000	)
Accretion of discount		3,917,000			4,609,000			8,832,000			7,053,000
Net change in income taxes		(63,792,000	)		(21,485,000	)		(44,827,000	)		139,272,000

Total change in standardized measure of discounted future net cash flows	$	186,876,000		$	61,659,000		$	58,067,000		$	(129,622,000	)


(1)		Includes $30.1 million related to increase in future development costs.

The following schedule contains a comparison of the standardized measure of discounted future net cash flows to the net carrying value of proved natural gas and oil properties at December 31, 2004, 2005 and 2006:


	Year Ended At December 31,
	2004			2005			2006

Standardized measure of discounted future net cash flows before hedges	$	295,603,000		$	353,670,000		$	224,048,000
Proved natural gas & oil property, net of accumulated depletion		(138,358,000	)		(165,085,000	)		(224,048,000	)

Standardized measure of discounted future net cash flows in excess of net carrying value of proved natural gas & oil properties	$	157,245,000		$	188,585,000		$	0

F-37

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


16.	Comparison of Certain Financial Data Due To Change in Fiscal Year End

Seven months ended December 31, 2003 compared to the seven months ended December 31, 2004

The Predecessor changed its fiscal year-end from May 31 to December 31, effective January 1, 2005. As a result of this change, the Predecessor has prepared financial statements for the seven-month transition period ended December 31, 2004. Accordingly, the following results of operations compares unaudited balances for the seven months ended December 31, 2003 to the audited balances for the seven months ended December 31, 2004 (dollars in thousands).


	Seven Months Ended December 31,
	2003			2004
	(Unaudited)

Revenues:
Oil and gas sales	$	8,755		$	24,201
Other revenue/expense		(1,862	)		37

Total revenues		6,893			24,238

Cost and expenses:
Oil and gas production		2,430			5,389
Transportation expense		1,035			3,196
General and administrative expense		603			2,328
Depreciation, depletion and amortization		1,773			6,954

Total costs and expenses		5,841			17,867

Operating income		1,052			6,371
Change in derivative fair value		3,312			(1,487	)
Other income (expense):
Interest expense		(882	)		(7,711	)
Interest income		—			9

Total other income (expense)		2,430			(9,189	)

Income (loss) before income taxes		3,482			(2,818	)
Deferred income tax (expense)		—			—

Net income (loss) before cumulative effect of accounting change		3,482			(2,818	)
Cumulative effect of accounting change, net of income tax of $19,000		(28	)		—

Net income (loss)	$	3,454		$	(2,818	)

F-38

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The following analysis of cash flows compares the unaudited seven months ended December 31, 2003 to the audited seven months ended December 31, 2004 (dollars in thousands).


	Seven Months Ended
	December 31,
	2003			2004
	(Unaudited)

Cash flows from operating activities:
Net income (loss)	$	3,454		$	(2,818	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation & depletion		1,773			6,954
Accrued interest subordinated notes		—			4,866
Change in derivative fair value		(3,312	)		1,243
Cumulative effect of accounting change		28			—
Accretion of line of credit		1,204			—
Stock issued for services		62			—
Stock issued for director fees		—			62
Amortization of loan origination fees		—			530
Other		—			163
Change in assets and liabilities:
Accounts receivable		(2,324	)		893
Other receivables		(63	)		66
Other current assets		397			14
Inventory		148			161
Accounts payable		1,353			6,454
Accrued expenses		155			190

Net cash provided by operating activities		2,875			18,778
Cash flows from investing activities:
Acquisition of proved gas & oil properties		(109,855	)		—
Equipment, development & leasehold costs		(13,225	)		(27,660	)
Other assets		—			(415	)

Net cash used in investing activities		(123,080	)		(28,075	)
Cash flows from financing activities:
Long-term debt		71,416			121,711
Repayments of note borrowings		(10,585	)		(104,732	)
Proceeds from subordinated debt		40,576			—
Refinancing costs		—			(4,943	)
Acquisition holdback payable		12,417			—
Proceeds from capital contributions		4,601			887
Change in other long-term liabilities		—			(638	)

Net cash provided by financing activities		118,425			12,285

Net increase in cash		(1,780	)		2,988
Cash, beginning of period		2,180			3,459

Cash, end of period	$	400		$	6,447

F-39

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


17.	Recent Accounting Pronouncements

The Financial Accounting Standards Board recently issued the following standards which the Predecessor reviewed to determine the potential impact on its financial statements upon adoption.

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), Share-Based Payment, which revised SFAS 123, Accounting for Stock-Based Compensation. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. This statement is effective as of the beginning of the first annual reporting period that begins after June 15, 2005. Since the issuance of SFAS 123(R), three FASB Staff Positions (FSPs) have been issued regarding SFAS 123(R): FSP FAS 123(R)-1 — Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R), FSP FAS 123(R)-2 — Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R), and FSP FAS 123(R)-3 — Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards. These FSPs will be applicable upon the initial adoption of FAS 123(R). The effect of SFAS 123(R) is more fully described in “Note 10 — Company Benefit Plan” above.

In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations. FIN 47 specifies the accounting treatment for conditional asset retirement obligations under the provisions of SFAS 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005. The Predecessor adopted this statement effective December 31, 2005. Implementation of FIN 47 did not have a material effect on its financial statements.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but the Predecessor does not currently expect SFAS 154 to have a material impact on its financial statements.

In June 2005, the EITF reached a consensus on Issue No. 04-10, Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds. EITF Issue 04-10 confirmed that operating segments that do not meet the quantitative thresholds can be aggregated only if aggregation is consistent with the objective and basic principles of SFAS 131, Disclosure about Segments of an Enterprise and Related Information. The consensus in this issue should be applied for fiscal years ending after September 30, 2005, and the corresponding information for earlier periods, including interim periods, should be restated unless it is impractical to do so. The adoption of EITF Issue 04-10 is not expected to have a material impact on the Predecessor’s disclosures.

In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. The adoption of EITF Issue 04-13 is not expected to have a material impact on the Predecessor’s financial statements.

F-40

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

In February 2006, the FASB issued Statement No. 155, “Accounting for Certain Hybrid Financial Instruments” (“SFAS No. 155”), which amends FASB Statements No. 133 and 140. SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation, and broadens a Qualified Special Purpose Entity’s permitted holdings to include passive derivative financial instruments that pertain to other derivative financial instruments. SFAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring after the beginning of an entity’s first fiscal year beginning after September 15, 2006. SFAS No. 155 has no current applicability to the Predecessor’s financial statements. Management plans to adopt SFAS No. 155 on January 1, 2007 and it is anticipated that the initial adoption of this statement will not have a material impact on the Predecessor’s financial position, results of operations, or cash flows.

In June 2006, the FASB issued Interpretation 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 clarifies the accounting and reporting for income taxes where interpretation of the law is uncertain. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of income tax uncertainties with respect to positions taken or expected to be taken in income tax returns. FIN 48 is effective for fiscal years beginning after December 15, 2006 and has no current applicability to the Predecessor’s financial statements. Management plans to adopt FIN 48 on January 1, 2007 and it is anticipated that the initial adoption of FIN 48 will not have a material impact on the Predecessor’s financial position, results of operations, or cash flows.

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands the required disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 157.

In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”), an amendment of FASB Statements No. 87, 88, 106 and 132(R). SFAS No. 158 requires (a) recognition of the funded status (measured as the difference between the fair value of the plan assets and the benefit obligation) of a benefit plan as an asset or liability in the employer’s statement of financial position, (b) measurement of the funded status as of the employer’s fiscal year-end with limited exceptions, and (c) recognition of changes in the funded status in the year in which the changes occur through comprehensive income. The requirement to recognize the funded status of a benefit plan and the disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure the plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. SFAS No. 158 has no current applicability to the Predecessor’s financial statements. Management plans to adopt SFAS No. 158 on December 31, 2006 and it is anticipated the adoption of SFAS No. 158 will not have a material impact to the Predecessor’s financial position, results of operations, or cash flows.

F-41

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

January 1, 2007 and it is anticipated that the initial adoption of SAB No. 108 will not have a material impact on the Predecessor’s financial position, results of operations, or cash flows.

In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), an amendment of FASB Statement No. 115. SFAS No. 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 159.


18.	Subsequent Events

On April 25, 2007, the Predecessor entered into amendments to its credit facilities. Under the amendments, the lenders waived the default under the credit facilities due to the Predecessor’s failure to comply with the maximum total debt to EBITDA ratio for the fiscal quarter ended March 31, 2007. After giving effect to the amendments, the Predecessor’s ratio of total net debt to EBITDA for each quarter ending on the dates set forth below may not exceed:


	•	4.50 to 1.0 for the quarter ended March 31, 2007;

	•	5.50 to 1.0 for the quarter ended June 30, 2007;

	•	4.75 to 1.0 for the quarter ended September 30, 2007;

	•	4.25 to 1.0 for the quarter ended December 31, 2007;

	•	3.50 to 1.0 for the quarter ended March 31, 2008;

	•	3.25 to 1.0 for the quarter ended June 30, 2008; and

	•	3.0 to 1.0 for the quarter ended on or after September 30, 2008.

In connection with the amendments, the Predecessor paid the lenders an aggregate amount equal to $1,687,500.


19.	Restatement of Certain Carve Out Financial Statements

In the previously issued carve out financial statements, cash was attributed to QRC rather than to the Predecessor. Certain carve out financial statements as of and for the year ended December 31, 2006 have been restated to appropriately show cash at the Predecessor. When compared to the previously issued carve out balance sheet, cash increased by $21,334,000 and partners’ capital increased by the same amount on the restated carve out balance sheet as of December 31, 2006. The carve out statement of cash flows and the carve out statement of partners’ capital have also been restated for the year ended December 31, 2006 to reflect these changes.

F-42

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT BALANCE SHEETS


	December 31,			June 30,
	2006			2007
	(Restated)			(Unaudited)
	($ in thousands)
ASSETS
Current assets:
Cash	$	21,334		$	9,980
Restricted cash		1,150			1,160
Accounts receivable, trade		9,840			12,442
Other receivables		371			1,509
Inventory		3,378			5,563
Other current assets		1,053			1,644
Short-term derivative asset		10,795			6,302

Total current assets		47,921			38,600
Property and equipment, net of accumulated depreciation of $5,045 and $5,183		16,054			18,150
Oil and gas properties:
Properties being amortized		316,783			359,705
Properties not being amortized		9,445			12,390

		326,228			372,095
Less: Accumulated depreciation, depletion, amortization and impairment		(92,733	)		(106,646	)

Net property, plant and equipment		233,495			265,449
Other assets, net		9,466			10,016
Long-term derivative asset		4,782			1,843

Total assets	$	311,718		$	334,058


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	13,929		$	15,182
Revenue payable		4,540			7,063
Accrued expenses		2,486			1,138
Current portion of notes payable		324			179
Short-term derivative liability		5,244			6,814

Total current liabilities		26,523			30,376
Non-current liabilities:
Long-term derivative liability		7,449			4,198
Asset retirement obligation		1,410			1,546
Notes payable		225,569			235,270
Less current maturities		(324	)		(179	)

Total non-current liabilities		234,104			240,835

Total liabilities		260,627			271,211

Commitments and contingencies		—			—
Partners’ capital:
Partners’ capital		50,663			67,987
Accumulated other comprehensive income		428			(5,140	)

Total partners’ capital		51,091			62,847

Total liabilities and partners’ capital	$	311,718		$	334,058

The accompanying notes are an integral part of these financial statements.

F-43

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT STATEMENTS OF OPERATIONS


							Six Months
	Three Months Ended June 30,						Ended June 30,
	2006			2007			2006			2007
	(Unaudited)
	($ in thousands)

Revenues:
Oil and gas sales	$	15,306		$	27,867		$	33,785		$	53,416
Other revenue/(expense)		(30	)		(19	)		(67	)		(32	)

Total revenues		15,276			27,848			33,718			53,384
Costs and expenses:
Oil and gas production		4,646			7,723			8,572			14,967
Transportation expense		3,577			6,826			5,167			13,170
General and administrative expenses		1,950			4,093			3,214			5,846
Depreciation, depletion and amortization		6,263			7,326			11,680			14,063

Total cost of revenues		16,436			25,968			28,633			48,046

Operating income (loss)		(1,160	)		1,880			5,085			5,338
Other income (expense):
Change in derivative fair value		(446	)		279			6,631			(185	)
Sale of assets		23			(304	)		43			(197	)
Interest expense		(3,625	)		(7,189	)		(6,434	)		(14,160	)
Interest income		113			103			249			280

Total other income (expense)		(3,935	)		(7,111	)		489			(14,262	)

Income (loss) before income taxes		(5,095	)		(5,231	)		5,574			(8,924	)
Income tax expense		—			—			—			—

Net income (loss)	$	(5,095	)	$	(5,231	)	$	5,574		$	(8,924	)

The accompanying notes are an integral part of these financial statements.

F-44

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CARVE OUT STATEMENTS OF CASH FLOWS


	Six Months
	Ended June 30,
	2006			2007
	(Unaudited)
	($ in thousands)

Cash flows from operating activities:
Net income (loss)	$	5,574		$	(8,924	)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and depletion		13,515			15,316
Change in derivative fair value		(16,865	)		185
Capital contributions for retirement plan		428			—
Capital contributions for directors fees		239			(25	)
Capital contributions to employees		254			2,343
Amortization of loan origination fees		547			1,024
Amortization of gas swap fees		83			125
Amortization of deferred hedging gains		(275	)		—
(Gain) loss on sale of assets		(43	)		240
Change in assets and liabilities:
Restricted cash		3,169			(10	)
Accounts receivable		2,736			(2,602	)
Other receivables		10			(1,143	)
Other current assets		(211	)		(591	)
Inventory		(1,392	)		(1,083	)
Accounts payable		5,362			(3,496	)
Revenue payable		—			2,524
Accrued expenses		415			(1,344	)

Net cash provided by (used in) operating activities		13,546			2,539
Cash flows from investing activities:
Equipment, development and leasehold costs		(62,726	)		(41,804	)
Net additions to other property and equipment		(4,884	)		(3,662	)
Proceeds from sale of property and equipment		162			(20	)
Increase in other assets		—			(10	)

Net cash used in investing activities		(67,448	)		(45,496	)
Cash flows from financing activities:
Proceeds from bank borrowings		90,122			10,000
Repayments of note borrowings		(163	)		(300	)
Refinancing costs		(1,105	)		(1,688	)
Capital contributions (distributions)		(2,237	)		23,511
Change in other long-term liabilities		81			80

Net cash provided from financing activities		86,698			31,603

Net increase (decrease) in cash		32,796			(11,354	)
Cash, beginning of period		2,527			21,334

Cash, end of period	$	35,323		$	9,980

The accompanying notes are an integral part of these financial statements.

F-45

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS

JUNE 30, 2007

(UNAUDITED)


1.	Formation of the Partnership and Description of Business

Quest Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), was formed in July 2007 by Quest Resource Corporation (together with its subsidiaries, “QRC”) to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. QRC currently owns all the general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering of its common units representing limited partner interests (the “Offering”). At the closing of the Offering, the Partnership will hold gas and oil properties and related assets in the Cherokee Basin of Kansas and Oklahoma (the “Cherokee Basin Operations”) currently owned by Quest Cherokee, LLC, a wholly owned subsidiary of QRC. At the closing of the Offering, QRC will contribute Quest Cherokee, LLC to the Partnership in exchange for general partner units, the incentive distribution rights, common units and subordinated units in the Partnership.


2.	Basis of Presentation

The accompanying carve out financial statements and related notes thereto represent the carve out financial position, results of operations and cash flows of the Cherokee Basin Operations, referred to as Quest Energy Partners, L.P. Predecessor or the Predecessor. The carve out financial statements have been prepared in accordance with Regulation S-X, Article 3 “General instructions as to financial statements” and Staff Accounting Bulletin (“SAB”) Topic 1-B “Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.” Certain expenses incurred by QRC are only indirectly attributable to its ownership of the Cherokee Basin Operations as QRC owns interests in midstream assets and other gas and oil properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to the Predecessor, so that the accompanying carve out financial statements reflect substantially all the costs of doing business. The allocations and related estimates and assumptions are described more fully in “Note 3 — Summary of Significant Accounting Policies” below.


3.	Summary of Significant Accounting Policies

Use of Estimates

F-46

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Basis of Accounting

The Predecessor’s financial statements are prepared using the accrual method of accounting. Revenues are recognized when earned and expenses when incurred.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Cash Equivalents

Uninsured Cash Balances

Accounts Receivable

The Predecessor conducts the majority of its operations in the States of Kansas and Oklahoma and operates exclusively in the natural gas and oil industry. The Predecessor’s joint interest and natural gas and oil sales receivables are generally unsecured; however, the Predecessor has not experienced any significant losses to date. Receivables are recorded at the estimate of amounts due based upon the terms of the related agreements.

