Grizzly Energy (GRZZP) 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration No. 333-179050

The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the accompanying prospectus are not an offer to sell the securities described herein and are not soliciting an offer to buy such securities in any jurisdiction where the offer or sale of such securities is not permitted.

SUBJECT TO COMPLETION, DATED MARCH 26, 2012

PRELIMINARY PROSPECTUS SUPPLEMENT
(To Prospectus Dated January 18, 2012)

$300,000,000

Vanguard Natural Resources, LLC
VNR Finance Corp.

    % Senior Notes due 2020

 

We are offering $300,000,000 aggregate principal amount of     % senior notes due 2020 of Vanguard Natural Resources, LLC and VNR Finance Corp., which we refer to in this prospectus supplement as the “notes.” Interest on the notes is payable on       and      of each year, beginning on       , 2012. The notes will mature on       , 2020.

We may redeem some or all of the notes at any time on or after       , 2016 at the redemption prices and as described under the caption “Description of Notes — Optional Redemption,” and we may redeem some or all of the notes at any time prior to       , 2016, at a price equal to 100% of the aggregate principal amount of the notes redeemed, plus a “make-whole” premium. In addition, before       , 2015 and following certain equity offerings, we may redeem up to 35% of the aggregate principal amount of the notes at the redemption price equal to     % of the aggregate principal amount of the notes redeemed. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to repurchase all or a portion of the notes.

The notes will be the senior unsecured obligations of Vanguard Natural Resources, LLC and VNR Finance Corp., a wholly owned subsidiary of ours that has no material assets and was formed for the sole purpose of being a co-issuer of some of our debt, including the notes. The notes will be guaranteed on a senior unsecured basis by all of our existing subsidiaries (other than the co-issuer) and certain future subsidiaries. The notes and the guarantees will rank equally in right of payment with all of the existing and future senior indebtedness of the issuers and the guarantors, but will be effectively subordinated to any of their existing or future secured indebtedness, including indebtedness under our senior secured reserve-based credit facility, to the extent of the value of the collateral securing such indebtedness.

 

Investing in the notes involves risks. See “Risk Factors” beginning on page S-15 of this prospectus supplement and on page 5 of the accompanying prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

	Per Note			Total
Public Offering Price			%	$
Underwriting Discount		%		$
Proceeds before expenses, to us		%		$

Interest on the notes will accrue from       , 2012 to date of delivery.

The underwriters expect to deliver the notes to purchasers on or about       , 2012, only in book-entry form through the facilities of The Depository Trust Company.

 

Joint Book-Running Managers

Citigroup	Credit Agricole CIB

RBC Capital Markets	RBS	UBS Investment Bank	Wells Fargo Securities

Senior Co-Managers

BMO Capital Markets Comerica Securities	Capital One Southcoast Scotiabank

Junior Co-Managers

Lloyds Securities	Natixis	US Bancorp

      , 2012

Our Operating Areas

You should rely only on the information contained in or incorporated by reference in this prospectus supplement and the accompanying prospectus. We 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 the offer or sale is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of this prospectus supplement or the accompanying prospectus.

 

TABLE OF CONTENTS

Glossary of Terms		S-ii
Cautionary Statement Regarding Forward Looking Statements		S-iii
Summary		S-1
Risk Factors		S-15
Use of Proceeds		S-36
Ratio of Earnings to Fixed Charges		S-37
Capitalization		S-38
Selected Historical and Consolidated Financial and Operating Data		S-39
Management’s Discussion and Analysis of Financial Condition and Results of Operations		S-41
Business		S-60
Management		S-86
Description of Other Indebtedness		S-88
Description of Notes		S-91
Certain United States Federal Income and Estate Tax Considerations		S-139
Underwriting		S-145
Legal Matters		S-149
Experts		S-149
Where You Can Find More Information		S-150
Index to Financial Statements		F-1

Prospectus dated January 18, 2012

About this Prospectus		ii
Where You Can Find More Information		1
Forward-Looking Statements		2
About Vanguard Natural Resources, LLC and VNR Finance Corp.		4
Risk Factors		5
Use of Proceeds		6
Ratio of Earnings to Fixed Charges		7
Selling Unitholder		8
Description of Our Debt Securities		9
Description of Our Common Units		17
Cash Distribution Policy		19
Description of Our Limited Liability Company Agreement		20
Material Tax Consequences		28
Plan of Distribution		45
Legal Matters		48
Experts		48

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GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:

/day	= per day	Mcf	= thousand cubic feet
Bbls	= barrels	Mcfe	= thousand cubic feet of natural gas equivalents
BOE	= barrel of oil equivalent	MMBOE	= million barrels of oil equivalent
Btu	= British thermal unit	MMBtu	= million British thermal units
MBbls	= thousand barrels	MMcf	= million cubic feet
MBOE	= thousand barrels of oil equivalent	NGLs	= natural gas liquids

When we refer to oil, natural gas and NGLs in “equivalents,” we are doing so to compare quantities of NGLs and oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which 42 gallons is equal to one Bbl of oil or one Bbl of NGLs, and one Bbl of oil or one Bbl of NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

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CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS

Certain statements and information in this prospectus supplement, the accompanying prospectus and the documents we incorporate by reference may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The words “may,” “will,” “estimate,” “predict,” “potential,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors and other factors that could cause our actual results to differ from those in the forward-looking statements include, but are not limited to:

• the volatility of realized oil, natural gas and NGLs prices;

• the potential for additional impairment due to future declines in oil, natural gas and NGLs prices;

• uncertainties about the estimated quantities of oil, natural gas and NGLs reserves, including uncertainties about the effects of the Securities and Exchange Commission’s (the “SEC”) rules governing reserve reporting;

• the conditions of the capital markets, liquidity, general economic conditions, interest rates and the availability of credit to support our business requirements;

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

• our business and financial strategy;

• our future operating results;

• our drilling locations;

• technology;

• our cash flow, liquidity and financial position;

• the timing and amount of our future production of oil, natural gas and NGLs;

• our operating expenses, general and administrative costs, and finding and development costs;

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

• our prospect development and property acquisitions;

• the marketing of oil, natural gas and NGLs;

• competition in the oil, natural gas and NGLs industry;

• the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters;

• governmental regulation of the oil, natural gas and NGLs industry;

• environmental regulations;

• the effect of legislation, regulatory initiatives and litigation related to climate change;

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

• our strategic plans, objectives, expectations and intentions for future operations.

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Other factors that could cause our actual results to differ from our expected results are described in (1) this prospectus supplement, (2) our Annual Report on Form 10-K for the year ended December 31, 2011 (“our 2011 Annual Report”), (3) our other reports filed from time to time with the SEC and (4) other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise, except as required by law.

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SUMMARY

This summary highlights information included or incorporated by reference in this prospectus supplement and the accompanying prospectus. It does not contain all of the information that may be important to you. You should read carefully this entire prospectus supplement, the accompanying prospectus, the documents incorporated herein and therein by reference and the other documents to which we refer herein for a more complete understanding of our business and the terms of the notes, as well as tax and other considerations that are important to you in making your investment decision. You should pay special attention to the “Risk Factors” sections on page S-15 of this prospectus supplement and on page 5 of the accompanying prospectus and the risk factors included in “Item 1A. Risk Factors” of our 2011 Annual Report to determine whether an investment in the notes is appropriate for you.

Unless the context otherwise requires, references to (1) “Vanguard Natural Resources,” “Vanguard,” “we,” “us,” “our” and similar terms, as well as references to the “Company,” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC, Trust Energy Company, LLC, VNR Holdings, LLC, Ariana Energy, LLC, Vanguard Permian, LLC, VNR Finance Corp., Encore Energy Partners GP LLC (“ENP GP”), Encore Energy Partners LP (“ENP”), Encore Energy Partners Operating LLC and Encore Clear Fork Pipeline LLC and (2) “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC. With respect to the cover page and in the sections entitled “Summary — The Offering” and “Underwriting,” “we,” “our” and “us” refer only to Vanguard Natural Resources, LLC. Unless otherwise indicated, our reserve and production data and related operation data presented in this prospectus supplement do not give effect to the Appalachian Exchange (described below in “— Recent Developments — Appalachian Exchange”).

The estimates of our natural gas and oil reserves at December 31, 2011 included in this prospectus supplement and in the documents incorporated by reference herein are based upon the reports of DeGolyer and MacNaughton (“D&M”), an independent petroleum engineering firm.

Our Company

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and, over time, increasing our quarterly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, after giving effect to the Appalachian Exchange, we own properties and oil and natural gas reserves primarily located in six operating areas:

• the Permian Basin in West Texas and New Mexico;

• the Big Horn Basin in Wyoming and Montana;

• South Texas;

• the Williston Basin in North Dakota and Montana;

• Mississippi; and

• the Arkoma Basin in Arkansas and Oklahoma.

At December 31, 2011, we owned working interests in 4,900 gross (2,245 net) productive wells. Our average net daily production for the year ended December 31, 2011 was 13,405 BOE/day. Our operated wells accounted for approximately 62% of our total estimated proved reserves by PV-10 at December 31, 2011. Our average net daily production for the year ended December 31, 2011 includes production from the properties acquired in connection with the ENP Acquisition (described below). Production from these properties during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP. In the Permian Basin, Big Horn Basin, South Texas and Williston Basin, we own working interests ranging from 30 – 100% in approximately 42,468 gross undeveloped acres surrounding our existing wells.

S-1

In addition to these productive wells, we own leasehold acreage allowing us to drill new wells. In the Permian, Big Horn Basin, South Texas and Williston Basin, we own working interests ranging from 30 – 100% in approximately 31,802 gross undeveloped acres surrounding our existing wells. Approximately 14% or 11.1MMBOE of our estimated proved reserves were attributable to our working interests in undeveloped acreage.

The following table sets forth certain information with respect to our estimated proved reserves, after giving effect to the Appalachian Exchange, by operating area as of December 31, 2011 based on estimates made in a reserve report prepared by D&M. For more information on the Appalachian Exchange please read “— Recent Developments — Appalachian Exchange” below.

	Estimated Proved Developed Reserve Quantities								Estimated Proved Undeveloped Reserve Quantities								Estimated Proved Reserve Quantities
	Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		Total (MMBOE)		Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		Total (MMBOE)		Total (MMBOE)
Operating Area
Permian Basin		64.9		12.1		2.7		25.6		8.5		2.7		0.2		4.3		29.9
Big Horn Basin		20.0		20.8		1.5		25.6		—		0.9		—		0.9		26.5
South Texas		18.0		0.1		2.0		5.1		9.8		0.1		1.0		2.7		7.8
Williston Basin		2.5		4.4		—		4.9		0.2		0.5		—		0.5		5.4
Mississippi		0.1		1.9		—		1.9		—		0.6		—		0.6		2.5
Arkoma Basin		4.8		0.3		—		1.1		—		—		—		—		1.1
Total		110.3		39.6		6.2		64.2		18.5		4.8		1.2		9.0		73.2

Business Strategies

Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders, and over the long-term to increase the amount of our future distributions by executing the following business strategies:

• Acquire Long-Lived Assets with Low-Risk Exploitation and Development Opportunities.  We target the acquisition of oil and natural gas properties that we believe will generate attractive risk adjusted expected rates of return and be financially accretive. Our acquisitions have been characterized by long-lived production, relatively low decline rates and predictable production profiles, as well as low-risk development opportunities in known producing basins of the continental United States. We expect to make additional acquisitions on properties with similar profiles.

• Manage our Diverse Portfolio of Oil and Gas Properties with a Focus on Maintaining Stable Cash Flow.  We manage our diverse portfolio of oil and gas properties in an effort to maintain cash flow. This is primarily accomplished by replacing production and reserves through workovers and recompletions as well as the development of our inventory of proved undeveloped locations. We maintain an inventory of drilling and optimization projects within each of the regions in which we operate to achieve organic growth from our capital development program. We aim to operate our properties so we can develop drilling programs and optimization projects to replace production and add value through reserve and production growth and other operational synergies. Our development program is focused on lower-risk, repeatable drilling opportunities to maintain and, in some cases, grow cash flow. Many of the wells in our development program are completed in multiple producing zones with commingled production and long economic lives. As of December 31, 2011, we operated 72% of our production on a cash flow basis.

• Maintain a Conservative Capital Structure to Ensure Financial Flexibility to Pursue Acquisitions.  We have actively managed our debt levels by accessing equity markets when necessary. Since our initial public offering in 2007, we have financed approximately 63% of our $1.6 billion of oil and natural gas property acquisitions with the issuance of our common units. We maintain adequate liquidity and capitalization not only for our operating positions but also to maintain the financial flexibility necessary to compete for opportunistic acquisitions. Finally, we expect to maintain a prudent coverage ratio in order to support distribution levels in the future.

S-2

• Reduce Cash Flow Volatility Through Commodity Price and Interest Rate Derivatives.  We use a robust hedging strategy to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions. Our commodity hedging transactions are primarily in the form of swap contracts and collars that are designed to provide a fixed price (swap contracts) or range of prices between a price floor and a price ceiling (collars) that we will receive, instead of being exposed to the full range of commodity price fluctuations. Our goal is to hedge 70% to 85% of our estimated production on a rolling basis. We also expect to hedge a high percentage of acquired production immediately upon execution of a purchase and sale agreement in order to secure the returns contemplated at the outset of a transaction. Finally, we also anticipate opportunistically hedging interest rates to protect against future interest rate increases.

Competitive Strengths

We believe our competitive strengths position us to successfully execute our business strategies. Our competitive strengths are as follows:

• High-Quality, Long-Lived Reserve Base.  After giving effect to the Appalachian Exchange, our diverse portfolio is comprised of 73.2 MMBoe of proved reserves across eight states. These properties typically have had a long history of relatively stable production characterized by low to moderate rates of production decline. Our estimated proved reserves as of December 31, 2011 had an average reserve life of approximately 17 years, and 88% of our reserves were classified as developed (either proved developed producing or proved developed non-producing), giving us an average developed reserve life of 15 years. We believe the highly developed nature of our reserves reduces our development risk.

• Geographically Diverse Asset Base Which is Weighted Towards Liquid Properties.  Our portfolio of assets is well diversified, stretching across six regions which have long oil and gas production histories, including the Permian Basin in West Texas and New Mexico, the Big Horn Basin in Wyoming and Montana, South Texas, the Williston Basin in North Dakota and Montana, Mississippi and the Arkoma Basin in Arkansas and Oklahoma. The geographic breadth of our portfolio significantly reduces the risk to our investors of a problem in any particular asset. As of December 31, 2011, after giving effect to the Appalachian Exchange, our reserves consist of 61% oil and 10% NGLs, and our production consists of 54% oil and 11% NGLs. We believe that our being significantly weighted towards oil and NGLs provides a more stable cash flow outlook given the current price outlook for natural gas.

• Substantial Hedging Through 2014 at Attractive Prices.  We use a combination of fixed price swap and option arrangements to hedge NYMEX crude oil and natural gas prices. By mitigating the price volatility from a portion of our crude oil and natural gas production, we have worked to manage the potential effects of changing crude oil and natural gas prices on our cash flow from operations for the hedged periods. After giving effect to the Appalachian Exchange, we have hedged approximately 80% of expected oil production through 2014 at an average floor price of $89.98 per barrel, and 75% of expected natural gas production at an average price $5.36 per MMBtu.

• Significant Inventory of Low Risk Development Opportunities.  We also have an inventory of low risk drilling locations to maintain the cash flow from our properties. As of December 31, 2011, after giving effect to the Appalachian Exchange, we had identified 147 proved undeveloped drilling locations and an additional 205 other locations on our leasehold acreage. We intend to spend $37.5 million in capital expenditures in 2012 on low risk development and workover projects which are attractive at today’s commodity prices in an effort to maintain stable cash flow.

• Stable Cash Flows with Low Capital Requirements.  We have stable operating cash margins combined with limited reliance on higher risk development relative to many of our peers and the sale of oil and NGLs contributing over 85% of our revenue. For 2012, we estimate our capital expenditures excluding acquisitions will be $37.5 million, which is approximately 15% of expected Adjusted EBITDA.

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• Significant Financial Flexibility.  We are committed to maintaining a conservative financial position, ample liquidity and a strong balance sheet. After giving effect to the automatic reduction in our borrowing base resulting from the closing of this offering and the Appalachian Exchange, we will have $    million in outstanding debt, which will give us, based on our outstanding borrowings as of March 23, 2012, approximately $     million in borrowing capacity under our senior secured reserve-based credit facility (the “Reserve-Based Credit Facility”) to help fund acquisitions, development and working capital. We have prudently raised equity throughout industry cycles to maintain a strong balance sheet, as demonstrated following the ENP acquisition. We may also issue additional common units that, combined with our Reserve-Based Credit Facility, will provide us with resources to finance future acquisitions and internal development projects.

• Experienced Management Team.  Our executive officers have an average of over 25 years of experience in the oil and natural gas industry and have diverse backgrounds ranging from large, public oil and natural gas companies to entrepreneurial startups. We also have experienced technical and operational teams that provide keen insight into prospective acquisitions. Moreover, we believe that our experience integrating the properties associated with our many recent purchases, including the ENP acquisition, will de-risk the integration of future acquisitions.

Recent Developments

ENP Acquisition

On December 31, 2010, we acquired (the “ENP Purchase”) all of the member interests in ENP GP, the general partner of ENP, and 20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), together representing a 46.7% aggregate equity interest in ENP at the date of the ENP Purchase, from Denbury Resources Inc. (“Denbury”), Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Operating, L.P. (collectively, the “Encore Selling Parties” and, together with Denbury, the “Selling Parties”). As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million at December 31, 2010.

On December 1, 2011, we acquired the remaining 53.4% of the ENP Units not held by us through a merger (the “ENP Merger”) with one of our wholly owned subsidiaries. In connection with the ENP Merger, ENP’s public unitholders received 0.75 VNR common units in exchange for each ENP common unit they owned at the effective date of the ENP Merger, which resulted in the issuance of approximately 18.4 million VNR common units valued at $511.4 million at December 1, 2011. We refer to the ENP Purchase and ENP Merger collectively as the “ENP Acquisition.” ENP’s properties are located in Wyoming, Montana, West Texas, New Mexico, North Dakota, Arkansas and Oklahoma. As of December 31, 2011, based on a reserve report prepared by D&M, the acquired properties from the ENP Acquisition had estimated proved reserves of 44.0MMBOE, of which 71% was oil and 88% was proved developed producing.

Public Offering of Our Common Units

In January 2012, we completed an offering of 7,137,255 of our common units at a price of $27.71 per unit. The 7,137,255 common units offering included 4.0 million of our common units (“primary units”) and 3,137,255 common units (“secondary units”) offered by Denbury Onshore, LLC (“selling unitholder”). We received proceeds of approximately $106.4 million from the offering of primary units, after deducting underwriting discounts of $4.3 million and offering costs of $0.2 million. We did not receive any proceeds from the sale of the secondary units. In addition, we received proceeds of approximately $28.5 million, after deducting underwriting discounts of $1.2 million, from the sale of additional 1,070,588 of our common units that were offered to the underwriters to cover over-allotments pursuant to this offering. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility and our senior secured second lien term loan facility (the “Facility Term Loan”).

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Appalachian Exchange

In February 2012, we entered into a Unit Exchange Agreement with our founding unitholder to transfer our ownership interests in oil and natural gas properties in the Appalachian Basin in exchange for 1.9 million VNR common units with an effective date of January 1, 2012 (we refer to this transaction as the “Appalachian Exchange”). As of December 31, 2011, based on a reserve report prepared by D&M, total estimated net proved reserves attributable to these interests were 6.2 MMBOE, of which 92% was natural gas and 65% was proved developed. This transaction is expected to close on March 28, 2012.

Our Principal Executive Offices

We are a limited liability company formed under the laws of the State of Delaware. Our executive offices are located at 5847 San Felipe, Suite 3000, Houston, Texas 77057. Our telephone number is (832) 327-2255. We maintain a website athttp://www.vnrllc.com that provides information about our business and operations. Information contained on our website, however, is not incorporated into or otherwise a part of this prospectus supplement or the accompanying prospectus.

Our Organizational Structure

In February 2012, we completed an internal reorganization whereby Encore Energy Partners GP LLC and Encore Energy Partners LP were merged into Vanguard Natural Gas, LLC. The following diagram depicts our organizational structure as of March 23, 2012, after giving effect to the Appalachian Exchange.

Our operating subsidiary, Vanguard Natural Gas, LLC, is the borrower on $57 million in aggregate principal amount of loans outstanding under our Facility Term Loan and on approximately $571 million in aggregate principal amount of loans outstanding under our Reserve-Based Credit Facility, each as of March 23, 2012. Vanguard Natural Resources, LLC and VNR Finance Corp. are co-issuers of the notes offered hereby. The notes will be unconditionally guaranteed, jointly and severally, on an unsecured basis, by all of our existing subsidiaries (other than VNR Finance Corp.) and by certain of our future subsidiaries.

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The Offering

The following summary contains basic information about the notes and is not intended to be complete. For a more complete understanding of the notes, please refer to the section in this prospectus supplement entitled “Description of Notes” and the section in the accompanying prospectus entitled “Description of Our Debt Securities.”

Issuers

Vanguard Natural Resources, LLC
VNR Finance Corp.

VNR Finance Corp. is a wholly owned subsidiary of Vanguard Natural Resources, LLC that has no material assets and was formed for the sole purpose of being a co-issuer of some of our debt, including the notes.

Notes Offered

$300,000,000 principal amount of     % senior notes due 2020.

Issue Price

    % of principal plus accrued interest, if any, from       , 2012.

Maturity Date

      , 2020.

Interest Rate

    % per year (calculated using a 360-day year).

Interest Payment Dates

    and     of each year, commencing on       , 2012.

Ranking

The notes will be our senior unsecured obligations. The notes will:

•  

rank equally in right of payment with all of our existing and future senior indebtedness;

•  

be effectively junior to any of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including our guarantee of borrowings under our Reserve-Based Credit Facility;

•  

rank senior in right of payment to any of our future subordinated indebtedness; and

•  

be structurally subordinated to all indebtedness and other obligations of our future subsidiaries that do not guarantee the notes.

As of December 31, 2011, on an as further adjusted basis after giving effect to the issuance and sale of the notes and the application of the related net proceeds therefrom and the other transactions as set forth under “Capitalization,” we would have had (i) total debt outstanding in the principal amount of approximately $    million, consisting of the notes offered hereby and approximately $    million of outstanding borrowings under our Reserve-Based Credit Facility, (ii) approximately $    million in further availability under our Reserve-Based Credit Facility after giving effect to the automatic reduction in our borrowing base resulting from the closing of this offering and the Appalachian Exchange, and (iii) no indebtedness contractually subordinated to the notes or the guarantees, as applicable.

Subsidiary Guarantees

The notes will be unconditionally guaranteed, jointly and severally, on an unsecured basis, by all of our existing subsidiaries (other than VNR Finance Corp.) and by certain of our future subsidiaries, which we refer to as “the guarantors.” The guarantors own all of our consolidated assets. Each guarantee of the notes will:

•  

be a general unsecured obligation of the subsidiary guarantor;

S-6

•  

rank equally in right of payment with all existing and future senior indebtedness of that subsidiary guarantor;

•  

be effectively junior to any secured indebtedness of that subsidiary guarantor to the extent of the value of the collateral securing such indebtedness, including its obligations under our Reserve-Based Credit Facility;

•  

rank senior in right of payment to any future subordinated indebtedness of that subsidiary guarantor; and

•  

be structurally subordinated to all future indebtedness and other obligations of any guarantor’s subsidiary that does not guarantee the notes.

Optional Redemption

At any time prior to      , 2015, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes, but not more than the net cash proceeds of certain equity offerings by us, at a redemption price equal to     % of the principal amount of the notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the notes remain outstanding immediately after any such redemption and the redemption occurs within 180 days of such equity offering.

On or after       , 2016, we may redeem all or part of the notes, in each case at the redemption prices described under “Description of Notes — Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.

In addition, prior to       , 2016, we may redeem all or part of the notes at a “make-whole” redemption price described under “Description of Notes — Optional Redemption,” together with any accrued and unpaid interest to the date of redemption.

Mandatory Offer to
Purchase

Upon the occurrence of a change of control, unless we have exercised our optional redemption right with respect to the notes, holders of the notes will have the right to require us to purchase all or any part of the notes at a price equal to 101% of the aggregate principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset dispositions, we will be required to use the net cash proceeds of the asset dispositions to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase.

Certain Covenants

We will issue the notes under an indenture with U.S. Bank National Association, as trustee. The indenture will, among other things, limit our ability and the ability of our restricted subsidiaries to:

•  

incur, assume or guarantee additional indebtedness or issue preferred units;

•  

create liens to secure indebtedness;

•  

make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness;

•  

make investments;

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•  

restrict dividends, loans or other asset transfers from our restricted subsidiaries;

•  

consolidate with or merge with or into, or sell substantially all of our properties to, another person;

•  

sell or otherwise dispose of assets, including equity interests in subsidiaries;

•  

enter into transactions with affiliates; or

•  

create unrestricted subsidiaries.

However, if both Standard & Poor’s Ratings Services and Moody’s Investors Service, Inc. assign the notes an investment grade rating and no default under the indenture exists, many of the foregoing covenants will terminate.

These covenants are subject to important exceptions and qualifications, which are described under “Description of Notes — Certain Covenants.”

Use of proceeds

We expect to receive net proceeds from this offering of approximately $     million, after deducting the underwriters’ discount and estimated offering expenses. We intend to use a portion of the net proceeds from the offering to repay all indebtedness outstanding under our Facility Term Loan and to apply the balance to outstanding borrowings under our Reserve-Based Credit Facility. Please read “Use of Proceeds.”

Affiliates of all of the underwriters are lenders under those credit facilities and will receive a portion of the proceeds from this offering through the repayment of indebtedness under our credit facilities. See “Underwriting.”

Risk Factors

Investing in the notes involves risks. Please read “Risk Factors” for a discussion of certain factors you should consider before making an investment in the notes. You should also carefully consider the risk factors in “Item 1A. Risk Factors” of our 2011 Annual Report.

Original issue discount

The notes may be issued with original issue discount (“OID”) for U.S. federal income tax purposes. If the notes are issued with OID, U.S. holders (as defined in “Certain United States Federal Income and Estate Tax Considerations”), whether on the cash or accrual method of tax accounting, will be required to include any amounts representing OID in gross income (as ordinary income) on a constant yield to maturity basis for U.S. federal income tax purposes in advance of the receipt of cash payments to which such income is attributable. For further discussion, see “Certain United States Federal Income and Estate Tax Considerations.”

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Summary Historical Consolidated Financial and Operating Data

Set forth below is our summary historical consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC. The summary historical financial data for the years ended December 31, 2011, 2010 and 2009 and the balance sheet data as of December 31, 2011 and 2010 have been derived from our audited financial statements.

You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus supplement.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in “Summary — Non-GAAP Financial Measure.”

	Year Ended December 31,(3)
	2011(4)			2010			2009
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues:
Oil, natural gas and NGLs sales	$	312,842		$	85,357		$	46,035
Gain (loss) on commodity cash flow hedges		(3,071	)		(2,832	)		(2,380	)
Realized gain (loss) on other commodity derivative contracts		10,276			24,774			29,993
Unrealized gain (loss) on other commodity derivative contracts		(470	)		(14,145	)		(19,043	)
Total revenues		319,577			93,154			54,605
Costs and Expenses:
Production:
Lease operating expenses		63,944			18,471			12,652
Production and other taxes		28,621			6,840			3,845
Depreciation, depletion, amortization and accretion		84,857			22,231			14,610
Impairment of oil and natural gas properties		—			—			110,154
Selling, general and administrative expenses(1)		19,779			10,134			10,644
Bad debt expense		—			—			—
Total costs and expenses		197,201			57,676			151,905
Income (Loss) from Operations:		122,376			35,478			(97,300	)
Other Income (Expense):
Other income		77			1			—
Interest and financing expenses		(28,994	)		(5,766	)		(4,276	)
Realized loss on interest rate derivative contracts		(2,874	)		(1,799	)		(1,903	)
Net gain (loss) on acquisition of oil and natural gas properties		(367	)		(5,680	)		6,981
Unrealized gain (loss) on interest rate derivative contracts		(2,088	)		(349	)		763
Loss on extinguishment of debt		—			—			—
Total other income (expenses)		(34,246	)		(13,593	)		1,565
Net Income (Loss)	$	88,130		$	21,885		$	(95,735	)
Less: Net income attributable to non-controlling interest		(26,067	)		—			—
Net Income (Loss) attributable to Vanguard unitholders	$	62,063		$	21,885		$	(95,735	)
Net Income (Loss) Per Unit:
Common and Class B units – basic & diluted	$	1.95		$	1.00		$	(6.74	)
Distributions Declared Per Unit	$	2.28		$	2.15		$	2.00
Weighted Average Common Units Outstanding		31,369			21,500			13,791
Weighted Average Class B Units Outstanding		420			420			420
Cash Flow Data:
Net cash provided by operating activities	$	176,332		$	71,577		$	52,155
Net cash used in investing activities		(236,350	)		(429,994	)		(109,315	)
Net cash provided by financing activities		61,041			359,758			57,644
Other Financial Information:
Adjusted EBITDA before non-controlling interest(2)	$	224,601		$	80,396		$	56,202

(1) Includes $3.0 million, $1.0 million and $2.9 million of non-cash unit-based compensation expense in 2011, 2010 and 2009, respectively.