Inventory

Concentration of Credit Risk

A significant portion of the Predecessor’s liquidity is concentrated in cash and derivative contracts that enable the Predecessor to hedge a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Predecessor to credit risk from its counterparties. The Predecessor’s accounts receivable are primarily from purchasers of natural gas and oil products. Natural gas sales to one purchaser, ONEOK, accounted for approximately 95% of our natural gas and oil revenues for the six months ended June 30, 2006, and natural gas sales to two purchasers, ONEOK and Tenaska, accounted for approximately 72% and 28%, respectively, of our natural gas and oil revenues for the six months ended June 30, 2007. The industry concentration has the potential to impact the Predecessor’s overall exposure to credit risk, either positively or negatively, in that the Predecessor’s customers may be similarly affected by changes in economic, industry or other conditions.

F-47

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Natural Gas and Oil Properties

All capitalized costs of natural gas and oil properties, including estimated future costs to develop proved reserves, are amortized on the units-of-production method using estimates of proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. The Predecessor reviews all of its unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unevaluated properties are assessed individually when individual costs are significant.

As of December 31, 2006, the Predecessor’s net book value of gas and oil properties exceeded the ceiling. Accordingly, a provision for impairment was recognized in the fourth quarter of 2006 of $30.7 million. The provision for impairment was primarily attributable to declines in the prevailing market prices of oil and gas at the measurement date.

Other Property and Equipment

Other property and equipment is reviewed on an annual basis for impairment and as of June 30, 2007, the Predecessor had not identified any such impairment. Repairs and maintenance are charged to operations when incurred and improvements and renewals are capitalized.

Other property and equipment are stated at cost. Depreciation is calculated using the straight-line method for financial reporting purposes and accelerated methods for income tax purposes.

F-48

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The estimated useful lives are as follows:


	•	Buildings: 25 years;

	•	Equipment: 10 years; and

	•	Vehicles: 7 years.

Debt Issue Costs

Included in other assets are costs associated with bank credit facilities. The remaining unamortized debt issue costs at December 31, 2006 and June 30, 2007 totaled $9.1 million and $9.9 million, respectively, and are being amortized over the life of the credit facilities.

Other Dispositions

Marketable Securities

In accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“SFAS No. 115”), the Predecessor classifies its investment portfolio according to the provisions of SFAS 115 as either held to maturity, trading, or available for sale. At June 30, 2007, the Predecessor did not have any investments in its investment portfolio classified as available for sale and held to maturity.

Income Taxes

Fair Value of Financial Instruments

The Predecessor’s financial instruments consist of cash, receivables, deposits, hedging contracts, accounts payable, accrued expenses and notes payable. The carrying amount of cash, receivables, deposits, accounts payable and accrued expenses approximates fair value because of the short-term nature of those instruments. The hedging contracts are recorded in accordance with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 113”). The carrying amounts for notes payable approximate fair value due to the variable nature of the interest rates of the notes payable.

Accounting for Derivative Instruments and Hedging Activities

The Predecessor seeks to reduce its exposure to unfavorable changes in natural gas prices by utilizing energy swaps and collars (collectively, “fixed-price contracts”). The Predecessor has adopted Statement of Financial Accounting Standards No. 133, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Derivative Instruments and Hedging Activities, which contains accounting and reporting guidelines for derivative instruments and hedging activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the

F-49

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.

Pursuant to the provisions of SFAS No. 133, all hedging designations and the methodology for determining hedge ineffectiveness must be documented at the inception of the hedge, and, upon the initial adoption of the standard, hedging relationships must be designated anew. Based on the interpretation of these guidelines by the Predecessor, the changes in fair value of all of its derivatives during the period from June 1, 2003 to December 22, 2003 were required to be reported in results of operations, rather than in other comprehensive income.

Although the Predecessor’s fixed-price contracts may not qualify for special hedge accounting treatment from time to time under the specific guidelines of SFAS No. 133, the Predecessor has continued to refer to these contracts in this document as hedges inasmuch as this was the intent when such contracts were executed, the characterization is consistent with the actual economic performance of the contracts, and the Predecessor expects the contracts to continue to mitigate its commodity price and interest rate risks in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS No. 133. Please read “Note 6 — Financial Instruments and Hedging Activities” below.

Asset Retirement Obligations

The Predecessor has adopted FASB’s Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). SFAS No. 143 requires companies to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

The Predecessor’s asset retirement obligations relate to the plugging and abandonment of natural gas and oil properties.

Allocation of Costs

F-50

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Historical financial statements of the Cherokee Basin Operations as of December 31, 2006 and June 30, 2007 and for the three and six months ended June 30, 2006 and 2007 are presented. The historical financial statements were prepared as follows:


	•	Revenues include all revenues earned by the Cherokee Basin Operations, before elimination of intercompany sales with QRC and its subsidiaries. Prior to December 22, 2006, pursuant to a transportation agreement, Bluestem Pipeline, a wholly-owned subsidiary of QRC, generally charged the Cherokee Basin Operations transportation fees ranging from $0.78 per thousand cubic feet (“Mcf”) to $0.87 per Mcf. Effective December 1, 2006 pursuant to the midstream services agreement, the fee gathering, dehydration and treating services is $0.50 per MMBtu of gas and $1.10 per MMBtu of gas for compression services, subject to annual adjustment.

	•	Certain common expenses of QRC’s operations and the Cherokee Basin Operations were treated as follows:


	•	general and administrative expenses associated with the pipeline operations were eliminated;

	•	costs associated with the salt water disposal system, which were previously reported in Bluestem operations prior to the formation of Quest Midstream Partners, L.P. (“Quest Midstream”) in December 2006, were allocated to the Cherokee Basin Operations; and

	•	third party costs incurred at the QRC level that are clearly identifiable as Cherokee Basin Operations costs, such as insurance premiums related to the Cherokee Basin Operations and legal fees of outside counsel related to contracts entered into or claims made by or against the Cherokee Basin Operations and salaries and benefits of Cherokee Basin Operations executives paid by QRC, were allocated to the Cherokee Basin Operations.


	•	Non-producing acreage located outside of the Cherokee Basin and not transferred to the Partnership was eliminated from the balance sheet and related expenses were eliminated.

	•	To the extent that the common expenses described above were charged to the Cherokee Basin Operations in the past, the reduction in expenses was retroactively reflected with the offsetting debit to partner’s equity.

	•	Since the Partnership is not subject to entity level income taxes, no allocation of income taxes or deferred income taxes was reflected in the financial statements.

	•	Derivative transactions remained with the Cherokee Basin Operations.

	•	Management’s estimates of the expenses of the Cherokee Basin Operations on a stand-alone basis were not expected to be significantly different from those reflected in the statements.

Earnings per Share

During the periods presented, the Cherokee Basin Operations were wholly owned by QRC. Accordingly, earnings per share has not been presented.

Recently Issued Accounting Standards

The Financial Accounting Standards Board (“FASB”) recently issued the following standards which the Predecessor reviewed to determine the potential impact on our financial statements upon adoption.

F-51

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

presentation and disclosure of income tax uncertainties with respect to positions taken or expected to be taken in income tax returns. FIN 48 is effective for fiscal years beginning after December 15, 2006 and has no current applicability to the Predecessor’s financial statements.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands the required disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 157.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”), an amendment of FASB Statement of Financial Accounting Standards No. 115. SFAS No. 159 addresses how companies should measure many financial instruments and certain other items at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. Management is assessing the impact of the adoption of SFAS No. 159.

F-52

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


4.	Long Term Debt

Long-term debt consists of the following:


	December 31,		June 30,
	2006		2007
	($ in thousands)

Senior credit facilities	$	225,000	$	235,000
Notes payable to banks and finance companies, secured by equipment and vehicles, due in installments through October 2013 with interest ranging from 5.5% to 11.5% per annum		569		270

Total long-term debt		225,569		235,270
Less — current maturities		324		179

Total long term debt, net of current maturities	$	225,245	$	235,091

The aggregate scheduled maturities of notes payable and long-term debt for the five years ending December 31, 2012 and thereafter were as follows as of June 30, 2007:


2008	$	179,000
2009		58,000
2010		11,000
2011		50,006,000
2012		185,007,000
Thereafter		9,000

	$	235,270,000

Credit Facilities

As of June 30, 2007, Quest Resource Corporation and Quest Cherokee were co-borrowers under the following credit facilities (which are referred to as the Predecessor credit facilities):


	•	$100 million Senior Credit Agreement with Guggenheim Corporate Funding, LLC (“Guggenheim”), as administrative agent and syndication agent, and the lenders party thereto, which consists of a five-year $50 million revolving credit facility and a five-year $50 million first lien term loan;

	•	$100 million Second Lien Term Loan Agreement with Guggenheim, as Administrative Agent, and the lenders party thereto; and

	•	$75 million Third Lien Term Loan Agreement with Guggenheim, as Administrative Agent, and the lenders party thereto.

F-53

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

The financial covenants applicable to the credit agreements require that:


	•	for the Senior Credit Agreement, the Predecessor is required to maintain a ratio of PV-10 value for all of its proved reserves to indebtedness under the Senior Credit Agreement (excluding obligations under hedging agreements secured by the Senior Credit Agreement) of not less than 2.0 to 1.0.

	•	for the Second and Third Lien Term Loan Agreements, the Predecessor’s ratio of PV-10 value for all of its proved reserves to total net debt must not be less than 1.5 to 1.

	•	for all credit agreements, after giving effect to the amendments described below, the Predecessor’s ratio of total net debt to EBITDA for each quarter ending on the dates set forth below must not be more than:


	•	4.50 to 1.0 for the quarter ended March 31, 2007;

	•	5.50 to 1.0 for the quarter ended June 30, 2007;

	•	4.75 to 1.0 for the quarter ended September 30, 2007;

	•	4.25 to 1.0 for the quarter ended December 31, 2007;

	•	3.50 to 1.0 for the quarter ended March 31, 2008;

	•	3.25 to 1.0 for the quarter ended June 30, 2008; and

	•	3.0 to 1.0 for the quarter ended on or after September 30, 2008.

Total net debt is generally defined as funded debt, less cash and cash equivalents, reimbursement obligations under letters of credit and certain surety bonds.

For the quarter ended March 31, 2007, the Predecessor was not in compliance with the minimum total debt to EBITDA ratio under its credit facilities. On April 25, 2007, the Predecessor obtained a waiver from its lenders with respect to this quarter and the minimum ratios were amended for the remainder of 2007. In connection with the amendments, the Predecessor paid the lenders an aggregate amount equal to $1,687,500.

For additional information regarding the Predecessor’s credit facilities, please read “Note 5 — Long Term Debt” to the financial statements for the year ended December 31, 2006.

Other Long-Term Indebtedness

$270,000 of notes payable to banks and finance companies were outstanding at June 30, 2007 and are secured by equipment and vehicles, with payments due in monthly installments through October 2013 with interest ranging from 1.9% to 11.5% per annum.

F-54

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)


5.	Commitments and Contingencies

STP, Inc., STP Cherokee, LLC, Quest Cherokee, LLC, Quest Energy Service, LLC and Bluestem have been named defendants in a lawsuit (Case No. CJ-2005-143) by plaintiffs John C. Kirkpatrick, et ux., in the District Court for Craig County, Oklahoma. Plaintiffs have requested an accounting to determine if royalties have been properly paid and stated, that if Plaintiffs have suffered any damages for failure to properly pay royalties, Plaintiffs have a right to recover those damages and have asserted a claim of fraud. Discovery is ongoing and defendants are vigorously contesting Plaintiffs’ claims. Plaintiffs have not quantified their alleged damages. Quest Cherokee intends to defend vigorously against these 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 (approximately 1,100 acres). 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. 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 conversion of the gas and seeks an accounting for all gas produced 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. Quest Cherokee has asserted third party claims against the persons who entered into the gas leases with Quest Cherokee for breach of the warranty of title contained in their leases in the event that the court finds that Plaintiff owns the coal bed methane gas. The District Court granted Quest Cherokee’s motion for summary judgment, ruling that coal bed methane gas is owned by the owners of the gas rights. That ruling was appealed and the appeal is pending before the Kansas Supreme Court. The appeal has been fully briefed, but the Kansas Supreme Court has not yet set the matter for oral argument.

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 2,500 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

F-55

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

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 Plaintiff’s claims.

Quest Cherokee is a defendant in several lawsuits in which the plaintiffs allege that certain of the oil and gas leases owned by Quest Cherokee are either invalid, have expired by their terms and/or have been forfeited by Quest Cherokee. Plaintiffs in those cases are generally seeking statutory damages of $100 per lease, attorneys fees, and a judicial declaration that Quest Cherokee’s leases have terminated. As of August 7, 2007, the total amount of acreage covered by the leases at issue in these lawsuits was approximately 7,300 acres. Quest Cherokee contends that it has complied with the terms of these oil and gas leases and that they remain in full force and effect. Quest Cherokee intends to vigorously defend against the claims.

The Predecessor, from time to time, may be subject to legal proceedings and claims that arise in the ordinary course of its 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 the Predecessor’s business, financial position or results of operations. Like other natural gas and oil producers and marketers, the Predecessor’s 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.


6.	Financial Instruments and Hedging Activities

Natural Gas Hedging Activities

The Predecessor seeks to reduce its exposure to unfavorable changes in natural gas prices, which are subject to significant and often volatile fluctuation, through the use of fixed-price contracts. The fixed-price contracts are comprised of energy swaps and collars. These contracts allow the Predecessor to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Predecessor will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. Collar structures provide for participation in price increases and decreases to the extent of the ceiling and floor prices provided in those contracts. For the six months ended June 30, 2006 and 2007, fixed-price contracts hedged approximately 68.5%, and 68.2%, respectively, of the Predecessor’s natural gas production. As of June 30, 2007, fixed-price contracts are in place to hedge 24.8 Bcf of estimated future natural gas production. Of this total volume, 5.4 Bcf are hedged for 2007 and 19.4 Bcf thereafter.

F-56

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

NYMEX future prices), to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. Natural gas collars contain a fixed floor price (put) and ceiling price (call) (generally a regional spot market index or in some cases, NYMEX future prices). If the market price of natural gas exceeds the call strike price or falls below the put strike price, then the Predecessor receives the fixed price and pays the market price. If the market price of natural gas is between the call and the put strike price, then no payments are due from either party.

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the fixed-price contracts as of June 30, 2007.


	Six Months
	Ending			Year Ending			Year Ending
	December 31,			December 31,			December 31,
	2007			2008			2009		Total
	(Dollars in thousands, except per MMBtu data)

Natural Gas Swaps:
Contract vols (MMBtu)		1,187,000			2,332,000			9,999,000		13,518,000
Weighted-avg fixed price per MMBtu(1)	$	7.20		$	7.35		$	7.85	$	7.70
Fixed-price sales	$	8,544		$	17,141		$	78,451	$	104,136
Fair value, net	$	884		$	35		$	25	$	944
Natural Gas Collars:
Contract vols (MMBtu):
Floor		4,251,000			7,028,000			—		11,279,000
Ceiling		4,251,000			7,028,000			—		11,279,000
Weighted-avg fixed price per MMBtu(1)
Floor	$	6.63		$	6.54			—	$	6.57
Ceiling	$	7.54		$	7.54			—	$	7.54
Fixed-price sales(2)	$	28,174		$	45,973			—	$	74,147
Fair value, net	$	(1,418	)	$	(2,447	)		—	$	(3,865	)
Total Natural Gas Contracts(3):
Contract vols (MMBtu)		5,438,000			9,360,000			9,999,000		24,797,000
Weighted-avg fixed price per MMBtu(1)	$	6.75		$	6.74		$	7.85	$	7.19
Fixed-price sales(2)	$	36,718		$	63,114		$	78,451	$	178,283
Fair value, net	$	(534	)	$	(2,412	)	$	25	$	(2,921	)


(1)		The prices to be realized for hedged production are expected to vary from the prices shown due to basis.

(2)		Assumes floor prices for natural gas collar volumes.

(3)		Does not include basis swaps with notional volumes by year, as follows: 2007: 920,000 MMBtu; 2008: 1,464,000 MMBtu.

F-57

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

All fixed-price contracts have been approved by the Predecessor’s board of directors. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For fixed-price contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil and gas sales in the period for which the underlying production was hedged. For the six months ended June 30, 2006 and 2007, oil and gas sales included a loss of $663,000 and a gain of $1.4 million, respectively, associated with realized losses under fixed-price contracts.

Change in Derivative Fair Value

Change in derivative fair value in the statements of operations for the three months ended June 30, 2006 and 2007 and six months ended June 30, 2006 and 2007 are comprised of the following:


	For the Three						For the Six
	Months Ended						Months Ended
	June 30,						June 30,
	2006			2007			2006			2007
	($ in thousands)

Change in fair value of derivatives not qualifying as cash flow hedges	$	1,260		$	(285	)	$	14,630		$	(1,321	)
Settlements due to ineffective cash flow hedges		(2,828	)		—			(10,233	)		—
Ineffective portion of derivatives qualifying as cash flow hedges		1,123			564			2,234			1,136

	$	(446	)	$	279		$	6,631		$	(185	)

Credit Risk

Market Risk

F-58

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”), that is, it receives the fixed price amount stated in the contract and pays to its counterparty the current market price for gas as listed on the NYMEX. However, due to the geographic location of the Predecessor’s natural gas assets and the cost of transporting the natural gas to another market, the amount that it receives when the Predecessor actually sells its natural gas is based on the Southern Star first of month index, with a small portion being sold based on the daily price on the Southern Star index. The difference between natural gas prices on the NYMEX and the price actually received by the Predecessor is referred to as a basis differential. Typically, the price for natural gas on the Southern Star first of month index is less than the price on the NYMEX due to the more limited demand for natural gas on the Southern Star first of month index.

The effective price realizations that result from the fixed-price contracts are affected by movements in this basis differential. Basis movements can result from a number of variables, including regional supply and demand factors, changes in the portfolio of the Predecessor’s fixed-price contracts and the composition of its producing property base. Basis movements are generally considerably less than the price movements affecting the underlying commodity, but their effect can be significant. Recently, the basis differential has been increasingly volatile and has on occasion resulted in the Predecessor receiving a net price for its natural gas that is significantly below the price stated in the fixed price contract.

Fair Value of Financial Instruments

The following information is provided regarding the estimated fair value of the financial instruments, including derivative assets and liabilities as defined by SFAS 133 that the Predecessor held as of December 31, 2006 and June 30, 2007 and the methods and assumptions used to estimate their fair value:


	December 31,						June 30,
	2006						2007
	Carrying						Carrying
	Amount			Fair Value			Amount			Fair Value
	(In thousands)

Derivative assets:
Interest rate swaps and caps	$	197		$	197		$	63		$	63
Basis swaps	$	62		$	62		$	101		$	101
Fixed-price natural gas swaps	$	2,207		$	2,207		$	994		$	944
Fixed-price natural gas collars	$	13,111		$	13,111		$	7,037		$	7,037
Derivative liabilities:
Basis swaps	$	(377	)	$	(377	)	$	(110	)	$	(110	)
Fixed-price natural gas collars	$	(12,316	)	$	(12,316	)	$	(10,902	)	$	(10,902	)
Credit facilities	$	(225,000	)	$	(225,000	)	$	(235,000	)	$	(235,000	)
Other financing agreements	$	(569	)	$	(569	)	$	(270	)	$	(270	)

The fair value of all derivative instruments as of December 31, 2006 and June 30, 2007 was based upon estimates determined by the Predecessor’s counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, and time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

F-59

QUEST ENERGY PARTNERS, L.P. PREDECESSOR

CONDENSED NOTES TO CARVE OUT FINANCIAL STATEMENTS — (Continued)

Derivative assets and liabilities reflected as current in the December 31, 2006 and June 30, 2007 balance sheets represent the estimated fair value of fixed-price contract and interest rate cap settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and fluctuations in interest rates as of the balance sheet date. The offsetting increase in value of the hedged future production has not been accrued in the accompanying balance sheet, creating the appearance of a working capital deficit from these contracts. The contract settlement amounts are not due and payable until the monthly period that the related underlying hedged transaction occurs. In some cases the recorded liability for certain contracts significantly exceeds the total settlement amounts that would be paid to a counterparty based on prices and interest rates in effect at the balance sheet date due to option time value. Since the Predecessor expects to hold these contracts to maturity, this time value component has no direct relationship to actual future contract settlements and consequently does not represent a liability that will be settled in cash or realized in any way.


7.	Asset Retirement Obligations

The Predecessor has adopted SFAS 143, Accounting for Asset Retirement Obligations. The following table provides a roll forward of the asset retirement obligations for the six months ended June 30, 2006 and 2007:


	Six Months Ended
	June 30,
	2006			2007
	($ in thousands)

Asset retirement obligation beginning balance	$	1,150		$	1,410
Liabilities incurred		84			83
Liabilities settled		(3	)		(3	)
Accretion expense		44			56
Revisions in estimated cash flows		—			—

Asset retirement obligation ending balance	$	1,275		$	1,546


8.	Subsequent Events

On August 3, 2007, certain mineral and overriding royalty interest owners in land located in the Kansas portion of the Cherokee Basin filed a putative class action lawsuit against Quest Cherokee. Hugo Spieker, et al. v. Quest Cherokee, LLC, United States District Court for the District of Kansas, Case No. 07-1225-MLB. The named plaintiffs allege that Quest Cherokee has 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 of gas measured at the wellheads, and by allocating certain expenses to plaintiffs’ interests. Plaintiffs also allege that Quest Cherokee is improperly charging the royalty owners in excess of the actual costs of the services provided. Plaintiffs allege that the amount in controversy exceeds $5 million. Quest Cherokee is in the process of investigating and evaluating the claims. Quest Cherokee denies any wrongdoing and intends to vigorously defend against the claims.


9.	Restatement of Certain Carve Out Financial Statements

In the previously issued carve out balance sheet as of December 31, 2006, cash was attributed to QRC rather than to the Predecessor. The carve out balance sheet as of December 31, 2006 has been restated to appropriately show cash at the Predecessor. When compared to the previously issued carve out balance sheet, cash increased by $21,334,000 and partners’ capital increased by the same amount on the restated carve out balance sheet as of December 31, 2006.

F-60

QUEST ENERGY PARTNERS, L.P.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of Quest Energy Partners, L.P.

We have audited the balance sheet of Quest Energy Partners, L.P. as of July 19, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Quest Energy Partners, L.P. as of July 19, 2007 in conformity with accounting principles generally accepted in the United States of America.

/s/ Murrell Hall McIntosh & Co PLLP

Oklahoma City, Oklahoma

September 5, 2007

F-61

QUEST ENERGY GP, LLC

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Quest Energy GP, LLC

We have audited the accompanying consolidated balance sheet of Quest Energy GP, LLC as of July 19, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Quest Energy GP, LLC as of July 19, 2007 in conformity with accounting principles generally accepted in the United States of America.

/s/ Murrell Hall McIntosh & Co PLLP

Oklahoma City, Oklahoma

September 5, 2007

F-64

QUEST ENERGY GP, LLC

NOTES TO CONSOLIDATED BALANCE SHEET


1.	Nature of Operations

Quest Energy GP, LLC (the “General Partner”) is a single member Delaware limited liability company, formed on July 12, 2007 to become the general partner of Quest Energy Partners, L.P. (the “Partnership”). The General Partner is a direct wholly-owned subsidiary of Quest Resource Corporation. The General Partner owns a 2% general partner interest in the Partnership.

On July 18, 2007, Quest Resource Corporation contributed $1,000 to the General Partner in exchange for a 100% ownership interest.

The General Partner has invested $20 in the Partnership, as general partner. There have been no other transactions involving the General Partner as of July 19, 2007.

Quest Resource Corporation, as limited partner, contributed $980 to the Partnership on July 18, 2007.


2.	Principles of Presentation and Consolidation

The consolidated balance sheet includes the financial position of the General Partner and the Partnership. All significant intercompany balances and transactions have been eliminated in consolidation. As the General Partner only has a 2% interest in the Partnership, the remaining 98% not owned is shown as minority interests in the consolidated balance sheet.

F-66

TABLE OF CONTENTS


		Page
ARTICLE I	Definitions	A-1
Section 1.1	Definitions.	A-1
Section 1.2	Construction.	A-17
ARTICLE II	Organization	A-17
Section 2.1	Formation.	A-17
Section 2.2	Name.	A-17
Section 2.3	Registered Office; Registered Agent; Principal Office; Other Offices.	A-17
Section 2.4	Purpose and Business.	A-17
Section 2.5	Powers.	A-18
Section 2.6	Power of Attorney.	A-18
Section 2.7	Term.	A-19
Section 2.8	Title to Partnership Assets.	A-19
ARTICLE III	Rights of Limited Partners	A-19
Section 3.1	Limitation of Liability.	A-19
Section 3.2	Management of Business.	A-19
Section 3.3	Outside Activities of the Limited Partners.	A-20
Section 3.4	Rights of Limited Partners.	A-20
ARTICLE IV	Certificates; Record Holders; Transfer of Partnership Interests; Redemption of Partnership Interests	A-20
Section 4.1	Certificates.	A-20
Section 4.2	Mutilated, Destroyed, Lost or Stolen Certificates.	A-21
Section 4.3	Record Holders.	A-22
Section 4.4	Transfer Generally.	A-22
Section 4.5	Registration and Transfer of Limited Partner Interests.	A-22
Section 4.6	Transfer of the General Partner’s General Partner Interest.	A-23
Section 4.7	Transfer of Incentive Distribution Rights.	A-23
Section 4.8	Restrictions on Transfers.	A-24
Section 4.9	Eligible Holder Certifications; Non-Eligible Holders.	A-25
Section 4.10	Redemption of Partnership Interests of Non-Eligible Holder.	A-25
ARTICLE V	Capital Contributions and Issuance of Partnership Interests	A-26
Section 5.1	Organizational Contributions.	A-26
Section 5.2	Contributions by the General Partner.	A-27
Section 5.3	Contributions by Initial Limited Partners.	A-27
Section 5.4	Interest and Withdrawal.	A-27
Section 5.5	Capital Accounts.	A-28
Section 5.6	Issuances of Additional Partnership Securities.	A-30
Section 5.7	Conversion of Subordinated Units.	A-31
Section 5.8	Limited Preemptive Right.	A-33
Section 5.9	Splits and Combinations.	A-33
Section 5.10	Fully Paid and Non-Assessable Nature of Limited Partner Interests.	A-33
Section 5.11	Issuance of Class B Units in Connection with Reset of Incentive Distribution Rights.	A-33
ARTICLE VI	Allocations and Distributions	A-35
Section 6.1	Allocations for Capital Account Purposes.	A-35
Section 6.2	Allocations for Tax Purposes.	A-41
Section 6.3	Requirement and Characterization of Distributions; Distributions to Record Holders.	A-43

A-i


		Page
Section 6.4	Distributions of Available Cash from Operating Surplus.	A-44
Section 6.5	Distributions of Available Cash from Capital Surplus.	A-45
Section 6.6	Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.	A-45
Section 6.7	Special Provisions Relating to the Holders of Subordinated Units and Class B Units.	A-45
Section 6.8	Special Provisions Relating to the Holders of Incentive Distribution Rights.	A-46
Section 6.9	Entity-Level Taxation.	A-46
ARTICLE VII	Management and Operation of Business	A-47
Section 7.1	Management.	A-47
Section 7.2	Certificate of Limited Partnership.	A-48
Section 7.3	Restrictions on the General Partner’s Authority.	A-49
Section 7.4	Reimbursement of the General Partner.	A-49
Section 7.5	Outside Activities.	A-50
Section 7.6	Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.	A-51
Section 7.7	Indemnification.	A-51
Section 7.8	Liability of Indemnitees.	A-52
Section 7.9	Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.	A-53
Section 7.10	Other Matters Concerning the General Partner.	A-54
Section 7.11	Purchase or Sale of Partnership Securities.	A-55
Section 7.12	Registration Rights of the General Partner and its Affiliates.	A-55
Section 7.13	Reliance by Third Parties.	A-57
ARTICLE VIII	Books, Records, Accounting and Reports	A-58
Section 8.1	Records and Accounting.	A-58
Section 8.2	Fiscal Year.	A-58
Section 8.3	Reports.	A-58
ARTICLE IX	Tax Matters	A-58
Section 9.1	Tax Returns and Information.	A-58
Section 9.2	Tax Elections.	A-59
Section 9.3	Tax Controversies.	A-59
Section 9.4	Withholding.	A-59
ARTICLE X	Admission of Partners	A-59
Section 10.1	Admission of Limited Partners	A-59
Section 10.2	Admission of Successor General Partner.	A-60
Section 10.3	Amendment of Agreement and Certificate of Limited Partnership.	A-60
ARTICLE XI	Withdrawal or Removal of Partners	A-60
Section 11.1	Withdrawal of the General Partner.	A-60
Section 11.2	Removal of the General Partner.	A-62
Section 11.3	Interest of Departing General Partner and Successor General Partner.	A-62
Section 11.4	Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.	A-63
Section 11.5	Withdrawal of Limited Partners.	A-63
ARTICLE XII	Dissolution and Liquidation	A-63
Section 12.1	Dissolution.	A-63
Section 12.2	Continuation of the Business of the Partnership After Dissolution.	A-64
Section 12.3	Liquidator.	A-64
Section 12.4	Liquidation.	A-65

A-ii


		Page
Section 12.5	Cancellation of Certificate of Limited Partnership.	A-65
Section 12.6	Return of Contributions.	A-65
Section 12.7	Waiver of Partition.	A-65
Section 12.8	Capital Account Restoration.	A-65
ARTICLE XIII	Amendment of Partnership Agreement; Meetings; Record Date	A-66
Section 13.1	Amendments to be Adopted Solely by the General Partner.	A-66
Section 13.2	Amendment Procedures.	A-67
Section 13.3	Amendment Requirements.	A-67
Section 13.4	Special Meetings.	A-68
Section 13.5	Notice of a Meeting.	A-68
Section 13.6	Record Date.	A-68
Section 13.7	Adjournment.	A-68
Section 13.8	Waiver of Notice; Approval of Meeting; Approval of Minutes.	A-68
Section 13.9	Quorum and Voting.	A-69
Section 13.10	Conduct of a Meeting.	A-69
Section 13.11	Action Without a Meeting.	A-69
Section 13.12	Right to Vote and Related Matters.	A-70
ARTICLE XIV	Merger, Consolidation or Conversion	A-70
Section 14.1	Authority.	A-70
Section 14.2	Procedure for Merger, Consolidation or Conversion	A-70
Section 14.3	Approval by Limited Partners.	A-71
Section 14.4	Certificate of Merger.	A-72
Section 14.5	Effect of Merger, Consolidation or Conversion.	A-72
ARTICLE XV	Right to Acquire Limited Partner Interests	A-73
Section 15.1	Right to Acquire Limited Partner Interests.	A-73
ARTICLE XVI	General Provisions	A-75
Section 16.1	Addresses and Notices.	A-75
Section 16.2	Further Action.	A-75
Section 16.3	Binding Effect.	A-75
Section 16.4	Integration.	A-75
Section 16.5	Creditors.	A-75
Section 16.6	Waiver.	A-75
Section 16.7	Third-Party Beneficiaries.	A-75
Section 16.8	Counterparts.	A-75
Section 16.9	Applicable Law.	A-76
Section 16.10	Invalidity of Provisions.	A-76
Section 16.11	Consent of Partners.	A-76
Section 16.12	Facsimile Signatures.	A-76

A-iii

First Amended and Restated
Agreement of Limited Partnership
of
Quest Energy Partners, L.P.

This First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., dated as of , 2007, is entered into by and between Quest Energy GP, LLC, a Delaware limited liability company, as the General Partner, and Quest Resource Corporation, a Nevada corporation, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

Definitions

Section 1.1 Definitions. The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the production of the oil and gas properties or the asset base owned by of the Partnership Group over the long term from the production or operating capacity of the Partnership Group existing immediately prior to such transaction.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year, are reasonably expected to be made to such Partner’s Capital Account in respect of the oil and gas properties of the Partnership, (ii) the amount of

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all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a General Partner Unit, a Common Unit, a Subordinated Unit, a Class B Unit or an Incentive Distribution Right or any other Partnership Interest shall be the amount that such Adjusted Capital Account would be if such General Partner Unit, Common Unit, Subordinated Unit, Class B Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Unit, Common Unit, Subordinated Unit, Class B Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, Operating Surplus generated with respect to such period (a) less (i) any net increase in Working Capital Borrowings with respect to such period and (ii) any net decrease in cash reserves for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period, and (b) plus (i) any net decrease in Working Capital Borrowings with respect to such period and (ii) any net increase in cash reserves for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

“Aggregate Quantity of Class B Units” has the meaning assigned to such term in Section 5.11(a).

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the General Partner. The General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar

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fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of (i) all cash and cash equivalents of the Partnership Group on hand at the end of such Quarter, and (ii) all additional cash and cash equivalents of the Partnership Group on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter, less

(b) the amount of any cash reserves established by the General Partner to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.4 or Section 6.5 in respect of any one or more of the next four Quarters; provided, however, that the General Partner may not establish cash reserves pursuant to (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means the board of directors or managers, as applicable, of a corporation or limited liability company or the board of directors or board of managers, as applicable, of the general partner of a limited partnership.

“Book Basis Derivative Items” means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, gain, loss, Simulated Gain or Simulated Loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Oklahoma shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of a General Partner Unit, a Common Unit, a Subordinated Unit, a Class B Unit, an Incentive Distribution Right or any Partnership Interest shall be the amount that such Capital

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Account would be if such General Partner Unit, Common Unit, Subordinated Unit, Class B Unit, Incentive Distribution Right or other Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such General Partner Unit, Common Unit, Class B Unit, Subordinated Unit, Incentive Distribution Right or other Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership.