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(2) See “Summary — Non-GAAP Financial Measure” beginning on page S-13 of this prospectus supplement.

(3) From 2009 through 2011, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in the Permian Basin, Big Horn Basin, South Texas and Mississippi. The operating results of these properties were included with ours from the closing date of the acquisition forward.

(4) The operating results of the subsidiaries we acquired in the ENP Purchase through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest.

	As of December 31,
	2011		2010(1)
	(in thousands)
Balance Sheet Data(2):
Cash and cash equivalents	$	2,851	$	1,828
Short-term derivative assets		2,333		16,523
Other current assets		51,508		34,435
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment		1,217,985		1,063,403
Long-term derivative assets		1,105		1,479
Goodwill(3)		420,955		420,955
Other intangible assets		8,837		9,017
Other assets		10,789		7,552
Total Assets	$	1,716,363	$	1,555,192
Short-term derivative liabilities	$	12,774	$	6,209
Other current liabilities		33,064		34,261
Term loan – current		—		175,000
Long-term debt		771,000		410,500
Long-term derivative liabilities		20,553		30,384
Other long-term liabilities		35,051		29,445
Members’ equity		843,921		320,731
Non-controlling interest in subsidiary		—		548,662
Total Liabilities and Members’ Equity	$	1,716,363	$	1,555,192

(1) Includes the fair value of the ENP assets and liabilities we acquired on December 31, 2010.

(2) From 2009 through 2011, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in the Permian Basin, Big Horn Basin, South Texas and Mississippi. The assets and liabilities associated with these acquired properties were included in our balance sheet data as of each year end.

(3) Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Purchase completed on December 31, 2010.

S-10

Summary Reserve and Operating Data

The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of the estimated proved reserves at December 31, 2011 (on a historical basis and pro forma as adjusted to give effect to the Appalachian Exchange), based on reserve reports prepared by D&M. Copies of their summary reports are included as exhibits to our 2011 Annual Report. The estimate of net proved reserves has not been filed with or included in reports to any federal authority or agency. The Standardized Measure value shown in the table is not intended to represent the current market value of our estimated oil, natural gas and NGLs reserves. You should refer to “Risk Factors,” “Business — Oil, Natural Gas and NGLs Data —  Estimated Proved Reserves,” “— Production and Price History” and “Summary — Recent Developments —  Appalachian Exchange” included in this prospectus supplement in evaluating the material presented below.

	As of December 31, 2011			Pro Forma as Adjusted
Reserve Data:
Estimated net proved reserves:
Crude oil (MBbls)		44,803			44,317
Natural gas (Bcf)		163			129
NGLs (MBbls)		7,385			7,385
Total (MMBOE)		79.3			73.2
Proved developed (MMBOE)		68.2			64.2
Proved undeveloped (MMBOE)		11.1			9.0
Proved developed reserves as % of total proved reserves		86	%		88	%
Average developed reserve life		15 years			15 years
Standardized Measure (in millions)(1)(2)	$	1,476.2		$	1,435.3
Representative Oil and Natural Gas Prices(3):
Oil – WTI per Bbl	$	96.24		$	96.24
Natural gas – Henry Hub per MMBtu	$	4.12		$	4.12

(1) Standardized Measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using the 12-month average price) without giving effect to non-property related expenses such as selling, general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion, amortization and accretion and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income tax expenses because we are not subject to income taxes and our reserves are owned by our subsidiaries which are also not subject to income taxes. Standardized Measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Business — Operations — Price Risk and Interest Rate Management Activities” included elsewhere in this prospectus supplement and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of our 2011 Annual Report.

(2) For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement.

(3) Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month average price for January through December 2011, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price.

S-11

The following table shows certain summary unaudited financial information with respect to our production and sales of oil, natural gas and NGLs. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Production and Price History” included in this prospectus supplement in evaluating the material presented below.

	Net Production						Average Realized Sales Prices(4)						Production Cost(5)
	Crude Oil Bbls/day		Natural Gas Mcf/day		NGLs Bbls/day		Crude Oil Per Bbl		Natural Gas Per Mcf		NGLs Per Bbl		Per BOE
Year Ended December 31, 2011(1)(6)
Elk Basin Field		2,098		315		328	$	81.02	$	3.38	$	84.90	$	10.99
Other		5,370		28,214		855	$	83.02	$	7.50	$	59.96	$	13.54
Total		7,468		28,529		1,183	$	82.45	$	7.45	$	66.88	$	13.07
Year Ended December 31, 2010(2)
Sun TSH Field		40		2,586		358	$	75.74	$	7.59	$	47.88	$	5.77
Other		1,830		11,086		216	$	76.54	$	10.45	$	41.58	$	11.77
Total		1,870		13,672		574	$	76.53	$	9.91	$	45.78	$	10.72
Year Ended December 31, 2009(3)
Sun TSH Field		26		1,124		169	$	65.40	$	11.03	$	39.90	$	3.76
Other		921		11,320		146	$	75.54	$	11.16	$	31.50	$	11.25
Total		947		12,444		315	$	75.26	$	11.15	$	36.12	$	10.39

(1) Average daily production for 2011 calculated based on 365 days including production for all of our and ENP’s acquisitions from the closing dates of these acquisitions.

(2) Average daily production for 2010 calculated based on 365 days including production for the Parker Creek Acquisition from the closing date of this acquisition.

(3) Average daily production for 2009 calculated based on 365 days including production for the Sun TSH and Ward County acquisitions from the closing dates of these acquisitions.

(4) Average realized sales prices including hedges but excluding the non-cash amortization of premiums paid and non-cash amortization of value on derivative contracts acquired.

(5) Production costs include such items as lease operating expenses, gathering and compression fees and other customary charges and exclude production taxes (severance and ad valorem taxes).

(6) Production results for properties acquired in the ENP Purchase on December 31, 2010 through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest in ENP.

S-12

Non-GAAP Financial Measure

Adjusted EBITDA

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

• Net interest expense, including write-off of deferred financing fees and realized gains and losses on interest rate derivative contracts;

• Loss on extinguishment of debt;

• Depreciation, depletion and amortization (including accretion of asset retirement obligations);

• Impairment of oil and natural gas properties;

• Bad debt expenses;

• Amortization of premiums paid on derivative contracts;

• Amortization of value on derivative contracts acquired;

• Unrealized gains and losses on other commodity and interest rate derivative contracts;

• Net gains and losses on acquisitions of oil and natural gas properties;

• Deferred taxes;

• Unit-based compensation expense;

• Realized gains and losses on cancelled derivatives;

• Unrealized fair value of phantom units granted to officers;

• Cash settlement of phantom units granted to officers;

• Material transaction costs incurred on acquisitions and mergers;

• Non-controlling interest amounts attributable to each of the items above from the beginning of year through the completion of the ENP Merger on December 1, 2011, which revert the calculation back to an amount attributable to the Vanguard unitholders; and

• Administrative services fees charged to ENP, excluding the non-controlling interest, which are eliminated in consolidation.

Adjusted EBITDA is a significant performance metric used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors, debt service and capital expenditures) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

S-13

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA (in thousands):

	Year Ended December 31,
	2011(1)			2010(2)			2009
	(in thousands)
Net income (loss) attributable to Vanguard unitholders	$	62,063		$	21,885		$	(95,735	)
Net income attributable to non-controlling interest		26,067			—			—
Net income (loss)		88,130			21,885			(95,735	)
Plus:
Interest expense, including realized losses on interest rate derivative contracts		31,868			7,565			6,179
Loss on extinguishment of debt		—			—			—
Depreciation, depletion, amortization and accretion		84,857			22,231			14,610
Impairment of oil and natural gas properties		—			—			110,154
Bad debt expense		—			—			—
Amortization of premiums paid on derivative contracts		11,346			1,950			3,502
Amortization of value on derivative contracts acquired		169			1,995			3,619
Unrealized (gains) losses on other commodity and interest rate derivative contracts(3)		2,558			14,494			18,280
Net (gain) loss on acquisitions of oil and natural gas properties		367			5,680			(6,981	)
Deferred taxes		261			(12	)		(302	)
Unit-based compensation expense		2,557			847			2,483
Realized loss on cancelled derivatives		—			—			—
Unrealized fair value of phantom units granted to officers		469			179			4,299
Cash settlement of phantom units granted to officers		—			—			(3,906	)
Material transaction costs incurred on acquisitions and mergers		2,019			3,583			—
Less:
Interest income		—			1			—
Adjusted EBITDA before non-controlling interest		224,601			80,396			56,202
Non-controlling interest attributable to adjustments above		(62,838	)		—			—
Administrative services fees eliminated in consolidation		2,840			—			—
Adjusted EBITDA attributable to Vanguard unitholders	$	164,603		$	80,396		$	56,202

(1) Results of operations from oil and natural gas properties acquired in the ENP Purchase on December 31, 2010 through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest.

(2) As the ENP Purchase was completed on December 31, 2010, no results of operations were included for the year ended December 31, 2010.

(3) Oil and natural gas derivative contracts were used to reduce our exposure to changes in oil and natural gas prices. In 2007, we designated all commodity derivative contracts as cash flow hedges. In 2008, all commodity derivative contracts were either de-designated as cash flow hedges or they failed to meet the hedge documentation requirements for cash flow hedges. As a result, the changes in the fair value of other commodity derivative contracts are recorded in earnings and classified as gain (loss) on other commodity derivative contracts. The changes in fair value of interest rate derivative contracts is recorded in earnings and classified as gain (loss) on interest rate derivative contracts.

S-14

RISK FACTORS

An investment in the notes involves a high degree of risk. You should carefully read the risk factors under the caption “Risk Factors” on page 5 of the accompanying prospectus and the risk factors included in “Item 1A. Risk Factors” in our 2011 Annual Report, each of which is incorporated by reference herein. If any of these risks were to occur, our business, financial condition, results of operations or prospects could be materially adversely affected. In any such case, you could lose all or part of your investment or fail to achieve the expected return on the notes.

Risks Relating to the Notes

Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on the notes and our other debt obligations.

We have, and after this notes offering will continue to have, a substantial amount of indebtedness. As of December 31, 2011, on an as adjusted basis, after giving effect to this notes offering and our anticipated use of proceeds therefrom, the Appalachian Exchange and the other transactions described under “Capitalization,” we would have had approximately $    million of total indebtedness, including the notes, and additional borrowing capacity of $    million under our Reserve-Based Credit Facility. The terms and conditions governing our indebtedness, including the notes and our Reserve-Based Credit Facility:

• require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

• increase our vulnerability to economic downturns and adverse developments in our business;

• limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

• place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

• place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;

• make it more difficult for us to satisfy our obligations under the notes or other debt and increase the risk that we may default on our debt obligations; and

• limit management’s discretion in operating our business.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We depend on our Reserve-Based Credit Facility for future capital needs, because we use operating cash flows for investing activities and borrow as needed. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt, including the notes, and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, including the notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

S-15

Availability under our Reserve-Based Credit Facility is subject to adjustment from time to time, but not less than on a semi annual basis, based on the projected discounted present value of estimated future net cash flows (as determined by the bank’s petroleum engineers utilizing the bank’s internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. Significant declines in natural gas, NGL or oil prices may result in a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Reserve-Based Credit Facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our Reserve-Based Credit Facility.

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments, including the notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the notes. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our ability to make payments on the notes and our business, financial condition, results of operations and prospects.

We distribute all of our available cash to our unitholders after reserves established by our general partner, which may limit the cash available to service the notes or repay them at maturity.

Subject to the limitations on restricted payments contained in the indenture governing the notes offered hereby and in our Reserve-Based Credit Facility, we will distribute all of our “available cash” each quarter to our unitholders. “Available cash” is defined in our partnership agreement, and it generally means, for any quarter, prior to liquidation:

• the sum of:

• all our and our subsidiaries’ cash and cash equivalents (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) on hand at the end of that quarter; and

• all our and our subsidiaries’ additional cash and cash equivalents (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made subsequent to the end of such quarter,

S-16

• less the amount of any cash reserves established by the board of directors (or our proportionate share of cash and cash equivalents in the case of subsidiaries that are not wholly-owned) to:

• provide for the proper conduct of our or our subsidiaries’ business (including reserves for future capital expenditures, including drilling and acquisitions, and for our and our subsidiaries’ anticipated future credit needs);

• comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we are bound or our assets are subject; or

• provide funds for distributions to our unitholders with respect to any one or more of the next four quarters;

provided that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of a quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if the board of directors so determines.

As a result, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash available to us in subsequent periods to make payments on the notes.

The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.

The notes and the guarantees will be general unsecured senior obligations ranking effectively junior in right of payment to all existing and future secured debt of ours and that of each subsidiary guarantor, respectively, including obligations under our Reserve-Based Credit Facility, to the extent of the value of the collateral securing the debt. At December 31, 2011, on an as further adjusted basis after giving effect to this notes offering and our anticipated use of proceeds therefrom, the Appalachian Exchange and the other transactions described under “Capitalization,” our total debt would have been approximately $    million, $    million of which would have been secured by liens on our assets; and we would have had approximately $    million in additional borrowing capacity under our Reserve-Based Credit Facility after giving effect to the automatic reduction in our borrowing base resulting from the closing of this offering and the Appalachian Exchange.

If we or a subsidiary guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, any secured debt of ours or of that subsidiary guarantor will be entitled to be paid in full from our assets or the assets of the guarantor, as applicable, securing that debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably with all holders of our other unsecured indebtedness that does not rank junior to the notes, including all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Reserve-Based Credit Facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. If interest rates on our facility increased by 1%, interest expense for the year ended December 31, 2011 would have increased by approximately $10 million.

S-17

Despite our and our subsidiaries’ current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Reserve-Based Credit Facility and under the indenture for the notes offered hereby. For example, after giving effect to the offering of the notes and the application of the proceeds of this offering as described under “Use of Proceeds,” we expect to have approximately $336 million of borrowing capacity under our Reserve-Based Credit Facility after giving effect to the automatic reduction in our borrowing base resulting from the closing of this offering and the Appalachian Exchange. See “Description of Other Indebtedness — Existing Debt and Credit Facilities — Senior Secured Reserve-Based Credit Facility.” If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations, including those relating to the notes.

We may not be able to repurchase the notes upon a change of control.

Upon the occurrence of certain change of control events, we would be required to offer to repurchase all or any part of the notes then outstanding for cash at 101% of the principal amount plus accrued and unpaid interest. The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from our operations or other sources, including:

• borrowings under our Reserve-Based Credit Facility or other sources;

• sales of assets; or

• sales of equity.

We cannot assure you that sufficient funds would be available at the time of any change of control to repurchase your notes after first repaying any of our senior debt that may exist at the time. In addition, restrictions under our Reserve-Based Credit Facility will not allow such repurchases and additional credit facilities we enter into in the future also may prohibit such repurchases. We cannot assure you that we can obtain waivers from the lenders. Additionally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

A Delaware court has recently held that a provision similar to the change of control put right that will be in the indenture for the notes may not be enforceable if it is used to improperly limit the ability of equity owners to effect a change of control.

The Chancery Court of Delaware has held in a published opinion that a provision in an indenture requiring a majority of the directors of the company issuing the notes be “continuing directors” could breach the fiduciary duties of the directors and be unenforceable if improperly used to prevent shareholders from effecting a change of control of the company. Under the continuing director provision of the indenture for the notes offered hereby, a majority of our board of directors must be “continuing directors” defined as either (i) a director on the date of the indenture or (ii) a director whose nomination for election, or whose election, to the board of directors was approved by a majority of the continuing directors. Under the court’s decision, a decision by a board of directors not to approve dissident shareholder nominees as continuing directors and to allow a change of control to occur would be subject to enhanced fiduciary duties typically applied in corporate change of control disputes. If the directors did not properly discharge those fiduciary duties, the change of control put right could be unenforceable by the holders of the notes. As a result, the ability of the holders of notes to enforce the continuing director provision in situations in which the provision acted to impede a change of control would be subject to the enhanced judicial scrutiny of the actions by our directors not to approve the director nominees whose election caused the provision to be invoked.

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A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.

Initially, all of our subsidiaries (other than VNR Finance Corp.) will guarantee the notes. Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, our subsidiary guarantees can be voided, or claims under the subsidiary guarantees may be subordinated to all other debts of that subsidiary guarantor if, among other things, the subsidiary guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:

• was insolvent or rendered insolvent by reason of such incurrence;

• was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

• intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

A court would likely find that a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the subsidiary guarantor did not substantially benefit directly or indirectly from the issuance of the guarantees. If a court were to void a subsidiary guarantee, you would no longer have a claim against the subsidiary guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining subsidiary guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:

• the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all its assets;

• the present fair saleable value of its assets is less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

Our subsidiary guarantees may also be voided, without regard to the above factors, if a court finds that the subsidiary guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors.

Each subsidiary guarantee contains a provision intended to limit the subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. Such provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

A financial failure by us or our subsidiaries may result in the assets of any or all of those entities becoming subject to the claims of all creditors of those entities.

A financial failure by us or our subsidiaries could affect payment of the notes if a bankruptcy court were to substantively consolidate us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would become subject to the claims of creditors of all entities. This would expose holders of notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the notes could occur through the “cram-down” provisions of the bankruptcy code. Under these provisions, the notes could be restructured over your objections as to their general terms, primarily interest rate and maturity.

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Because we are a holding company, we are financially dependent on receiving distributions from our subsidiaries.

We are a holding company and our assets consist primarily of investments in our subsidiaries. Our rights and the rights of our creditors, including holders of the notes, to participate in the distribution of assets of any entity in which we own an equity interest will be subject to prior claims of the entity’s creditors upon the entity’s liquidation or reorganization. However, we may ourselves be a creditor with recognized claims against this entity, but our claims would still be subject to the prior claims of any secured creditor of this entity and of any holder of indebtedness of this entity that is senior to that held by us. Accordingly, a holder of our debt securities, including holders of the notes, may be deemed to be effectively subordinated to those claims.

Many of the covenants contained in the indenture will terminate if the notes are rated investment grade by both Standard & Poor’s and Moody’s and no default (other than a reporting default) has occurred and is continuing.

Many of the covenants in the indenture governing the notes will terminate if the notes are rated investment grade by both Standard & Poor’s and Moody’s provided at such time no default has occurred and is continuing. The covenants will restrict, among other things, our ability to pay distributions on our common units, incur debt and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade. However, termination of these covenants would allow us to engage in certain transactions that would not have been permitted while these covenants were in force, and the effects of any such transactions will be permitted to remain in place even if the notes are subsequently downgraded below investment grade. See “Description of Notes — Certain Covenants — Changes in Covenants if Notes Rated Investment Grade.”

If we were to become subject to entity-level taxation for U.S. federal income tax purposes or in states where we are not currently subject to entity-level taxation, our cash available for payment on the notes could be materially reduced.

In order for us to avoid paying U.S. federal income tax at the entity level, we must qualify for treatment as a partnership for U.S. federal income tax purposes. In order to qualify for partnership treatment, at least 90% of our annual gross income must be “qualifying income” derived from marketing crude oil and natural gas and other specified activities. While we believe 90% or more of our gross income for each taxable year consists of qualifying income, and we intend to meet this gross income requirement for future taxable years, we may not find it possible, regardless of our efforts, to meet this gross income requirement or we may inadvertently fail to meet this gross income requirement. Moreover, at the federal level, legislation has recently been considered by members of Congress that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although it does not appear that the legislation considered would have affected our tax treatment, we are unable to predict whether any of these changes or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income taxes at varying rates in some states where we are not currently subject to state income tax. If we were required to pay tax on our taxable income, our anticipated cash flow could be materially reduced, which could materially and adversely affect our ability to make payments on the notes and on our other debt obligations.

In addition, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. The imposition of such taxes could reduce the cash available for payment on the notes and on our other debt obligations.

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Risks Relating to Our Business

We may not have sufficient cash from operations to pay quarterly distributions on our common units or make payments on the notes and our other debt obligations following establishment of cash reserves and payment of operating costs.

We may not have sufficient cash flow from operations pay quarterly distributions on our common units or to make payments on the notes and our other debt obligations. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. 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, among other things:

• the amount of oil, natural gas and NGLs we produce;

• the price at which we are able to sell our oil, natural gas and NGLs production;

• the level of our operating costs;

• the level and success of our price risk management activities;

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

• the level of our capital expenditures; and

• voluntary or required payments on our debt agreements.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

• the level of our capital expenditures;

• our ability to make working capital borrowings under our financing arrangements to pay distributions;

• the cost of acquisitions, if any;

• our debt service requirements;

• fluctuations in our working capital needs;

• timing and collectability of receivables;

• prevailing economic conditions; and

• the amount of cash reserves established by our board of directors for the proper conduct of our business.

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. If we do not achieve our expected operational results or cannot borrow the amounts needed, we may not be able to pay the full, or any, amount of the quarterly distributions, in which event the market price of our common units may decline substantially.

Growing the Company will require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.

We plan to fund our growth through acquisitions with proceeds from sales of our debt and equity securities, borrowings under our Reserve-Based Credit Facility and other financing arrangements; however, we cannot be certain that we will be able to issue our debt and equity securities on terms or in the proportions that we expect, or at all, and we may be unable to refinance our Reserve-Based Credit Facility and other financing arrangements when they expire.

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A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our Reserve-Based Credit Facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or not pursue growth opportunities.

Our financing arrangements have substantial restrictions and financial covenants and we may have difficulty obtaining additional credit, which could adversely affect our operations.

Our borrowing base is the amount of money available for borrowing, as determined semi-annually by our lenders in their sole discretion. The lenders will re-determine the borrowing base based on an engineering report with respect to our oil, natural gas and NGLs reserves, which will take into account the prevailing oil, natural gas and NGLs prices at such time. In the future, we may not be able to access adequate funding under our Reserve-Based Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.

A future decline in commodity prices could result in a redetermination lowering our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our financing arrangements. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our Reserve-Based Credit Facility.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

A principal component of our business strategy is to grow our asset base and production through the acquisition of oil and natural gas properties characterized by long-lived, stable production. The character of newly acquired properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. The changes in the characteristics and risk profiles of such new properties will in turn affect our risk profile, which may negatively affect our ability to issue equity or debt securities in order to fund future acquisitions and may inhibit our ability to renegotiate our existing credit facilities on favorable terms.

Our future distributions and proved reserves will be dependent upon the success of our efforts to prudently acquire, manage and develop oil and natural gas properties that conform to the acquisition profile described in our 2011 Annual Report.

In addition to ownership of the properties currently owned by us, unless we acquire properties in the future containing additional proved reserves or successfully develop proved reserves on our existing properties, our proved reserves will decline as the reserves attributable to the underlying properties are produced. In addition, if the costs to develop or operate our properties increase, the estimated proved reserves associated with properties will be reduced below the level that would otherwise be estimated. We will manage and develop our properties, and the ultimate value to us of such properties which we acquire will be dependent upon the price we pay and our ability to prudently acquire, manage and develop such properties. As a result, our ability to make payments on the notes and on our other debt obligations will be dependent to a substantial extent upon our ability to prudently acquire, manage and develop such properties.

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Suitable acquisition candidates may not be available on terms and conditions that we find acceptable, we may not be able to obtain financing for certain acquisitions, and acquisitions pose substantial risks to our businesses, financial conditions and results of operations. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions, which could reduce the amount of cash available from the affected properties:

• some of the acquired properties may not produce revenues, reserves, earnings or cash flow at anticipated levels;

• we may assume liabilities that were not disclosed or that exceed their estimates;

• we may be unable to integrate acquired properties successfully and may not realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

• acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

• we may incur additional debt related to future acquisitions.

Oil, natural gas and NGLs prices are volatile. A decline in oil, natural gas and NGLs prices could adversely affect our financial position, financial results, cash flow, access to capital and ability to grow and make payments on the notes and on our other debt obligations.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil, natural gas and NGLs production and the prices prevailing from time to time for oil, natural gas and NGLs. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our Reserve-Based Credit Facility and through the capital markets. The amount available for borrowing under our Reserve-Based Credit Facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. The recent volatility in oil, natural gas and NGLs prices has impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. Further, because we have elected to use the full-cost accounting method, each quarter we must perform a “ceiling test” that is impacted by declining prices. Additionally, we have recorded goodwill which represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Acquisition. Significant price declines could cause us to take one or more ceiling test write downs or cause us to record an impairment of goodwill, which would be reflected as non-cash charges against current earnings.

Oil, natural gas and NGLs prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, the crude oil spot price per barrel for the period between January 1, 2011 and December 31, 2011 ranged from a high of $113.39 to a low of $75.40 and the NYMEX natural gas spot price per MMBtu for the period January 1, 2011 to December 31, 2011 ranged from a high of $4.85 to a low of $2.99. As of February 28, 2012, the crude oil spot price per barrel was $106.59 and the NYMEX natural gas spot price per MMBtu was $2.52. This price volatility affects the amount of our cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil, natural gas and NGLs are subject to a variety of factors, including:

• the level of consumer demand for oil, natural gas and NGLs;

• the domestic and foreign supply of oil, natural gas and NGLs;

• commodity processing, gathering and transportation availability, and the availability of refining capacity;

• the price and level of imports of foreign crude oil, natural gas and NGLs;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and to enforce crude oil price and production controls;

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• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• political conditions or hostilities in oil and gas producing regions, including the Middle East, Africa and South America;

• technological advances affecting energy consumption; and

• worldwide economic conditions.

Declines in oil, natural gas and NGLs prices would not only reduce our revenue, but could reduce the amount of oil, natural gas and NGLs that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. If the gas and oil industry experiences significant price declines, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms or make payment on the notes and on our other debt obligations.

Unless we replace our reserves, our existing reserves and production will decline, which would adversely affect our cash flow from operations and our ability to make payment on the notes and on our other debt obligations.

Producing oil and natural gas wells extract hydrocarbons from underground structures referred to as reservoirs. Reservoirs contain a finite volume of hydrocarbon reserves referred to as reserves in place. Based on prevailing prices and production technologies, only a fraction of reserves in place can be recovered from a given reservoir. The volume of the reserves in place that is recoverable from a particular reservoir is reduced as production from that well continues. The reduction is referred to as depletion. Ultimately, the economically recoverable reserves from a particular well will deplete entirely, and the producing well will cease to produce and will be plugged and abandoned. In that event, we must replace our reserves. Unless we are able over the long-term to replace the reserves that are produced, our ability to make payments on the notes and our other debt obligations could materially decrease.

Lower oil, natural gas and NGLs prices and other factors have resulted, and in the future may result, in ceiling test or goodwill write downs and other impairments of our asset carrying values.

We use the full cost method of accounting to report our oil and natural gas properties. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write down.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write down would not impact cash flow from operating activities, but it could have a material adverse effect on our results of operations in the period incurred and would reduce our members’ equity.

The risk that we will be required to write down the carrying value of our oil and natural gas properties increases when oil and gas prices are low or volatile. In addition, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties and goodwill if we experience substantial downward adjustments to our estimated proved reserves, or if estimated future operating or development costs increase. For example, oil, natural gas and NGLs prices were very volatile throughout 2009. We recorded a non-cash ceiling test impairment of natural gas and oil properties for the year ended December 31, 2009 of $110.2 million. The impairment for the first quarter 2009 was $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and $49.64 per barrel of crude oil. The SEC’s Final Rule, “Modernization of Oil and Gas Reporting,” which became effective December 31, 2009, changed the price used to calculate oil and gas reserves to a 12-month average price rather than a year-end price. As a result of declines in natural gas and oil prices based upon the 12-month average price, we recorded an

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additional impairment of $46.4 million in the fourth quarter of 2009. This impairment was calculated using the 12-month average price for natural gas and oil of $3.87 per MMBtu for natural gas and $ 61.04 per barrel of crude oil. These and other factors could cause us to record write downs of our oil and natural gas properties and other assets in the future and incur additional charges against future earnings. Based on the 12-month average natural gas and oil prices through February 2012, we do not anticipate an impairment at March 31, 2012.

Additionally, we have recorded goodwill which represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Acquisition. Significant price declines could cause us to record an impairment of goodwill, which would be reflected as non-cash charge against current earnings.

Our acquisition activities will subject us to certain risks.

We have expanded our operations through acquisitions. Any acquisition involves potential risks, including, among other things: the validity of our assumptions about reserves, future production, revenues and costs, including synergies; an inability to integrate successfully the businesses we acquire; a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; the diversion of management’s attention to other business concerns; an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; the incurrence of other significant charges, such as impairment of recorded goodwill or other intangible assets, asset devaluation or restructuring charges; unforeseen difficulties encountered in operating in new geographic areas; an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes; and customer or key employee losses at the acquired businesses.

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 us 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.

If our acquisitions do not generate increases in available cash per unit, our ability to make payments on the notes and our other debt obligations could materially decrease.

We could lose our interests in future wells in our South Texas area if we fail to participate under our operating agreement with Lewis Petroleum in the drilling of these wells.

Under the terms of our operating agreement with Lewis Petroleum, we may elect to forego participation in the future drilling of wells. Should we do so, we will become obligated to transfer without compensation all of our right, title and interest in those wells.

The amount of cash that we have available to make payments on the notes and our other debt obligations depends primarily upon our cash flow and not our profitability.

The amount of cash that we have available to make payments on the notes and our other debt obligations depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-cash items. As a result, we may be unable to make payments on the notes and our other debt obligations even when we record net income, and we may be able to make payments on the notes and our other debt obligations during periods when we incur net losses.

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

No one can measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and/or natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Independent petroleum engineers prepare estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, the calculation of estimated reserves requires certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs, any of which assumptions may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per MMBtu and oil prices declined by $6.00 per barrel, the standardized measure of our proved reserves as of December 31, 2011 would decrease from $1.5 billion to $1.3 billion, based on price sensitivity generated from an internal evaluation. Our standardized measure is calculated using unhedged oil and natural gas prices and is determined in accordance with the rules and regulations of the SEC. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGLs we ultimately recover being different from our reserve estimates.

The present value of future net cash flows from our 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 proved reserves using a 12-month average price and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

• the volume, pricing and duration of our oil and natural gas hedging contracts;

• supply of and demand for oil, natural gas and NGLs;

• actual prices we receive for oil, natural gas and NGLs;

• our actual operating costs in producing oil, natural gas and NGLs;

• the amount and timing of our capital expenditures;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations, financial condition and our ability to make payments on the notes and our other debt obligations.

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Our operations require substantial capital expenditures, which will reduce our cash available to make payments on the notes and our other debt obligations. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves and adversely affect our ability to make payments on the notes and our other debt obligations.

The oil and natural gas industry is capital intensive. We have made and ultimately expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGLs reserves. These expenditures will reduce our cash available to make payments on the notes and our other debt obligations. We intend to finance our future capital expenditures with cash flow from operations and our financing arrangements. Our cash flow from operations and access to capital is subject to a number of variables, including:

• our proved reserves;

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

• the prices at which our oil, natural gas and NGLs are sold; and

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

If our revenues or the borrowing base under our Reserve-Based Credit Facility decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels or to replace or add to our reserves. Our Reserve-Based Credit Facility restricts our ability to obtain new debt financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our Reserve-Based Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production and a reduction in our cash available to make payments on the notes and our other debt obligations.

Our business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and NGLs we produce and could reduce our revenues and cash available to make payments on the notes and our other debt obligations.

The marketability of our oil, natural gas and NGLs production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available to make payments on the notes and our other debt obligations.

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Our sales of oil, natural gas and NGLs and other energy commodities, and related hedging activities, expose us to potential regulatory risks.

The Federal Trade Commission (“FTC”), Federal Regulatory Commission (“FERC”) and the Commodities Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil, natural gas and NGLs or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and our ability to make payments on the notes and our other debt obligations.

We are subject to FERC requirements related to our use of capacity on natural gas pipelines that are subject to FERC regulation. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.

Climate change legislation and regulatory initiatives restricting emissions of greenhouse gases may adversely affect our operations, our cost structure, or the demand for oil and natural gas.

In response to findings made by the EPA in December 2009 that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes, the EPA, has adopted regulations under existing provisions of the federal Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that triggers construction and operating permit review for GHG emissions from certain stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under Prevention of Significant Deterioration, (“PSD”) and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities, which may include certain of our operations on an annual basis. Congress has from time to time actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our provision of services.

The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief for certain regulations applicable to swaps, until no later than July 16, 2012. The CFTC has issued final regulations to set position limits for certain

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futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The legislation and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures or to make payments on the notes and our other debt obligations. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have material, adverse effect on us, our financial condition, and our results of operations.

We depend on certain key customers for sales of our oil, natural gas and NGLs. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs they purchase from us, or to the extent these customers cease to be creditworthy, our revenues and cash available to make payments on the notes and our other debt obligations could decline.

For the year ended December 31, 2011, sales of oil, natural gas and NGLs to Marathon Oil Company, Plains Marketing LP, Shell Trading (US) Company, Flint Hills Resources, LP and Lewis Petro Properties Inc. accounted for approximately 22%, 11%, 8%, 6% and 5%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2011, therefore accounted for 52% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available to make payments on the notes and our other debt obligations could decline.

We are subject to compliance with environmental and occupational safety and health laws and regulations that may expose us to significant costs and liabilities.

The operations of our wells are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, environmental protection, and the health and safety of employees. These laws and regulations may impose numerous obligations on our operations including the acquisition of permits, including drilling permits, to conduct regulated activities; the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities; restriction of types, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmental sensitive areas such as wetlands, wilderness regions and other protected areas; the imposition of substantial liabilities for pollution resulting from our operations; and the application of specific health and safety criteria addressing worker protection. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, and under certain circumstances, joint and several liability for costs required to clean up and restore sites where hazardous substances or wastes have been disposed of or otherwise released. Moreover, it is not

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uncommon for neighboring landowners and other third parties to file claims for personal injury and property or natural resource damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We may incur significant environmental costs and liabilities due to the nature of our business and the petroleum hydrocarbons, hazardous substances and wastes resulting from or associated with operation of our wells. For example, an accidental release of petroleum hydrocarbons from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance. Please read “Business — Operations — Environmental and Occupational Health and Safety Matters.”

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and operating restrictions or delays in the completion of oil and natural gas wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Texas and Wyoming, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

Locations that we or the operators of our properties decide to drill may not yield oil or natural gas in commercially viable quantities.

The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we or the operators of our properties drill dry holes or wells that are productive but do not produce enough to be commercially viable after drilling, operating and other costs. If we or the operators of our properties drill future wells that we identify as dry holes, our drilling success rate would decline and may adversely affect our results of operations and our ability to make payments on the notes and our other debt obligations.

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Many of our leases are in areas that have been partially depleted or drained by offset wells.

Many of our leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our ability to find economically recoverable quantities of oil or natural gas in these areas.

Our identified drilling location inventories are scheduled out 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 make payments on the notes and our other debt obligations.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2011, after giving effect to the Appalachian Exchange, we have identified 147 proved undeveloped drilling locations and over 205 additional drilling locations. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, drilling and operating costs and drilling results. In addition, D&M has not assigned any proved reserves to the over 205 unproved drilling locations we have identified and scheduled for drilling and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on 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 oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to make payments on the notes and our other debt obligations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil or natural gas can be uneconomical, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

• the high cost, shortages or delivery delays of equipment and services;

• shortages of or delays in obtaining water for hydraulic fracturing operations;

• unexpected operational events;

• adverse weather conditions;

• facility or equipment malfunctions;

• title problems;

• pipeline ruptures or spills;

• compliance with environmental and other governmental requirements;

• unusual or unexpected geological formations;

• loss of drilling fluid circulation;

• formations with abnormal pressures;

• environmental hazards, such as oil, natural gas or well fluids spills or releases, pipeline or tank ruptures and discharges of toxic gas;

• fires;

• blowouts, craterings and explosions;

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• uncontrollable flows of oil, natural gas or well fluids; and

• pipeline capacity curtailments.

Any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

We ordinarily maintain insurance against various losses and liabilities arising from our operations; however, insurance against all operational risks is not available to us. 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. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

We may incur substantial additional debt in the future to enable us to pursue our business plan and to pay distributions to our unitholders.

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 borrow, to the extent available, significant amounts under our Reserve-Based Credit Facility in the future to enable us to pay quarterly distributions. Significant declines in our production or significant declines in realized oil, natural gas and NGLs prices for prolonged periods and resulting decreases in our borrowing base may force us to reduce or suspend distributions to our unitholders.

If 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 Reserve-Based Credit Facility to pay distributions rather than to maintain or expand our operations. If we use borrowings under our Reserve-Based 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 common units. If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce or suspend our distribution in order to avoid excessive leverage and debt covenant violations.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas and as a result, we generally perform the majority of our drilling in these areas during the summer and fall months. These seasonal anomalies can pose challenges for meeting our well drilling 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. Additionally, many municipalities impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This limits our access to these jobsites and our ability to service wells in these areas. Generally, but not always, oil is typically in higher demand in the summer for its use in road construction and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

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Our price risk management activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to make payments on the notes and our other debt obligations.

We enter into derivative contracts to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Currently, we use a combination of fixed-price swaps, basis swaps, swaptions, put options, NYMEX collars and three-way collars to mitigate the volatility of future oil and natural gas prices received. Please read “Business — Operations — Price Risk and Interest Rate Management Activities” included elsewhere in this prospectus supplement and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of our 2011 Annual Report.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional 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 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 price risk management 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.

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 vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’, customers’ and counterparties’ liquidity and ability to make payments or perform on their obligations to us. 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 vendors, customers and/or counterparties could reduce our ability to make payments on the notes and our other debt obligations.

We depend on senior management personnel, each of whom would be difficult to replace.

We depend on the performance of Scott W. Smith, our President and Chief Executive Officer, Richard A. Robert, our Executive Vice President and Chief Financial Officer and Britt Pence, our Senior Vice President of Operations. We maintain no key person insurance for either Mr. Smith, Mr. Robert or Mr. Pence. The loss of any or all of Messrs. Smith, Robert and Pence could negatively impact our ability to execute our strategy and our results of operations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to make payments on the notes and our other debt obligations.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and

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evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil, natural gas and NGLs 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 adverse impact on our business activities, financial condition and results of operations.

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

Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property and natural resource damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our profitability. At this time, we cannot predict the effect of this increase on our results of operations. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating staff. Please read “Business —  Operations — Environmental and Occupational Health and Safety Matters” and “Business — Operations —  Other Regulation of the Oil and Natural Gas Industry” included elsewhere in this prospectus supplement for a description of the laws and regulations that affect us.

Shortages of drilling rigs, supplies, oilfield services, equipment and crews could delay our operations and reduce our cash to make payments on the notes and our other debt obligations.

Higher oil, natural gas and NGLs prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. In the past, we and other oil, natural gas and NGLs companies have experienced higher drilling and operating costs. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Sustained periods of lower oil, natural gas and NGLs prices could bring about the closure or downsizing of entities providing drilling services, supplies, oil field services, equipment and crews. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues and cash available to make payments on the notes and our other debt obligations.

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Tax Risks Relating to the Notes

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 for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for payment of principal and interest on the notes.

Despite the fact that we are a limited liability company (LLC) under Delaware law, a publicly traded LLC such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Failing to meet the qualifying income requirement or a change in current law may cause us to be treated as a corporation for federal income tax purposes.

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 rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Any such tax imposed on us would reduce our cash available for payment of principal and interest on the notes.

Current law or our business 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. At the federal level, legislation has been recently considered that would have eliminated partnership tax treatment for certain publicly traded LLCs. Although such legislation did not appear as if it would have applied to us as proposed, it could be reconsidered in a manner that would apply to us. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively.

The notes may be issued with OID for U.S. federal income tax purposes.

The notes will be treated as issued with OID for U.S. federal income tax purposes if the difference between the principal amount of the notes and their issue price is equal to or greater than a specified de minimis amount. If the notes are issued with OID, U.S. holders (as defined in “Certain United States Federal Income and Estate Tax Considerations”) will be required to include such OID in gross income (as ordinary income) on a constant yield to maturity basis in advance of the receipt of cash payment thereof, regardless of such holders’ method of accounting for U.S. federal income tax purposes. See “Certain United States Federal Income and Estate Tax Considerations.”

If a bankruptcy petition were filed by or against us under the U.S. Bankruptcy Code after the issuance of the notes, the claim by any holder of the notes for the principal amount of the notes may be limited to an amount equal to the sum of:

• the original issue price for the notes; and

• that portion of the OID (if any) that does not constitute “unmatured interest” for purposes of the U.S. Bankruptcy Code.

Any OID that was not amortized as of the date of the bankruptcy filing would constitute unmatured interest. Accordingly, holders of the notes under these circumstances may receive a lesser amount than they would be entitled to receive under the terms of the indenture governing the notes, even if sufficient funds were available.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $       million from the sale of the notes after deducting underwriting discounts and estimated offering expenses. We intend to use a portion of the net proceeds from this offering to repay all indebtedness outstanding under our Facility Term Loan, and we plan to apply the balance of the net proceeds to outstanding borrowings under our Reserve-Based Credit Facility.

Amounts repaid under our Facility Term Loan may not be reborrowed. Amounts repaid under our Reserve-Based Credit Facility may be reborrowed from time to time for acquisitions, growth capital expenditures, working capital needs and other general limited liability company purposes. As of March 23, 2012, there was $57 million in aggregate principal amount of loans under our Facility Term Loan and approximately $571 million in aggregate principal amount of loans outstanding under our Reserve-Based Credit Facility, substantially all of which was incurred to finance acquisitions. As of March 23, 2012, interest on borrowings under our Facility Term Loan had a variable interest rate of approximately 5.8%, and our Reserve-Based Credit Facility had a variable interest rate of approximately 2.5%, excluding the effect of interest rate swaps. Our Facility Term Loan matures on May 30, 2017, and the commitments under our Reserve-Based Credit Facility mature on October 31, 2016.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our historical consolidated ratio of earnings to fixed charges for the periods indicated:

	Year Ended December 31,
	2011		2010		2009		2008		2007
Ratio of Earnings to Fixed Charges		3.74		3.88		(a)		(a)		1.31

For purposes of computing the ratio of earnings to fixed charges, “earnings” consist of pretax income from continuing operations available to Vanguard unitholders plus fixed charges (excluding capitalized interest). “Fixed charges” represent interest incurred (whether expensed or capitalized), amortization of debt expense, and that portion of rental expense on operating leases deemed to be the equivalent of interest.

(a) In the years ended December 31, 2009 and 2008, earnings were inadequate to cover fixed charges by approximately $95.7 million and $3.8 million, respectively. The shortfalls for the years ended December 31, 2009 and 2008 were principally the result of non-cash natural gas and oil property impairment charges of $110.2 million and $58.9 million, respectively.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of December 31, 2011:

• on a consolidated historical basis;

• as adjusted to give effect to (i) our recent common unit offering described in this prospectus supplement under “Summary — Recent Developments — Public Offering of Our Common Units” and (ii) the Appalachian Exchange described in this prospectus supplement under “Summary —  Recent Developments — Appalachian Exchange;” and

• as further adjusted to reflect the sale of the notes offered hereby at par and the application of the net proceeds therefrom as described in “Use of Proceeds.”

You should read our financial statements and notes that are incorporated by reference into this prospectus supplement for additional information.

	As of December 31, 2011
	(in thousands) (unaudited)
	Historical		As Adjusted		As Further Adjusted for this Offering
Cash and cash equivalents	$	2,851	$	2,851	$	2,851
Current and long-term debt:
Facility Term Loan	$	100,000	$	57,000	$	—
Reserve-Based Credit Facility(1)		671,000		579,120
% Senior Notes due 2020 offered hereby		—		—			(2)
Total debt		771,000		636,120
Members’ equity:
Members’ capital		839,714		920,520		920,520
Class B units		4,207		4,207		4,207
Total members’ equity		843,921		924,727		924,727
Total capitalization	$	1,614,921	$	1,560,847	$

(1) As of March 23, 2012, we had approximately $571 million of borrowings outstanding under our Reserve-Based Credit Facility.

(2) Reflects $300 million of principal amount of the notes less underwriting discounts of $        .

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SELECTED HISTORICAL AND CONSOLIDATED FINANCIAL AND OPERATING DATA

Set forth below is our selected historical consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC. The summary historical financial data for the years ended December 31, 2011, 2010, 2009, 2008 and 2007 have been derived from our audited financial statements.

You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes appearing elsewhere in this prospectus supplement.

The following table presents a non-GAAP financial measure, Adjusted EBITDA, which we use in our business. This measure is not calculated or presented in accordance with GAAP. We explain this measure below and reconcile it to the most directly comparable financial measure calculated and presented in accordance with GAAP in “Summary — Non-GAAP Financial Measure.”

	Year Ended December 31,(5)
	2011(6)			2010			2009			2008			2007
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues:
Oil, natural gas and NGLs sales	$	312,842		$	85,357		$	46,035		$	68,850		$	34,541
Gain (loss) on commodity cash flow hedges(1)		(3,071	)		(2,832	)		(2,380	)		269			(702	)
Realized gain (loss) on other commodity derivative contracts(1)		10,276			24,774			29,993			(6,552	)		—
Unrealized gain (loss) on other commodity derivative contracts(1)		(470	)		(14,145	)		(19,043	)		39,029			—
Total revenues		319,577			93,154			54,605			101,596			33,839
Costs and Expenses:
Production:
Lease operating expenses		63,944			18,471			12,652			11,112			5,066
Production and other taxes		28,621			6,840			3,845			4,965			2,054
Depreciation, depletion, amortization and accretion		84,857			22,231			14,610			14,910			8,981
Impairment of oil and natural gas properties		—			—			110,154			58,887			—
Selling, general and administrative expenses(2)		19,779			10,134			10,644			6,715			3,507
Bad debt expense		—			—			—			—			1,007
Total costs and expenses		197,201			57,676			151,905			96,589			20,615
Income (Loss) from Operations:		122,376			35,478			(97,300	)		5,007			13,224
Other Income (Expense):
Other income		77			1			—			17			62
Interest and financing expenses		(28,994	)		(5,766	)		(4,276	)		(5,491	)		(8,135	)
Realized loss on interest rate derivative contracts		(2,874	)		(1,799	)		(1,903	)		(107	)		—
Net gain (loss) on acquisition of oil and natural gas properties		(367	)		(5,680	)		6,981			—			—
Unrealized gain (loss) on interest rate derivative contracts		(2,088	)		(349	)		763			(3,178	)		—
Loss on extinguishment of debt		—			—			—			—			(2,502	)
Total other income (expenses)		(34,246	)		(13,593	)		1,565			(8,759	)		(10,575	)
Net Income (Loss)	$	88,130		$	21,885		$	(95,735	)	$	(3,752	)	$	2,649
Less: Net income attributable to non-controlling interest		(26,067	)		—			—			—			—
Net Income (Loss) attributable to Vanguard unitholders	$	62,063		$	21,885		$	(95,735	)	$	(3,752	)	$	2,649
Net Income (Loss) Per Unit:
Common and Class B units – basic & diluted	$	1.95		$	1.00		$	(6.74	)	$	(0.32	)	$	0.39
Distributions Declared Per Unit	$	2.28		$	2.15		$	2.00		$	1.77	(3)	$	0.425	(3)
Weighted Average Common Units Outstanding		31,369			21,500			13,791			11,374			6,533
Weighted Average Class B Units Outstanding		420			420			420			420			420
Cash Flow Data:
Net cash provided by operating activities	$	176,332		$	71,577		$	52,155		$	39,554		$	1,373
Net cash used in investing activities		(236,350	)		(429,994	)		(109,315	)		(119,539	)		(26,409	)
Net cash provided by financing activities		61,041			359,758			57,644			76,878			26,415
Other Financial Information:
Adjusted EBITDA attributable before non-controlling interest(4)	$	224,601		$	80,396		$	56,202		$	48,754		$	30,395

(1) Oil and natural gas derivative contracts were used to reduce our exposure to changes in oil and natural gas prices. In 2007, we designated all commodity derivative contracts as cash flow hedges; therefore, the

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changes in fair value in 2007 are included in other comprehensive income (loss). In 2008, all commodity derivative contracts were either de-designated as cash flow hedges or they failed to meet the hedge documentation requirements for cash flow hedges. As a result, (a) for the cash flow hedges that were settled in 2008 through 2011, the change in fair value through December 31, 2007 has been reclassified to earnings from accumulated other comprehensive loss and is classified as gain (loss) on commodity cash flow hedges and (b) the changes in the fair value of other commodity derivative contracts are recorded in earnings and classified as gain (loss) on other commodity derivative contracts.

(2) Includes $3.0 million, $1.0 million, $2.9 million, $3.6 million and $2.1 million of non-cash unit-based compensation expense in 2011, 2010, 2009, 2008 and 2007, respectively.

(3) Distributions declared per unit for 2008 were calculated using total distributions to members of $20.1 million over the weighted average common units for the year. The 2007 distribution was pro-rated for the period from the closing of our initial public offering on October 28, 2007 through December 31, 2007, resulting in a distribution of $0.291 per unit for the period.

(4) See “Summary — Summary Historical Consolidated Financial and Operating Data — Non- GAAP Financial Measure.”

(5) From 2008 through 2011, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in the Permian Basin, Big Horn Basin and Mississippi. The operating results of these properties were included in the accompanying financial statements and related notes included elsewhere in this prospectus supplement from the closing date of the acquisition forward.

(6) The operating results of the subsidiaries we acquired in the ENP Purchase through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest.

	As of December 31,
	2011		2010(1)		2009		2008		2007
	(in thousands)
Balance Sheet Data(2):
Cash and cash equivalents	$	2,851	$	1,828	$	487	$	3	$	3,110
Short-term derivative assets		2,333		16,523		16,190		22,184		4,017
Other current assets		51,508		34,435		11,566		9,691		4,826
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment		1,217,985		1,063,403		172,525		182,269		106,983
Long-term derivative assets		1,105		1,479		5,225		15,749		1,330
Goodwill(3)		420,955		420,955		—		—		—
Other intangible assets		8,837		9,017		—		—		—
Other assets		10,789		7,552		4,707		2,666		10,913
Total assets	$	1,716,363	$	1,555,192	$	210,700	$	232,562	$	131,179
Short-term derivative liabilities	$	12,774	$	6,209	$	253	$	486	$	—
Other current liabilities		33,064		34,261		12,166		7,278		5,355
Term loan – current		—		175,000		—		—		—
Long-term debt		771,000		410,500		129,800		135,000		37,400
Long-term derivative liabilities		20,553		30,384		2,036		2,313		5,903
Other long-term liabilities		35,051		29,445		6,159		2,134		190
Members’ equity		843,921		320,731		60,286		85,351		82,331
Non-controlling interest in subsidiary		—		548,662		—		—		—
Total Liabilities and Members’ Equity	$	1,716,363	$	1,555,192	$	210,700	$	232,562	$	131,179

(1) Includes the fair value of the ENP assets and liabilities we acquired on December 31, 2010.

(2) From 2008 through 2011, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in the Permian Basin, Big Horn Basin, South Texas and Mississippi. The assets and liabilities associated with these acquired properties were included in our balance sheet data as of each year end.

(3) Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the ENP Purchase completed on December 31, 2010.

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

The following discussion and analysis should be read in conjunction with “Selected Historical and Consolidated Financial and Operating Data” and the accompanying financial statements and related notes included elsewhere in this prospectus supplement. The following discussion is historical in nature and does not give effect to the Appalachian Exchange. The following discussion contains forward-looking statements that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in our 2011 Annual Report, particularly in “Item 1A. Risk Factors” and “Forward Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and over time to increase our quarterly cash distributions through the acquisition of new oil and natural gas properties. Through our operating subsidiaries, after giving effect to the Appalachian Exchange, we own properties and oil and natural gas reserves primarily located in six operating areas:

• the Permian Basin in West Texas and New Mexico;

• the Big Horn Basin in Wyoming and Montana;

• South Texas;

• the Williston Basin in North Dakota and Montana;

• Mississippi; and

• the Arkoma Basin in Arkansas and Oklahoma.

At December 31, 2011, we owned working interests in 4,900 gross (2,245 net) productive wells. In addition to these productive wells, we own leasehold acreage allowing us to drill new wells. In the Permian, Big Horn, South Texas and Williston Basins, we own working interests ranging from 30 – 100% in approximately 42,468 gross undeveloped acres surrounding our existing wells. Approximately 14% or 11.1 MMBOE of our estimated proved reserves were attributable to our working interests in undeveloped acreage.

In February 2012, we entered into a Unit Exchange Agreement with our founding unitholder to transfer our ownership interests in oil and natural gas properties in the Appalachian Basin in exchange for 1.9 million VNR common units with an effective date of January 1, 2012 (we refer to this transaction as the “Appalachian Exchange”). As of December 31, 2011, based on a reserve report prepared by D&M, total estimated net proved reserves attributable to these interests were 6.2 MMBOE, of which 92% was natural gas and 65% was proved developed. This transaction is expected to close on March 28, 2012.

Outlook

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as access to capital, economic, political and regulatory developments, and competition from other sources of energy. Oil, natural gas and NGLs prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil, natural gas and NGLs could materially and adversely affect our financial position, our results of operations, the quantities of oil, natural gas and NGLs reserves that we can economically produce, our access to capital and our ability to pay distributions. We have mitigated the volatility on our cash flows through 2014 with oil and natural gas price derivative contracts.

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These hedges are placed on a portion of our proved producing and a portion of our total anticipated production during this time frame. As oil, natural gas and NGLs prices fluctuate, we will recognize non-cash, unrealized gains and losses in our consolidated statement of operations related to the change in fair value of our commodity derivative contracts.

We face the challenge of oil, natural gas and NGLs production declines. As a given well’s initial reservoir pressures are depleted, oil, natural gas and NGLs production decreases, thus reducing our total reserves. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will maintain our focus on controlling costs to add reserves through drilling and acquisitions, as well as controlling the corresponding costs necessary to produce such reserves. During the year ended December 31, 2011, we drilled and completed seven gross (5.9 net) wells on operated properties and drilled and completed eight gross (3.0 net) non-operated wells. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including the ability to timely obtain drilling permits and regulatory approvals and voluntary reductions in capital spending in a low commodity price environment. 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 at existing levels over the long-term provided that it is economical to do so based on the commodity price environment. However, we cannot be certain that we will be able to issue equity or debt securities on favorable terms, or at all, and we may be unable to refinance our Reserve-Based Credit Facility when it expires. Additionally, in the event of significant declines in commodity prices, our borrowing base under our Reserve-Based Credit Facility may be re-determined such that it will not provide for the working capital necessary to fund our capital spending program and could affect our ability to make distributions. The next scheduled redetermination of our borrowing base is April 2012.

Results of Operations

The following table sets forth selected financial and operating data for the periods indicated.

	Year Ended December 31,(1)
	2011(2)			2010(3)			2009
	(in thousands)
Revenues:
Oil sales	$	236,003		$	50,022		$	19,940
Gas sales		47,977			25,778			21,966
NGLs sales		28,862			9,557			4,129
Oil, natural gas and NGLs sales		312,842			85,357			46,035
Loss on commodity cash flow hedges		(3,071	)		(2,832	)		(2,380	)
Realized gain on other commodity derivative contracts		10,276			24,774			29,993
Unrealized loss on other commodity derivative contracts		(470	)		(14,145	)		(19,043	)
Total revenues	$	319,577		$	93,154		$	54,605
Costs and expenses:
Lease operating expenses	$	63,944		$	18,471		$	12,652
Production and other taxes		28,621			6,840			3,845
Depreciation, depletion, amortization and accretion		84,857			22,231			14,610
Impairment of oil and natural gas properties		—			—			110,154
Selling, general and administrative expenses		19,779			10,134			10,644
Total costs and expenses	$	197,201		$	57,676		$	151,905
Other income and expenses:
Other income		77			1			—
Interest expense	$	(28,994	)	$	(5,766	)	$	(4,276	)
Realized loss on interest rate derivative contracts	$	(2,874	)	$	(1,799	)	$	(1,903	)
Net gain (loss) on acquisition of oil and natural gas properties	$	(367	)	$	(5,680	)	$	6,981
Unrealized gain (loss) on interest rate derivative contracts	$	(2,088	)	$	(349	)	$	763

(1) From 2009 through 2011, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties, in the Permian Basin, the Big Horn Basin, South Texas and

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Mississippi. The operating results of these properties are included in the accompanying financial statements and related notes included elsewhere in this prospectus supplement from the date of the acquisition forward.

(2) The operating results of the subsidiaries we acquired in the ENP Purchase through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest.