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new, capital assets (including, without limitation, oil and gas leases, mineral interests, drilling rigs, gathering lines, treating facilities, processing plants, pipelines and related or similar upstream assets) or (c) capital contributions by a Group Member to a Person in which a Group Member has an equity interest to fund such Group Member’s pro rata share of the cost of the acquisition of existing, or the construction of new, capital assets (including, without limitation, oil and gas leases, mineral interests, drilling rigs, gathering lines, treating facilities, processing plants, pipelines and related or similar upstream assets) by such Person, in each case if such addition, improvement, acquisition or construction is made to increase the production from oil and gas properties or the asset base of the Partnership Group over the long term, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the production or asset base of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, acquisition or construction.

“Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

“Carrying Value” initially means (a) with respect to a Contributed Property, the Agreed Value of such property as of the time of contribution, and (b) with respect to any other Partnership property, the initial adjusted tax basis of such property for federal income tax purposes as of the time of its acquisition by the Partnership. The initial Carrying Value of any property will thereafter be (i) reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such property and (ii) adjusted from time to time in accordance with Section 5.5(d)(i) and Section 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“claim” (as used in Section 7.12(d)) has the meaning assigned to such term in Section 7.12(d).

“Class B Units” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Class B Units in this Agreement.

“Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” has the meaning assigned to such term in Section 15.1(a).

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“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” has the meaning assigned to such term in Section 11.3(a).

“Commission” means the United States Securities and Exchange Commission.

“Common Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Subordinated Unit or Class B Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, as to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

“Conflicts Committee” means a committee of the Board of Directors of the General Partner composed entirely of two or more directors, each of whom (a) is not a security holder, officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner, (c) is not a holder of any ownership interest in the Partnership Group other than Common Units and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed or admitted to trading.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Contribution Agreement” means that certain Contribution, Conveyance and Assumption Agreement, dated as of the Closing Date, among the General Partner, the Partnership, the Operating Company and the other parties named therein, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

“Converted Common Units” has the meaning assigned to such term in Section 6.1(d)(x)(B).

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum resulting from adding together the Common Unit Arrearage as to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” has the meaning assigned to such term in Section 15.1(a).

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former general partner from and after the effective date of any withdrawal or removal of such former general partner pursuant to Section 11.1 or Section 11.2.

“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

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“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. For the avoidance of doubt, 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.

“Eligible Holder Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder.

“Eligible Holder Notice” means the giving of notice by the Partnership to the Limited Partners in the manner specified in Section 16.1 that the Partnership is implementing procedures pursuant to this Agreement to require a Limited Partner or a transferee of a Limited Partner to certify that such Person is an Eligible Holder.

“Estimated Average Maintenance Capital Expenditures” means an estimate, made in good faith, by the Board of Directors with the concurrence of the Conflicts Committee of the average quarterly Maintenance Capital Expenditures that the Partnership Group will incur over the long term. The Board of Directors will be permitted to make such estimate in any manner it deems reasonable in its sole discretion. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of quarterly Maintenance Capital Expenditures. The Partnership shall disclose to the Partners the amount of Estimated Average Maintenance Capital Expenditures. Except as provided in the definition of Subordination Period and in Section 5.7(h), any adjustments to Estimated Average Maintenance Capital Expenditures shall be prospective only.

“Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.9.

“Event of Withdrawal” has the meaning assigned to such term in Section 11.1(a).

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures. Expansion Capital Expenditures will include interest (and related fees) on debt incurred to finance the construction or development of a Capital Improvement and paid during the period beginning on the date that the Partnership enters into a binding commitment to commence construction or development of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement is put into service and the date that such Capital Improvement is abandoned or disposed of. Debt incurred to fund such construction period interest payments (including periodic net payments under related interest rate swap agreements) paid during such period shall also be deemed to be debt incurred to finance the construction or development of a Capital Improvement.

“Final Subordinated Units” has the meaning assigned to such term in Section 6.1(d)(x).

“First Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(E).

“First Target Distribution” means $0.46 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2007, it means the product of $0.46 multiplied by a fraction of which the numerator is the number of days in such period, and of which the denominator is 92), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Fully Diluted Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes, in addition to the Outstanding Units, all Partnership Securities and options, rights, warrants and appreciation rights relating to an equity interest in the Partnership (a) that are convertible into or exercisable or exchangeable for Units that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may

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be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Basis when calculating whether the Subordination Period has ended or Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Securities, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

“General Partner” means Quest Energy GP, LLC, a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified in this Agreement with respect to the General Partner Interest. A General Partner Unit is not a Unit.

“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Hedge Contract” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of a member of the Partnership Group shall be a Hedge Contract. If a Hedge Contract provides for settlement payments less frequently than quarterly, in calculating Operating Surplus and

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Operating Expenses, the General Partner may allocate the settlement payments over Quarterly periods in a manner approved by the Conflicts Committee.

“Hedge Payment” means any payment made or received by a member of the Partnership Group in connection with or pursuant to a Hedge Contract, including periodic settlement payments, and payments made or received in connection with the entering into, termination or modification of a Hedge Contract.

“Holder” as used in Section 7.12, has the meaning assigned to such term in Section 7.12(a).

“IDR Reset Election” has the meaning assigned to such term in Section 5.11(a).

“Incentive Distribution Right” means a non-voting Limited Partner Interest issued to the General Partner, which Limited Partner Interest will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

“Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Section 6.4(a)(v)(B), Section 6.4(a)(vi)(B), Section 6.4(b)(iii)(B), and Section 6.4(b)(iv)(B).

“Incremental Income Taxes” has the meaning assigned to such term in Section 6.9.

“Indemnified Persons” has the meaning assigned to such term in Section 7.12(d).

“Indemnitee” means (a) the General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a member, partner, director, officer, fiduciary or trustee of any Group Member, the General Partner or any Departing General Partner or any Affiliate of any Group Member, the General Partner or any Departing General Partner, (e) any Person who is or was serving at the request of the General Partner or any Departing General Partner or any Affiliate of the General Partner or any Departing General Partner as an officer, director, member, partner, fiduciary or trustee of another Person; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, and (f) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Initial Common Units” means the Common Units sold in the Initial Offering.

“Initial Limited Partners” means QRC and the General Partner (with respect to the Common Units, Subordinated Units and Incentive Distribution Rights received by them pursuant to Section 5.2) and the Underwriters upon the issuance by the Partnership of Common Units as described in Section 5.3(a) in connection with the Initial Offering.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of Units.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the exercise of the Over-Allotment Option); (c) sales

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or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of production, inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) the termination of commodity and interest rate swap agreements prior to the termination date specified therein; (e) capital contributions received; (f) corporate reorganizations or restructurings; or (g) sales in connection with plugging and abandoning and other reclamation activities for a well in which a Group Member owns an interest.

“Issue Price” means the price at which a Unit is purchased pursuant to the Underwriting Agreement, net of any sales commission or underwriting discount.

“Limited Partner” means, unless the context otherwise requires, the Organizational Limited Partner prior to its withdrawal from the Partnership, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Class B Units, Subordinated Units, Incentive Distribution Rights or other Partnership Securities or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any vote or other approval, including Article XIII and Article XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may otherwise be required by law.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures for the addition or improvement to the capital assets owned by any Group Member or for the acquisition of existing, or the construction of new, capital assets) if such expenditures are made to maintain production levels of the oil and gas properties or asset base of the Partnership Group over the long term.

“Merger Agreement” has the meaning assigned to such term in Section 14.1.

“Midstream Services and Gas Dedication Agreement” means that certain Midstream Services and Gas Dedication Agreement dated December 22, 2006, but effective December 1, 2006, by and between Bluestem Pipeline, LLC and QRC, as amended on August 9, 2007, by and between Bluestem Pipeline, LLC and QRC and which was assigned by QRC to the Partnership effective as of the date hereof.

“Minimum Quarterly Distribution” means $0.40 per Unit per Quarter (or with respect to the period commencing on the Closing Date and ending on December 31, 2007, it means the product of $0.40 multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Section 6.6 and Section 6.9.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act and any successor to such statute.

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“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

“Net Income” means, for any taxable year, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d); shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“Net Loss” means, for any taxable year, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xii) were not in this Agreement.

“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Partnership after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Non-Eligible Holder” means a Person whom the General Partner has determined does not constitute an Eligible Holder and as to whose Partnership Interest the General Partner has become the substituted limited partner, pursuant to Section 4.9.

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Section 6.2(d)(i)(A), Section 6.2(d)(ii)(A), and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

“Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in

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accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

“Notice of Election to Purchase” has the meaning assigned to such term in Section 15.1(b).

“Omnibus Agreement” means that certain Omnibus Agreement, dated as of the Closing Date, among QRC, the General Partner, the Partnership, and certain other parties thereto, as such may be amended, supplemented or restated from time to time.

“Operating Company” means Quest Cherokee, LLC, a Delaware limited liability company, the membership interests of which were acquired by the Partnership pursuant to the Contribution Agreement, and any successors thereto.

“Operating Expenditures” means all Partnership Group cash expenditures, including, but not limited to, lease operating expenditures, taxes, reimbursements of the General Partner, in accordance with this Agreement, interest payments, repayment of Working Capital Borrowings, and non-Pro Rata repurchases of Units (other than those made with the proceeds of an Interim Capital Transaction), subject to the following:

(a) repayment of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid;

(b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures; and

(c) Operating Expenditures shall not include (i) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (ii) distributions to Partners, (iii) Expansion Capital Expenditures or (iv) actual Maintenance Capital Expenditures, but shall include Estimated Average Maintenance Capital Expenditures. Where capital expenditures consist of both Maintenance Capital Expenditures and Expansion Capital Expenditures, the General Partner, with the concurrence of the Conflicts Committee, will determine the allocation between the portion consisting of Maintenance Capital Expenditures and the portion consisting of Expansion Capital Expenditures.

(d) Operating Expenditures in any Quarter shall include all Hedge Payments made by a member of the Partnership Group during such Quarter, provided, however, that the General Partner may treat all or any portion of any Hedge Payment as a Maintenance Capital Expenditure or Expansion Capital Expenditure, or may allocate a Hedge Payment among one or more Quarters, in either case with the approval of the Conflicts Committee.

“Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of (i) $25.9 million, (ii) all cash receipts of the Partnership Group for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.5), (iii) any decrease made during the period in cash reserves for Operating Expenditures, and (iv) all cash receipts of the Partnership Group after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings, less,

(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period, (ii) the amount of cash reserves established by the General Partner to provide funds for future Operating Expenditures and (iii) all Working Capital Borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional Working Capital Borrowings; provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such

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period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, (i) the General Partner may treat all or any portion of any Hedge Payment received by a member of the Partnership Group as an Interim Capital Transaction or may allocate such payment received over one or more Quarters, in either case with the approval of the Conflicts Committee and (ii) “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by QRC to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means QRC in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Securities of any class then Outstanding, all Partnership Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Units so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Units shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates, (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership with the prior approval of the Board of Directors of the General Partner.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Quest Energy Partners, L.P., a Delaware limited partnership.

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

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“Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including Common Units, Class B Units, Subordinated Units, General Partner Units and Incentive Distribution Rights.

“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any Unit held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“Percentage Interest” means as of any date of determination (a) as to the General Partner with respect to General Partner Units and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and General Partner Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

“Plan of Conversion” has the meaning assigned to such term in Section 14.1.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“QRC” means Quest Resource Corporation, a Nevada corporation.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the fiscal quarter of the Partnership that includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

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“Registration Statement” means the Registration Statement on Form S-1 as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the Unitholders holding Common Units, Class B Units or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) or Section 6.1(c)(ii) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(vii) or Section 6.1(d)(ix).

“Reset MQD” has the meaning assigned to such term in Section 5.11(e).

“Reset Notice” has the meaning assigned to such term in Section 5.11(b).

“Residual Gain” or “Residual Loss” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or Section 6.2(d)(ii)(A) respectively, to eliminate Book-Tax Disparities.

“Retained Converted Subordinated Unit” has the meaning assigned to such term in Section 5.5(c)(ii).

“Second Liquidation Target Amount” has the meaning assigned to such term in Section 6.1(c)(i)(F).

“Second Target Distribution” means $0.50 per Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2007, it means the product of $0.50 multiplied by a fraction of which the numerator is equal to the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units, Class B Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

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“Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

“Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property was its adjusted tax basis) and in the manner specified in Treasury Regulation Section 1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

“Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

“Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

“Special Approval” means approval by a majority of the members of the Conflicts Committee acting in good faith.

“Subordinated Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not include a Common Unit or Class B Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

“Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:

(a) the first day of any Quarter beginning after December 31, 2012 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of the Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all Outstanding Common Units, Subordinated Units and General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods and (B) the Adjusted Operating Surplus generated during each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units and General Partner Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis, and (ii) there are no Cumulative Common Unit Arrearages;

(b) the first date on which there are no longer outstanding any Subordinated Units due to the conversion of Subordinated Units into Common Units pursuant to Section 5.7 or otherwise; and

(c) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal.

For purposes of determining whether the test in subclause (a)(i)(B) above has been satisfied, Adjusted Operating Surplus will be adjusted upwards or downwards if the Conflicts Committee determines in good faith that the amount of Estimated Average Maintenance Capital Expenditures used in the determination of Adjusted Operating Surplus in subclause (a)(i)(B) was materially incorrect, based on circumstances prevailing at the time of original determination of Estimated Average Maintenance Capital Expenditures, for any one or more of the preceding four quarter periods.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of

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directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” has the meaning assigned to such term in Section 14.2(b).

“Target Distributions” means, collectively, the First Target Distribution and Second Target Distribution.

“Trading Day” has the meaning assigned to such term in Section 15.1(a).

“transfer” has the meaning assigned to such term in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as shall be appointed from time to time by the General Partner to act as registrar and transfer agent for the Common Units; provided, that if no Transfer Agent is specifically designated for any other Partnership Securities, the General Partner shall act in such capacity.

“Underwriter” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement dated as of , 2007, among the Underwriters, the Partnership, the General Partner, the Operating Company and other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units, Class B Units and Subordinated Units, each a separate class, but shall not include (i) General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class, and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units and Class B Units, if any, voting as a single class.

“Unitholders” means the holders of Units.

“Unpaid MQD” has the meaning assigned to such term in Section 6.1(c)(i)(B).

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted

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as the General Partner determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

“U.S. GAAP” means United States generally accepted accounting principles consistently applied.

“Withdrawal Opinion of Counsel” has the meaning assigned to such term in Section 11.1(b).

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners made pursuant to a credit facility, commercial paper facility or similar financing arrangement; provided, that when incurred it is the intent of the borrower to repay such borrowings within 12 months from other than additional Working Capital Borrowings.

Section 1.2 Construction. Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

ARTICLE II

Organization

Section 2.1 Formation. The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Quest Energy Partners, L.P. in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name. The name of the Partnership shall be “Quest Energy Partners, L.P.” The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices. Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at Corporation Trust Center, 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be The Corporation Trust Company. The principal office of the Partnership shall be located at Oklahoma Tower, 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner shall determine necessary or appropriate. The address of the General Partner shall be Oklahoma Tower, 210 Park Avenue, Suite 2750, Oklahoma City, Oklahoma 73102, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business. The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business

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activity that is approved by the General Partner and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may decline to propose or approve, the conduct by the Partnership of any business free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to so propose or approve, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

Section 2.5 Powers. The Partnership shall be empowered to do any and all acts and things necessary or appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Power of Attorney.

(a) Each Limited Partner hereby constitutes and appoints the General Partner and, if a Liquidator shall have been selected pursuant to Section 12.3, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise) and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

(i) execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (A) all certificates, documents and other instruments (including this Agreement and the Certificate of Limited Partnership and all amendments or restatements hereof or thereof) that the General Partner or the Liquidator determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Partnership as a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware and in all other jurisdictions in which the Partnership may conduct business or own property; (B) all certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement; (C) all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the General Partner or the Liquidator determines to be necessary or appropriate to reflect the dissolution and liquidation of the Partnership pursuant to the terms of this Agreement; (D) all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Partner pursuant to, or other events described in, Article IV, Article X, Article XI or Article XII; (E) all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Partnership Securities issued pursuant to Section 5.6; and (F) all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Partnership pursuant to Article XIV; and

(ii) execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the General Partner or the Liquidator determines to be necessary or appropriate to make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Partners hereunder or is consistent with the terms of this Agreement or effectuate the terms or intent of this Agreement; provided, that when required by Section 13.3 or any other provision of this Agreement that establishes a percentage of the Limited Partners or of the Limited Partners of any class or series required to take any action, the General Partner and the Liquidator may exercise the power of attorney made in this Section 2.6(a)(ii) only after the necessary vote, consent or approval of the Limited Partners or of the Limited Partners of such class or series, as applicable.

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(iii) Nothing contained in this Section 2.6(a) shall be construed as authorizing the General Partner to amend this Agreement except in accordance with Article XIII or as may be otherwise expressly provided for in this Agreement.