(3) Excludes operating results for the oil and natural gas properties acquired in the ENP Purchase as the acquisition closed on December 31, 2010.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Revenues

Oil, natural gas and NGLs sales increased $227.5 million to $312.8 million during the year ended December 31, 2011 as compared to the same period in 2010. The key revenue measurements were as follows:

	Year Ended December 31,						Percentage Increase (Decrease)
	2011(2)			2010(1)
Net Oil Production:
VNR oil (Bbls)		765,867	(4)		682,447	(3)		12	%
ENP oil (Bbls)		1,959,986	(4)(2)		—			—
Total oil production (Bbls)		2,725,853			682,447			299	%
Average VNR daily oil production (Bbls/day)		2,098	(4)		1,870	(3)		12	%
Average ENP daily oil production (Bbls/day)		5,370	(4)(2)		—			—
Average daily oil production (Bbls/day)		7,468			1,870			299	%
Average Oil Sales Price per Bbl:
Net realized oil price, including hedges	$	82.45	(5)	$	76.53	(5)		8	%
Net realized oil price, excluding hedges	$	86.52		$	73.30			18	%
Net Natural Gas Production:
VNR gas (MMcf)		4,575	(4)		4,990	(3)		(8	)%
ENP gas (MMcf)		5,838	(4)(2)		—			—
Total natural gas production (MMcf)		10,413			4,990			109	%
Average VNR daily gas production (Mcf/day)		12,536	(4)		13,672	(3)		(8	)%
Average ENP daily gas production (Mcf/day)		15,993	(4)(2)		—			—
Average daily gas production (Mcf/day)		28,529			13,672			109	%
Average Natural Gas Sales Price per Mcf:
Net realized gas price, including hedges	$	7.45	(5)	$	9.91	(5)		(25	)%
Net realized gas price, excluding hedges	$	4.59		$	5.17			(11	)%
Net NGLs Production:
VNR NGLs (Bbls)		200,361	(4)		209,531	(3)		(4	)%
ENP NGLs (Bbls)		231,189	(4)(2)		—			—
Total NGLs production (Bbls)		431,550			209,531			106	%
Average VNR daily NGLs production (Bbls/day)		549	(4)		574	(3)		(4	)%
Average ENP daily NGLs production (Bbls/day)		634	(4)(2)		—			—
Average daily NGLs production (Bbls/day)		1,183			574			106	%
Average Net Realized NGLs Sales Price per Bbl	$	66.88		$	45.78			46	%
Total production (MBOE)		4,893			1,723			184	%

(1) Excludes production results for the oil and natural gas properties acquired in the ENP Purchase as the acquisition closed on December 31, 2010.

(2) Production results for oil and natural gas properties acquired in the ENP Purchase through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest.

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(3) South Texas area includes production from the Dos Hermanos, Sun TSH and a portion of the Parker Creek Acquisitions. During 2010, we acquired certain oil and natural gas properties and related assets in Mississippi. The operating results of these properties are included with ours from the closing date of the acquisition forward.

(4) During 2011, we and ENP acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in the Permian Basin, the Big Horn Basin and Mississippi. The operating results of these properties are included with ours from the closing date of the acquisition forward.

(5) Excludes amortization of premiums paid and amortization of value on derivative contracts acquired.

The increase in oil, natural gas and NGLs sales during the year ended December 31, 2011 compared to the same period in 2010 was due primarily to the increases in production from our acquisitions. We experienced an 18% increase in the average realized oil price, excluding hedges, and an 11% decrease in the average realized natural gas sales price received, excluding hedges. Oil revenues increased 372% from $50.0 million during the year ended December 31, 2010 to $236.0 million during the same period in 2011 as a result of a $13.22 per Bbl increase in our average realized oil price, excluding hedges, and a 2,043 MBbls increase in our oil production volumes. Our higher average realized oil price was primarily due to a higher average NYMEX price, which increased from $79.51 per Bbl during the year ended December 31, 2010 to $95.00 per Bbl during the same period in 2011. However, we did not recognize the entire benefit of the 18% increase in the NYMEX oil price due to significant widening of the basis differential received on our oil primarily as a result of the temporary closure of Exxon Mobil’s pipelines in Wyoming during the third quarter 2011 due to leaks which affected production from ENP’s Elk Basin field where we had to settle for a lower price per barrel of oil produced during the closure. Natural gas revenues increased 86% from $25.8 million during the year ended December 31, 2010 to $48.0 million during the same period in 2011 as a result of a 109% increase in our natural gas production volumes from the wells acquired in the Encore Acquisition. The impact of the increase in our natural gas production volumes was offset by a $0.58 per Mcf decrease in our average realized natural gas price, excluding hedges, primarily due to a lower average NYMEX price, which decreased from $4.40 per Mcf during the year ended December 31, 2010 to $4.02 per Mcf during the same period in 2011. Additionally, our total production increased by 184% on a BOE basis. The increase in production for the year ended December 31, 2011 over the comparable period in 2010 was primarily attributable to the impact from the Encore Acquisition completed in December 2010 and all of the additional acquisitions completed during the 2011. On a BOE basis, crude oil, natural gas and NGLs accounted for 56%, 35% and 9%, respectively, of our production during the year ended December 31, 2011 compared to crude oil, natural gas, and NGLs of 40%, 48% and 12%, respectively, during the same period in 2010.

Hedging and Price Risk Management Activities

During the year ended December 31, 2011, we recognized a $10.3 million realized gain on other commodity derivative contracts related to the settlements recognized during the period and a $0.5 million loss related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting. These realized and unrealized gains and losses resulted from the changes in commodity prices, and the effect of these price changes is discussed in the paragraph below. During the years ended December 31, 2011 and 2010, we recognized $3.1 million and $2.8 million in losses on commodity cash flow hedges that previously met the criteria for cash flow hedge accounting, respectively. These amounts relate to derivative contracts that we entered into in order to mitigate commodity price exposure on a portion of our expected production and designated as cash flow hedges. They were later de-designated as cash flow hedges and the losses for the years ended December 31, 2011 and 2010 relate to amounts that settled in the respective periods which have been reclassified to earnings from accumulated other comprehensive loss.

The purpose of our hedging program is to mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and we pay the counterparty when commodity prices are above the hedged price. In either case, the impact on our operating cash flow is approximately the same. However, because the majority of our hedges are not designated as cash flow hedges, there can be a significant amount of volatility in our earnings when we record the change in the fair value of all of our derivative contracts. As commodity prices fluctuate, the fair value of those contracts will fluctuate and the impact is reflected as a

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non-cash, unrealized gain or loss in our consolidated statement of operations. However, these fair value changes that are reflected in the consolidated statement of operations only reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged.

Costs and Expenses

Lease operating expenses include third-party transportation costs, gathering and compression fees, field personnel, and other customary charges. Lease operating expenses increased by $45.5 million to $63.9 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010, of which $43.6 million related to the Encore Acquisition and to increased lease operating expenses for oil and natural gas properties acquired during 2011. Additionally, contributing to this increase were higher lease operating expenses for wells acquired in the Parker Creek Acquisition and the Permian Basin I Acquisition.

Production and other taxes include severance, ad valorem and other taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state/county and are based on the value of our reserves. Production taxes increased by $21.8 million for the year ended December 31, 2011 as compared to the same period in 2010, primarily due to higher wellhead revenues, which exclude the effects of commodity derivative contracts. Severance taxes increased by $13.3 million as a result of increased oil, natural gas and NGLs production due to the Encore Acquisition. Ad valorem taxes increased by $8.2 million primarily due to the taxes on oil and natural gas properties acquired in the Encore Acquisition. As a percentage of wellhead revenues, production, severance, and ad valorem taxes increased from 8% for the year ended December 31, 2010 to 9.1% during the year ended December 31, 2011.

Depreciation, depletion, amortization and accretion increased to approximately $84.9 million for the year ended December 31, 2011 from approximately $22.2 million for the year ended December 31, 2010 due primarily to approximately $58.9 million additional depletion recorded on oil and natural gas properties acquired in the Encore Acquisition and oil and natural gas properties acquired during 2011.

Selling, general and administrative expenses include the costs of our administrative employees and executive officers, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the year ended December 31, 2011 increased $9.6 million as compared to the year ended December 31, 2010 principally due to approximately $9.0 million in incremental costs related to ENP, a $2.4 million increase in compensation related expenses due to the hiring of additional personnel and expanding operations in connection with the ENP Acquisition, a $1.2 million increase in non-cash compensation charges related to the grant of units to employees and the grant of phantom units to officers and a $0.3 million increase in general office expenses also resulting from our expanding operations. Additionally, during 2010 we incurred $3.6 million in non-recurring transaction costs in connection with the ENP Purchase.

Other Income and Expense

Interest expense increased to $29.0 million for the year ended December 31, 2011 as compared to $5.8 million for the year ended December 31, 2010 primarily due to approximately $9.3 million of interest expense on the Term Loan (as discussed below) borrowed in connection with the Encore Acquisition, $7.8 million of interest expense incurred for the ENP Credit Agreement (as discussed below) and higher average outstanding debt under our Reserve-Based Credit Facility during the year ended December 31, 2011.

In accordance with the guidance contained within ASC Topic 805, “Business Combinations,” (“ASC Topic 805”), the measurement of the fair value at acquisition date of the assets acquired in the acquisitions completed during 2011 compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $1.9 million, which was immediately impaired and recorded as a loss, and a gain of $1.5 million for the year ended December 31, 2011, resulting in a combined net loss of $0.4 million. The measurement of the fair value at acquisition date of the assets acquired in the Parker Creek acquisition as

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compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $5.7 million, which was immediately impaired and recorded as a loss for the year ended December 31, 2010. The gain and losses resulted from the increases and decreases in oil and natural gas prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Revenues

Oil, natural gas and NGLs sales increased $39.3 million to $85.3 million during the year ended December 31, 2010 as compared to the same period in 2009. The key revenue measurements were as follows:

	Year Ended December 31,				Percentage Increase (Decrease)
	2010(1)(3)		2009(2)
Average realized prices(4):
Oil (Price/Bbl)	$	73.30	$	57.73		27	%
Natural Gas (Price/Mcf)		5.17		4.84		7	%
NGLs (Price/Bbl)		45.78		36.12		27	%
Combined (Price/BOE)		49.56		37.86		31	%
Total production volumes:
Oil (Bbls)		682,447		345,400		98	%
Natural Gas (MMcf)		4,990		4,542		10	%
NGLs (Bbls)		209,531		114,785		83	%
Combined (MBOE)		1,723		1,217		42	%
Average daily production volumes:
Oil (Bbls/day)		1,870		947		98	%
Natural Gas (Mcf/day)		13,672		12,444		10	%
NGLs (Bbls/day)		574		314		83	%
Combined (MBOE/day)		4,721		3,335		42	%

(1) Excludes production results for the oil and natural gas properties acquired in the ENP Purchase as the acquisition closed on December 31, 2010.

(2) Includes production from the Permian Basin and Ward County Acquisitions. During 2009, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in Ward County. Also, during 2009, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets, in South Texas from the Sun TSH acquisition. The operating results of these properties are included with ours from the date of acquisition forward.

(3) South Texas area includes production from the Dos Hermanos, Sun TSH and a portion of the Parker Creek Acquisitions. During 2010, we acquired certain oil and natural gas properties and related assets in Mississippi. The operating results of these properties are included with ours from the date of acquisition forward.

(4) Excludes results from hedging activities.

The increase in oil, natural gas and NGLs sales during the year ended December 31, 2010 compared to the same period in 2009 was due primarily to the increases in commodity prices and an increase in production. We experienced a 7% increase in the average realized natural gas sales price received (excluding hedges) and a 27% increase in the average realized oil price (excluding hedges). Additionally, our total production increased by 42% on a BOE basis. The increase in production for the year ended December 31, 2010 over the comparable period in 2009 was primarily attributable to the impact from the Sun TSH, Ward County and Parker Creek acquisitions completed in August 2009, December 2009 and May 2010, respectively. In Appalachia, we experienced a 6% decrease in natural gas production which was partially offset by a 23% increase in oil production during year ended December 31, 2010 compared to the same period in 2009 for a

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net production decline of 1% on a BOE basis. While our natural gas wells had lower production during 2010, we experienced a 23% increase in Appalachian oil production primarily due to our focus on completing seven vertical oil wells in 2009.

Hedging and Price Risk Management Activities

During the years ended December 31, 2010 and 2009, we recognized $2.8 million and $2.4 million in losses on commodity cash flow hedges, respectively. These amounts relate to derivative contracts we entered into in order to mitigate commodity price exposure on a portion of our expected production and designated as cash flow hedges. The losses on commodity cash flow hedges for the years ended December 31, 2010 and 2009 relate to the amounts that settled in those years and have been reclassified to earnings from accumulated other comprehensive loss. During the years ended December 31, 2010 and 2009, we recognized a $24.8 million and $30.0 million realized gain on other commodity derivative contracts, respectively, related to the settlements recognized during those periods and a $14.1 million and $19.0 million loss related to the change in fair value of derivative contracts not meeting the criteria for cash flow hedge accounting in those periods, respectively.

Costs and Expenses

Lease operating expenses in Appalachia historically included a $60 per well per month administrative charge pursuant to a management services agreement with Vinland. This fee was temporarily increased to $95 per well per month beginning March 1, 2009 through December 31, 2009 pursuant to an agreement whereunder Vinland provided well-tending services on Vanguard-owned wells under a turnkey pricing contract. In addition, we historically have paid a $0.25 per Mcf and $0.55 per Mcf gathering and compression charge for production from wells drilled pre and post January 1, 2007, respectively, to Vinland pursuant to a gathering and compression agreement with Vinland. This gathering and compression agreement was amended for the period beginning March 1, 2009 through December 31, 2009 to provide for a temporary fee based upon the actual costs incurred by Vinland to provide gathering and transportation services plus a $0.05 per Mcf margin. Both temporary amendments expired on December 31, 2009 and all the terms of the agreements reverted back to the original agreements.

In June 2010, we began discussions with Vinland regarding an amendment to the gathering and compression agreement which would go into effect beginning on July 1, 2010. The amended agreement would provide gathering and compression services based upon actual costs plus a margin of $.055 per Mcf. We and Vinland agreed in principle to this change effective July 1, 2010, and we have jointly operated on this basis although the formal agreements have yet to be signed. Lease operating expenses increased by $5.8 million to $18.5 million for the year ended December 31, 2010 as compared to the year ended December 31, 2009 of which $4.0 million related to the Sun TSH and Ward County and Parker Creek acquisitions and $1.8 million related to increase lease operating expenses for wells in Appalachia.

Production and other taxes increased by $3.0 million for the year ended December 31, 2010 as compared to the same period in 2009. Severance taxes increased $2.2 million as a result of increased oil, natural gas and NGLs sales. Texas margin and other corporate taxes increased by $0.7 million and ad valorem taxes increased by $0.1 million primarily due to an increase of $0.6 million in the taxes on oil and natural gas properties acquired in the Sun TSH, Ward County and Parker Creek acquisitions, offset by a $0.5 million decrease in the taxes on Appalachia properties.

Depreciation, depletion, amortization and accretion increased to approximately $22.2 million for the year ended December 31, 2010 from approximately $14.6 million for the year ended December 31, 2009 due primarily to the additional depletion recorded on the oil and natural gas properties acquired in the Sun TSH, Ward County and Parker Creek acquisitions.

An impairment of oil and natural gas properties in the amount of $110.2 million was recognized during the year ended December 31, 2009 as the unamortized cost of oil and natural gas properties exceeded the sum of the estimated future net revenues from proved properties using the 12-month average price of oil and natural gas, discounted at 10% and the lower of cost or fair value of unproved properties. The impairment for the first quarter 2009 was $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and

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$49.64 per barrel of crude oil. The SEC’s Final Rule, “Modernization of Oil and Gas Reporting,” which became effective December 31, 2009, changed the price used to calculate oil and gas reserves to a 12-month average price rather than a year-end price. As a result of declines in oil and natural gas prices based upon the 12-month average price, we recorded an additional impairment of $46.4 million in the fourth quarter of 2009. This impairment was calculated using the 12-month average price for natural gas and oil of $3.87 per MMBtu for natural gas and $ 61.04 per barrel of crude oil. The majority of the fourth quarter impairment was incurred on properties that we acquired in the last six months of 2009 when oil and natural gas prices were higher than the 12-month average price. We were able to lock in the higher prices at the time of the acquisitions for a substantial portion of the expected production through 2011 for natural gas and 2013 for crude oil by using commodity derivative contracts. However, the impairment calculation did not consider the positive impact of our commodity derivative positions as generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges. No impairment of oil and natural gas properties was necessary during the year ended December 31, 2010. In addition, our analysis of goodwill concluded that there was no impairment of goodwill as of December 31, 2010.

Selling, general and administrative expenses for the year ended December 31, 2010 decreased $0.5 million as compared to the year ended December 31, 2009 principally due to a decrease in non-cash compensation charges related to the grant of restricted Class B units to officers and an employee, the grant of phantom units to officers and the grant of common units to board members and employees. Non-cash compensation charges declined $5.8 million to $1.0 million for the year ended December 31, 2010. Offsetting this decline was a $3.6 million increase in general and administrative expenses primarily related to transaction costs incurred in connection with the ENP Acquisition and a $1.6 million increase in bonuses awarded to employees.

Other Income and Expense

Interest expense increased to $5.8 million for the year ended December 31, 2010 compared to $4.3 million for the year ended December 31, 2009 primarily due to higher interest rates and higher average outstanding debt for the year ended December 31, 2010.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We have discussed the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. Please read Note 1 to the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement for a discussion of additional accounting policies and estimates made by management.

Full-Cost Method of Accounting for Oil and Natural Gas Properties

The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for gas and oil business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Under the successful-efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges

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would be capitalized to the full-cost pool. In the measurement of impairment of proved gas and oil properties, the successful-efforts method of accounting follows the guidance provided in ASC Topic 360, “Property, Plant and Equipment,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10% using commodity prices based upon the 12-month average price (ceiling limitation). If the full-cost pool is in excess of the ceiling limitation, the excess amount is charged as an expense.

We have elected to use the full-cost method to account for our investment in oil and natural gas properties. Under this method, we capitalize all acquisition, exploration and development costs for the purpose of finding oil, natural gas and NGLs reserves, including salaries, benefits and other internal costs directly related to these finding activities. For the years ended December 31, 2011 and 2010, there were no internal costs capitalized. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of oil and natural gas properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Our results of operations would have been different had we used the successful-efforts method for our oil and natural gas investments. Generally, the application of the full-cost method of accounting results in higher capitalized costs and higher depletion rates compared to similar companies applying the successful-efforts method of accounting.

Full-Cost Ceiling Test

At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties is limited to the sum of the estimated future net revenues from proved properties using oil and natural gas price based upon the 12-month average price, after giving effect to cash flow hedge positions, for which hedge accounting is applied, discounted at 10% and the lower of cost or fair value of unproved properties (“Ceiling Test”). In 2011 and 2010, our hedges were not considered cash flow hedges for accounting purposes, and thus the value of our hedges were not considered in our ceiling test calculations, except for the amounts in other comprehensive income (loss) related to the 2007 commodity derivative contracts designated as cash flow hedges. The SEC’s Final Rule, “Modernization of Oil and Gas Reporting,” requires that the present value of future net revenue from proved properties be calculated based upon the 12-month average price.

The calculation of the Ceiling Test and the provision for depletion and amortization are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development as more fully discussed in “— Oil, Natural Gas and NGLs Reserve Quantities” below. Due to the imprecision in estimating oil, natural gas and NGLs reserves as well as the potential volatility in oil, natural gas and NGLs prices and their effect on the carrying value of our proved oil, natural gas and NGLs reserves, there can be no assurance that additional Ceiling Test write downs in the future will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas properties. These factors include declining oil, natural gas and NGLs prices, downward revisions in estimated proved oil, natural gas and NGLs reserve quantities and unsuccessful drilling activities.

While no ceiling test impairment was required during 2011 and 2010, we recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2009 of $110.2 million. The impairment for the first quarter of 2009 was $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and $49.64 per barrel of crude oil. The SEC’s Final Rule, “Modernization of Oil and Gas Reporting,” which became effective December 31, 2009, changed the price used to calculate oil and gas reserves to a 12-month average price rather than a year-end price. As a result of declines in oil and natural gas prices based upon the 12-month average price, we recorded an additional impairment of $46.4 million in the fourth quarter of 2009. This impairment was calculated using the 12-month average price for natural gas and oil of $3.87 per MMBtu for natural gas and $61.04 per barrel of crude oil.

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Business Combinations

We account for business combinations under ASC Topic 805, “Business Combinations.” We recognize and measure in our financial statements the fair value of all identifiable assets acquired, the liabilities assumed, any non-controlling interests in the acquiree and any goodwill acquired in all transactions in which control of one or more businesses is obtained.

Goodwill and Other Intangible Assets

We apply the provisions of ASC Topic 350 “Intangibles — Goodwill and Other” (“ASC Topic 350”). Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level. We have determined that we have two reporting units, which are Vanguard’s historical oil and natural gas operations in the United States and ENP’s oil and natural gas operations in the United States. At December 31, 2011, all goodwill was assigned to the reporting unit comprised of ENP’s oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.

We utilize a market approach to determine the fair value of our reporting units. Our analysis concluded that there was no impairment of goodwill as of October 1 or December 1, 2011. Any sharp decreases in the prices of oil and natural gas or any significant negative reserve adjustments from the December 31, 2011 assessment could change our estimates of the fair value of our reporting units and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. Estimates of fair value are based upon, among other things, reserve estimates, anticipated future prices and costs, and expected net cash flows to be generated. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities.

Asset Retirement Obligation

We have obligations to remove tangible equipment and restore land at the end of an oil or natural gas well’s life. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and the decommissioning of our Elk Basin gas plant. Estimating the future plugging and abandonment costs requires management to make estimates and judgments inherent in the present value calculation of the future obligation. These include ultimate plugging and abandonment costs, inflation factors, credit adjusted discount rates, and timing of the obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

Oil, Natural Gas and NGLs Reserve Quantities

Proved oil and gas reserves are defined by the SEC as the estimated quantities of crude oil, natural gas and NGLs which 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 oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological

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advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

In addition, the SEC has released only limited interpretive guidance regarding reporting of reserve estimates under the rules and may not issue further interpretive guidance on the rules. Accordingly, while the estimates of our proved reserves at December 31, 2011 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.

Revenue Recognition

Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, our revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase without consideration of hedging. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded.

The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. We did not have any significant gas imbalance positions at December 31, 2011 or 2010.

Price Risk Management Activities

We periodically use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Currently, these derivative financial instruments include fixed-price swaps, basis swaps, swaptions, put options, collars and three-way collars.

Under ASC Topic 815, the fair value of hedge contracts is recognized in the Consolidated Balance Sheets as an asset or liability, and the change in fair value of the hedge contracts are reflected in earnings. If the hedge contracts qualify for hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income,” and changes in the fair value do not affect net income until the contract is settled. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as gain or loss on other commodity derivatives.

Stock Based Compensation

We account for Stock Based Compensation pursuant to ASC Topic 718 “Compensation-Stock Compensation” (“ASC Topic 718”). ASC Topic 718 requires an entity to recognize the grant-date fair-value of stock options and other equity-based compensation issued to employees in the income statement. It establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all companies to apply a fair-value-based measurement method in accounting for generally all share-based payment transactions with employees. On March 29, 2005, the SEC staff issued SAB No. 107, Share-Based Payment, to express the views of the staff regarding the interaction between ASC Topic 718 and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies.

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Capital Resources and Liquidity

Overview

We have utilized private equity, proceeds from bank borrowings, cash flow from operations and more recently the public equity markets for capital resources and liquidity. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties; however, we expect to distribute to unitholders a significant portion of our free cash flow. As we execute our business strategy, we will continually monitor the capital resources available to us to meet future financial obligations, planned capital expenditures, acquisition capital and distributions to our unitholders. Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for and acquiring additional reserves. We expect to fund our drilling capital expenditures and distributions to unitholders with cash flow from operations, while funding any acquisition capital expenditures that we might incur with borrowings under our financing arrangements and publicly offered equity and debt, depending on market conditions. As of March 1, 2012, we had $184.0 million available to be borrowed under our Reserve-Based Credit Facility.

The borrowing base under our Reserve-Based Credit Facility is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the lenders’ petroleum engineers utilizing the lenders’ internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. Our current commitment levels and borrowing base are set at $765.0 million, which was reaffirmed on March 19, 2012. The next scheduled redetermination is scheduled for October 2012. If commodity prices decline and banks lower their internal projections of oil, natural gas and NGLs prices, it is possible that we will be subject to a decrease in our borrowing base availability in the future.

As a result, absent accretive acquisitions, to the extent available after unitholder distributions, debt service, and capital expenditures, it is our current intention to utilize our excess cash flow during 2012 to reduce our borrowings under our financing arrangements. Based upon current expectations, we believe existing liquidity and capital resources will be sufficient for the conduct of our business and operations for the foreseeable future.

The following table summarizes our primary sources and uses of cash in each of the most recent three years:

	Year Ended December 31,
	2011			2010			2009
	(in millions)
Net cash provided by operating activities	$	176.3		$	71.6		$	52.2
Net cash used in investing activities	$	(236.4	)	$	(430.0	)	$	(109.3	)
Net cash provided by financing activities	$	61.0		$	359.8		$	57.6

Cash Flow from Operations

Net cash provided by operating activities was $176.3 million during the year ended December 31, 2011, compared to $71.6 million during the year ended December 31, 2010. The increase in cash provided by operating activities during the year ended December 31, 2011 as compared to the same period in 2010 was substantially generated from increased production volumes related to the acquisitions completed during 2011 which had been hedged at favorable prices generating realized gains on commodity derivative contracts. Changes in working capital decreased total cash flows by $18.3 million in 2011 compared to an increase of $0.9 million in 2010. Contributing to the decrease in working capital during 2011 was a $15.1 million increase in accounts receivable related to the timing of receipts from production from the acquisitions and a $4.4 million decrease in accrued expenses that resulted primarily from the timing effects of payments for transaction costs related to the ENP Purchase and compensation-related amounts. Offsetting this decrease in cash flows from operating activities during 2011 was a $3.0 million increase in accounts payable that resulted primarily from the timing of payment for invoices. Unrealized derivative gains and losses are accounted for as non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the years ended December 31, 2011 or 2010.

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Net cash provided by operating activities was $71.6 million during the year ended December 31, 2010, compared to $52.2 million during the year ended December 31, 2009. The increase in cash provided by operating activities during the year ended December 31, 2010 as compared to the same period in 2009 was substantially generated from increased production volumes related to Sun TSH, Ward County and Parker Creek Acquisitions which had been hedged at favorable prices generating significant realized gains on commodity derivative contracts. Changes in working capital increased total cash flows by $0.9 million in 2010 compared to $1.2 million in 2009. Contributing to the increase in the level of cash provided by operating activities during 2010 was a $2.7 million increase in accrued expenses that resulted primarily from the timing effects of payments for general operating expenses and bonuses awarded to employees. Offsetting this increase in cash flows from operating activities during 2010 was a $1.8 million increase in accounts receivable related to the timing of receipts from production from the acquisitions. Unrealized derivative gains and losses are accounted for as non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the years ended December 31, 2010 or 2009.

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and NGLs prices. Oil, natural gas and NGLs prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic and political activity, weather and other factors beyond our control. Future cash flow from operations will depend on our ability to maintain and increase production through our drilling program and acquisitions, as well as the prices of oil, natural gas and NGLs. We enter into derivative contracts to reduce the impact of commodity price volatility on operations. Currently, we use a combination of fixed-price swaps, basis swaps, swaptions, put options, NYMEX collars and three-way collars to reduce our exposure to the volatility in oil and natural gas prices. Please read “Business — Operations — Price Risk and Interest Rate Management Activities” included elsewhere in this prospectus supplement and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of our 2011 Annual Report for details about derivatives in place through 2014.

Investing Activities — Acquisitions and Capital Expenditures

Cash used in investing activities was approximately $236.4 million for the year ended December 31, 2011, compared to $430.0 million during the same period in 2010. The decrease in cash used in investing activities was primarily attributable to $205.2 million for the acquisition of oil and natural gas properties and $34.1 million for the drilling and development of oil and natural gas properties, offset by $5.2 million in proceeds from the divestiture of certain oil and natural gas properties in the Permian Basin. During the year ended December 31, 2010, we used cash of $298.6 million for the ENP Purchase, $115.8 million for the acquisition of oil and natural gas properties in the Parker Creek Acquisition and $15.3 million for the drilling and development of oil and natural gas properties.

Cash used in investing activities was approximately $430.0 million for the year ended December 31, 2010, compared to $109.3 million during the same period in 2009. The increase in cash used in investing activities was primarily attributable to $298.6 million net cash paid for the ENP Purchase, $115.8 million for the acquisition of oil and natural gas properties in the Parker Creek Acquisition and $15.3 million for the drilling and development of oil and natural gas properties. During the year ended December 31, 2009, the cash used in investing activities was lower as a result of our decision to not drill wells in 2009 due to low natural gas prices. We used cash of $103.9 million for the Sun TSH and Ward County Acquisitions and $5.0 million for the drilling and development of oil and natural gas properties.

Excluding any potential acquisitions, we currently anticipate a capital budget for 2012 of between $35.0 million and $40.0 million. Our capital budget will largely include oil focused drilling in the Permian Basin, Williston Basin and Mississippi. We anticipate that our cash flow from operations and available borrowing capacity under our financing arrangements will exceed our planned capital expenditures and other cash requirements for the year ended December 31, 2012. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

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Financing Activities

Cash provided by financing activities was approximately $61.0 million for year ended December 31, 2011, compared to $359.8 million for the year ended December 31, 2010. During the year ended December 31, 2011, total net proceeds from our financing arrangements were $185.5 million. During 2011, $69.0 million was used for distributions to unitholders and $5.3 million was paid for financing costs, compared to $46.7 million used for distributions to unitholders and $3.7 million paid for financing costs in the comparable period in 2010. Additionally, cash of $47.4 million was used in ENP’s distributions to non-controlling interest and $2.7 million was used for costs incurred related to the ENP Merger and offering costs, during the year ended December 31, 2011. Comparatively, proceeds from the equity offerings of 8.3 million common units completed during 2010 provided financing cash flows totaling $193.5 million, net of offering costs of $0.5 million, during the year ended December 31, 2010. Furthermore, $3.7 million was used to redeem common units held by our founding unitholder.

Cash provided by financing activities was approximately $359.8 million for year ended December 31, 2010, compared to $57.6 million for the year ended December 31, 2009. During the year ended December 31, 2010, total net proceeds from our financing arrangements were $221.7 million. During 2010, $46.7 million was used for distributions to unitholders and $3.7 million was paid for financing costs, compared to $27.1 million used for distributions to unitholders and $3.1 million paid for financing costs in the comparable period in 2009. Proceeds from the equity offerings of 8.3 million common units completed during 2010 provided financing cash flows totaling $193.5 million, net of offering costs of $0.5 million, during the year ended December 31, 2010. Furthermore during 2010, $3.7 million was used to redeem common units held by our founding unitholder. Comparatively, proceeds from the equity offerings of 6.5 million common units completed in August 2009 and December 2009 provided financing cash flows totaling $97.6 million, net of offering costs of $0.6 million, during the year ended December 31, 2009. Furthermore, $4.3 million was used to redeem common units held by our founding unitholder.

Shelf Registration Statements and Related Offerings

2009 Shelf Registration Statement and Related Offerings

During the third quarter 2009, we filed a registration statement with the SEC which registered offerings of up to $300.0 million (the “2009 shelf registration statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of each offering of securities issued under the 2009 shelf registration statement are determined at the time of such offering. The 2009 shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2009 shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In August 2009, we completed an offering of 3.9 million of our common units. The units were offered to the public at a price of $14.25 per unit. We received net proceeds of approximately $53.2 million from the offering, after deducting underwriting discounts of $2.4 million and offering costs of $0.5 million. In December 2009, we completed an offering of 2.6 million of our common units. The units were offered to the public at a price of $18.00 per unit. We received net proceeds of approximately $44.4 million from the offering, after deducting underwriting discounts of $2.0 million and offering costs of $0.1 million. We paid $4.3 million of the proceeds from this offering to redeem 250,000 common units from our founding unitholder.

In May 2010, we completed an offering of 3.3 million of our common units. The units were offered to the public at a price of $23.00 per unit. We received proceeds of approximately $71.5 million from the offering, after deducting underwriting discounts of $3.2 million and offering costs of $0.1 million.

In August 2010, we entered into an Equity Distribution Program Distribution Agreement (the “2010 Distribution Agreement”) relating to our common units representing limited liability company interests having an aggregate offering price of up to $60.0 million. In accordance with the terms of the 2010 Distribution Agreement we may offer and sell up to the maximum dollar amount of our units from time to time through our sales agent. Sales of the units, if any, may be made by means of ordinary brokers’ transactions through the

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facilities of the New York Stock Exchange, or NYSE, at market prices. Our sales agent will receive from us a commission of 1.25% based on the gross sales price per unit for any units sold through it as agent under the 2010 Distribution Agreement. Through December 31, 2011, we have received net proceeds of approximately $6.3 million from the sales of 240,111 common units, after commissions, under the 2010 Distribution Agreement. Sales made pursuant to the 2010 Distribution Agreement were made through a prospectus supplement to our 2009 shelf registration statement.

On September 9, 2011, we entered into an amended and restated Equity Distribution Program Distribution Agreement (the “2011 Distribution Agreement”) which extended, for an additional three years, the existing agreement with our sales agent to act as our exclusive distribution agent with respect to the issuance and sale of our common units up to an aggregate gross sales price of $200.0 million. Of the $200.0 million common units under the 2011 Distribution Agreement, $115.0 million common units may be offered through a prospectus supplement to our 2009 shelf registration statement. The additional $85.0 million common units may be offered pursuant to a new prospectus supplement to one of our other effective shelf registration statements or a new shelf registration statement to be filed when the 2009 shelf registration statement expires in August of 2012. Through December 31, 2011, we sold 18,700 common units, under the 2011 Distribution Agreement and proceeds of approximately $0.5 million were settled in January 2012.

2010 Shelf Registration Statement and Related Offerings

In July 2010, we filed a registration statement with the SEC which registered offerings of up to $800.0 million (the “2010 shelf registration statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of each offering of securities issued under the 2010 shelf registration statement are determined at the time of such offerings. The 2010 shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2010 shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In October 2010, we completed an offering of 4.8 million of our common units. The units were offered to the public at a price of $25.40 per unit. We received net proceeds of approximately $115.8 million from the offering, after deducting underwriting discounts of $5.1 million and offering costs of $0.3 million. We paid $3.7 million of the proceeds of this offering to redeem 150,000 common units from our founding unitholder. The remaining net proceeds of $112.1 million were used to pay down outstanding borrowings under our Reserve-Based Credit Facility.

As a result of these offerings, as of December 31, 2011, we have approximately $116.2 million and $678.8 million remaining available under our 2009 and 2010 shelf registration statements, respectively.

2012 Automatic Shelf Registration Statement and Related Offerings

In January 2012, we filed a registration statement (the “2012 shelf registration statement”) with the SEC, which registered offerings of up to 3.1 million common units representing limited liability company interests in VNR held by certain selling unitholders. By means of the same registration statement, we also registered an indeterminate amount of common units, debt securities and guarantees of debt securities. Net proceeds, terms and pricing of each offering of securities issued under the 2012 shelf registration statement are determined at the time of such offerings. The 2012 shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2012 shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us and the selling unitholder named therein.

In January 2012, we completed an offering of 7,137,255 of our common units at a price of $27.71 per unit. The 7,137,255 common units offering included 4.0 million of our common units (“primary units”) and 3,137,255 common units (“secondary units”) offered by Denbury Onshore, LLC (“selling unitholder”). Offers were made pursuant to a prospectus supplement to the 2012 shelf registration statement. The secondary units were obtained by the selling unitholder as partial consideration for our acquisition of all of the member interests in ENP GP and ENP, and certain common units representing limited partnership interests in ENP

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from subsidiaries of the selling unitholder. We received proceeds of approximately $106.4 million from the offering of primary units, after deducting underwriting discounts of $4.3 million and offering costs of $0.2 million. We did not receive any proceeds from the sale of the secondary units. In addition, we received proceeds of approximately $28.5 million, after deducting underwriting discounts of $1.2 million, from the sale of additional 1,070,588 of our common units that were offered to the underwriters to cover over-allotments pursuant to this offering. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility and our Facility Term Loan.

Debt and Credit Facilities

Senior Secured Reserve-Based Credit Facility

On September 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) with a maximum facility amount of $1.5 billion (the “Reserve-Based Credit Facility”) and initial commitments and a borrowing base of $765.0 million. This Credit Agreement provides for the (1) extension of the maturity date by five years maturing on October 31, 2016, (2) increase in the number of lenders from eight to twenty, (3) increase in the percentage of production that can be hedged into the future, (4) increase in the permitted debt to EBITDA coverage ratio from 3.5x to 4.0x, (5) elimination of the required interest coverage ratio, (6) elimination of the ten percent liquidity requirement to pay distributions to unitholders, and (7) ability to incur unsecured debt. Borrowings from our Reserve-Based Credit Facility and the Facility Term Loan (as discussed below) were used to fully repay outstanding borrowings from the ENP Credit Agreement and our $175.0 million Term Loan (each discussed below). In November 2011, we entered into the First Amendment to the Third Amended and Restated Credit Agreement, which included amendments to (a) specify the effective date of November 30, 2011, (b) allow us to use the proceeds from our Reserve-Based Credit Facility to refinance our debt under the Facility Term Loan, (c) exclude the current maturities under the Facility Term Loan in determining the consolidated current ratio, and (d) provide a cap on the amount of outstanding debt under the Facility Term Loan.

At December 31, 2011, we had $671.0 million of borrowings outstanding under our Reserve-Based Credit Facility and $94.0 million of borrowing capacity. The applicable margins and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage	<25%			25% <50%			50% <75%			75% <90%			90%
Eurodollar Loans Margin		1.50	%		1.75	%		2.00	%		2.25	%		2.50	%
ABR Loans Margin		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%
Commitment Fee Rate		0.50	%		0.50	%		0.375	%		0.375	%		0.375	%
Letter of Credit Fee		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%

The borrowing base is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the bank’s petroleum engineers utilizing the bank’s internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. Our next borrowing base redetermination is scheduled for April 2012 utilizing our December 31, 2011 reserve report. Our borrowing base will be reduced automatically to $680.0 million upon closing this offering and the Appalachian Exchange. If commodity prices decline and banks lower their internal projections of oil, natural gas and NGLs prices, it is possible that we will be subject to further decreases in our borrowing base in the future.

Borrowings under the Reserve-Based Credit Facility are available for development and acquisition of oil and natural gas properties, working capital and general limited liability company purposes. Our obligations under the Reserve-Based Credit Facility are secured by substantially all of our assets.

At our election, interest is determined by reference to:

• the London interbank offered rate, or LIBOR, plus an applicable margin between 1.50% and 2.50% per annum; or

• a domestic bank rate plus an applicable margin between 0.50% and 1.50% per annum.

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As of December 31, 2011, we have elected for interest to be determined by reference to the LIBOR method described above. Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans, but not less frequently than quarterly.

The Reserve-Based Credit Facility contains various covenants that limit our ability to:

• incur indebtedness;

• grant certain liens;

• make certain loans, acquisitions, capital expenditures and investments;

• merge or consolidate; or

• engage in certain asset dispositions, including a sale of all or substantially all of our assets.

The Reserve-Based Credit Facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

• consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC Topic 815, which includes the current portion of derivative contracts; and

• consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures, of not more than 4.0 to 1.0.

We have the ability to borrow under the Reserve-Based Credit Facility to pay distributions to unitholders as long as there has not been a default or event of default.

We believe that we are in compliance with the terms of our Reserve-Based Credit Facility at December 31, 2011. If an event of default exists under the Reserve-Based Credit Facility, the lenders will be able to accelerate its maturity and exercise other rights and remedies. Each of the following will be an event of default:

• failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

• a representation or warranty is proven to be incorrect when made;

• failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

• default by us on the payment of any other indebtedness in excess of $5.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

• bankruptcy or insolvency events involving us or our subsidiaries;

• the entry of, and failure to pay, one or more adverse judgments in excess of 2% of the existing borrowing base (to the extent not covered by independent third party insurance provided by insurers of the highest claims paying rating or financial strength as to which the insurer does not dispute coverage and is not subject to insolvency proceeding) or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

• specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.0 million in any year; and

• a change of control, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Exchange Act and the

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rules and regulations of the SEC) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests, or (2) the replacement of a majority of our directors by persons not approved by our board of directors.

Senior Secured Second Lien Term Loan

On November 30, 2011, we entered into a $100.0 million senior secured second lien term loan facility (the “Facility Term Loan”) with seven banks from the Reserve-Based Credit Facility, with a maturity date of May 30, 2017. The Facility Term Loan will be repaid in full with part of the net proceeds of this offering, and the facility will be terminated. See “Use of Proceeds.”

Borrowings under the Facility Term Loan are comprised entirely of Eurodollar Loans. Interest on borrowings under the Facility Term Loan is payable quarterly on the last day of each March, June, September and December and accrues at a rate per annum equal to the sum of the applicable margin plus the Adjusted LIBO Rate in effect on such day. The applicable margin increases based upon the number of days after the effective date of the Facility Term Loan as follows:

	Days after effective date
	1 – 180			181 – 360			360+
Applicable Margin		5.50	%		6.00	%		8.50	%

The effective dates of the increase in the applicable margins will accelerate if we are unable to comply with the requirements under the Facility Term Loan agreement as it relates to title covering oil and natural gas properties included in our reserve reports as indicated below:

	Until 1/15/12			1/16/12 –  5/30/12			5/31/12 and thereafter
Applicable Margin		5.50	%		6.00	%		8.50	%

Amounts outstanding under the Facility Term Loan may only be prepaid prior to maturity, together with all accrued and unpaid interest relating to the amount prepaid, when all outstanding borrowings under the Reserve-Based Credit Facility are paid in full except for mandatory prepayments related to any future equity and debt offerings. The Facility Term Loan contains principally the same covenants as our Reserve-Based Credit Facility, including restrictions on liens, restrictions on incurring other indebtedness without the lenders’ consent and restrictions on entering into certain transactions. A test of the Company’s collateral coverage ratio, a defined below, will also be performed semi-annually starting on April 1, 2012. Amounts outstanding under the Facility Term Loan are secured by a second priority lien on all assets of VNG and its subsidiaries securing VNG’s current Reserve-Based Credit Facility.

The Facility Term Loan also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

• consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC Topic 815, which includes the current portion of derivative contracts;

• consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 4.0 to 1.0;

• pre-tax present value of estimated future net cash flows to be generated from the production of from proved reserves, at least 60% of which must be proved developed producing, discounted at 10% to consolidated debt or a collateral coverage ratio of not less than 1.5 to 1.0.

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We believe that we are in compliance with the terms of our Facility Term Loan at December 31, 2011.

Term Loan

Concurrent with the ENP Purchase, VNG entered into a $175.0 million term loan (the “Term Loan”) with BNP Paribas to fund a portion of the consideration for the acquisition. As discussed above, the amount outstanding under the Term Loan was fully repaid from proceeds under the Reserve-Based Credit Facility and Facility Term Loan in December 2011.

ENP’s Credit Agreement

ENP was a party to a five-year credit agreement dated March 7, 2007 (as amended, the “ENP Credit Agreement”) with a maturity date of March 7, 2012. All outstanding debt under this facility was repaid in full from proceeds under our Reserve-Based Credit Facility.

Off-Balance Sheet Arrangements

We have no guarantees or off-balance-sheet debt to third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.

Contingencies

The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. As of December 31, 2011, there were no material loss contingencies.

Commitments and Contractual Obligations

A summary of our contractual obligations as of December 31, 2011 is provided in the following table.

	Payments Due by Year (in thousands)
	2012		2013		2014		2015		2016		After 2016		Total
Management base salaries	$	1,045	$	116	$	—	$	—	$	—	$	—	$	1,161
Asset retirement obligations(1)		1,144		1,573		422		529		2,696		29,556		35,920
Derivative liabilities(2)		32,598		24,681		10,716		4,827		75		—		72,897
Financing arrangements(3)		—		—		—		—		671,000		100,000		771,000
Operating leases		549		204		215		195		—		—		1,163
Development commitments(4)		4,103		—		—		—		—		—		4,103
Total	$	39,439	$	26,574	$	11,353	$	5,551	$	673,771	$	129,556	$	886,244

(1) Represents the discounted future plugging and abandonment costs of oil and natural gas wells and decommissioning of ENP’s Elk Basin gas plant. Please read Note 7 of the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement for additional information regarding our asset retirement obligations.

(2) Represents liabilities for commodity and interest rate derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2011 Annual Report and Note 5 of the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement for additional information regarding our commodity and interest rate derivative contracts.

(3) This table does not include interest to be paid on the principal balances shown as the interest rates on our financing arrangements are variable. Please read Note 4 of the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement for additional information regarding our long-term debt.

(4) Represents authorized purchases for work in process.

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BUSINESS

Overview

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders and, over time, increasing our quarterly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, after giving effect to the Appalachian Exchange, we own properties and oil and natural gas reserves primarily located in six operating areas:

• the Permian Basin in West Texas and New Mexico;

• the Big Horn Basin in Wyoming and Montana;

• South Texas;

• the Williston Basin in North Dakota and Montana;

• Mississippi; and

• the Arkoma Basin in Arkansas and Oklahoma.

Our common units are listed on the New York Stock Exchange, or “NYSE,” under the symbol “VNR.”

Recent Developments

ENP Acquisition

On December 31, 2010, we acquired (the “ENP Purchase”) all of the member interests in ENP GP, the general partner of ENP, and 20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), together representing a 46.7% aggregate equity interest in ENP at the date of the ENP Purchase, from Denbury Resources Inc. (“Denbury”), Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Operating, L.P. (collectively, the “Encore Selling Parties” and, together with Denbury, the “Selling Parties”). As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million at December 31, 2010.

On December 1, 2011, we acquired the remaining 53.4% of the ENP Units not held by us through a merger (the “ENP Merger”) with one of our wholly owned subsidiaries. In connection with the ENP Merger, ENP’s public unitholders received 0.75 VNR common units in exchange for each ENP common unit they owned at the effective date of the ENP Merger, which resulted in the issuance of approximately 18.4 million VNR common units valued at $511.4 million at December 1, 2011. We refer to the ENP Purchase and ENP Merger collectively as the “ENP Acquisition.” As of December 31, 2011, based on a reserve report prepared by D&M, the acquired properties from the ENP Acquisition had estimated proved reserves of 44.0 MMBOE, of which 71% was oil and 88% was proved developed producing.

Other Acquisitions

Newfield Acquisition

On April 28, 2011, we entered into a Purchase and Sale Agreement with a private seller, for the acquisition of certain oil and natural gas properties located in Texas and New Mexico. We refer to this acquisition as the “Newfield Acquisition.” The purchase price for the assets was $9.1 million with an effective date of April 1, 2011. We completed this acquisition on May 12, 2011 for an adjusted purchase price of $9.2 million. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, these acquired properties had estimated proved reserves of 0.3 MMBOE, of which 85% was oil and 100% was proved developed producing.

Permian Basin Acquisition I

On June 22, 2011, pursuant to two Purchase and Sale Agreements, we and ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. We refer to this acquisition as the “Permian Basin Acquisition I.” We and ENP agreed to

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purchase 50% of the Purchased Assets for an aggregate of $85.0 million and each paid the seller a non-refundable deposit of $4.25 million. The effective date of this acquisition was May 1, 2011. This acquisition was completed on July 29, 2011 for an aggregate adjusted purchase price of $81.4 million. The purchase price was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 4.0 MMBOE, of which 69% was oil and NGLs reserves and are 100% was proved developed.

Permian Basin Acquisition II

On August 8, 2011, ENP entered into assignment agreements and completed the acquisition of certain oil and natural gas properties located in the Permian Basin of West Texas from a private seller. We refer to this acquisition as the “Permian Basin Acquisition II.” The adjusted purchase price for the assets was $14.8 million with an effective date of May 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 1.2 MMBOE, of which 89% was oil and are 57% was proved developed.

Wyoming Acquisition

On August 15, 2011, ENP entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Wyoming. We refer to this acquisition as the “Wyoming Acquisition.” The purchase price for the assets was $28.5 million with an effective date of June 1, 2011. ENP completed this acquisition on September 1, 2011 for an adjusted purchase price of $27.7 million. The purchase price was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 2.9 MMBOE, of which 94% was natural gas reserves and 100% was proved developed.

Gulf Coast Acquisition

On August 31, 2011, ENP entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the Texas and Louisiana onshore Gulf Coast area from a private seller. We refer to this acquisition as the “Gulf Coast Acquisition.” The adjusted purchase price for the assets was $47.6 million with an effective date of August 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 2.2 MMBOE, of which 81% was oil and NGLs reserves and 100% was proved developed.

North Dakota Acquisition

On December 1, 2011, we entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the North Dakota from a private seller. We refer to this acquisition as the “North Dakota Acquisition.” The adjusted purchase price for the assets was $7.6 million with an effective date of September 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, the interests acquired had estimated total net proved reserves of 0.5 MMBOE, of which 96% was oil and 100% was proved developed.

Parker Creek Acquisition

During 2010, we completed an acquisition of certain oil and natural gas properties located in Mississippi, Texas and New Mexico. We refer to this acquisition as the “Parker Creek Acquisition.” On December 12, 2011, we acquired additional working interest in the same oil properties acquired in the Parker Creek Acquisition located in Mississippi. We completed this acquisition on December 22, 2011 for a purchase price of $14.4 million. The effective date of this acquisition was December 1, 2011. The acquisition of additional working interest was funded with borrowings under financing arrangements existing at that time. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, these properties acquired in 2010 and 2011 had estimated proved reserves of 2.6 MMBOE, of which 96% was oil and 58% was proved developed producing.

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Credit Facilities

On September 30, 2011 we entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) with a maximum facility amount of $1.5 billion (the “Reserve-Based Credit Facility”). The Credit Agreement, which was effective December 1, 2011, provides for an initial borrowing base of $765.0 million and a maturity date of October 31, 2016. As a result of this amendment and restatement, our interest rates are lower and several key covenant limitations were amended, including increasing the percentage of production that can be hedged into the future which provides us greater flexibility. Our obligations under the Reserve-Based Credit Facility are secured by mortgages on our oil and natural gas properties and other assets and are guaranteed by all of our operating subsidiaries. As of March 1, 2012 we had $581.0 million in borrowings outstanding under the Reserve-Based Credit Facility.

On November 30, 2011, we also entered into a $100.0 million senior secured second lien term loan facility (the “Facility Term Loan”). The loans under the Facility Term Loan mature on May 30, 2017 and accrue interest at an interest rate per annum equal to the London interbank offered rate, or LIBOR, plus 5.5%. In January 2012, we repaid $43.0 million of our borrowings under the Facility Term Loan. As of March 1, 2012 we had $57.0 million in borrowings outstanding under the Facility Term Loan.

Borrowings under each of the Reserve-Based Credit Facility and the Facility Term Loan were used to repay loans outstanding under ENP’s senior secured revolving credit facility (the “ENP Credit Agreement”) and our $175.0 million term loan (the “Term Loan”). Please see “Management’s Discussion and Analysis and Results of Operations — Capital Resources and Liquidity — Debt and Credit Facilities” included elsewhere in this prospectus supplement for additional information regarding our credit facilities.

Proved Reserves

Based on reserve reports prepared by D&M, our total estimated proved reserves at December 31, 2011 were 79.3 MMBOE, of which approximately 57% were oil reserves, 34% were natural gas reserves and 9% were NGLs reserves. Of these total estimated proved reserves, approximately 86% were classified as proved developed. At December 31, 2011, we owned working interests in 4,900 gross (2,245 net) productive wells. Our average net daily production for the year ended December 31, 2011 was 13,405 BOE/day. Our operated wells accounted for approximately 62% of our total estimated proved reserves at PV-10 at December 31, 2011. Our average net daily production for the year ended December 31, 2011 includes production from the properties acquired in connection with the ENP Acquisition. Production from these properties during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP. In the Permian Basin, Big Horn Basin, South Texas and Williston Basin, we own working interests ranging from 30-100% in approximately 42,468 gross undeveloped acres surrounding our existing wells.

Our average proved reserves-to-production ratio, or average reserve life, is approximately 16 years based on our total proved reserves as of December 31, 2011 and the combined production of VNR and ENP for 2011. As of December 31, 2011, after giving effect to the Appalachian Exchange, we have identified 147 proved undeveloped drilling locations and over 205 other drilling locations on our leasehold acreage.

In February 2012, we entered into a Unit Exchange Agreement with our founding unitholder to transfer our ownership interests in oil and natural gas properties in the Appalachian Basin in exchange for 1.9 million VNR common units with an effective date of January 1, 2012 (we refer to this transaction as the “Appalachian Exchange”). As of December 31, 2011, based on a reserve report prepared by D&M, total estimated net proved reserves attributable to these interests were 6.2 MMBOE, of which 92% was natural gas and 65% was proved developed. This transaction is expected to close on March 28, 2012.

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Business Strategies

Our primary business objective is to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders, and over the long-term to increase the amount of our future distributions by executing the following business strategies:

• Acquire Long-Lived Assets with Low-Risk Exploitation and Development Opportunities.  We target the acquisition of oil and natural gas properties that we believe will generate attractive risk adjusted expected rates of return and be financially accretive. Our acquisitions have been characterized by long-lived production, relatively low decline rates and predictable production profiles, as well as low-risk development opportunities in known producing basins of the continental United States. We expect to make additional acquisitions on properties with similar profiles.

• Manage our Diverse Portfolio of Oil and Gas Properties with a Focus on Maintaining Stable Cash Flow.  We manage our diverse portfolio of oil and gas properties in an effort to maintain cash flow. This is primarily accomplished by replacing production and reserves through workovers and recompletions as well as the development of our inventory of proved undeveloped locations. We maintain an inventory of drilling and optimization projects within each of the regions in which we operate to achieve organic growth from our capital development program. We aim to operate our properties so we can develop drilling programs and optimization projects to replace production and add value through reserve and production growth and other operational synergies. Our development program is focused on lower-risk, repeatable drilling opportunities to maintain and, in some cases, grow cash flow. Many of the wells in our development program are completed in multiple producing zones with commingled production and long economic lives. As of December 31, 2011, we operated 72% of our production on a cash flow basis.

• Maintain a Conservative Capital Structure to Ensure Financial Flexibility to Pursue Acquisitions.   We have actively managed our debt levels by accessing equity markets when necessary. Since our initial public offering in 2007, we have financed approximately 63% of our $1.6 billion of oil and natural gas property acquisitions with the issuance of our common units. We maintain adequate liquidity and capitalization not only for our operating positions but also to maintain the financial flexibility necessary to compete for opportunistic acquisitions. Finally, we expect to maintain a prudent coverage ratio in order to support distribution levels in the future.

• Reduce Cash Flow Volatility Through Commodity Price and Interest Rate Derivatives.  We use a robust hedging strategy to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions. Our commodity hedging transactions are primarily in the form of swap contracts and collars that are designed to provide a fixed price (swap contracts) or range of prices between a price floor and a price ceiling (collars) that we will receive, instead of being exposed to the full range of commodity price fluctuations. Our goal is to hedge 70% to 85% of our estimated production on a rolling basis. We also expect to hedge a high percentage of acquired production immediately upon execution of a purchase and sale agreement in order to secure the returns contemplated at the outset of a transaction. Finally, we also anticipate opportunistically hedging interest rates to protect against future interest rate increases.

Competitive Strengths

We believe our competitive strengths position us to successfully execute our business strategies. Our competitive strengths are as follows:

• High-Quality, Long-Lived Reserve Base.  After giving effect to the Appalachian Exchange, our diverse portfolio is comprised of 73.2 MMBoe of proved reserves across eight states. These properties typically have had a long history of relatively stable production characterized by low to moderate rates of production decline. Our estimated proved reserves as of December 31, 2011 had an average reserve life of approximately 17 years, and 88% of our reserves were classified as developed (either proved developed producing or proved developed non-producing), giving us an average developed reserve life of 15 years. We believe the highly developed nature of our reserves reduces our development risk.

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• Geographically Diverse Asset Base Which is Weighted Towards Liquid Properties.  Our portfolio of assets is well diversified, stretching across six regions which have long oil and gas production histories, including the Permian Basin in West Texas and New Mexico, the Big Horn Basin in Wyoming and Montana, South Texas, the Williston Basin in North Dakota and Montana, Mississippi and the Arkoma Basin in Arkansas and Oklahoma. The geographic breadth of our portfolio significantly reduces the risk to our investors of a problem in any particular asset. As of December 31, 2011, after giving effect to the Appalachian Exchange, our reserves consist of 61% oil and 10% NGLs, and our production consists of 54% oil and 11% NGLs. We believe that our being significantly weighted towards oil and NGLs provides a more stable cash flow outlook given the current price outlook for natural gas.

• Substantial Hedging Through 2014 at Attractive Prices.  We use a combination of fixed price swap and option arrangements to hedge NYMEX crude oil and natural gas prices. By mitigating the price volatility from a portion of our crude oil and natural gas production, we have worked to manage the potential effects of changing crude oil and natural gas prices on our cash flow from operations for the hedged periods. After giving effect to the Appalachian Exchange, we have hedged approximately 80% of expected oil production through 2014 at an average floor price of $89.98 per barrel, and 75% of expected natural gas production at an average price $5.36 per MMBtu.

• Significant Inventory of Low Risk Development Opportunities.  We also have an inventory of low risk drilling locations to maintain the cash flow from our properties. As of December 31, 2011, after giving effect to the Appalachian Exchange, we had identified 147 proved undeveloped drilling locations and an additional 205 other locations on our leasehold acreage. We intend to spend $37.5 million in capital expenditures in 2012 on low risk development and workover projects which are attractive at today’s commodity prices in an effort to maintain stable cash flow.

• Stable cash flows with low capital requirements.  We have stable operating cash margins combined with limited reliance on higher risk development relative to many of our peers and the sale of oil and NGLs contributing over 85% of our revenue. For 2012, we estimate our capital expenditures excluding acquisitions will be $37.5 million, which is approximately 15% of expected Adjusted EBITDA.

• Significant Financial Flexibility.  We are committed to maintaining a conservative financial position, ample liquidity and a strong balance sheet. After giving effect to the automatic reduction in our borrowing base resulting from the closing of this offering and the Appalachian Exchange, we will have $    million in outstanding debt, which will give us, based on our outstanding borrowings as of March 23, 2012, approximately $     million in borrowing capacity under our senior secured reserve-based credit facility (the “Reserve-Based Credit Facility”) to help fund acquisitions, development and working capital. We have prudently raised equity throughout industry cycles to maintain a strong balance sheet, as demonstrated following the ENP acquisition. We may also issue additional common units that, combined with our Reserve-Based Credit Facility, will provide us with resources to finance future acquisitions and internal development projects.