(b) The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Limited Partner and the transfer of all or any portion of such Limited Partner’s Partnership Interest and shall extend to such Limited Partner’s heirs, successors, assigns and personal representatives. Each such Limited Partner hereby agrees to be bound by any representation made by the General Partner or the Liquidator acting in good faith pursuant to such power of attorney; and each such Limited Partner, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the General Partner or the Liquidator taken in good faith under such power of attorney. Each Limited Partner shall execute and deliver to the General Partner or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as the General Partner or the Liquidator may request in order to effectuate this Agreement and the purposes of the Partnership.

Section 2.7 Term. The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.8 Title to Partnership Assets. Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

Rights of Limited Partners

Section 3.1 Limitation of Liability. The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business. No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participation in the control of the business of the Partnership by a

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limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners. Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership (provided that the requirements of this Section 3.4(a)(i) will be satisfied by furnishing to a Limited Partner upon its demand pursuant to this Section 3.4(a)(i) the Partnership’s most recent filings with the Commission on Form 10-K and any subsequent filings on Form 10-Q and 8-K);

(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner in good faith believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

ARTICLE IV

Certificates; Record Holders;
Transfer of Partnership Interests;
Redemption of Partnership Interests

Section 4.1 Certificates. Upon the Partnership’s issuance of Common Units, Subordinated Units or Class B Units to any Person, the Partnership shall issue, upon the request of such Person, one or more Certificates in the name of such Person (or, if issued in global form, in the name of the Depositary or its nominee) evidencing the number of such Units being so issued. In addition, (a) upon the General Partner’s

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request, the Partnership shall issue to it one or more Certificates in the name of the General Partner evidencing its General Partner Units and (b) upon the request of any Person owning Incentive Distribution Rights or any other Partnership Securities other than Common Units, Subordinated Units or Class B Units, the Partnership shall issue to such Person one or more certificates evidencing such Incentive Distribution Rights or other Partnership Securities other than Common Units, Subordinated Units or Class B Units. Certificates shall be executed on behalf of the Partnership by the Chairman of the Board, Chief Executive Officer, President or any Executive Vice President, Senior Vice President or Vice President and the Secretary or any Assistant Secretary of the General Partner. No Common Unit Certificate shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that the Units may be certificated or uncertificated as provided in the Delaware Act; provided further, that if the General Partner elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), the Partners holding Certificates evidencing Subordinated Units may exchange such Certificates for Certificates evidencing Common Units on or after the date on which such Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7. Subject to the requirements of Section 6.7(e), the Partners holding Certificates evidencing Class B Units may exchange such Certificates for Certificates evidencing Common Units on or after the period set forth in Section 5.11(f) pursuant to the terms of Section 5.11.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units), the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent (for Common Units) or the General Partner (for Partnership Securities other than Common Units) shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent (for Common Units) shall countersign, a new Certificate in place of any Certificate previously issued, or issue uncertificated Common Units, if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate or the issuance of uncertificated Units before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate or uncertificated Units.

(c) As a condition to the issuance of any new Certificate or uncertificated Unit under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental

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charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders. The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Partnership Interest.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Units to another Person or by which a holder of Incentive Distribution Rights assigns its Incentive Distribution Rights to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than an Incentive Distribution Right) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Partnership shall not recognize transfers of Certificates evidencing Limited Partner Interests or of uncertificated Limited Partner Interests, unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(b) Except as otherwise provided in Section 4.9, the General Partner shall not recognize any transfer of Limited Partner Interests until either (i) the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer or (ii) the receipt of proper transfer instructions from the registered owner of uncertificated Common Units. In addition, following an Eligible Holder Notice, the General Partner shall not recognize any transfer of Limited Partner Interests until such Certificates are also accompanied by an Eligible Holder Certification, properly completed and duly executed by the transferee (or the transferee’s attorney-in-fact duly authorized in writing). No charge shall be imposed by the General Partner for such

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transfer; provided, that as a condition to the issuance of any new Certificate representing Limited Partner Interests or uncertificated Limited Partner Interests under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

(c) Upon the receipt of proper transfer instructions from the registered owner of uncertificated Common Units, such uncertificated Common Units will be cancelled, issuance of new equivalent uncertificated Common Units or Certificates will be made to the holder of Common Units entitled thereto and the transaction will be recorded upon the books of the Partnership.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests (other than the Incentive Distribution Rights) shall be freely transferable.

(e) The General Partner and its Affiliates and QRC and its Affiliates shall have the right at any time to transfer their Subordinated Units, Class B Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c), prior to December 31, 2017, the General Partner shall not transfer all or any part of its General Partner Interest (represented by General Partner Units) to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c), on or after December 31, 2017, the General Partner may transfer all or any of its General Partner Interest without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability of any Limited Partner under the Delaware Act or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate portion thereof, if applicable) of the partnership or membership interest of the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.3, be admitted to the Partnership as the General Partner immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Transfer of Incentive Distribution Rights. Prior to December 31 2017, a holder of Incentive Distribution Rights may transfer any or all of the Incentive Distribution Rights held by such holder without any consent of the Unitholders to (a) an Affiliate of such holder (other than an individual) or (b) another Person (other than an individual) in connection with (i) the merger or consolidation of such holder of Incentive Distribution Rights with or into such other Person, (ii) the transfer by such holder of all or substantially all of its assets to such other Person or (iii) the sale of all the ownership interests in such holder. Any other transfer of the Incentive Distribution Rights prior to December 31, 2017 shall require the prior approval of holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates). On or after December 31, 2017, the General Partner or any other holder of Incentive

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Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval. Notwithstanding anything herein to the contrary, (i) the transfer of Class B Units issued pursuant to Section 5.11, or the transfer of Common Units issued upon conversion of the Class B Units, shall not be treated as a transfer of all or any part of the Incentive Distribution Rights and (ii) no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement.

Section 4.8 Restrictions on Transfers.

(a) Except as provided in Section 4.8(d), and notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it receives an Opinion of Counsel that such restrictions are necessary to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Subordinated Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(c).

(d) The transfer of a Class B Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7(e).

(e) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(f) Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF QUEST ENERGY PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF QUEST ENERGY PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, (C) CAUSE QUEST ENERGY PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED), OR (D) VIOLATE THE TERMS AND CONDITIONS OF THE FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF QUEST ENERGY PARTNERS, L.P., DATED , 2007, AS THE SAME MAY BE AMENDED FROM TIME TO TIME. QUEST ENERGY GP, LLC, THE GENERAL PARTNER OF QUEST ENERGY PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF QUEST ENERGY PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR

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FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.9 Eligible Holder Certifications; Non-Eligible Holders.

(a) Following an Eligible Holder Notice, if a transferee of a Limited Partner Interest fails to furnish a properly completed Eligible Holder Certification in the manner specified in Section 4.5(b) or if, upon receipt of such Eligible Holder Certification or otherwise, the General Partner determines that such transferee is not an Eligible Holder, the Limited Partner Interests owned by such transferee shall be subject to redemption in accordance with the provisions of Section 4.10.

(b) Following an Eligible Holder Notice, the General Partner may request any Limited Partner to furnish to the General Partner, within 30 days after receipt of such request, an executed Eligible Holder Certification or such other information concerning his nationality, citizenship or other related status (or, if the Limited Partner is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the General Partner may reasonably request. If a Limited Partner or assignee fails to furnish to the General Partner within the aforementioned 30-day period such Eligible Holder Certification or other requested information or if upon receipt of such Eligible Holder Certification or other requested information the General Partner determines that a Limited Partner is not an Eligible Holder, the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner may require that the status of any such Limited Partner be changed to that of a Non-Eligible Holder and, thereupon, the General Partner shall be substituted for such Non-Eligible Holder as the Limited Partner in respect of the Non-Eligible Holder’s Limited Partner Interests.

(c) Following an Eligible Holder Notice, the General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Non-Eligible Holders, distribute the votes in the same ratios as the votes of Partners (including without limitation the General Partner) in respect of Limited Partner Interests other than those of Non-Eligible Holders are cast, either for, against or abstaining as to the matter.

(d) Upon dissolution of the Partnership, a Non-Eligible Holder will have no right to receive a distribution in kind pursuant to Section 12.4 but will be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Non-Eligible Holder’s share of any distribution in kind. Such payment and assignment will be treated for Partnership purposes as a purchase by the Partnership from the Non-Eligible Holder of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(e) At any time after a Non-Eligible Holder can and does certify that it has become an Eligible Holder, such Non-Eligible Holder may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Non-Eligible Holder not redeemed pursuant to Section 4.10, such Non-Eligible Holder be admitted as a Limited Partner, and upon approval of the General Partner, such Non-Eligible Holder will be admitted as a Limited Partner and will no longer constitute a Non-Eligible Holder and the General Partner will cease to be deemed to be the Limited Partner in respect of such Non-Eligible Holder’s Limited Partner Interests.

Section 4.10 Redemption of Partnership Interests of Non-Eligible Holder.

(a) If at any time following an Eligible Holder Notice, a transferee of a Limited Partner Interest fails to furnish the General Partner an Eligible Holder Certification in the manner specified in Section 4.5(b) or any Limited Partner fails to furnish the General Partner an Eligible Holder Certification or other information requested within the 30-day period specified in Section 4.9(b), or if upon receipt of such Eligible Holder Certification or other information the General Partner determines that a Limited Partner or transferee is not an

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Eligible Holder, the Partnership may redeem the Limited Partner Interest of such Limited Partner or transferee as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner or transferee, at his last address designated on the records of the Partnership or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice will specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests or, if uncertificated, upon receipt of evidence satisfactory to the General Partner of the ownership of the Redeemable Interests, and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests will be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price will be paid as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of 7% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) Upon surrender by or on behalf of the Limited Partner, at the place specified in the notice of redemption, of (x) if certificated, the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank, or (y) if uncertificated, upon receipt of evidence satisfactory to the General Partner of the ownership of the Redeemable Interests, the Limited Partner or transferee or his duly authorized representative will be entitled to receive the payment therefor.

(iv) After the redemption date, Redeemable Interests will no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.10 will also be applicable to Limited Partner Interests held by a Limited Partner as a nominee of a Person determined to be other than an Eligible Holder.

(c) Nothing in this Section 4.10 will prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner in an Eligible Holder Certification that he is an Eligible Holder. If the transferee fails to make such certification, such redemption will be effected from the transferee on the original redemption date.

ARTICLE V

Capital Contributions and

Issuance of Partnership Interests

Section 5.1 Organizational Contributions. In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $20.00, for a 2% General Partner Interest in the Partnership and has been admitted as the General Partner of the Partnership, and the Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $980.00 for a 98% Limited Partner Interest in the Partnership and has been admitted as a Limited Partner of the Partnership. On the Closing Date, pursuant to the Contribution Agreement, the interest of the Organizational Limited Partner shall be partially redeemed in exchange for the return of the initial Capital Contribution of the Organizational Limited Partner. Ninety-eight percent of any interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated

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and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner.

Section 5.2 Contributions by the General Partner.

(a) On the Closing Date and pursuant to the Contribution Agreement, the General Partner shall contribute to the Partnership, as a Capital Contribution, 3.36279% of the limited liability company membership interests in the Operating Company, in exchange for (i) 431,827 General Partner Units representing a continuation of its 2% General Partner Interest, subject to all of the rights, privileges and duties of the General Partner under this Agreement and (ii) the Incentive Distribution Rights.

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership (other than the Common Units and Subordinated Units issued pursuant to Section 5.2(a), any Class B Units issued pursuant to Section 5.11 and any Common Units issued upon conversion of Class B Units), the General Partner may, in exchange for a proportionate number of General Partner Units with rights to allocations and distributions that correspond to those applicable to such additional Limited Partner Interests, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest immediately prior to the issuance of such additional Limited Partner Interests by the Partnership by (B) 100 less the General Partner’s Percentage Interest immediately prior to the issuance of such additional Limited Partner Interests by the Partnership times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Contribution Agreement, QRC shall contribute to the Partnership, as a Capital Contribution, 96.63721% of the limited liability company membership interests in the Operating Company, in exchange for an aggregate of 3,551,521 Common Units and 8,857,981 Subordinated Units.

(b) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contribution to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit.

(c) Upon the exercise of the Over-Allotment Option, each Underwriter shall contribute to the Partnership cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Partnership shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made in an amount equal to the quotient obtained by dividing (i) the cash contributions to the Partnership by or on behalf of such Underwriter by (ii) the Issue Price per Initial Common Unit. Upon receipt by the Partnership of the Capital Contributions from the Underwriters as provided in this Section 5.3(c), the Partnership shall use the net proceeds from such exercise to redeem a number of Common Units from QRC equal to the number of Common Units issued upon the exercise of the Over-Allotment Option.

(d) No Limited Partner Interests will be issued or issuable as of or at the Closing Date other than (i) the Common Units issuable pursuant to subparagraph (b) hereof in aggregate number equal to 8,750,000, (ii) the 8,857,981 Subordinated Units issuable to pursuant to subparagraph (a) hereof, (iii) the 3,551,521 Common Units issuable pursuant to subparagraph (a) hereof, and (iv) the Incentive Distribution Rights.

Section 5.4 Interest and Withdrawal. No interest shall be paid by the Partnership on Capital Contributions. No Partner or Assignee shall be entitled to the withdrawal or return of its Capital Contribution, except

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to the extent, if any, that distributions made pursuant to this Agreement or upon termination of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). The initial Capital Account balance attributable to the General Partner Units issued to the General Partner pursuant to Section 5.2(a) will equal the Net Agreed Value of the Capital Contribution specified in Section 5.2(a), which will be deemed to equal the product of the number of General Partner Units issued to the General Partner pursuant to Section 5.2(a) and the Initial Unit Price for each Common Unit (and the initial Capital Account balance attributable to each General Partner Unit will equal the Initial Unit Price for each Common Unit). The initial Capital Account balance attributable to the Common Units and Subordinated Units issued to QRC pursuant to Section 5.3(a) will equal the Net Agreed Value of the Capital Contribution specified in Section 5.3(a), which will be deemed to equal the product of the number of Common Units and Subordinated Units issued to QRC pursuant to Section 5.3(a) and the Initial Unit Price for each such Common Unit and Subordinated Unit (and the initial Capital Account balance attributable to each such Common Unit and Subordinated Unit will equal its Initial Unit Price). The initial Capital Account balance attributable to the Common Units issued to the Underwriters pursuant to Section 5.3(b) will equal the product of the number of Common Units so issued to the Underwriters and the Initial Unit Price for each such Common Unit (and the initial Capital Account balance attributable to each such Common Unit will equal its Initial Unit Price). Thereafter, the Capital Account will in respect of each such Partnership Interest be increased by (i) the amount of all cash and the Net Agreed Value of any property contributed to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement or governing, organizational or similar documents) of all property owned by (x) any other Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can be neither deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain or Simulated

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Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) An item of income of the Partnership that is described in Section 705(a)(1)(B) of the Code (with respect to items of income that are exempt from tax) will be treated as an item of income for the purpose of this Section 5.5(b) and an item of expense of the Partnership that is described in Section 705(a)(2)(B) of the Code (with respect to expenditures that are not deductible and not chargeable to capital accounts), will be treated as an item of deduction for the purpose of this Section 5.5(b).

(vi) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery, amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery, amortization or Simulated Depletion, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using a rate of depreciation, cost recovery, amortization or Simulated Depletion derived from the same method and useful life (or, if applicable, the remaining useful life) as is applied for federal income tax purposes; provided, however, that, if the asset has a zero adjusted basis for federal income tax purposes, depreciation, cost recovery, amortization or Simulated Depletion deductions shall be determined using any method that the General Partner may adopt.

(vii) If the Partnership’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Partners pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Partners to whom such deemed deduction was allocated.

(c) (i) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this Section 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units (“Retained Converted Subordinated Units”). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove. Immediately after the issuance of Class B Units to the holder of the

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Incentive Distribution Rights pursuant to Section 5.11, the entire Capital Account balance of such holder with respect to its Incentive Distribution Rights immediately prior to such issuance will (A) first, be allocated to (and will constitute such holder’s initial Capital Account balance in respect of) the Class B Units issued in an amount equal to the product of (x) the number of such Class B Units to be issued and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will constitute such holder’s Capital Account balance with respect to the Incentive Distribution Rights retained by such holder.

(d) (i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services, the issuance of Class B Units pursuant to Section 5.11 or the conversion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Account of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property or cash (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of each Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Securities.

(a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Security; (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion

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or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6, (ii) the conversion of the General Partner Interest (represented by General Partner Units) or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, (iii) the issuance of Class B Units pursuant to Section 5.11 and the conversion of Class B Units into Common Units pursuant to the terms of this Agreement, (iv) the issuance of Common Units upon the conversion of Subordinated Units pursuant to Section 5.7, (v) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holder of such Limited Partner Interest, and (vi) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the General Partner Interest or any Incentive Distribution Rights into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.7 Conversion of Subordinated Units.

(a) A total of 25% of the Outstanding Subordinated Units will convert automatically into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2010, in respect of which:

(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods;

(ii) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis; and

(iii) there are no Cumulative Common Unit Arrearages.