• Experienced Management Team.  Our executive officers have an average of over 25 years of experience in the oil and natural gas industry and have diverse backgrounds ranging from large, public oil and natural gas companies to entrepreneurial startups. We also have experienced technical and operational teams that provide keen insight into prospective acquisitions. Moreover, we believe that our experience integrating the properties associated with our many recent purchases, including the ENP acquisition, will de-risk the integration of future acquisitions.

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Properties

As of December 31, 2011, after giving effect to the Appalachian Exchange, through certain of our subsidiaries, we own interests in oil and gas properties located in the Permian Basin, the Big Horn Basin, South Texas, the Williston Basin, Mississippi and the Arkoma Basin. The following table presents the production for the year ended December 31, 2011 and the estimated proved reserves for each operating area (after giving effect to the Appalachian Exchange):

	Operator		2011 Net Production			Net Estimated Proved Reserves
			(MBOE)			(MBOE)
Permian Basin		Vanguard Permian, LLC		586			10,056
Permian Basin		Encore Energy Partners Operating LLC		1,261	(1)		19,847
Big Horn Basin
Elk Basin		Encore Energy Partners Operating LLC		905	(1)		17,684
Others		Encore Energy Partners Operating LLC		522	(1)		8,797
South Texas		Lewis Petroleum		393			7,844
Williston Basin		Encore Energy Partners Operating LLC		344	(1)		5,353
Mississippi		Vanguard Permian, LLC		218			2,487
Arkoma Basin		Encore Energy Partners Operating LLC		133	(1)		1,086

(1) Production from the properties acquired in connection with the ENP Purchase during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP.

The following is a description of our properties by operating area:

Permian Basin Properties

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States extending over West Texas and southeast New Mexico. The Permian Basin is characterized by oil and natural gas fields with long production histories and multiple producing formations. Our properties classified as Permian Basin properties also include properties we acquired on August 31, 2011 in the onshore Gulf Coast area where most of the production comes from the Silsbee Field in Hardin County, Texas. The Silsbee Field is operated by Silver Oak Energy. Most of the Silsbee production is oil produced from the Yegua formation.

During 2011, our Permian Basin operations produced approximately 1,847 MBOE, of which 57% was oil, condensate and NGLs. These properties accounted for approximately 29,903 MBOE or 38% of our total estimated proved reserves at year end, of which 25,616 MBOE were proved developed and 4,287 MBOE were proved undeveloped. Our average working interest in these properties is approximately 79%. As of December 31, 2011, our Permian Basin properties consisted of 121,952 gross (91,564 net) acres.

Big Horn Basin Properties

The Big Horn Basin is a prolific basin which is characterized by oil and natural gas fields with long production histories and multiple producing formations.

Our Big Horn Basin properties are located in Wyoming and south Central Montana. In addition, we own the Gooseberry field in Wyoming. We own working interests ranging from 61% to 100% in our Big Horn Basin properties, which consisted of 36,312 gross (31,651 net) acres as of December 31, 2011. During 2011, our properties in the Big Horn Basin produced approximately 1,427 MBOE, of which 80% was oil. The Big Horn Basin properties accounted for approximately 26,480 MBOE or 33% of our total estimated proved reserves at year end, of which 25,575 MBOE were proved developed and 905 MBOE were proved undeveloped.

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Our Elk Basin field is located in Park County, Wyoming and Carbon County, Montana. We operate all properties in the Elk Basin area which includes the Embar-Tensleep, Madison and Frontier formations as discussed below.

Embar-Tensleep Formation.  Production in the Embar-Tensleep formation is being enhanced through a tertiary recovery technique involving effluent gas, or flue gas, from a natural gas processing facility located in the Elk Basin field. From 1949 to 1974, flue gas was injected into the Embar-Tensleep formation to increase pressure and improve production of resident hydrocarbons. Flue gas injection was re-established in 1998, and pressure monitoring wells indicate that the reservoir pressure continues to increase. Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 4,200 to 5,400 feet.

Madison Formation.  Production in the Madison formation is being enhanced through a waterflood. We believe that we can enhance production in the Madison formation by, among other things, reestablishing optimal injection and producing well patterns. The wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,800 to 5,800 feet.

Frontier Formation.  The Frontier formation is being produced through primary recovery techniques. The wells in the Frontier formation of the Elk Basin field are typically drilled to a depth of 1,600 to 2,900 feet.

The Gooseberry field is located in Park County and Hot Springs County, Wyoming and is made up of two waterflood units in the Big Horn Basin. The field is located 60 miles south of Elk Basin in Wyoming and consists of 26 active producing wells. Gooseberry is an active waterflood project. The wells in the Gooseberry field are completed at 9,000 feet of depth from the Phosphoria and Tensleep formations.

Most of the production from our Big Horn Basin properties in southwest Wyoming comes from the Hay Reservoir Field located in Sweetwater County, Wyoming. Most of the Hay Reservoir production is high BTU gas produced from the Lewis formation.

We operate and own a 62% interest in the Elk Basin natural gas processing plant near Powell, Wyoming, which was first placed into operation in the 1940s. ExxonMobil Corporation (“Exxon”) owns a 34% interest in the Elk Basin natural gas processing plant, and other parties own the remaining 4% interest. This plant is a refrigeration natural gas processing plant that receives natural gas supplies through a natural gas gathering system from Elk Basin fields.

We own and operate the Wildhorse pipeline system, which is an approximately 12-mile natural gas gathering system that transports approximately 1.0 MMcf/day of low-sulfur natural gas from the South Elk Basin fields to the Elk Basin natural gas processing plant.

South Texas Properties

Most of our South Texas properties are operated by Lewis Petroleum and are located in two fields, Gold River North Field and Sun TSH Field, located in Webb and LaSalle Counties, Texas, respectively. Vanguard’s working interest ranges from 45% to 100%. Most of the production is high BTU gas that is produced from the Olmos and Escondido sand formations from a depth ranging from 4,700 feet to 7,800 feet.

During 2011, the South Texas properties produced approximately 393 MBOE, of which 61% was natural gas. These properties accounted for approximately 7,844 MBOE or 10% of our total estimated proved reserves at year end, of which 5,112 MBOE were proved developed and 2,733 MBOE were proved undeveloped. As of December 31, 2011, our South Texas properties consisted of 21,020 gross (14,267 net) acres.

Williston Basin Properties

Our Williston Basin properties include: Horse Creek, Charlson Madison Unit, Elk, Cedar Creek MT, Lookout Butte East, Pine, Beaver Creek, Buffalo Wallow, Buford, Crane, Charlie Creek, Dickinson, Elm Coulee, Lone Butte, Lonetree Creek, Missouri Ridge, Tracy Mountain, Tract Mountain Fryburg, Treetop, Trenton and Whiskey Joe. During 2011, the properties produced approximately 344 MBOE, of which 90% was oil. Our Williston Basin properties had estimated proved reserves at December 31, 2011 of 5,353 MBOE or 7% of our total estimated proved reserves at year end, of which 92% was oil and 91% of which was proved developed.

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Mississippi Properties

Most of our Mississippi properties, which we operate, are located in the Mississippi Salt Basin. The majority of our production comes from the Parker Creek Field in Jones County, Mississippi, where our working interest is approximately 65%. We also have a license for 10 square miles of 3-D seismic data for the development of Parker Creek Field. Our production is mainly oil that produces from the Hosston Formation from a depth ranging from approximately 13,000 feet to 15,000 feet.

During 2011, the Mississippi properties produced approximately 218 MBOE, of which 99% was oil. These properties accounted for approximately 2,487 MBOE or 3% of our total estimated proved reserves at year end, of which 1,894 MBOE were proved developed and 593 MBOE were proved undeveloped. As of December 31, 2011, our Mississippi properties consisted of 2,560 gross (1,296 net) acres.

Arkoma Basin Properties

Our Arkoma Basin properties include royalty interests and non-operated working interest properties. The royalty interest properties include interests in over 1,700 wells in Arkansas, Texas, and Oklahoma as well as 10,300 unleased mineral acres. The non-operated working interest properties include interests in over 100 producing wells in the Chismville field. During 2011, the properties produced approximately 133 MBOE, of which 85% was natural gas. At December 31, 2011, the properties had total proved reserves of approximately 1,086 MBOE or 1% of our total estimated proved reserves at year end, all of which were proved developed and 73% of which were natural gas.

Oil, Natural Gas and NGLs Prices

In the Permian Basin, most of our gas production is casinghead gas produced in conjunction with our oil production. Casinghead gas typically has a high Btu content and requires processing prior to sale to third parties. We have a number of processing agreements in place with gatherers/processors of our casinghead gas, and we share in the revenues associated with the sale of NGLs resulting from such processing, depending on the terms of the various agreements. For the year ended December 31, 2011, the average premium over New York Mercantile Exchange, or “NYMEX,” from the sale of casinghead gas plus our share of the revenues from the sale of NGLs was $1.30 per Mcfe.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other interstate pipelines. Our Big Horn Basin sweet crude oil production is transported from the field by a third party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. During 2011, we received the average NYMEX price less $14.42 per barrel in the Big Horn Basin and the average NYMEX price less $9.57 per barrel in the Williston Basin.

Our oil production is sold under month-to-month sales contracts with purchasers that take delivery of the oil volumes at the tank batteries adjacent to the producing wells. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies. During 2011, we received the average West Texas Intermediate, or “WTI,” price less $3.55 per barrel in the Permian Basin.

In South Texas, our natural gas production has a high Btu content and requires processing prior to sale to third parties. Through our relationship with the operator of our South Texas properties, an affiliate of Lewis Petroleum, we benefit from a processing agreement that was in place prior to our acquisition of these natural gas properties. Our proportionate share of the gas volumes are sold at the tailgate of the processing plant at the Houston Ship Channel Index price which typically results in a discount to NYMEX prices. However, with our share of the NGLs associated with the processing of such gas, our revenues on an Mcf basis are a premium to the NYMEX prices. For the year ended December 31, 2011, the average premium over NYMEX from the sale of natural gas plus our share of the revenues from the sale of NGLs was $2.17 per Mcfe.

The difference between NYMEX market prices and the price received at the wellhead for oil and natural gas production is commonly referred to as a differential. In recent years, production increases from competing Canadian and Rocky Mountain producers, in conjunction with limited refining and pipeline capacity from the Rocky Mountain area, have affected this differential. We cannot always accurately predict future crude oil and natural gas differentials.

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Certain of our natural gas marketing contracts determine the price that we are paid based on the value of the dry gas sold plus a portion of the value of NGLs extracted. Since title of the natural gas sold under these contracts passes at the inlet of the processing plant, we report inlet volumes of natural gas in Mcf as production. As a result of the incremental NGLs value and the improved differential, the price we were paid per Mcf for natural gas sold under certain contracts during 2011 increased to a level above NYMEX.

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Currently, we use fixed-price swaps, basis swaps, swaptions, put options, NYMEX collars and three-way collars to hedge oil and natural gas prices. By removing the price volatility from a significant portion of our oil and natural gas production, we have mitigated for a period of time, but not eliminated, the potential effects of fluctuation in oil and natural gas prices on our cash flow from operations. For a description of our derivative positions, please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2011 Annual Report.

Oil, Natural Gas and NGLs Data

Estimated Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGLs reserves and the present value of the estimated proved reserves at December 31, 2011 (on a historical basis and pro forma as adjusted to give effect to the Appalachian Exchange), based on reserve reports prepared by D&M. Copies of their summary reports are included as exhibits to our 2011 Annual Report. The estimate of net proved reserves has not been filed with or included in reports to any federal authority or agency. The Standardized Measure value shown in the table is not intended to represent the current market value of our estimated oil, natural gas and NGLs reserves. You should refer to “Risk Factors,” “Business — Oil, Natural Gas and NGLs Data — Estimated Proved Reserves,” “— Production and Price History” and “Summary — Recent Developments — Appalachian Exchange” included in this prospectus supplement in evaluating the material presented below.

	As of December 31, 2011			Pro Forma as Adjusted
Reserve Data:
Estimated net proved reserves:
Crude oil (MBbls)		44,803			44,317
Natural gas (Bcf)		163			129
NGLs (MBbls)		7,385			7,385
Total (MMBOE)		79.3			73.2
Proved developed (MMBOE)		68.2			64.2
Proved undeveloped (MMBOE)		11.1			9.0
Proved developed reserves as % of total proved reserves		86	%		88	%
Average developed reserve life		15 years			15 years
Standardized Measure (in millions)(1)(2)	$	1,476.2		$	1,435.3
Representative Oil and Natural Gas Prices(3):
Oil – WTI per Bbl	$	96.24		$	96.24
Natural gas – Henry Hub per MMBtu	$	4.12		$	4.12

(1) Does not give effect to hedging transactions. For a description of our hedging transactions, please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our 2011 Annual Report.

(2) For an explanation of Standardized Measure, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement.

(3) Oil and natural gas prices are based on spot prices per Bbl and MMBtu, respectively, calculated using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”) for January through December 2011, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price.

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The following tables set forth certain information with respect to our estimated proved reserves, after giving effect to the Appalachian Exchange, by operating area as of December 31, 2011 based on estimates made in a reserve report prepared by D&M.

	Estimated Proved Developed Reserve Quantities								Estimated Proved Undeveloped Reserve Quantities								Estimated Proved Reserve Quantities
	Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		Total (MMBOE)		Natural Gas (Bcf)		Oil (MMBbls)		NGLs (MMBbls)		Total (MMBOE)		Total (MMBOE)
Operating Area
Permian Basin		64.9		12.1		2.7		25.6		8.5		2.7		0.2		4.3		29.9
Big Horn Basin		20.0		20.8		1.5		25.6		—		0.9		—		0.9		26.5
South Texas		18.0		0.1		2.0		5.1		9.8		0.1		1.0		2.7		7.8
Williston Basin		2.5		4.4		—		4.9		0.2		0.5		—		0.5		5.4
Mississippi		0.1		1.9		—		1.9		—		0.6		—		0.6		2.5
Arkoma Basin		4.8		0.3		—		1.1		—		—		—		—		1.1
Total		110.3		39.6		6.2		64.2		18.5		4.8		1.2		9.0		73.2

	PV10 Value(1)
Operating Area	Developed		Undeveloped		Total
	(in millions)
Permian Basin	$	471.9	$	71.8	$	543.7
Big Horn Basin		558.5		20.3		578.8
South Texas		59.9		18.3		78.2
Williston Basin		115.1		6.7		121.8
Mississippi		71.4		23.8		95.2
Arkoma Basin		17.6		—		17.6
Total	$	1,294.4	$	140.9	$	1,435.3

(1) PV10 is not a measure of financial or operating performance under generally accepted accounting principles, or “GAAP,” nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. However, for Vanguard, PV10 is equal to the standardized measure of discounted future net cash flows under GAAP because the Company is not a tax paying entity. For our presentation of the standardized measure of discounted future net cash flows, please see “Supplemental Oil and Natural Gas Information” in the Notes to the Consolidated Financial Statements included in “Financial Statements and Supplementary Data” included elsewhere in this prospectus supplement.

The data in the above tables represent estimates only. Oil, natural gas and NGLs reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future sales prices may differ from those assumed in these estimates. Please read “Risk Factors.”

In accordance with the guidelines of the SEC, our independent reserve engineers’ estimates of future net revenues from our properties, and the standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the unweighted arithmetic average first day of the month prices for the 12-month period ended December 31, 2011 for each product.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. 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 Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”),

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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.

From time to time, we engage reserve engineers to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither the reserve engineers nor any of their respective employees have any interest in those properties and the compensation for these engagements is not contingent on their estimates of reserves and future net revenues for the subject properties. During 2011, we paid D&M approximately $53,000 for all reserve and economic evaluations.

Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2011, as estimated by our independent petroleum engineers, were 11.1 MMBOE, consisting of 4.8 million barrels of oil, 31.4 MMcf of natural gas and 1.2 million barrels of NGLs. Our proved undeveloped reserves decreased by 2.5 MMBOE during the year ended December 31, 2011, as compared to the year ended December 31, 2010, resulting from the development of 13% of our total proved undeveloped reserves booked as of December 31, 2010 through the drilling of nine gross (6.9 net) wells at an aggregate capital cost of approximately $13.5 million, offset by the additions of proved undeveloped reserves through acquisitions made in 2011.

At December 31, 2011, we have proved undeveloped properties that are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped and therefore the reserves from these properties are not included in our year end reserve report prepared by our independent reserve engineers. These properties include nine locations with 0.4 MMBOE of proved undeveloped reserves in the Permian Basin, two locations with 0.2 MMBOE of proved undeveloped reserves in the Big Horn Basin and 50 locations with 1.7 MMBOE of proved undeveloped reserves in the South Texas area. None of our proved undeveloped reserves at December 31, 2011 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves.

At December 31, 2011, all of our leases were held by production.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our proved reserve information as of December 31, 2011 included in this prospectus supplement was estimated by our independent petroleum engineers, D&M, in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers and definitions and guidelines established by the SEC.

Our Senior Vice President of Operations, Britt Pence, is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for the coordination of the third-party reserve reports provided by D&M. Mr. Pence has over 28 years of experience and graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering in 1983. He is a member of the Society of Petroleum Engineers. Prior to joining us in 2007, Mr. Pence held engineering and managerial positions with Anadarko Petroleum Corporation, Greenhill Petroleum Company and Mobil Oil Corporation.

Within D&M, the technical person primarily responsible for preparing the estimates set forth in the D&M report letter is Mr. Paul J. Szatkowski. Mr. Szatkowski is a Senior Vice President with D&M and has over 36 years of experience in oil and gas reservoir studies and reserves evaluations. He graduated from Texas A&M University in 1974 with a Bachelor of Science Degree in Petroleum Engineering and is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists. Mr. Szatkowski meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

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We maintain an internal staff of petroleum engineers who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished to D&M in their reserves estimation process. In the fourth quarter, our technical team met on a regular basis with representatives of D&M to review properties and discuss methods and assumptions used in D&M’s preparation of the year-end reserves estimates. All field and reserve technical information, which is updated annually, is assessed for validity when D&M holds technical meetings with our internal staff of petroleum engineers, operations and land personnel to discuss field performance and to validate future development plans. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, the D&M reserve report is reviewed by our senior management and internal technical staff.

Reserve Technologies

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, D&M employed technologies that have been demonstrated to yield results with consistency and repeatability. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, production data, seismic data, well test data, historical price and cost information and property ownership interests.

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain price and cost information for each of the periods indicated.

	Net Production						Average Realized Sales Prices(4)						Production Cost(5)
	Crude Oil Bbls/day		Natural Gas Mcf/day		NGLs Bbls/day		Crude Oil Per Bbl		Natural Gas Per Mcf		NGLs Per Bbl		Per BOE
Year Ended December 31, 2011(1)(6)
Elk Basin Field		2,098		315		328	$	81.02	$	3.38	$	84.90	$	10.99
Other		5,370		28,214		855	$	83.02	$	7.50	$	59.96	$	13.54
Total		7,468		28,529		1,183	$	82.45	$	7.45	$	66.88	$	13.07
Year Ended December 31, 2010(2)
Sun TSH Field		40		2,586		358	$	75.74	$	7.59	$	47.88	$	5.77
Other		1,830		11,086		216	$	76.54	$	10.45	$	41.58	$	11.77
Total		1,870		13,672		574	$	76.53	$	9.91	$	45.78	$	10.72
Year Ended December 31, 2009(3)
Sun TSH Field		26		1,124		169	$	65.40	$	11.03	$	39.90	$	3.76
Other		921		11,320		146	$	75.54	$	11.16	$	31.50	$	11.25
Total		947		12,444		315	$	75.26	$	11.15	$	36.12	$	10.39

(1) Average daily production for 2011 calculated based on 365 days including production for all of our and ENP’s acquisitions from the closing dates of the acquisitions.

(2) Average daily production for 2010 calculated based on 365 days including production for the Parker Creek Acquisition from the closing date of this acquisition.

(3) Average daily production for 2009 calculated based on 365 days including production for the Sun TSH and Ward County Acquisitions from the closing dates of these acquisitions.

(4) Average realized sales prices including hedges but excluding the non-cash amortization of premiums paid and non-cash amortization of value on derivative contracts acquired.

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(5) Production costs include such items as lease operating expenses, which include transportation charges, gathering and compression fees and other customary charges and exclude production taxes (severance and ad valorem taxes).

(6) Production from the properties acquired related to the ENP Purchase during 2011 through the date of the completion of the ENP Merger on December 1, 2011 was subject to a 53.4% non-controlling interest in ENP.

Productive Wells

The following table sets forth information at December 31, 2011, after giving effect to the Appalachian Exchange, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

	Natural Gas Wells				Oil Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		582		282		2,391		564		2,973		846
Big Horn Basin		85		45		305		251		390		296
South Texas		198		194		12		12		210		206
Williston Basin		90		7		162		67		252		74
Mississippi		3		—		17		9		20		9
Arkoma Basin		131		11		2		—		133		11
Total		1,089		539		2,889		903		3,978		1,442

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2011, after giving effect to the Appalachian Exchange, relating to our leasehold acreage.

	Developed Acreage(1)				Undeveloped Acreage(2)				Total Acreage
	Gross(3)		Net(4)		Gross(3)		Net(4)		Gross(3)		Net(4)
Permian Basin		112,707		84,634		9,245		6,930		121,952		91,564
Big Horn Basin		35,192		30,578		1,120		1,073		36,312		31,651
South Texas		8,480		8,262		12,540		6,004		21,020		14,266
Williston Basin		44,790		35,548		19,206		9,474		63,996		45,022
Mississippi		2,560		1,296		—		—		2,560		1,296
Arkoma Basin		3,192		411		357		84		3,549		495
Total		206,921		160,729		42,468		23,565		249,389		184,294

(1) Developed acres are acres spaced or assigned to productive wells.

(2) 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 oil or natural gas, regardless of whether such acreage contains proved reserves.

(3) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Drilling Activity

In the Permian Basin, we drilled one Vanguard-operated horizontal oil well during 2011 in the Bone Spring sand in Ward County, Texas. This well was drilled to a vertical depth of approximately 11,300 feet with an approximate 4,500 feet lateral and completed with a nine stage fracture stimulation job. There were four proved undeveloped horizontal Bone Spring wells remaining to drill at year end 2011.

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In the Big Horn Basin, during 2011 we drilled three productive vertical Madison oil wells in the Elk Basin field with approximately 62.2% working interest. Many of our wells are completed to multiple producing zones and production from these zones may be commingled.

In South Texas, most of our wells are drilled to depths ranging from 5,500 feet to 7,800 feet. Most of the reserves are produced from the Olmos gas sands. In 2011, we drilled three vertical Olmos and Escondido gas wells in La Salle County, Texas with a 100% working interest. During 2012, we expect to install pumping equipment to facilitate water removal and increase gas production.

In the Williston Basin, we participated in drilling three horizontal Bakken oil wells during 2011 with working interest ranging from 10% to 18%. We expect to participate in drilling approximately five wells in 2012 within the Bakken formation.

In Mississippi, during 2011, we participated in the drilling of three 14,400 foot Hosston oil wells in the Parker Creek Field with an approximate 65% working interest.

During 2012, we intend to concentrate our drilling on low risk, development opportunities with the majority of drilling capital focused on oil wells. Excluding any potential acquisitions, we currently anticipate a capital budget for 2012 of between $35.0 million and $40.0 million. We expect to spend 43% of the 2012 capital budget in the Permian Basin, 40% in the Williston Basin, 5% in Mississippi and 12% in all remaining areas.

The following table sets forth information with respect to wells completed during the years ended December 31, 2011, 2010 and 2009. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil, natural gas and NGLs regardless of whether they produce a reasonable rate of return.

	Year Ended December 31,
	2011		2010		2009
Gross wells:
Productive		15		8		1
Dry		—		—		—
Total		15		8		1
Net Development wells:
Productive		8.9		4.6		0.45
Dry		—		—		—
Total		8.9		4.6		0.45
Net Exploratory wells:
Productive		—		—		—
Dry		—		—		—
Total		—		—		—

Operations

Principal Customers

For the year ended December 31, 2011, sales of oil, natural gas and NGLs to Marathon Oil Company, Plains Marketing LP, Shell Trading (US) Company, Flint Hills Resources LP and Lewis Petro Properties Inc. accounted for approximately 22%, 11%, 8%, 6% and 5%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2011 therefore accounted for 52% of our total revenues. To the extent these and other customers reduce the volumes of oil, natural gas and NGLs that they purchase from us and they are not replaced in a timely manner with a new customer, our revenues and cash available for distribution could decline. However, if we were to lose a customer, we believe a substitute purchaser could be identified in a timely manner.

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Delivery Commitments and Marketing Arrangements

Our oil and natural gas production is principally sold to marketers, processors, refiners, and other purchasers that have access to nearby pipeline, processing and gathering facilities. In areas where there is no practical access to pipelines, oil is trucked to central storage facilities where it is aggregated and sold to various markets and downstream purchasers. Our production sales agreements generally contain customary terms and conditions for the oil and natural gas industry, provide for sales based on prevailing market prices in the area, and generally are month-to-month or have terms of one year or less. As of December 31, 2011, we did not have any ongoing delivery commitments of fixed and determinable quantities of oil or natural gas.

We generally sell our natural gas production from our operated properties on the spot market or under market-sensitive, short-term agreements with purchasers, including the marketing affiliates of intrastate and interstate pipelines, independent marketing companies, gas processing companies, and other purchasers who have the ability to pay the highest price for the natural gas production and move the natural gas under the most efficient and effective transportation agreements. Because all of our natural gas production from our operated properties is sold under market-priced agreements, we are positioned to take advantage of future increases in natural gas prices but we are also subject to any future price declines. We do not market our own natural gas on our non-operated properties, but receive our share of revenues from the operator.

The marketing of heavy sour crude oil production from our Big Horn Basin properties is done through our Clearfork pipeline, which transports the crude oil to local and other refiners through connections to other interstate pipelines. Our Big Horn Basin sweet crude oil production is transported from the field by a third party trucking company that delivers the crude oil to a centralized facility connected to a common carrier pipeline with delivery points accessible to local refiners in the Salt Lake City, Utah and Guernsey, Wyoming market centers. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies.

Price Risk and Interest Rate Management Activities

We enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that mitigate the volatility of future prices received. These transactions may include price swaps whereby we will receive a fixed-price for our production and pay a variable market price to the contract counterparty. Additionally, we may acquire put options for which we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. As each monthly contract settles, we receive the excess, if any, of the fixed floor over the floating rate. We also enter into basis swap contracts which guarantee a price differential between the NYMEX prices and our physical pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. Furthermore, we may enter into collars where we pay the counterparty if the market price is above the ceiling price and the counterparty pays us if the market price is below the floor on a notional quantity. We also may enter into three-way collar contracts which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price of NYMEX WTI crude oil drops below the price of the short put. This allows us to settle for WTI market plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. We also enter into swaption agreements, under which we provide options to counterparties to extend swap contracts into subsequent years. In deciding which type of derivative instrument to use, our management considers the relative benefit of each type against any cost that would be incurred, prevailing commodity market conditions and management’s view on future commodity pricing. The amount of oil and natural gas production which is hedged is determined by applying a percentage to the expected amount of production in our most current reserve report in a given year. Typically, management intends to hedge 70% to 85% of projected production up to a four year period. These activities are intended to support our realized commodity prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Management will consider liquidating a derivative contract if they believe

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that they can take advantage of an unusual market condition allowing them to realize a current gain and then have the ability to enter into a new derivative contract in the future at or above the commodity price of the contract that was liquidated.

The following tables summarize commodity derivative contracts in place at December 31, 2011:

	Year 2012		Year 2013		Year 2014
Gas Positions:
Fixed Price Swaps:
Notional Volume (MMBtu)		5,929,932		6,460,500		452,500
Fixed Price ($/MMBtu)	$	5.51	$	5.24	$	4.80
Puts:
Notional Volume (MMBtu)		328,668		—		—
Floor Price ($/MMBtu)	$	6.76	$	—	$	—
Total Gas Positions:
Notional Volume (MMBtu)		6,258,600		6,460,500		452,500
Price ($/MMBtu)	$	5.57	$	5.24	$	4.80

	Year 2012		Year 2013		Year 2014
Oil Positions:
Fixed Price Swaps:
Notional Volume (Bbls)		1,487,790		1,423,500		1,414,375
Fixed Price ($/Bbl)	$	87.95	$	89.17	$	89.91
Collars:
Notional Volume (Bbls)		411,750		82,125		12,000
Floor Price ($/Bbl)	$	80.89	$	88.89	$	100.00
Ceiling Price ($/Bbl)	$	99.47	$	107.34	$	116.20
Three-Way Collars:
Notional Volume (Bbls)		640,500		688,650		164,250
Floor Price ($/Bbl)	$	85.14	$	90.91	$	93.33
Ceiling Price ($/Bbl)	$	101.70	$	104.01	$	105.00
Put Sold ($/Bbl)	$	67.14	$	65.57	$	70.00
Total Oil Positions:
Notional Volume (Bbls)		2,540,040		2,194,275		1,590,625
Floor Price ($/Bbl)	$	86.10	$	89.71	$	90.34

As of December 31, 2011, the Company had the following open basis swap contracts:

	Year 2012			Year 2013			Year 2014
Gas Positions:
Notional Volume (MMBtu)		915,000			912,500			452,500
Weighted Avg. Basis Differential ($/MMBtu)(1)	$	(0.32	)	$	(0.32	)	$	(0.32	)
Oil Positions:
Notional Volume (Bbls)		84,000			84,000			—
Weighted Avg. Basis Differential ($/Bbl)(2)	$	15.15		$	9.60		$	—

(1) Natural gas basis swap contracts represent a weighted average differential between prices against Rocky Mountains (CIGC) and NYMEX Henry Hub prices.