(b) An additional 25% of the Subordinated Units Outstanding on the date Subordinated Units were converted under Section 5.7(a) (adjusted for any splits or combinations as provided in Section 5.9) will convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2011, in respect of which:

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consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods;

(ii) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the Common Units, Subordinated Units, General Partner Units and any other Units that are senior or equal in right of distribution to the Subordinated Units that were Outstanding during such periods on a Fully Diluted Basis; and

(iii) there are no Cumulative Common Unit Arrearages; provided, however, that the conversion of Subordinated Units pursuant to this Section 5.7(b) may not occur until at least one year following the end of the last four-Quarter period in respect of which conversion of Subordinated Units pursuant to Section 5.7(a) occurred.

(c) All of the Outstanding Subordinated Units will convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter ending on or after December 31, 2010, in respect of which:

(i) distributions of Available Cash from Operating Surplus under Section 6.4(a) on each of the Outstanding Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units with respect to each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded 125% of the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods;

(ii) the Adjusted Operating Surplus for each of the two consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded 125% of the sum of the Minimum Quarterly Distribution on all of the Outstanding Common Units, Subordinated Units, General Partner Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units during such periods on a Fully Diluted Basis; and

(iii) there are no Cumulative Common Unit Arrearages.

(d) If less than all of the Outstanding Subordinated Units shall convert into Common Units pursuant to Section 5.7(a), Section 5.7(b) or Section 5.7(c) at a time when there shall be more than one holder of Subordinated Units, then, unless all of the holders of Subordinated Units shall agree to a different allocation, the Subordinated Units that are to be converted into Common Units shall be allocated among the holders of Subordinated Units pro rata based on the number of Subordinated Units held by each such holder.

(e) Any Subordinated Units that are not converted into Common Units pursuant to Section 5.7(a), Section 5.7(b) or Section 5.7(c) shall convert into Common Units on a one-for-one basis on the second Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of the final Quarter of the Subordination Period.

(f) Notwithstanding any other provision of this Agreement, all the then Outstanding Subordinated Units will automatically convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

(g) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7(b) and Section 6.7(c).

(h) For purposes of determining whether the test in Section 5.7(a), Section 5.7(b) or Section 5.7(c) above has been satisfied, Adjusted Operating Surplus will be adjusted upwards or downwards if the Conflicts Committee determines in good faith that the amount of Estimated Average Maintenance Capital Expenditures used in the determination of Adjusted Operating Surplus was materially incorrect, based on circumstances

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prevailing at the time of the original determination of Estimated Average Maintenance Capital Expenditures, for any one or more of the preceding four quarter periods referenced in Section 5.7(a), Section 5.7(b) or Section 5.7(c).

Section 5.8 Limited Preemptive Right. Except as provided in this Section 5.8 and Section 5.2, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates equal to that which existed immediately prior to the issuance of such Partnership Securities.

Section 5.9 Splits and Combinations.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units (including the number of Subordinated Units that may convert prior to the end of the Subordination Period) are proportionately adjusted.

(b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates or uncertificated Partnership Securities to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests. All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 and Section 17-804 of the Delaware Act.

Section 5.11 Issuance of Class B Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, at any time when there are no Subordinated Units outstanding and the Partnership has made a distribution pursuant to Section 6.4(b)(iv) for each of the four

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most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the “IDR Reset Election”) to cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Class B Units derived by dividing (i) the average amount of cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b)) in respect of the Incentive Distribution Rights by (ii) the average of the cash distributions made by the Partnership in respect of each Common Unit for each of the two full Quarters immediately preceding the giving of the Reset Notice (the number of Class B Units determined by such quotient is referred to herein as the “Aggregate Quantity of Class B Units”). Upon the issuance of such Class B Units, the Partnership will issue to the General Partner that number of additional General Partner Units equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner immediately prior to such issuance by (B) a percentage equal to 100% less such Percentage Interest by (y) the number of such Class B Units, and the General Partner shall not be obligated to make any additional Capital Contribution to the Partnership in exchange for such issuance. The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive Class B Units and General Partner Units on the basis specified above, without any further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

(b) To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the “Reset Notice”) to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership’s determination of the aggregate number of Class B Units that each holder of Incentive Distribution Rights will be entitled to receive.

(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of Class B Units and related additional General Partner Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice, and the Partnership shall issue Class B Unit Certificates or uncertificated Class B Units to the holder or holders of the Incentive Distribution Rights; provided, however, that the issuance of Class B Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of the Common Units into which the Class B Units are convertible pursuant to Section 5.11(f) by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

(d) If the principal National Securities Exchange upon which the Common Units are then traded have not approved the listing or admission for trading of the Common Units into which the Class B Units are convertible pursuant to Section 5.11(f) on or before the 30th calendar day following the Partnership’s receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Securities having such terms as the General Partner may approve, with the approval of the Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of Class B Units would have had at the time of the Partnership’s receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion of such Partnership Securities into Common Units within not more than 12 months following the Partnership’s receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more

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than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

(e) The Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution shall be adjusted at the time of the issuance of Class B Units or other Partnership Securities pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal the average cash distribution amount per Common Unit for the two Quarters immediately prior to the Partnership’s receipt of the Reset Notice (the “Reset MQD”), (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD and (iii) the Second Target Distribution shall be reset to equal to 125% of the Reset MQD.

(f) Any holder of Class B Units shall have the right to elect, by giving written notice to the General Partner, to convert all or a portion of the Class B Units held by such holder, at any time following the first anniversary of the issuance of such Class B Units, into Common Units on a one-for-one basis, such conversion to be effective on the second Business Day following the General Partner’s receipt of such written notice.

ARTICLE VI

Allocations and Distributions

Section 6.1 Allocations for Capital Account Purposes. For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.5(b) and Section 5.5(d)) shall be allocated among the Partners in each taxable year (or portion thereof) as provided below.

(a) Net Income. After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated as follows:

(i) First, 100% to the General Partner, in an amount equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable year and all previous taxable years is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(iii) for all previous taxable years;

(ii) Second, 100% to the General Partner and the Unitholders, in proportion to, and until the aggregate Net Income allocated pursuant to this Section 6.1(a)(ii) for the current taxable year and all previous taxable years is equal to, the aggregate Net Losses allocated to such Partners pursuant to Section 6.1(b)(ii) for all previous taxable years; and

(iii) Thereafter, the balance, if any, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests.

(b) Net Losses. After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated as follows:

(i) First, 100% to the General Partner and the Unitholders, in proportion to, and until the aggregate Net Losses allocated to such Partners pursuant to this Section 6.1(b)(i) for the current taxable year and all previous taxable years is equal to, the aggregate Net Income allocated to such Partners pursuant to Section 6.1(a)(iii) for all previous taxable years, provided that the Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account);

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(ii) Second, 100% to the General Partner and the Unitholders, in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(ii) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account); and

(iii) Thereafter, the balance, if any, 100% to the General Partner.

(c) Net Termination Gains and Losses. After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Gain shall be allocated among the Partners in the following manner (and the Capital Accounts of the Partners shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

(A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Class B Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Class B Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Class B Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(b)(i) with respect to such Class B Unit for such Quarter;

(D) Fourth, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

(E) Fifth, to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to

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Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of (1), (2), (3) and (4) is hereinafter defined as the “First Liquidation Target Amount”);

(F) Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of (1) and (2) is hereinafter defined as the “Second Liquidation Target Amount”); and

(G) Thereafter, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (G).

(ii) If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.5(d)), such Net Termination Loss shall be allocated among the Partners in the following manner:

(A) First, if such Net Termination Loss is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Class B Unitholders, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until the Capital Account in respect of each Class B Unit then Outstanding has been reduced to zero;

(C) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest until the Capital Account in respect of each Unit then Outstanding has been reduced to zero; and

(D) Thereafter, the balance, if any, 100% to the General Partner.

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this

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Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for a taxable year is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) there shall be allocated income, gain and Simulated Gain to each Unitholder receiving such greater cash or property distribution until the aggregate amount of such items allocated pursuant to this Section 6.1(d)(iii)(A) for the current taxable year and all previous taxable years is equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated income, gain and Simulated Gain in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs by (y) 100% less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs times (bb) the sum of the amounts allocated in clause (1) above.

(B) After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership income, gain and Simulated Gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable year; and (2) to the General Partner an amount equal to the product obtained by multiplying (a) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) 100% less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership income, gain and Simulated Gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

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(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset), loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain, loss, Simulated Gain or Simulated Loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity.

(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership income, gain or Simulated Gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of income, gain or Simulated Gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount equal to the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

(B) At the election of the General Partner with respect to any taxable period ending upon, or after, the conversion of the Class B Units pursuant to Section 5.11(f), all or a portion of the remaining items of Partnership income, gain or Simulated Gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii) and Section 6.1(d)(x)(A), or all or a portion of the Partnership’s items of loss and deduction, shall be allocated 100% to the holder or holders of the Common Units resulting from the conversion pursuant to Section 5.11(f) (“Converted Common Units”) in the proportion of the number of the Converted Common Units held by such holder or holders to the total number of Converted

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Common Units then Outstanding, until each such holder has been allocated an amount of income, gain or Simulated Gain that increases, or an amount of loss and deduction, as the case may be, the Capital Account maintained with respect to such Converted Common Units to an amount equal to the product of (A) the number of Converted Common Units held by such holder and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Converted Common Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the receipt of Common Units pursuant to Section 5.11(f).

(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partnership Minimum Gain and (2) Partner Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Partner Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners. Further, allocations pursuant to this Section 6.1(d)(xi)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the General Partner determines that such allocations are likely to be offset by subsequent Required Allocations.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d)), the General Partner shall allocate additional items of income, gain and Simulated Gain away from the holders of Incentive Distribution Rights to the Unitholders and the General Partner, or additional items of deduction, loss, Simulated Depletion or Simulated Loss away from the Unitholders and the General Partner to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders or the General Partner exceed their Share of Additional Book Basis Derivative Items. For this purpose, the Unitholders and the General Partner shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders or the General Partner under the Partnership Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this Section 6.1(d)(xii)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

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(B) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c).

(C) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii).

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Partners rather than by the Partnership in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Partnership under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Partners in accordance with their respective Percentage Interests. Each Partner shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Partnership.

(c) Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Partner on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Partnership’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Partners as follows:

(i) first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Partners in the same proportion as the depletable basis of such property was allocated to the Partners pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii);

(ii) second, the remainder of such amount realized, if any, to the Partners so that, to the maximum extent possible, the amount realized allocated to each Partner under this Section 6.2(c)(ii) will equal such Partner’s share of the Simulated Gain recognized by the Partnership from such sale or disposition.

(iii) The Partners recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Partners to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d).

(iv) Any elections or other decisions relating to such allocations shall be made by the Board of Directors in any manner that reasonably reflects the purpose and intention of the Agreement.

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(d) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than oil and gas properties pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

(e) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(f) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Partnership’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-1(a)(6), Treasury Regulation Section 1.197-2(g)(3), the legislative history to Section 743 or any successor regulations thereto. If the General Partner determines that such reporting position cannot be reasonably taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(g) In accordance with Treasury Regulation Section 1.1245-1(e), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income

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in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(h) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(i) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(j) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2007, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 17-607 of the Delaware Act, be distributed in accordance with this Article VI by the Partnership to the Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” Notwithstanding any provisions to the contrary contained in this Agreement, the Partnership shall not make a distribution to any Partner on account of its interest in the Partnership if such distribution would violate the Delaware Act or any other applicable law.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

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Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall, subject to Section 17-607 of the Delaware Act, be distributed as follows, except as otherwise contemplated by Section 5.6 in respect of other Partnership Securities issued pursuant thereto:

(i) First, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

(iii) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(iv) Fourth, to the General Partner and all Unitholders, in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(v) Fifth, (A) to the General Partner in accordance with its Percentage Interest, (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v) until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter; and

(vi) Thereafter, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this subclause (vi);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, and the Second Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vi).

(b) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5, subject to Section 17-607 of the Delaware Act, shall be distributed as follows, except as otherwise required by Section 5.6(b) in respect of additional Partnership Securities issued pursuant thereto:

(i) First, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter; and

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(iv) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclause (A) and (B) of this clause (iv);

Section 6.5 Distributions of Available Cash from Capital Surplus. Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 17-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders in accordance with their respective Percentage Interests, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price. Available Cash that is deemed to be Capital Surplus shall then be distributed (A) to the General Partner in accordance with its Percentage Interest and (B) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

(a) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Securities in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution, shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Initial Unit Price of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Initial Unit Price of the Common Units immediately prior to giving effect to such distribution.

(b) The Minimum Quarterly Distribution, First Target Distribution, and Second Target Distribution shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units and Class B Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Section 5.5(c)(ii), Section 6.1(d)(x)(A), Section 6.7(b) and Section 6.7(c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

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(c) The Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate or an uncertificated Common Unit pursuant to Section 4.1, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Section 5.5(c)(ii), Section 6.1(d)(x) and Section 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

(d) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holders of Class B Units shall have all the rights and obligations of a Unitholder holding Common Units; provided, however, that immediately upon the conversion of Class B Units into Common Units pursuant to Section 5.11, the Unitholders holding a Class B Unit shall possess all the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Class B Units shall remain subject to the provisions of Section 6.1(d)(x)(B) and Section 6.7(e).

(e) The holder or holders of Common Units resulting from the conversion pursuant to Section 5.11(f) of any Class B Units pursuant to Section 5.11 shall not be issued a Common Unit Certificate or an uncertificated Common Unit pursuant to Section 4.1, and shall not be permitted to transfer such Common Units to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(e), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units, including the application of Section 6.1(d)(x)(B); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights. Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (ii) be entitled to any distributions other than as provided in Section 6.4(a)(v), Section 6.4(a)(vi), Section 6.4(b)(iii), Section 6.4(b)(iv), and Section 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

Section 6.9 Entity-Level Taxation. If legislation is enacted or the interpretation of existing language is modified by a governmental taxing authority so that a Group Member is treated as an association taxable as a corporation or is otherwise subject to an entity-level tax for federal, state or local income tax purposes, then the General Partner may reduce the Minimum Quarterly Distribution, the First Target Distribution and the Second Target Distribution by the amount of income taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Taxes”), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General Partner elects to reduce the Minimum Quarterly Distribution, the First Target Distribution and the Second Target Distribution for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such

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estimate and the actual tax liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the General Partner, be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII

Management and Operation of Business

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Partnership Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

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(viii) the maintenance of insurance for the benefit of the Partnership Group, the Partners and Indemnitees;

(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants, appreciation rights and tracking and phantom interests relating to Partnership Securities;

(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Omnibus Agreement, the Contribution Agreement, the Midstream Services and Gas Dedication Agreement, any Group Member Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the General Partner (on its own or through any officer of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the Assignees or the other Persons who may acquire an interest in Partnership Securities; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty stated or implied by law or equity.

Section 7.2 Certificate of Limited Partnership. The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other

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entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority. Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such encumbrance. Without the approval of holders of a Unit Majority, the General Partner shall not, on behalf of the Partnership, except as permitted under Section 4.6, Section 11.1 and Section 11.2, elect or cause the Partnership to elect a successor general partner of the Partnership.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner, Group Member or any Affiliates in each case for the benefit of employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates from the Partnership to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest (represented by General Partner Units) pursuant to Section 4.6.

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Section 7.5 Outside Activities.

(a) After the Closing Date, the General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement or (B) the acquiring, owning or disposing of debt or equity securities in any Group Member.

(b) Each Indemnitee (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty expressed or implied by law or equity to any Group Member or any Partner or Assignee. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Indemnitee.

(c) Notwithstanding anything to the contrary in this Agreement or any duty existing at law, in equity or otherwise, but subject to Section 7.5(d), (i) the engaging in competitive activities by any Indemnitees (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of any Indemnitee for the Indemnitees (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Indemnitees shall have no obligation hereunder or as a result of any duty expressed or implied by law to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Indemnitee (including the General Partner). No Indemnitee (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Indemnitee (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Indemnitee (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided such Indemnitee does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Indemnitee.

(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired pursuant to the Contribution Agreement and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units or other Partnership Securities acquired by them. The term “Affiliates” when used in this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) The Partners (and the General Partner on behalf of the Partnership) hereby:

(i) agree that (A) the terms of this section, to the extent that they modify or limit a duty, if any, that a Partner may have to the Partnership or another Partner are reasonable in form, scope and content; and (B) the terms of this section shall control to the fullest extent possible if it is in conflict with a duty, if any, that a Partner may have to the Partnership or another Partner, the Act or any other applicable law, rule or regulation; and

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(ii) waive a duty, if any, that a Partner may have to the Partnership or another Partner, under the Act or any other applicable law, rule or regulation to the extent necessary to give effect to the terms of this section;

(iii) it being expressly acknowledged and affirmed by the Partners (and the General Partner on behalf of the Partnership) that the execution and delivery of this Agreement by the Partners are of material benefit to the Partnership and the Partners and that the Partners would not be willing to execute and deliver this Agreement without the benefit of this section.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty, expressed or implied, of the General Partner or its Affiliates to the Partnership or the Limited Partners existing hereunder, or existing at law, in equity or otherwise by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement, the Omnibus Agreement, or the Contribution Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions described by the Registration Statement (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable

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for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a determination that the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be determined that the Indemnitee is not entitled to be indemnified as authorized in this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith

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or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval. If Special Approval is sought, then it will be presumed that, in making its decision, the Conflicts Committee acted in good faith, and if Special Approval is not sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in either case, in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement.