(2) Oil basis swap contracts represent a weighted average differential between prices against Light Louisiana Sweet Crude (LLS) and NYMEX WTI prices.

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Calls were sold or options provided to counterparties under swaption agreements to extend the swaps into subsequent years as follows:

	Year 2012		Year 2013		Year 2014		Year 2015
Gas Positions:
Notional Volume (MMBtu)		—		—		1,642,500		—
Weighted Average Fixed Price ($/MMBtu)	$	—	$	—	$	5.69	$	—
Oil Positions:
Notional Volume (Bbls)		137,250		196,350		127,750		328,500
Weighted Average Fixed Price ($/Bbl)	$	100.00	$	100.73	$	95.00	$	95.56

We have also entered into interest rate swaps, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.

The following summarizes information concerning our positions in open interest rate swaps at December 31, 2011 (in thousands):

	2012			2013			2014			2015(1)			2016
Weighted Average Notional Amount	$	260,164		$	310,000		$	298,781		$	197,932		$	114,325
Weighted Average Fixed LIBOR Rate		1.47	%		1.54	%		1.52	%		1.24	%		1.16	%

(1) The counterparty has the option to extend the termination date of a contract for a notional amount of $30.0 million at 2.25% to August 5, 2018.

Additionally, we sold the option to a counterparty to enter into a $25.0 million LIBOR swap at 1.25% beginning September 7, 2012 through September 7, 2016.

Counterparty Risk

At December 31, 2011, based upon all of our open derivative contracts shown above and their respective mark-to-market values, the Company had the following current and long-term derivative assets and liabilities shown by counterparty with their S&P financial strength rating in parentheses (in thousands):

	Current Assets		Long-Term Assets		Current Liabilities			Long-Term Liabilities			Total Amount Due From/(Owed To) Counterparty at December 31, 2011
Citibank, N.A. (A)	$	—	$	1,105	$	(421	)	$	—		$	684
Wells Fargo Bank N.A./Wachovia Bank, N.A. (AA-)		—		—		(4,616	)		(1,866	)		(6,482	)
BNP Paribas (AA-)		633		—		(1,402	)		(8,423	)		(9,192	)
The Bank of Nova Scotia (AA-)		34		—		(220	)		(3,485	)		(3,671	)
BBVA Compass (A)		—		—		—			(221	)		(221	)
Credit Agricole (A)		151		—		(5,931	)		(2,197	)		(7,977	)
Royal Bank of Canada (AA-)		1,288		—		—			(3,345	)		(2,057	)
Natixis (A)		227		—		—			(391	)		(164	)
Bank of America (A)		—		—		(184	)		(625	)		(809	)
Total	$	2,333	$	1,105	$	(12,774	)	$	(20,553	)	$	(29,889	)

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In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with our counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in two ways: (1) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (2) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staff substantially larger than ours or a different business model. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial, technical or personnel resources will permit.

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

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

Title to Properties

As is customary in the oil and natural gas 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 drilling operations on those properties, however, 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 will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our oil and natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, customary royalty interests, contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for taxes not yet payable and other burdens, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with our use of these properties in the operation of our business.

Natural Gas Gathering

We own and operate a network of natural gas gathering systems in the Big Horn Basin area of operation. These systems gather and transport our natural gas and a small amount of third-party natural gas to larger gathering systems and intrastate, interstate and local distribution pipelines. Our network of natural gas gathering systems permits us to transport production from our wells with fewer interruptions and also minimizes any delays associated with a gathering company extending its lines to our wells. Our ownership and control of these lines enables us to:

• realize faster connection of newly drilled wells to the existing system;

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• control pipeline operating pressures and capacity to maximize production;

• control compression costs and fuel use;

• maintain system integrity;

• control the monthly nominations on the receiving pipelines to prevent imbalances and penalties; and

• track sales volumes and receipts closely to assure all production values are realized.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in some of our operating areas and as a result, we generally perform the majority of our drilling in these areas during the summer and fall months. These seasonal anomalies can pose challenges for meeting our well drilling 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. Generally, but not always, oil is typically in higher demand in the summer for its use in road construction and natural gas is in higher demand in the winter for heating. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Environmental and Occupational Health and Safety Matters

General.  Our business involving the acquisition and development of oil and natural gas properties is subject to extensive and stringent federal, state and local laws and regulations governing the discharge of materials into the environment, environmental protection, and the health and safety of employees. These operations are subject to the same environmental, health and safety laws and regulations as other similarly situated companies in the oil and natural gas industry. These laws and regulations may:

• require the acquisition of permits before commencing drilling or other regulated activities;

• require the installation of expensive pollution control equipment and performance of costly remedial measures to mitigate or prevent pollution from historical and ongoing operations, such as pit closure and plugging of abandoned wells;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

• impose specific health and safety criteria addressing worker protection;

• impose substantial liabilities for pollution resulting from our operations; and

• with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of removal or remedial obligations, and the issuance of orders enjoining some or all of our operations deemed in non-compliance. Moreover, these laws and regulations may restrict our ability to produce oil, natural gas and NGLs by, among other things, limiting production from our wells, limiting the number of wells we are allowed to drill or limiting the locations at which we may conduct our drilling operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly well drilling, construction, completion, water management activities, or waste handling, disposal or clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs. We believe that operation of our wells is in substantial compliance with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse

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impact on our financial condition and results of operations. However, we cannot provide any assurance on how future compliance with existing or newly adopted environmental laws and regulations may impact our properties or the operations. For the year ended December 31, 2011, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this prospectus supplement, we are not aware of any environmental issues or claims that will require material capital expenditures during 2012 or that will otherwise have a material impact on our financial position or results of operations.

The following is a summary of the more significant existing environmental and occupational health and safety laws to which our business operations are subject and for which compliance may have a material impact on our operations as well as the oil and natural gas exploration and production industry in general.

Waste Handling. ��The Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state laws, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” as well as the disposal of non-hazardous wastes. Under the auspices of the U.S. Environmental Protection Agency, or “EPA,” individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. While drilling fluids, produced waters, and many other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions of the RCRA, there is no assurance that the EPA or individual states will not in the future adopt more stringent and costly requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous. For instance, in September 2010, the Natural Resources Defense Council filed a petition for rulemaking with the EPA requesting application of hazardous, rather than non-hazardous, requirements under RCRA to drilling fluids and produced waters but, to date, the EPA has not taken any action on the petition. Any legislative or regulatory reclassification of oil and natural gas exploitation and production wastes could increase our costs to manage and dispose of such wastes, which cost increase could be significant.

Hazardous Substance Releases.  The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA,” or “Superfund,” and analogous state laws, impose, under certain circumstances, joint and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that transported or disposed or arranged for the transportation or disposal of the hazardous substance found at the site. Under CERCLA, such persons may be liable 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 health 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. While materials are generated in the course of operation of our wells that may be regulated as hazardous substances, we have not received any pending notifications that we may be potentially responsible for cleanup costs under CERCLA.

We currently own, lease, or have a non-operating interest in numerous properties that have been used for oil and natural gas production for many years. Although we believe that operating and waste disposal practices used on these properties in the past were standard in the industry at the time, hazardous substances, wastes, or petroleum 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 these substances, wastes and hydrocarbons have been taken for treatment or disposal. In addition, some of these 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. 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 remedial plugging or pit closure operations to prevent future contamination.

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Our Elk Basin assets include a natural gas processing plant. Previous environmental investigations of the Elk Basin natural gas processing plant indicate historical soil and groundwater contamination by hydrocarbons and the presence of asbestos-containing material at the site. Although the environmental investigations did not identify an immediate need for remediation of the suspected historical hydrocarbon contamination or abatement of the asbestos, the extent of the hydrocarbon contamination is not known and, therefore, the potential liability for remediating this contamination may be significant. In the event we ceased operating the gas plant, the cost of decommissioning it and addressing the previously identified environmental conditions and other conditions, such as waste disposal, could be significant. We do not anticipate ceasing operations at the Elk Basin natural gas processing plant in the near future nor a need to commence remedial activities at this time. However, a regulatory agency could require us to investigate and remediate any hydrocarbon contamination even while the gas plant remains in operation. As of December 31, 2011, we have recorded $10.3 million as future abandonment liability for the estimated cost for decommissioning the Elk Basin natural gas processing plant. Due to the significant uncertainty associated with the known and unknown environmental liabilities at the gas plant, our estimate of the future abandonment liability includes a large reserve. Our estimates of the future abandonment liability and compliance costs are subject to change and the actual cost of these items could vary significantly from those estimates.

Water Discharges.  The Federal Water Pollution Control Act, as amended, or “Clean Water Act,” and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into state waters as well as 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 the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can 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.

The primary federal law for oil spill liability is the Oil Pollution Act, as amended, 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 held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.

Hydraulic Fracturing.  Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states, including Texas and Wyoming, have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and

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groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Air Emissions.  The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and their implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. To date, we believe that no unusual difficulties have been encountered in obtaining air permits. However, there is no assurance that in the future, we will not be required to incur capital expenditures in connection with maintaining or obtaining operating permits and approvals addressing air emission-related issues. For example, in July 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, a new source performance standard for volatile organic compounds that would apply to hydraulically fractured wells, compressors, pneumatic controllers, condensate and crude oil storage tanks, and natural gas processing plants. The EPA is under a court order to finalize these proposed regulations by April 3, 2012.

Activities on Federal Lands.  Oil and natural gas exploitation and production activities on federal lands are subject to the National Environmental Policy Act, as amended, 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 typically prepare an Environmental Assessment to assess 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. Our current production activities, as well as proposed development plans, on federal lands require governmental permits or similar authorizations that are subject to the requirements of NEPA. This process has the potential to delay, limit or increase the cost of developing oil and natural gas projects.

Climate Changes.  In response to findings made by the EPA in December 2009 that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gasses are contributing to the warming of the earth’s atmosphere and other climatic changes, the EPA, has adopted regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act including one that requires a reduction in emissions of GHGs from motor vehicles and another that triggers construction and operating permit review for GHG emissions from certain large stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from certain sources including, among others, onshore and offshore oil and natural gas production facilities, which may include certain of our operations, on

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an annual basis. We are conducting monitoring of GHG emissions from our operations in accordance with the GHG emissions reporting rule and we believe that our monitoring and reporting activities are in substantial compliance with applicable reporting obligations.

In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.

Endangered Species Act Considerations.  The federal Endangered Species Act, as amended, or the “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, we believe our operations are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

Occupational Safety and Health.  We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we maintain and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production.  Our operations are subject to various types of regulation at the 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;

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• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation 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 oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil, natural gas and NGLs 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, natural gas and NGLs within its jurisdiction.

Regulation of Transportation and Sales.  The availability, terms and cost of transportation significantly affect sales of oil, natural gas and NGLs. The interstate transportation of natural gas is subject to federal regulation primarily by the Federal Energy Regulatory Commission, or “FERC,” under the Natural Gas Act of 1938, or the “NGA.” FERC regulates interstate natural gas pipeline transportation rates and service conditions, which may affect the marketing and sales of natural gas. FERC requires interstate pipelines to offer available firm transportation capacity on an open-access, non-discriminatory basis to all natural gas shippers. FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. State laws and regulations generally govern the gathering and intrastate transportation of natural gas. Natural gas gathering systems in the states in which we operate are generally required to offer services on a non-discriminatory basis and are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discrimination in favor of one producer over another producer or one source of supply over another source of supply.

The ability to transport oil and NGLs is generally dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act, or subject to regulation by the particular state in which such transportation takes place. Laws and regulation applicable to pipeline transportation of oil largely require pipelines to charge just and reasonable rates published in agency-approved tariffs and require pipelines to provide non-discriminatory access and terms and conditions of service. The justness and reasonableness of interstate oil and natural gas liquid pipeline rates can be challenged at FERC through a protest or a complaint and, if such a protest or complaint results in a lower rate than that on file, pipeline shippers may be eligible to receive refunds or, in the case of a complaining shipper, reparations for the two-year period prior to the filing of the complaint. Certain regulations imposed by FERC, by the United States Department of Transportation and by other regulatory authorities on pipeline transporters in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

Under the Energy Policy Act of 2005, or “EPAct 2005,” Congress made it unlawful for any entity, as defined in the EPAct 2005, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services regulated by the FERC that violates the FERC’s rules. FERC’s rules implementing EPAct 2005 make it unlawful for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act up to $1,000,000 per day per violation. Pursuant to authority granted to FERC by EPAct 2005, FERC has also put in place additional regulations intended to prevent market manipulation and

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to promote price transparency. For example, FERC has imposed new rules discussed below requiring wholesale purchasers and sellers of natural gas to report to FERC certain aggregated volume and other purchase and sales data for the previous calendar year. While EPAct 2005 reflects a significant expansion of the FERC’s enforcement authority, we do not anticipate that we will be affected by EPAct 2005 any differently than energy industry participants.

In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report on Form No. 552, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Pursuant to Order 704, we may be required to annually report to FERC, starting May 1 of each year, information regarding natural gas purchase and sale transactions depending on the volume of natural gas transacted during the prior calendar year.

On August 6, 2009, the Federal Trade Commission, or “FTC,” issued a Final Rule prohibiting manipulative and deceptive conduct in the wholesale petroleum markets. The Final Rule applies to transactions in crude oil, gasoline, and petroleum distillates. The FTC promulgated the Final Rule pursuant to Section 811 of the Energy Independence and Security Act of 2007 (“EISA”), which makes it unlawful for anyone, in connection with the wholesale purchase or sale of crude oil, gasoline or petroleum distillates, to use any “manipulative or deceptive device or contrivance, in contravention of such rules and regulations as the Federal Trade Commission may prescribe.” The Final Rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale, from: a) knowingly engaging in any act, practice, or course of business — including making any untrue statement of material fact that operates or would operate as a fraud or deceit upon any person; or b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.

The price at which we buy and sell natural gas is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. Sales of condensate and NGLs are not currently regulated and are made at market prices. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or “CFTC.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural 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.

State Regulation.  The various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGLs, including imposing severance and other production related taxes and requirements for obtaining drilling permits. Reduced rates or credits may apply to certain types of wells and production methods. For example, currently, a severance tax on oil, natural gas and NGLs production is imposed at a rate of 9.26%, 6.0%, 4.5%, 3.0% and 3.75% in Montana, Wyoming, Kentucky, Tennessee and New Mexico, respectively. Texas currently imposes a 7.5% severance tax on gas production and 4.6% severance tax on oil production. Also, North Dakota currently imposes a 11.12% severance tax on gas production and

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5.0% severance tax on oil production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not currently 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 oil, natural gas and NGLs that may be produced from our wells, to increase our cost of production, to limit the number of wells or locations we can drill and to limit the availability of pipeline capacity to bring our products to market.

In addition to production taxes, Texas and Montana each impose ad valorem taxes on oil and natural gas properties and production equipment. Wyoming and New Mexico impose an ad valorem tax on the gross value of oil and natural gas production in lieu of an ad valorem tax on the underlying oil and natural gas properties. Wyoming also imposes an ad valorem tax on production equipment. North Dakota imposes an ad valorem tax on gross oil and natural gas production in lieu of an ad valorem tax on the underlying oil and gas leases or on production equipment used on oil and gas leases.

The petroleum industry participants are also subject to compliance with various other federal, state and local regulations and laws. Some of these regulations and those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these regulations and laws will have a material adverse effect upon the unitholders.

Federal, State or Native American Leases.  Our operations on federal, state, or Native American oil and natural gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Federal Bureau of Land Management, Minerals Management Service and other agencies.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards and other potential events that can adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may not obtain insurance for certain risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

Employees

As of March 1, 2012, we had 110 full time employees. We also contract for the services of independent consultants involved in land, regulatory, tax, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

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MANAGEMENT

The following table sets forth the names and ages of all of our executive officers and directors as of March 23, 2012.

Name	Age	Position with Our Company
Scott W. Smith	54	President, Chief Executive Officer and Director
Richard A. Robert	46	Executive Vice President, Chief Financial Officer and Secretary
Britt Pence	51	Senior Vice President of Engineering
W. Richard Anderson	58	Independent Director and Chairman
Loren Singletary	64	Independent Director
Bruce W. McCullough	63	Independent Director
John R. McGoldrick	54	Independent Director

Scott W. Smith is our President, Chief Executive Officer and Director and has served as President and Chief Executive Officer since October 2006 and as Director since March 2008. Prior to joining us, from July 2004 to October 2006, Mr. Smith served as the President of Ensource Energy Company, LLC during its tender offer for the units of the Eastern American Natural Gas Trust (NYSE: NGT). He has over 27 years of experience in the energy industry, primarily in business development, marketing, and acquisition and divestiture of producing assets and exploration/exploitation projects in the energy sector. Mr. Smith’s experience includes evaluating, structuring, negotiating and managing business and investment opportunities, including energy investments similar to our targeted investments totaling approximately $400 million as both board member and principal investor in Wiser Investment Company LLC, the largest shareholder in The Wiser Oil Company (NYSE: WZR) until its sale to Forest Oil Corporation (NYSE: FST) in June of 2004. From June 2000 to June 2004, Mr. Smith served on the Board of Directors of The Wiser Oil Company. Mr. Smith was also a member of the executive committee of The Wiser Oil Company during this period. From January of 1998 to June of 1999, Mr. Smith was the co-manager of San Juan Partners, LLC, which established control of Burlington Resources Coal Seam Gas Trust (NYSE: BRU), which was subsequently sold to Dominion Resources, Inc. We believe that Mr. Smith’s extensive energy industry background, particularly the five years he has spent serving as part of our executive management team, brings important experience and skill to the Board of Directors.

Richard A. Robert is our Executive Vice President, Chief Financial Officer and Secretary and has served in such capacities since January of 2007. Prior to joining us, Mr. Robert was involved in a number of entrepreneurial ventures and provided financial and strategic planning services to a variety of energy-related companies since 2003. He was Vice President of Finance for Enbridge US, Inc., a subsidiary of Enbridge Inc. (NYSE: ENB), a natural gas and oil pipeline company, after its acquisition of Midcoast Energy Resources, Inc. in 2001 where Mr. Robert was Chief Financial Officer and Treasurer. He held these positions from 1996 through 2002 and was responsible for acquisition and divestiture analysis, capital formation, taxation and strategic planning, accounting and risk management, and investor relations. Mr. Robert is a certified public accountant.

Britt Pence is our Senior Vice President of Engineering and has served in such capacity since May of 2007. Prior to joining us, since 1997, Mr. Pence was an Area Manager with Anadarko Petroleum Corporation (NYSE: APC) supervising evaluation and exploitation projects in coalbed methane fields in Wyoming and conventional fields in East Texas and the Gulf of Mexico. Prior to joining Anadarko, Mr. Pence served as a reservoir engineer with Greenhill Petroleum Company from 1991 to 1997 with responsibility for properties in the Permian Basin, South Louisiana and the Gulf of Mexico. From 1983 to 1991, Mr. Pence served as reservoir engineer with Mobil with responsibility for properties in the Permian Basin.

W. Richard Anderson is the Chairman of our Board of Directors and is currently the Chief Financial Officer of Eurasia Drilling Company, Ltd GDR (LSE: EDCL), a provider of exploratory and development drilling and oil and gas field services to companies operating within the Russian Federation, Kazakhstan, and Caspian Sea region. Mr. Anderson has served in this capacity since June 2008. Between June 2007 and June 2008, Mr. Anderson served as an independent consultant to Prime Natural Resources, a closely-held exploration and production company. Mr. Anderson was previously the President, Chief Financial Officer and a director of Prime Natural Resources from January 1999 to June 2007. Prior to his employment at Prime

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Natural Resources, he was employed by Hein & Associates LLP, a certified public accounting firm, where he served as a partner from 1989 to January 1995 and as a managing partner from January 1995 until October 1998. Mr. Anderson has also served on the board of directors of Transocean, Ltd. (NYSE: RIG) since November 2007 and the board of directors of Boots & Coots, Inc. (AMEX: WEL) since August 1999. Within the last five years, Mr. Anderson also served on the board of directors of Calibre Energy, Inc. from August 2005 to March 2007. We believe that Mr. Anderson’s extensive energy industry and financial background and his experience serving as the chief financial officer of a public company bring important experience and skill to the Board of Directors.

Loren Singletary is a member of our Board of Directors and is currently Vice President of Global Accounts for National Oilwell Varco (NYSE: NOV), an oilfield service company. Mr. Singletary has served in this capacity since 2003 and has also served as National Oilwell Varco’s Vice President of Investor Relations since January 2009. Prior to his current position, from 1998 to 2003, Mr. Singletary was the co-owner and President of LSI Interests, Ltd., an oilfield service company that was acquired by National Oilwell in 2003. In addition to his vast experience in the oilfield service sector, Mr. Singletary has also been involved in the upstream E&P sector, both onshore and offshore, as a private investor for the past 22 years. We believe that Mr. Singletary’s extensive energy industry background and his experience serving as an executive officer of a public company bring important experience and skill to the Board of Directors.

Bruce W. McCullough is a member of our Board of Directors and since 1986 has served as President and Chief Executive Officer of Huntington Energy Corp., an independent exploration and production company that has been involved in exploration and production activities in the Appalachian basin, East Texas, the Mid-Continent and the Gulf Coast. Prior to forming Huntington in 1986, Mr. McCullough held senior management positions with Pool Offshore, a Houston-based oil field service company. We believe that Mr. McCullough’s extensive energy industry background and his experience serving as the chief executive officer of an exploration and production company bring important experience and skill to the Board of Directors.

John R. McGoldrick is a member of our Board of Directors and since June 2006 has served as a director and Executive Chairman of Caza Oil & Gas, Inc. (LON: CAZA) (TSX: CAZ), a public company listed on the AIM and Toronto Stock Exchange. Prior to his current position, he was President of Falcon Bay Energy LLC, an independent oil and gas company with operations in Texas and South Louisiana from February 2004 to August 2006. From June 1984 to October 2002, Mr. McGoldrick was employed by Enterprise Oil plc in a number of senior management positions, including President of Enterprise Oil Gulf of Mexico Inc. from August 2000 to October 2002. We believe that Mr. McGoldrick’s extensive energy industry background and his experience serving as the executive chairman of a public company bring important experience and skill to the Board of Directors.

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DESCRIPTION OF OTHER INDEBTEDNESS

Existing Debt and Credit Facilities

Senior Secured Reserve-Based Credit Facility

On September 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) with a maximum facility amount of $1.5 billion (the “Reserve-Based Credit Facility”) and initial commitments and a borrowing base of $765.0 million. This Credit Agreement provides for the (1) extension of the maturity date by five years maturing on October 31, 2016, (2) increase in the number of lenders from eight to twenty, (3) increase in the percentage of production that can be hedged into the future, (4) increase in the permitted debt to EBITDA coverage ratio from 3.5x to 4.0x, (5) elimination of the required interest coverage ratio, (6) elimination of the ten percent liquidity requirement to pay distributions to unitholders, and (7) ability to incur unsecured debt. Borrowings from our Reserve-Based Credit Facility and the Facility Term Loan (as discussed below) were used to fully repay outstanding borrowings from the ENP Credit Agreement and our $175.0 million Term Loan (each discussed below). In November 2011, we entered into the First Amendment to the Third Amended and Restated Credit Agreement, which included amendments to (a) specify the effective date of November 30, 2011, (b) allow us to use the proceeds from our Reserve-Based Credit Facility to refinance our debt under the Facility Term Loan, (c) exclude the current maturities under the Facility Term Loan in determining the consolidated current ratio, and (d) provide a cap on the amount of outstanding debt under the Facility Term Loan.

At December 31, 2011, we had $671.0 million of borrowings outstanding under our Reserve-Based Credit Facility and $94.0 million of borrowing capacity. The applicable margins and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Percentage	<25%			25% <50%			50% <75%			75% <90%			90%
Eurodollar Loans Margin		1.50	%		1.75	%		2.00	%		2.25	%		2.50	%
ABR Loans Margin		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%
Commitment Fee Rate		0.50	%		0.50	%		0.375	%		0.375	%		0.375	%
Letter of Credit Fee		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%

The borrowing base is subject to adjustment from time to time but not less than on a semi-annual basis based on the projected discounted present value of estimated future net cash flows (as determined by the bank’s petroleum engineers utilizing the bank’s internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. Our next borrowing base redetermination is scheduled for April 2012 utilizing our December 31, 2011 reserve report. Our borrowing base will be reduced automatically to $680.0 million upon closing this offering and the Appalachian Exchange. If commodity prices decline and banks lower their internal projections of oil, natural gas and NGLs prices, it is possible that we will be subject to further decreases in our borrowing base in the future.

Borrowings under the Reserve-Based Credit Facility are available for development and acquisition of oil and natural gas properties, working capital and general limited liability company purposes. Our obligations under the Reserve-Based Credit Facility are secured by substantially all of our assets.

At our election, interest is determined by reference to:

• the London interbank offered rate, or LIBOR, plus an applicable margin between 1.50% and 2.50% per annum; or

• a domestic bank rate plus an applicable margin between 0.50% and 1.50% per annum.

As of December 31, 2011, we have elected for interest to be determined by reference to the LIBOR method described above. Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans, but not less frequently than quarterly.

The Reserve-Based Credit Facility contains various covenants that limit our ability to:

• incur indebtedness;

• grant certain liens;

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• make certain loans, acquisitions, capital expenditures and investments;

• merge or consolidate; or

• engage in certain asset dispositions, including a sale of all or substantially all of our assets.

The Reserve-Based Credit Facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

• consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC Topic 815, which includes the current portion of derivative contracts; and

• consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures. of not more than 4.0 to 1.0.

We have the ability to borrow under the Reserve-Based Credit Facility to pay distributions to unitholders as long as there has not been a default or event of default.

We believe that we are in compliance with the terms of our Reserve-Based Credit Facility at December 31, 2011. If an event of default exists under the Reserve-Based Credit Facility, the lenders will be able to accelerate its maturity and exercise other rights and remedies. Each of the following will be an event of default:

• failure to pay any principal when due or any interest, fees or other amount within certain grace periods;

• a representation or warranty is proven to be incorrect when made;

• failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

• default by us on the payment of any other indebtedness in excess of $5.0 million, or any event occurs that permits or causes the acceleration of the indebtedness;

• bankruptcy or insolvency events involving us or our subsidiaries;

• the entry of, and failure to pay, one or more adverse judgments in excess of 2% of the existing borrowing base (to the extent not covered by independent third party insurance provided by insurers of the highest claims paying rating or financial strength as to which the insurer does not dispute coverage and is not subject to insolvency proceeding) or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;

• specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.0 million in any year; and

• a change of control, which includes (1) an acquisition of ownership, directly or indirectly, beneficially or of record, by any person or group (within the meaning of the Exchange Act and the rules and regulations of the SEC) of equity interests representing more than 25% of the aggregate ordinary voting power represented by our issued and outstanding equity interests, or (2) the replacement of a majority of our directors by persons not approved by our board of directors.

Senior Secured Second Lien Term Loan

On November 30, 2011, we entered into a $100.0 million senior secured second lien term loan facility (the “Facility Term Loan”) with seven banks from the Reserve-Based Credit Facility, with a maturity date of May 30, 2017. The Facility Term Loan will be repaid in full with part of the net proceeds of this offering, and the facility will be terminated. See “Use of Proceeds.”

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Borrowings under the Facility Term Loan are comprised entirely of Eurodollar Loans. Interest on borrowings under the Facility Term Loan is payable quarterly on the last day of each March, June, September and December and accrues at a rate per annum equal to the sum of the applicable margin plus the Adjusted LIBO Rate in effect on such day. The applicable margin increases based upon the number of days after the effective date of the Facility Term Loan as follows:

	Days after effective date
	1 – 180			181 – 360			360+
Applicable Margin		5.50	%		6.00	%		8.50	%

The effective dates of the increase in the applicable margins will accelerate if we are unable to comply with the requirements under the Facility Term Loan agreement as it relates to title covering oil and natural gas properties included in our reserve reports as indicated below:

	Until 1/15/12			1/16/12 –  5/30/12			5/31/12 and thereafter
Applicable Margin		5.50	%		6.00	%		8.50	%

Amounts outstanding under the Facility Term Loan may only be prepaid prior to maturity, together with all accrued and unpaid interest relating to the amount prepaid, when all outstanding borrowings under the Reserve-Based Credit Facility are paid in full except for mandatory prepayments related to any future equity and debt offerings. The Facility Term Loan contains principally the same covenants as our Reserve-Based Credit Facility, including restrictions on liens, restrictions on incurring other indebtedness without the lenders’ consent and restrictions on entering into certain transactions. A test of the Company’s collateral coverage ratio, a defined below, will also be performed semi-annually starting on April 1, 2012. Amounts outstanding under the Facility Term Loan are secured by a second priority lien on all assets of VNG and its subsidiaries securing VNG’s current Reserve-Based Credit Facility.