(b) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, or such Affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking

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or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner, and the General Partner, or such Affiliates causing it to do so, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” or some variation of that phrase, is used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity. The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a limited partnership.

(d) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be at its option.

(e) Except as expressly set forth in this Agreement or required by the Delaware Act, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(f) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely and shall be protected in acting or refraining from acting upon any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership or any Group Member.

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Section 7.11 Purchase or Sale of Partnership Securities. The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities; provided that, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. Such Partnership Securities shall be held by the Partnership as treasury securities unless they are expressly cancelled by action of an appropriate officer of the General Partner. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Articles IV and X.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the “Holder”) to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a) and Section 7.12(b) and provided further that if the Conflicts Committee determines in good faith that the requested registration would be materially detrimental to the Partnership and its Partners because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to postpone such requested registration for a period of not more than six months after receipt of the Holder’s request, such right pursuant to this Section 7.12(a) or Section 7.12(a) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership will be deemed not to have used commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to the first sentence of this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If any Holder holds Partnership Securities that it desires to sell and Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such Holder to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so

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without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective date or such shorter period as shall terminate when all Partnership Securities covered by such shelf registration statement have been sold, a “shelf” registration statement covering the Partnership Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a) and Section 7.12(b) and provided further that if the Conflicts Committee determines in good faith that any offering under, or the use of any prospectus forming a part of, the shelf registration statement would be materially detrimental to the Partnership and its Partners because such offering or use would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Partnership, (y) require premature disclosure of material information that the Partnership has a bona fide business purpose for preserving as confidential or (z) render the Partnership unable to comply with requirements under applicable securities laws, then the Partnership shall have the right to suspend such offering or use for a period of not more than six months after receipt of the Holder’s request, such right pursuant to Section 7.12(a) or this Section 7.12(a) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Partnership will be deemed not to have used commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Partnership Securities covered thereby not being able to offer and sell such Partnership Securities at any time during such period, unless such action is required by applicable law. In connection with any shelf registration pursuant to this Section 7.12(a), the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such shelf registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such shelf registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such shelf registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(d), all costs and expenses of any such shelf registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Partnership for cash (other than an offering relating solely to an employee benefit plan), the Partnership shall notify all Holders of such proposal and use all reasonable efforts to include such number or amount of securities held by the Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the securities of the Holder once the registration statement is declared effective by the Commission or otherwise becomes effective, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(c) shall be an underwritten offering, then, if the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the success of the offering, the Partnership shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(d), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(d) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not

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in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(d) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or any free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or any free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(e) The provisions of Section 7.12(a), Section 7.12(a) and Section 7.12(c) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates), after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period. The provisions of Section 7.12(d) shall continue in effect thereafter.

(f) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(g) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution (unless the request is made pursuant to Section 7.12(b)), (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13 Reliance by Third Parties. Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no

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event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

Books, Records, Accounting and Reports

Section 8.1 Records and Accounting. The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual as is in accordance with U.S. GAAP.

Section 8.2 Fiscal Year. The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s or the Commission’s website) to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means (including posting on or accessible through the Partnership’s or the Commission’s website) to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

ARTICLE IX

Tax Matters

Section 9.1 Tax Returns and Information. The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable year or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable year other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable year of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax

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reporting purposes with respect to a taxable year shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(i) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies. Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding. Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner or Assignee (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Partner.

ARTICLE X

Admission of Partners

Section 10.1 Admission of Limited Partners

(a) Upon the issuance by the Partnership of Common Units, Subordinated Units and Incentive Distribution Rights to the General Partner, QRC and the Underwriters as described in Article V, the General Partner shall admit such parties to the Partnership as Initial Limited Partners in respect of the Common Units, Subordinated Units or Incentive Distribution Rights issued to them.

(b) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger consolidation pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer, issuance or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement, (iv) grants the powers of attorney set forth in this Agreement and (v) makes the consents

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and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is a Non-Eligible Holder shall be determined in accordance with Section 4.9.

(c) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate or be uncertificated, as provided in Section 4.1.

(d) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b).

Section 10.2 Admission of Successor General Partner. A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest (represented by General Partner Units) pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or Section 11.2 or the transfer of the General Partner Interest (represented by General Partner Units) pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

Section 10.3 Amendment of Agreement and Certificate of Limited Partnership. To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership, and the General Partner may for this purpose, among others, exercise the power of attorney granted pursuant to Section 2.6.

ARTICLE XI

Withdrawal or Removal of Partners

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its rights as General Partner pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this

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Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), Section 11.1(a)(v), or Section 11.1(a)(vi)(A), Section 11.1(a)(vi)(B), Section 11.1(a)(vi)(C) or Section 11.1(a)(vi)(E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 12:00 midnight, Central Standard Time, on December 31, 2017, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability of any Limited Partner or any Group Member or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 12:00 midnight, Central Standard Time, on December 31, 2017, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to (c) Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal, a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

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Section 11.2 Removal of the General Partner. The General Partner may be removed if such removal is approved by the Unitholders holding at least 662/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units and Class B Units, if any, voting as a single class and a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner, to require its successor to purchase its General Partner Interest (represented by General Partner Units) and its general partner interest (or equivalent interest), if any, in the other Group Members and all of its Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its departure. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the departure of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest of the Departing General Partner. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Departing General Partner’s Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s departure, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such departure, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall

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determine the fair market value of the Combined Interest of the Departing General Partner. In making its determination, such third independent investment banking firm or other independent expert may consider the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and its Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest of the Departing General Partner to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed its Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of the (x) quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages. Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist and Units held by the General Partner and its Affiliates are not voted in favor of such removal, (i) the Subordination Period will end and all Outstanding Subordinated Units will immediately and automatically convert into Common Units on a one-for-one basis, (ii) all Cumulative Common Unit Arrearages on the Common Units will be extinguished and (iii) the General Partner will have the right to convert its General Partner Interest (represented by General Partner Units) and its Incentive Distribution Rights into Common Units or to receive cash in exchange therefor in accordance with Section 11.3.

Section 11.5 Withdrawal of Limited Partners. No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

Dissolution and Liquidation

Section 12.1 Dissolution. The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1 or Section 11.2, the Partnership shall not be dissolved and such successor General

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Partner shall continue the business of the Partnership. The Partnership shall dissolve, and (subject to Section 12.2) its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in (b) Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and an Opinion of Counsel is received as provided in Section 11.1(b) or Section 11.2 and such successor is admitted to the Partnership pursuant to Section 10.2;

(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution. Upon (a) dissolution of the Partnership following an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or Section 11.1(a)(iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) dissolution of the Partnership upon an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), Section 11.1(a)(v) or Section 11.1(a)(vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement; provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability of any Limited Partner and (y) neither the Partnership nor any Group Member would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator. Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units, Class B Units (if any), and Subordinated Units voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units, Class B Units (if any), and Subordinated Units voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units, Class B Units (if any), and Subordinated Units voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article XII, the Liquidator approved in the manner provided herein shall

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have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation. The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable year of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership. Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions. The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

Section 12.7 Waiver of Partition. To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration. No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable year of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

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ARTICLE XIII

Amendment of Partnership Agreement;

Meetings; Record Date

Section 13.1 Amendments to be Adopted Solely by the General Partner. Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the Limited Partners have limited liability under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines, (i) does not adversely affect in any material respect the Limited Partners (considered as a whole or any particular class of Partnership Interests as compared to other classes of Partnership Interests), (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable year of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Partnership Securities pursuant to Section 5.6, including any amendment that the General Partner determines is necessary or appropriate in connection with (i) the adjustments of the Minimum Quarterly Distribution, First Target Distribution and Second Target Distribution pursuant to the provisions of Section 5.11, (ii) the implementation of the provisions of Section 5.11 or (iii) any modifications to the Incentive Distribution Rights made in connection with the issuance of Partnership Securities pursuant to Section 5.6, provided that, with respect to this clause (iii), the modifications to the Incentive Distribution Rights and the related issuance of Partnership Securities have received Special Approval;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

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(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4;

(k) merger, conveyance or conversion pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures. Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the requirements contained in this Section 13.2. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that to the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any Limited Partner and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units (including Units deemed owned by the General Partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

(b) Notwithstanding the provisions of Section 13.1 and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

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(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings. All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting. Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

Section 13.6 Record Date. For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern) or (b) if approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes. The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

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Section 13.9 Quorum and Voting. The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units deemed owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Outstanding Units specified in this Agreement (including Outstanding Units deemed owned by the General Partner). In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting (including Outstanding Units deemed owned by the General Partner) represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting. The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting. If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units (including Units deemed owned by the General Partner) that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner, (b) approvals sufficient to take the action proposed are dated as of a date not more than 90 days prior to the date sufficient approvals are deposited with the Partnership and (c) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize

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the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

Merger, Consolidation or Conversion

Section 14.1 Authority. The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) name and state of domicile of each of the business entities proposing to merge or consolidate;

(ii) the name and state of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any general or limited partner interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity, the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation,

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trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such general or limited partner interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property or general or limited partner interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, operating agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of merger and stated therein); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such articles of conversion and stated therein); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion, as applicable, be submitted to a vote of Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

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(b) Except as provided in Section 14.3(d), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority.

(c) Except as provided in Section 14.3(d), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or articles of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to the Partnership Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation do not exceed 20% of the Partnership Securities Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

Section 14.4 Certificate of Merger. Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or articles of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each a constituent business entity;

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(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the articles of conversion:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall continue to be owned by the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and may be pursued by such creditors and obligees as if the conversion did not occur;

(v) a proceeding pending by or against the Partnership or by or against any of Partners in their capacities as such may be continued by or against the converted entity in its new organizational form and by or against the prior partners without any need for substitution of parties; and

(vi) the Partnership Units that are to be converted into partnership interests, shares, evidences of ownership, or other securities in the converted entity as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

ARTICLE XV

Right to Acquire Limited Partner Interests

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable at its option, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed. As used in this Agreement, (i) “Current Market Price” as of any date of any class of Limited Partner Interests means the average of the daily Closing Prices (as hereinafter defined) per Limited Partner Interest of such class for the 20 consecutive Trading Days (as hereinafter defined) immediately prior to such date; (ii) “Closing Price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, as reported in the principal consolidated transaction reporting system with respect to securities listed on the principal National Securities Exchange (other than the Nasdaq Stock

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Market) on which such Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests of such class are not listed or admitted to trading on any National Securities Exchange (other than the Nasdaq Stock Market), the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the Nasdaq Stock Market or such other system then in use, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner; and (iii) “Trading Day” means a day on which the principal National Securities Exchange on which such Limited Partner Interests of any class are listed or admitted for trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted for trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article IV, Article V, Article VI and Article XII).

(c) At any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

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ARTICLE XVI

General Provisions

Section 16.1 Addresses and Notices.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Partnership is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications”, “written notice” and words of similar import will be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action. The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 16.4 Integration. This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors. None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver. No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries. Each Partner agrees that any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee.

Section 16.8 Counterparts. This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement

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immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereto.

Section 16.9 Applicable Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

Section 16.10 Invalidity of Provisions. If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 16.11 Consent of Partners. Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12 Facsimile Signatures. The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on certificates representing Common Units is expressly permitted by this Agreement.

Remainder of Page Intentionally Left Blank.
Signature Page Follows.

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EXHIBIT A
to the
First Amended and Restated
Agreement of Limited Partnership
of
Quest Energy Partners, L.P.

Certificate Evidencing Common Units
Representing Limited Partner Interests
in
Quest Energy Partners, L.P.

No. [ ] [ ] Common Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), Quest Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that (the “Holder”) is the registered owner of Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 9520 N. May Avenue, Suite 300, Oklahoma City, Oklahoma, 73120. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of

Exhibit A-1

[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:


TEN COM — as tenants in common	UNIF GIFT/TRANSFERS MIN ACT

		Custodian
TEN ENT — as tenants by the entireties	(Cust)		(Minor)
	under Uniform Gifts/Transfers to
JT TEN — as joint tenants with right of	Minors Act
survivorship and not as tenants in common	(State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF COMMON UNITS
Quest Energy Partners, L.P.

FOR VALUE RECEIVED, hereby assigns, conveys, sells and transfers unto



(Please print or typewrite name		(Please insert Social Security or
and address of Assignee)		other identifying number of Assignee)

Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint as its attorney-in-fact with full power of substitution to transfer the same on the books of Quest Energy Partners, L.P.


Date:		NOTE: The signature to any endorsement hereon must correspond with the name as written upon the fact of this Certificate in every particular, without alteration, enlarge- ment or change.
THE SIGNATURE(S) must be guaranteed By an eligible Guarantor or Institution (Banks, Stockbrokers, Savings and Loan
Associations and Credit Unions with Membership in an Approved Signature Guaranteed Medallion Program), pursuant to S.E.C. Rule 17Ad-15.		(Signature)

		(Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

Exhibit A-3

APPENDIX B — GLOSSARY OF SELECTED TERMS

The terms defined in this section are used throughout this prospectus. The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

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.

Cherokee Basin. A thirteen-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 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.

B-1

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.

MBbl. One thousand Bbls.

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 Web site 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 Web site 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 Web site at www.sec.gov/about/forms/regs-x.pdf.

B-2

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.

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.

Scf. Standard cubic feet of gas.

Scf/ton. Standard cubic feet of gas per ton.

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 Quest Energy Partners Predecessor included in this prospectus 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.

B-3

APPENDIX C — RESERVE REPORT SUMMARY

(CAWLEY, GILLESPIE AND ASSOCIATES LETTERHEAD)

August 31, 2007

Mr. Jerry Cash

Quest Energy Partners, L.P.

9520 N. May Avenue, Suite 300

Oklahoma City, OK 73120

Re: Evaluation Summary

Quest Energy Partners, L.P. Interests

Cherokee Basin

Proved Reserves


		As of June 30, 2007

Dear Mr. Cash:

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to certain oil and gas properties as of June 30, 2007 indirectly owned by Quest Resource Corporation. These properties are located in the Cherokee Basin in southeastern Kansas and northeastern Oklahoma. Quest Resource Corporation intends to contribute all of the properties included in this evaluation to a new partnership, Quest Energy Partners, L.P., recently formed as a Delaware limited partnership.

Composite reserve estimates and economic forecasts for the proved reserves are presented in the attached tables and are summarized below:


		Proved		Proved
		Developed		Developed		Proved
		Producing		Non-Producing		Undeveloped		Proved

Net Reserves
Oil/Condensate	–Mbbl		27.2		0.0		0.0		27.2
Gas	–MMcf		113,506.9		22,806.2		68,980.6		205,293.7
Revenue
Oil/Condensate	–M$		1,812.3		0.0		0.0		1,812.3
Gas	–M$		772,505.4		155,214.3		469,468.2		1,397,187.1
Severance and Ad Valorem Taxes	–M$		65,246.5		13,969.3		42,252.1		121,467.9
Operating Expenses	–M$		175,124.9		28,173.0		85,440.0		288,738.1
Gathering Expenses	–M$		181,606.3		36,489.9		110,369.0		328,465.2
Investments	–M$		0.0		5,650.0		105,840.0		111,490.0
Operating Income (BFIT)	–M$		352,339.7		70,932.1		125,567.1		548,838.9
Discounted @ 10%	–M$		257,357.9		43,777.9		51,915.3		353,051.0

The discounted value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

C-1

The detailed forecasts of reserves and economics are presented in the attached tables. Tables I-Proved, I-PDP, I-PDNP and I-PUD are summaries of the reserves and associated economics by reserve category. Table II — Proved is a summary of the ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flows for the individual forecasts in Table I — Proved. The individual forecasts of the reserves and economics are presented in Arabic numbered Tables 1 through 1923. The entries in these tables are area, then location and then lease name. Page 1 of the Appendix explains the types of data in these tables.

As directed, hydrocarbon pricing of $6.84 per MMBtu and $66.69 per barrel was applied as of June 30, 2007 with no escalation. The gas price was adjusted for a heating value of 0.995 MMBtu/Mcf.

Operating costs were based on an analysis by Quest Resource Corporation and were accepted as furnished. Direct lease operating expenses were forecast as $750 per well per month. Gas gathering expenses were forecast as $1.60 per Mcf per contractual arrangements. The gathering expenses appear in the “Other Deductions” column in the attached economics. No shrinkage was applied to the net gas volumes since the forecasts are based on historical sales volumes. State severance tax rates were forecast as 4.33% for Kansas and 7.085% for Oklahoma. An ad valorem tax rate of 5.00% was applied for the Kansas properties.

Drilling, completion and infrastructure costs were based on an analysis by Quest Resource Corporation and were accepted as furnished. Capital costs of $140,000 were applied for future locations. The PDNP reserves are associated with wells in various stages of completion. Capital costs of $25,000 were forecast for these wells. Neither expenses nor investments were escalated. The cost of plugging and the salvage value of equipment have not been considered.

The proved reserve classifications conform to criteria of the Securities and Exchange Commission. The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. The reserves were estimated using a combination of the production performance, volumetric and analogy methods. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by Quest Resource Corporation. Ownership interests were supplied by Quest Resource Corporation and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

This report was prepared for the exclusive use of Quest Energy Partners, L.P. We consent to you including this letter as an appendix to the prospectus for your initial public offering of common units. Third parties should not rely on it without the written consent of the above and Cawley, Gillespie & Associates, Inc. Our work-papers and related data are available for inspection and review by authorized parties.

Respectfully submitted,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

JZM:rkf

C-2

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

TABLE OF CONTENTS


Summary			1
Risk Factors			22
Cautionary Note Regarding Forward-Looking Statements			54
Use of Proceeds			55
Capitalization			57
Dilution			58
Our Cash Distribution Policy and Restrictions on Distributions			59
How We Make Cash Distributions			76
Selected Historical and Pro Forma Financial Data			87
Management’s Discussion and Analysis of Financial Condition and Results of Operations			90
Business			116
Management			136
Security Ownership of Certain Beneficial Owners and Management			147
Certain Relationships and Related Party Transactions			148
Conflicts of Interest and Fiduciary Duties			152
Description of the Common Units			161
The Partnership Agreement			163
Units Eligible for Future Sale			176
Material Tax Consequences			177
Selling Unitholder			194
Investment in Quest Energy Partners, L.P. by Employee Benefit Plans			195
Underwriting			196
Validity of the Common Units			200
Experts			200
Where You Can Find More Information			200
Index to Financial Statements			F-1
Appendix A — First Amended and Restated Agreement of Limited Partnership of Quest Energy Partners, L.P.			A-1
Appendix B — Glossary of Selected Terms			B-1
Appendix C — Reserve Report Summary			C-1

Until , 2007 (25 days after the date of
this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

8,750,000 Common Units

Representing

Limited Partner Interests

Quest Energy Partners, L.P.

PROSPECTUS

Wachovia Securities

RBC Capital Markets

Friedman Billings Ramsey

Oppenheimer & Co.

Stifel Nicolaus

Wells Fargo Securities

, 2007

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee, the amounts set forth below are estimates.


SEC registration fee	$	6,487
FINRA filing fee		21,631
Nasdaq listing fee		100,000
Printing and engraving expenses		280,000
Fees and expenses of counsel		750,000
Accounting fees and expenses		200,000
Transfer agent and registrar fees		25,000
Miscellaneous		116,882

Total	$	1,500,000


Item 14.	*Indemnification of Officers and Members of Our Board of Directors.*

The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Pursuant to the Underwriting Agreement filed as an exhibit to this registration statement in which Quest Energy Partners, L.P. and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.


Item 15.	*Recent Sales of Unregistered Securities.*

On July 18, 2007, in connection with the formation of Quest Energy Partners, L.P. (the “Partnership”), the Partnership issued to (1) our general partner the 2% general partner interest in the Partnership for $20.00 and (2) our Parent the 98% limited partner interest in the Partnership for $980.00. These issuances were exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

II-1


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) Exhibits.

The following documents are filed as exhibits to this registration statement:


Exhibit
Number			Description

	*1	.1	Form of Underwriting Agreement
	***3	.1	Certificate of Limited Partnership of Quest Energy Partners, L.P.
	***3	.2	Form of First Amended and Restated Limited Partnership Agreement of Quest Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	***3	.3	Certificate of Formation of Quest Energy GP, LLC
	***3	.4	Form of Amended and Restated Limited Liability Company Agreement of Quest Energy GP, LLC
	***5	.1	Opinion of Stinson Morrison Hecker LLP regarding validity of securities being issued
	***8	.1	Opinion of Stinson Morrison Hecker LLP relating to tax matters
	*10	.1	Form of Credit Agreement
	***10	.2	Form of Quest Energy Partners, L.P. Long-Term Incentive Plan
	*10	.3	Form of Restricted Unit Award Agreement
	***10	.4	Form of Contribution, Conveyance and Assumption Agreement
	***10	.5	Form of Omnibus Agreement
	***10	.6	Form of Management Services Agreement
	****10	.7	Midstream Services and Gas Dedication Agreement, dated December 22, 2006 (but effective as of December 1, 2006), between Bluestem Pipeline, LLC and Quest Resource Corporation, including exhibits thereto (incorporated herein by reference to Exhibit 10.6 to Quest Resource Corporation’s Current Report on Form 8-K (File No. 0-17371) filed on December 29, 2006)
	****10	.8	Amendment No. 1 to the Midstream Services and Gas Dedication Agreement, by and between Quest Resource Corporation and Bluestem Pipeline, LLC, dated as of August 9, 2007 (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K (File No. 0-017371) filed on August 13, 2007)
	***10	.9	Form of Assignment and Assumption Agreement relating to the Midstream Services and Gas Dedication Agreement.
	****10	.10	Quest Midstream Omnibus Agreement, dated December 22, 2006, among Quest Resource Corporation, Quest Midstream GP, LLC, Bluestem Pipeline, LLC and Quest Midstream Partners, L.P. (incorporated herein by reference to Exhibit 10.3 to Quest Resource Corporation’s Current Report on Form 8-K (File No. 0-17371) filed on December 29, 2006)
	***10	.11	Form of Acknowledgement and Consent relating to the Quest Midstream Omnibus Agreement.
	***21	.1	Subsidiaries of Quest Energy Partners, L.P.
	*23	.1	Consent of Murrell, Hall, McIntosh & Co., PLLP
	***23	.2	Consent of Stinson Morrison Hecker LLP (included in Exhibit 5.1)
	***23	.3	Consent of Stinson Morrison Hecker LLP (included in Exhibit 8.1)
	*23	.4	Consent of Cawley, Gillespie & Associates, Inc.
	***24	.1	Powers of Attorney
	***99	.1	Consent of Nominee for Director
	***99	.2	Consent of Nominee for Director


*		Filed herewith

II-2


**		To be filed by amendment

***		Previously filed

****		Incorporated by reference

(b) Financial Statement Schedules.

All schedules are omitted since the required information is not present, or is not present in amounts sufficient to require submission to the schedule, or because the information is included in the consolidated financial statements and notes thereto.


Item 17.	*Undertakings.*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Quest Energy GP, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Quest Energy GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-3

EXHIBIT INDEX


Exhibit
Number			Description

	*1	.1	Form of Underwriting Agreement
	***3	.1	Certificate of Limited Partnership of Quest Energy Partners, L.P.
	***3	.2	Form of First Amended and Restated Limited Partnership Agreement of Quest Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
	***3	.3	Certificate of Formation of Quest Energy GP, LLC
	***3	.4	Form of Amended and Restated Limited Liability Company Agreement of Quest Energy GP, LLC
	***5	.1	Opinion of Stinson Morrison Hecker LLP regarding validity of securities being issued
	***8	.1	Opinion of Stinson Morrison Hecker LLP relating to tax matters
	*10	.1	Form of Credit Agreement
	***10	.2	Form of Quest Energy Partners, L.P. Long-Term Incentive Plan
	*10	.3	Form of Restricted Unit Award Agreement
	***10	.4	Form of Contribution, Conveyance and Assumption Agreement
	***10	.5	Form of Omnibus Agreement
	***10	.6	Form of Management Services Agreement
	****10	.7	Midstream Services and Gas Dedication Agreement, dated December 22, 2006 (but effective as of December 1, 2006), between Bluestem Pipeline, LLC and Quest Resource Corporation, including exhibits thereto (incorporated herein by reference to Exhibit 10.6 to Quest Resource Corporation’s Current Report on Form 8-K (File No. 0-17371) filed on December 29, 2006)
	****10	.8	Amendment No. 1 to the Midstream Services and Gas Dedication Agreement, by and between Quest Resource Corporation and Bluestem Pipeline, LLC, dated as of August 9, 2007 (incorporated herein by reference to Exhibit 10.1 to Quest Resource Corporation’s Current Report on Form 8-K (File No. 0-017371) filed on August 13, 2007)
	***10	.9	Form of Assignment and Assumption Agreement relating to the Midstream Services and Gas Dedication Agreement.
	****10	.10	Quest Midstream Omnibus Agreement, dated December 22, 2006, among Quest Resource Corporation, Quest Midstream GP, LLC, Bluestem Pipeline, LLC and Quest Midstream Partners, L.P. (incorporated herein by reference to Exhibit 10.3 to Quest Resource Corporation’s Current Report on Form 8-K (File No. 0-17371) filed on December 29, 2006)
	***10	.11	Form of Acknowledgement and Consent relating to the Quest Midstream Omnibus Agreement.
	***21	.1	Subsidiaries of Quest Energy Partners, L.P.
	*23	.1	Consent of Murrell, Hall, McIntosh & Co., PLLP
	***23	.2	Consent of Stinson Morrison Hecker LLP (included in Exhibit 5.1)
	***23	.3	Consent of Stinson Morrison Hecker LLP (included in Exhibit 8.1)
	*23	.4	Consent of Cawley, Gillespie & Associates, Inc.
	***24	.1	Powers of Attorney
	***99	.1	Consent of Nominee for Director
	***99	.2	Consent of Nominee for Director


*		Filed herewith

**		To be filed by amendment

***		Previously filed

****		Incorporated by reference

II-5


SUMMARY			1
Quest Energy Partners, L.P.			1
Business Strategies			4
Competitive Strengths			4
Our Relationship with our Parent and Quest Midstream			4
Summary of Risk Factors			6
Formation Transactions and Partnership Structure			8
Summary of Conflicts of Interest and Fiduciary Duties			10
The Offering			12
Summary Historical and Pro Forma Financial Data			16
Non-GAAP Financial Measures			18
Summary Reserve and Operating Data			21
RISK FACTORS			22
Risks Related to Our Business			22
Risks Inherent in an Investment in Us			40
Tax Risks to Common Unitholders			49
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			54
USE OF PROCEEDS			55
CAPITALIZATION			57
DILUTION			58
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			59
Rationale for Our Cash Distribution Policy			59
Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy			59
Our Ability to Grow Depends on Our Ability to Access External Growth Capital			60
Our Initial Distribution Rate			61
Unaudited Pro Forma Available Cash for the Year Ended December 31, 2006 and the Twelve Months Ended June 30, 2007			63
Estimated Cash Available for Distribution for the Twelve Months Ending December 31, 2008			65
Assumptions and Considerations			68
HOW WE MAKE CASH DISTRIBUTIONS			76
Distributions of Available Cash			76
Operating Surplus and Capital Surplus			77
Subordination Period			79
Distributions of Available Cash from Operating Surplus during the Subordination Period			80
Distributions of Available Cash from Operating Surplus after the Subordination Period			81
Incentive Distribution Rights			81
General Partner’s Right to Reset Incentive Distribution Levels			81
Percentage Allocations of Available Cash from Operating Surplus			84
Distributions from Capital Surplus			84


Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			85
Distributions of Cash Upon Liquidation			85
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA			87
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			90
Overview			90
How We Evaluate Our Operations			90
Outlook			94
Factors That Significantly Affect Comparability of Our Results			95
Results of Operations for Quest Energy Partners Predecessor			96
Liquidity and Capital Resources			105
Critical Accounting Policies and Estimates			109
Recent Accounting Pronouncements			111
Quantitative and Qualitative Disclosures about Market Risk			112
BUSINESS			116
Overview			116
Business Strategies			117
Competitive Strengths			118
Our Relationship with Our Parent			118
Description of Our Properties and Projects			119
Gas and Oil Data			121
Operations			124
Gas Gathering			125
Marketing and Major Customers			126
Hedging Activity			126
Competition			127
Title to Properties			127
Seasonal Nature of Business			128
Environmental Matters and Regulation			128
Other Regulation of the Gas and Oil Industry			131
Employees			133
Offices			133
Legal Proceedings			133
MANAGEMENT			136
Management of Quest Energy Partners, L.P.			136
Directors and Executive Officers			138
Reimbursement of Expenses of Our General Partner			140
Executive Compensation Discussion and Analysis			140
Long-Term Incentive Plan			144
Compensation of Directors			146
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			147


CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			148
Distributions and Payments to Our General Partner and its Affiliates			148
Agreements Governing the Transactions			149
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			152
Conflicts of Interest			152
Fiduciary Duties			158
DESCRIPTION OF THE COMMON UNITS			161
The Units			161
Transfer Agent and Registrar			161
Transfer of Common Units			161
THE PARTNERSHIP AGREEMENT			163
Organization and Duration			163
Purpose			163
Power of Attorney			163
Cash Distributions			163
Capital Contributions			164
Voting Rights			164
Limited Liability			165
Issuance of Additional Securities			166
Amendment of the Partnership Agreement			167
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			169
Termination and Dissolution			169
Liquidation and Distribution of Proceeds			170
Withdrawal or Removal of the General Partner			170
Transfer of General Partner Units			171
Transfer of Ownership Interests in the General Partner			171
Transfer of Incentive Distribution Rights			171
Change of Management Provisions			172
Limited Call Right			172
Meetings; Voting			172
Status as Limited Partner			173
Non-Eligible Holders; Redemption			173
Indemnification			174
Reimbursement of Expenses			174
Books and Reports			175
Right to Inspect Our Books and Records			175
Registration Rights			175
UNITS ELIGIBLE FOR FUTURE SALE			176
MATERIAL TAX CONSEQUENCES			177
Partnership Status			177
Limited Partner Status			179
Tax Consequences of Unit Ownership			179


Public Common Units	40.5	%
Quest Resource Corporation and its affiliates
Common Units	16.5	%
Subordinated Units	41.0	%
General Partner Interest	2.0	%

Total	100.0	%


QUEST ENERGY PARTNERS, L.P. UNAUDITED PRO FORMA FINANCIAL STATEMENTS
Introduction		F-2
Unaudited Pro Forma Balance Sheet as of June 30, 2007		F-3
Unaudited Pro Forma Statement of Operations for the Year Ended December 31, 2006		F-4
Unaudited Pro Forma Statement of Operations for the Six Months Ended June 30, 2007		F-5
Notes to Unaudited Pro Forma Financial Statements		F-6

QUEST ENERGY PARTNERS, L.P. PREDECESSOR AUDITED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm		F-8
Carve Out Balance Sheets as of December 31, 2005 and 2006		F-9
Carve Out Statements of Operations for the Fiscal Year Ended May 31, 2004, Seven Months Ended December 31, 2004 and the Years Ended December 31, 2005 and 2006		F-10
Carve Out Statements of Cash Flows for the Fiscal Year Ended May 31, 2004, Seven Months Ended December 31, 2004 and the Years Ended December 31, 2005 and 2006		F-11
Carve Out Statements of Partners’ Capital for the Fiscal Year Ended May 31, 2004, Seven Months Ended December 31, 2004 and the Years Ended December 31, 2005 and 2006		F-12
Notes to Carve Out Financial Statements		F-13

QUEST ENERGY PARTNERS, L.P. PREDECESSOR UNAUDITED FINANCIAL STATEMENTS
Carve Out Balance Sheets as of December 31, 2006 and June 30, 2007		F-43
Carve Out Statements of Operations for the Three and Six Months Ended June 30, 2006 and 2007		F-44
Carve Out Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2007		F-45
Condensed Notes to Carve Out Financial Statements		F-46

QUEST ENERGY PARTNERS, L.P. AUDITED BALANCE SHEET
Report of Independent Registered Public Accounting Firm		F-61
Balance Sheet as of July 19, 2007		F-62
Note to Balance Sheet		F-63

QUEST ENERGY GP, LLC AUDITED CONSOLIDATED BALANCE SHEET
Report of Independent Registered Public Accounting Firm		F-64
Consolidated Balance Sheet as of July 19, 2007		F-65
Notes to Consolidated Balance Sheet		F-66


ASSETS
Current assets
Cash	$	1,000

Total Assets	$	1,000

PARTNERS’ CAPITAL
Limited partners’ capital	$	980
General partner’s capital		20

Total partners’ capital	$	1,000


Dated:		Quest Energy Partners, L.P.
Countersigned and Registered by: [Name of Transfer Agent]
		By:
By:
as Transfer Agent and Registrar


Signature		Title


* Jerry D. Cash		Chief Executive Officer (Principal Executive Officer) and Director

* David Lawler		Director

/s/ David E. Grose David E. Grose		Chief Financial Officer (Principal Financial and Accounting Officer)

*By:	/s/ David E. Grose David E. Grose Attorney-in-Fact