The Facility Term Loan also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

• consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC Topic 815, which includes the current portion of derivative contracts;

• consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 4.0 to 1.0;

• pre-tax present value of estimated future net cash flows to be generated from the production of from proved reserves, at least 60% of which must be proved developed producing, discounted at 10% to consolidated debt or a collateral coverage ratio of not less than 1.5 to 1.0.

We believe that we are in compliance with the terms of our Facility Term Loan at December 31, 2011.

Term Loan

Concurrent with the ENP Purchase, VNG entered into a $175.0 million term loan (the “Term Loan”) with BNP Paribas to fund a portion of the consideration for the acquisition. As discussed above, the amount outstanding under the Term Loan was fully repaid from proceeds under the Reserve-Based Credit Facility and Facility Term Loan in December 2011.

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DESCRIPTION OF NOTES

You can find the definitions of certain terms used in this description under the subheading “— Certain Definitions.” In this description, the word “Vanguard” refers only to Vanguard Natural Resources, LLC and not to any of its Subsidiaries, and the words “Finance Corp.” refer solely to Vanguard Finance Corp. The term “Issuers” refers to Vanguard and Finance Corp., collectively. Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture referred to below.

The Issuers will issue the notes under an indenture to be dated as of     , 2012 (the “base indenture”), as supplemented by a supplemental indenture establishing the form and terms of the notes (together with the base indenture, as such may be amended, supplemented or otherwise modified from time to time, the “indenture”) among themselves, the Guarantors and U.S. Bank National Association, as trustee. We have filed a copy of the base indenture as an exhibit to the registration statement which includes the accompanying base prospectus. Copies of the base indenture and the supplemental indenture are available as set forth below under “— Additional Information.” The terms of the notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

This “Description of Notes,” together with the “Description of Our Debt Securities” included in the accompanying base prospectus, is intended to be a useful overview of the material provisions of the notes and the indenture. Since this “Description of Notes” and such “Description of Our Debt Securities” is only a summary, you should refer to the indenture for a complete description of the obligations of the Issuers and your rights as holders of the notes. This “Description of Notes” supersedes the “Description of Our Debt Securities” in the accompanying base prospectus to the extent it is inconsistent with such “Description of Our Debt Securities.”

The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture.

Brief Description of the Notes and the Note Guarantees

The Notes

The notes will be:

• general unsecured obligations of the Issuers;

• pari passu in right of payment with all existing and future senior Indebtedness of either of the Issuers;

• senior in right of payment to any future subordinated Indebtedness of either of the Issuers; and

• unconditionally guaranteed by the Guarantors.

The Note Guarantees

Initially, the notes will be guaranteed by all of Vanguard’s current Subsidiaries (other than Finance Corp.).

Each guarantee of the notes will be:

• a general unsecured obligation of the Guarantor;

• pari passu in right of payment with all existing and future senior Indebtedness of that Guarantor; and

• senior in right of payment to any future subordinated Indebtedness of that Guarantor.

However, the notes and the guarantees will be effectively subordinated to all borrowings of our operating subsidiary, Vanguard Natural Gas, LLC, under the Credit Agreement, which is secured by substantially all of the assets of the Issuers and the Guarantors and guaranteed by Vanguard and all of its other Subsidiaries, and structurally subordinated to all indebtedness and other liabilities of any of our future Subsidiaries that do not guarantee the notes. See “Risk Factors — Risks Relating to the Notes — The notes

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and the guarantees will be unsecured obligations and will be effectively subordinated to all of our existing and future secured indebtedness and structurally subordinated to the indebtedness of any of our future non-guarantor subsidiaries.”

As of the date of the indenture, all of Vanguard’s Subsidiaries will be “Restricted Subsidiaries.” However, under the circumstances described below under the caption “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries,” Vanguard will be permitted to designate certain of its Subsidiaries as “Unrestricted Subsidiaries.” Vanguard’s Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes.

Principal, Maturity and Interest

The Issuers will issue $300 million in aggregate principal amount of notes in this offering. The Issuers may issue additional notes under the indenture from time to time after this offering. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Issuers will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on     , 2020.

Interest on the notes will accrue at the rate of   % per annum and will be payable semi-annually in arrears on        and       , commencing on     , 2012. Interest on overdue principal and interest will accrue at a rate that is 1% higher than the then applicable interest rate on the notes. The Issuers will make each interest payment to the holders of record on the immediately preceding     and     .

Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

If a holder of notes has given wire transfer instructions to Vanguard, the Issuers will pay all principal of, and premium and interest, if any, on, that holder’s notes in accordance with those instructions. All other payments on the notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless the Issuers elect to make interest payments by check mailed to the noteholders at their addresses set forth in the register of holders.

Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. The Issuers may change the paying agent or registrar without prior notice to the holders of the notes, and Vanguard or any of its Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. The Issuers will not be required to transfer or exchange any note selected for redemption. Also, the Issuers will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed or between a record date and the next succeeding interest payment date.

Note Guarantees

Initially, all of the notes will be guaranteed by each of Vanguard’s current Subsidiaries (except Finance Corp.). In the future, other Restricted Subsidiaries of Vanguard will be required to guarantee the notes under the circumstances described below under “— Certain Covenants — Additional Note Guarantees.” These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent

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conveyance under applicable law, although this limitation may not be effective to prevent the Note Guarantees from being voided in bankruptcy. See “Risk Factors — Risks Relating to the Notes — Federal bankruptcy and state fraudulent transfer laws and other limitations may preclude the recovery of payments under the guarantees for the notes.”

A Guarantor may not sell or otherwise dispose of, in one or more related transactions, all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, other than Vanguard or another Guarantor, unless:

(1)  immediately after giving effect to such transaction or series of transactions, no Default or Event of Default exists; and

(2)  either:

(a)  the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Guarantor) unconditionally assumes all the obligations of that Guarantor under its Note Guarantee and the indenture pursuant to a supplemental indenture in form reasonably satisfactory to the trustee; or

(b)  such transaction or series of transactions does not violate the “Asset Sales” provisions of the indenture.

The Note Guarantee of a Guarantor will be released:

(1)  in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor, by way of merger, consolidation or otherwise, to a Person that is not (either before or after giving effect to such transaction) Vanguard or a Restricted Subsidiary of Vanguard, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture;

(2)  in connection with any sale or other disposition of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) Vanguard or a Restricted Subsidiary of Vanguard, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture and the Guarantor ceases to be a Restricted Subsidiary of Vanguard as a result of the sale or other disposition;

(3)  if Vanguard designates such Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(4)  upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture as provided below under the captions “— Legal Defeasance and Covenant Defeasance” and “— Satisfaction and Discharge”;

(5)  upon the liquidation or dissolution of such Guarantor provided no Default or Event of Default has occurred that is continuing;

(6)  at such time as such Guarantor ceases both (a) to guarantee any other Indebtedness of either of the Issuers and any Indebtedness of any other Guarantor (except as a result of payment under any such other guarantee) and (b) to be an obligor with respect to any Indebtedness under any Credit Facility; or

(7)  upon such Guarantor consolidating with, merging into or transferring all of its properties or assets to either of the Issuers or another Guarantor, and as a result of, or in connection with, such transaction such Guarantor dissolving or otherwise ceasing to exist.

See “— Repurchase at the Option of Holders — Asset Sales.”

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Optional Redemption

At any time prior to     , 2015, the Issuers may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes issued under the indenture, but in an amount not greater than the net cash proceeds of an Equity Offering by Vanguard, upon notice as provided in the indenture, at a redemption price equal to     % of the principal amount of the notes redeemed, plus accrued and unpaid interest, if any, to the date of redemption (subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date); provided that:

(1)  at least 65% of the aggregate principal amount of notes originally issued under the indenture (excluding notes held by Vanguard and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

(2)  the redemption occurs within 180 days of the date of the closing of such Equity Offering.

At any time prior to     , 2016, the Issuers may on any one or more occasions redeem all or a part of the notes, upon notice as provided in the indenture, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus the Applicable Premium as of, and accrued and unpaid interest to, the date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding paragraphs and the final paragraph under “— Repurchase at the Option of Holders — Change of Control,” the notes will not be redeemable at the Issuers’ option prior to     , 2016.

On or after     , 2016, the Issuers may on any one or more occasions redeem all or a part of the notes, upon notice as provided in the indenture, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the notes redeemed, to the applicable date of redemption, subject to the rights of holders of notes on the relevant record date to receive interest on the relevant interest payment date, if redeemed during the twelve-month period beginning on         of the years indicated below:

Year	Percentage
2016		%
2017		%
2018 and thereafter		100.000	%

Mandatory Redemption

The Issuers are not required to make mandatory redemption or sinking fund payments with respect to the notes.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each holder of notes will have the right to require Vanguard to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder’s notes pursuant to a cash tender offer (“Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, Vanguard will offer a payment in cash (“Change of Control Payment”) equal to 101% of the aggregate principal amount of notes repurchased, plus accrued and unpaid interest, if any, on the notes repurchased to the date of purchase (the “Change of Control Purchase Date”), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, Vanguard will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes properly tendered prior to the expiration date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice. Vanguard will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the

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indenture, Vanguard will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.

Promptly following the expiration of the Change of Control Offer, Vanguard will, to the extent lawful, accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly after such acceptance, Vanguard will, on the Change of Control Purchase Date:

(1)  deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(2)  deliver or cause to be delivered to the trustee the notes properly accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions of notes being purchased by Vanguard.

The paying agent will promptly mail to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of The Depository Trust Company (“DTC”)), and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any. Vanguard will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Purchase Date.

The provisions described above that require Vanguard to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture will not contain provisions that permit the holders of the notes to require that Vanguard repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

Vanguard will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by Vanguard and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, (2) notice of redemption of all outstanding notes has been given pursuant to the indenture as described above under the caption “— Optional Redemption,” unless and until there is a default in payment of the applicable redemption price or (3) in connection with or in contemplation of any Change of Control, Vanguard has made an offer to purchase (an “Alternate Offer”) any and all notes validly tendered at a cash price equal to or higher than the Change of Control Payment and has purchased all notes properly tendered in accordance with the terms of such Alternate Offer. Notwithstanding anything to the contrary contained in the indenture, a Change of Control Offer may be made in advance of a Change of Control, conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer is made.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of Vanguard and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require Vanguard to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of Vanguard and its Subsidiaries taken as a whole to another Person or group may be uncertain.

In the event that holders of not less than 90% in aggregate principal amount of the outstanding notes accept a Change of Control Offer and Vanguard (or any third party making such Change of Control Offer in lieu of Vanguard as described above) purchases all of the notes held by such holders, the Issuers will have the right, upon not less than 30 nor more than 60 days prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer described above, to redeem all of the notes that remain outstanding following such purchase at a redemption price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest, if any, on the notes

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that remain outstanding, to the date of redemption (subject to the rights of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

Asset Sales

Vanguard will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1)  Vanguard (or a Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value (measured as of the date of the definitive agreement with respect to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and

(2)  at least 75% of the aggregate consideration received in the Asset Sale by Vanguard or a Restricted Subsidiary and all other Asset Sales since the date of the indenture is in the form of cash or Cash Equivalents. For purposes of this provision, each of the following will be deemed to be cash:

(a)  any liabilities, as shown on Vanguard’s most recent consolidated balance sheet, of Vanguard or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation or indemnity agreement that releases Vanguard or such Restricted Subsidiary from or indemnifies against further liability;

(b)   with respect to any Asset Sale of oil and gas properties by Vanguard or any of its Restricted Subsidiaries, any agreement by the transferee (or an Affiliate thereof) to pay all or a portion of the costs and expenses related to the exploration, development, completion or production of such properties and activities related thereto; and

(c)  any securities, notes or other obligations received by Vanguard or any Restricted Subsidiary from such transferee that are, within 90 days of the Asset Sale, converted by Vanguard or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, Vanguard (or any Restricted Subsidiary) may apply such Net Proceeds at its option to any combination of the following:

(1)  to repay, redeem or repurchase any Senior Debt;

(2)  invest in or acquire Additional Assets; or

(3)  to make capital expenditures in respect of Vanguard’s or any Restricted Subsidiaries’ Oil and Gas Business.

The requirement of clause (2) or (3) of the preceding paragraph shall be deemed to be satisfied if a bona fide binding contract committing to make the investment, acquisition or expenditure referred to therein is entered into by Vanguard (or any Restricted Subsidiary) with a Person other than an Affiliate of Vanguard within the time period specified in the preceding paragraph and such Net Proceeds are subsequently applied in accordance with such contract within six months following the date such agreement is entered into.

Pending the final application of any Net Proceeds, Vanguard (or any Restricted Subsidiary) may invest the Net Proceeds in any manner that is not prohibited by the indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the second paragraph of this covenant will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $20.0 million, within five days thereof, Vanguard will make an offer (an “Asset Sale Offer”) to all holders of notes and all holders of other Indebtedness that is pari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem, on a pro rata basis, the maximum principal amount of notes and such other pari passu Indebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued and unpaid interest, if any, to the date of purchase, prepayment or redemption, subject to

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the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, Vanguard or any Restricted Subsidiary may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes tendered in such Asset Sale Offer exceeds the amount of Excess Proceeds allocated to the purchase of notes, the trustee will select the notes to be purchased on a pro rata basis (except that any notes represented by a note in global form will be selected by such method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as the trustee deems fair and appropriate), based on the principal amounts tendered (with such adjustments as may be deemed appropriate by Vanguard so that only notes in denominations of $2,000, or an integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

Vanguard will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the “Asset Sales” provisions of the indenture, Vanguard will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the “Asset Sales” provisions of the indenture by virtue of such compliance.

The Credit Agreement contains, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale. The exercise by the holders of notes of their right to require Vanguard to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on Vanguard. In the event a Change of Control or Asset Sale occurs at a time when Vanguard is prohibited from purchasing notes, Vanguard could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If Vanguard does not obtain a consent or repay those borrowings, Vanguard will remain prohibited from purchasing notes. In that case, Vanguard’s failure to purchase tendered notes would constitute an Event of Default under the indenture, which could, in turn, constitute a default under the other indebtedness. Finally, Vanguard’s ability to pay cash to the holders of notes upon a repurchase may be limited by Vanguard’s then existing financial resources. See “Risk Factors — Risks Relating to the Notes — We may not be able to repurchase the notes upon a change of control.”

Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis (or, in the case of notes issued in global form as discussed under “— Book-Entry, Delivery and Form,” based on a method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as the trustee deems fair and appropriate) unless otherwise required by law or applicable stock exchange or depositary requirements.

No notes of $2,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional, except that any redemption pursuant to the first paragraph under the “— Optional Redemption” section, may, at Vanguard’s discretion, be subject to completion of the related Equity Offering.

If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note.

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Notes called for redemption without condition will become due on the date fixed for redemption. Unless the Issuers default in the payment of the redemption price, interest will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.

Certain Covenants

Changes in Covenants if Notes Rated Investment Grade

If on any date following the date of the indenture:

(1)  the notes are rated Baa3 or better by Moody’s and BBB- or better by S&P (or, if either such entity ceases to rate the notes for reasons outside of the control of Vanguard, the equivalent investment grade credit rating from any other “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act selected by Vanguard as a replacement agency);

(2)  no Default or Event of Default shall have occurred and be continuing;

(3)  the Issuers have delivered to the trustee an officers’ certificate certifying to the foregoing provisions of this paragraph,

Vanguard and its Restricted Subsidiaries will no longer be subject to the provisions of the indenture described below under the following captions in this description of notes:

(a)  “— Repurchase at the Option of Holders — Asset Sales”;

(b)  “— Certain Covenants — Restricted Payments”;

(c)  “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;

(d)  “— Certain Covenants — Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries”;

(e)  clause (4) of the covenant described below under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets”;

(f)  “— Certain Covenants — Transactions with Affiliates”;

(g)  “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries”; and

(h)  “— Certain Covenants — Reports.”

There can be no assurance that the notes will ever achieve an investment grade rating or that any such rating will be maintained.

Restricted Payments

Vanguard will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1)  declare or pay any dividend or make any other payment or distribution on account of Vanguard’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving Vanguard or any of its Restricted Subsidiaries) or to the direct or indirect holders of Vanguard’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of Vanguard and other than dividends or distributions payable to Vanguard or a Restricted Subsidiary of Vanguard);

(2)  repurchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving Vanguard) any Equity Interests of Vanguard or any direct or indirect parent of Vanguard;

(3)  make any payment on or with respect to, or repurchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of the Issuers or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee (excluding (a) any intercompany Indebtedness between or among Vanguard and any of its Restricted Subsidiaries and (b) the repurchase or other acquisition or retirement

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for value of any such Indebtedness in anticipation of satisfying a sinking fund or other payment obligation due within one year of the date of such repurchase or other acquisition or retirement for value), except a payment of interest or principal at the Stated Maturity thereof; or

(4)  make any Restricted Investment (all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),

unless, at the time of and after giving effect to such Restricted Payment, no Default (except a Reporting Default) or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment and either:

(I)  if the Fixed Charge Coverage Ratio for Vanguard’s most recently ended four full fiscal quarters for which internal financial statements are available at the time of such Restricted Payment (the “Trailing Four Quarters”) is not less than 2.25 to 1.0, such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Vanguard and its Restricted Subsidiaries (excluding Restricted Payments permitted by clauses (2) through (12) of the next succeeding paragraph) with respect to the fiscal quarter for which such Restricted Payment is made, is less than the sum, without duplication, of:

(a)  Available Cash with respect to Vanguard’s preceding fiscal quarter; plus

(b)  100% of the aggregate net proceeds, and the Fair Market Value of any Capital Stock of Persons engaged primarily in the Oil and Gas Business or any other assets that are used or useful in the Oil and Gas Business, in each case received by Vanguard since the date of the indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of Vanguard (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of Vanguard); plus

(c)  to the extent that any Restricted Investment that was made after the date of the indenture is sold for cash or Cash Equivalents or otherwise liquidated or repaid for cash or Cash Equivalents, the return of capital with respect to such Restricted Investment (less the cost of disposition, if any); plus

(d)  the net reduction in Restricted Investments resulting from dividends, repayments of loans or advances, or other transfers of assets in each case to Vanguard or any of its Restricted Subsidiaries from any Person (including, without limitation, Unrestricted Subsidiaries) or from redesignations of Unrestricted Subsidiaries as Restricted Subsidiaries, to the extent such amounts have not been included in Available Cash for any period commencing on or after the date of the indenture (items (b), (c) and (d) being referred to as “Incremental Funds”); minus

(e)  the aggregate amount of Incremental Funds previously expended pursuant to this clause (I) and clause (II) below; or

(II)  if the Fixed Charge Coverage Ratio for the Trailing Four Quarters is less than 2.25 to 1.0, such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Vanguard and its Restricted Subsidiaries (excluding Restricted Payments permitted by clauses (2) through (12) of the next succeeding paragraph) with respect to the fiscal quarter for which such Restricted Payment is made (such Restricted Payments for purposes of this clause (II) meaning only distributions on Vanguard’s common units), is less than the sum, without duplication, of:

(a)  $125.0 million, less the aggregate amount of all prior Restricted Payments made by Vanguard and its Restricted Subsidiaries pursuant to this clause (II)(a) since the date of the indenture; plus

(b)  Incremental Funds to the extent not previously expended pursuant to this clause (II) or the immediately proceeding clause (I) of this paragraph.

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The preceding provisions will not prohibit:

(1)  the payment of any dividend or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend or redemption payment would have complied with the provisions of the indenture;

(2)  the making of any Restricted Payment in exchange for, or out of or with the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of Vanguard) of, Equity Interests of Vanguard (other than Disqualified Stock) or from the substantially concurrent contribution of common equity capital to Vanguard; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will not be considered to be net proceeds of Equity Interests for purposes of clause (c)(ii) of the preceding paragraph and will not be considered to be net cash proceeds from an Equity Offering for purposes of the “Optional Redemption” provisions of the indenture;

(3)  the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of Vanguard to the holders of its Equity Interests on a pro rata basis;

(4)  the repurchase, redemption, defeasance or other acquisition or retirement for value of Indebtedness of Vanguard or any Guarantor that is contractually subordinated to the notes or to any Note Guarantee with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;

(5)  so long as no Default (other than a Reporting Default) or Event of Default has occurred and is continuing or would be caused thereby, the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of Vanguard or any Restricted Subsidiary of Vanguard held by any current or former officer, director or employee of Vanguard or any of its Restricted Subsidiaries pursuant to any equity subscription agreement, equity option agreement, unitholders’ agreement or similar agreement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $5.0 million in any calendar year (with any portion of such $5.0 million amount that is unused in any calendar year to be carried forward to successive calendar years and added to such amount) plus, to the extent not previously applied or included, (a) the cash proceeds received by Vanguard or any of its Restricted Subsidiaries from sales of Equity Interests of Vanguard to employees or directors of Vanguard or its Affiliates that occur after the date of the indenture (to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clauses (I)(b) or (II)(b) of the first paragraph of this covenant) and (b) the cash proceeds of key man life insurance policies received by Vanguard or any of its Restricted Subsidiaries after the date of the indenture;

(6)  the repurchase of Equity Interests deemed to occur upon the exercise of units or other equity options to the extent such Equity Interests represent a portion of the exercise price of those unit or other equity options and any repurchase or other acquisition of Equity Interests made in lieu of withholding taxes in connection with any exercise or exchange of equity options, warrants, incentives or other rights to acquire Equity Interests;

(7)  the repurchase, redemption or other acquisition or retirement for value of Equity Interests of Vanguard or any Restricted Subsidiary of Vanguard representing fractional units of such Equity Interests in connection with a merger or consolidation involving Vanguard or such Restricted Subsidiary or any other transaction permitted by the indenture;

(8)  any payments in connection with a consolidation, merger or transfer of assets in connection with a transaction that is not prohibited by the indenture not to exceed $5.0 million in the aggregate after the date of the indenture;

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(9)  so long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of Vanguard or any Preferred Stock of any Restricted Subsidiary of Vanguard issued on or after the date of the indenture in accordance with the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;

(10)  payments of cash, dividends, distributions, advances or other Restricted Payments by Vanguard or any of its Restricted Subsidiaries to allow the payment of cash in lieu of the issuance of fractional units upon (i) the exercise of options or warrants or (ii) the conversion or exchange of Capital Stock of any such Person;

(11)  the acquisition of Equity Interests of Vanguard or Vanguard Natural Gas, LLC pursuant to the Unit Exchange Agreement; and

(12)  so long as no Default (other than a Reporting Default) or Event of Default has occurred and is continuing or would be caused thereby, other Restricted Payments in an aggregate amount not to exceed $5.0 million since the date of the indenture.

The amount of all Restricted Payments (other than cash) will be the Fair Market Value, on the date of the Restricted Payment, of the Restricted Investment proposed to be made or the asset(s) or securities proposed to be transferred or issued by Vanguard or any of its Restricted Subsidiaries, as the case may be, pursuant to the Restricted Payment, except that the Fair Market Value of any non-cash dividend paid within 60 days after the date of declaration will be determined as of such date of declaration. The Fair Market Value of any Restricted Investment, assets or securities that are required to be valued by this covenant will be determined in accordance with the definition of that term. For purposes of determining compliance with this “Restricted Payments” covenant, (x) in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) through (12) of this covenant, or is permitted pursuant to the first paragraph of this covenant, Vanguard will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment (or portion thereof) on the date made or later reclassify such Restricted Payment (or portion thereof) in any manner that complies with this covenant; and (y) in the event a Restricted Payment is made pursuant to clause (I) or (II) of the first paragraph of this covenant, Vanguard will be permitted to classify whether all or any portion thereof is being (and in the absence of such classification shall be deemed to have classified the minimum amount possible as having been) made with Incremental Funds.

Incurrence of Indebtedness and Issuance of Preferred Stock

Vanguard will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, Guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and Vanguard will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any Preferred Stock; provided, however, that Vanguard may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Guarantors may incur Indebtedness (including Acquired Debt) or issue Preferred Stock, if the Fixed Charge Coverage Ratio for Vanguard’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such Preferred Stock is issued, as the case may be, would have been at least 2.25 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the Preferred Stock had been issued, as the case may be, at the beginning of such four-quarter period.

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The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness or issuances of Disqualified Stock or Preferred Stock, as applicable (collectively, “Permitted Debt”):

(1)  the incurrence by Vanguard and any of its Restricted Subsidiaries of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of Vanguard and its Restricted Subsidiaries thereunder) not to exceed the greater of (i) $1,000.0 million and (ii) $475.0 million plus 35% of Vanguard’s Adjusted Consolidated Net Tangible Assets determined on the date of such incurrence;

(2)  the incurrence by Vanguard and its Restricted Subsidiaries of the Existing Indebtedness;

(3)  the incurrence by Vanguard and the Guarantors of Indebtedness represented by the notes and the related Note Guarantees to be issued on the date of the indenture;

(4)  the incurrence by Vanguard or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, construction, installation or improvement of property, plant or equipment used in the business of Vanguard or any of its Restricted Subsidiaries, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4), not to exceed $25.0 million at any time outstanding;

(5)  the incurrence by Vanguard or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clause (2), (3), (4), (5), (15) or (16) of this paragraph;

(6)  the incurrence by Vanguard or any of its Restricted Subsidiaries of intercompany Indebtedness between or among Vanguard and any of its Restricted Subsidiaries; provided, however, that:

(a)  if Vanguard or any Guarantor is the obligor on such Indebtedness and the payee is not Vanguard or a Guarantor, such Indebtedness must be unsecured and expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of Vanguard, or the Note Guarantee, in the case of a Guarantor; and

(b)  (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than Vanguard or a Restricted Subsidiary of Vanguard and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either Vanguard or a Restricted Subsidiary of Vanguard,

will be deemed, in each case, to constitute an incurrence of such Indebtedness by Vanguard or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7)  the issuance by any of Vanguard’s Restricted Subsidiaries to Vanguard or to any of its Restricted Subsidiaries of any Preferred Stock; provided, however, that:

(a)  any subsequent issuance or transfer of Equity Interests that results in any such Preferred Stock being held by a Person other than Vanguard or a Restricted Subsidiary of Vanguard; and

(b)  any sale or other transfer of any such Preferred Stock to a Person that is not either Vanguard or a Restricted Subsidiary of Vanguard,

will be deemed, in each case, to constitute an issuance of such Preferred Stock by such Restricted Subsidiary that was not permitted by this clause (7);

(8)  the incurrence by Vanguard or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business and not for speculative purposes;

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(9)  the Guarantee by Vanguard or any of the Guarantors of Indebtedness of Vanguard or a Restricted Subsidiary of Vanguard to the extent that the guaranteed Indebtedness was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the notes, then the Guarantee must be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;

(10)  the incurrence by Vanguard or any of the Guarantors of Indebtedness in respect of self-insurance obligations or bid, plugging and abandonment, appeal, reimbursement, performance, surety and similar bonds and completion guarantees provided by Vanguard or a Restricted Subsidiary in the ordinary course of business and any Guarantees or letters of credit functioning as or supporting any of the foregoing bonds or obligations and workers’ compensation claims in the ordinary course of business;

(11)  the incurrence by Vanguard or any of its Restricted Subsidiaries of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five business days;

(12)  the incurrence by Vanguard or any of its Restricted Subsidiaries of in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business;

(13)  any obligation arising from agreements of Vanguard or any Restricted Subsidiary of Vanguard providing for indemnification, adjustment of purchase price, earn outs, or similar obligations, in each case, incurred or assumed in connection with the disposition or acquisition of any business, assets or Capital Stock of a Restricted Subsidiary in a transaction permitted by the indenture, provided such obligation is not reflected on the face of the balance sheet of Vanguard or any Restricted Subsidiary;

(14)  the incurrence by Vanguard or any of its Restricted Subsidiaries of liability in respect of Indebtedness of any Unrestricted Subsidiary of Vanguard or any Joint Venture but only to the extent that such liability is the result of Vanguard’s or any such Restricted Subsidiary’s being a general partner or member of, or owner of an Equity Interest in, such Unrestricted Subsidiary or Joint Venture and not as guarantor of such Indebtedness and provided that after giving effect to any such incurrence, the aggregate principal amount of all Indebtedness incurred under this clause (14) and then outstanding does not exceed $25.0 million;

(15)  the incurrence by Vanguard or its Restricted Subsidiaries of Permitted Acquisition Indebtedness; and

(16)  the incurrence by Vanguard or any of its Restricted Subsidiaries of additional Indebtedness or the issuance by Vanguard of any Disqualified Stock in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred or Disqualified Stock issued pursuant to this clause (16), not to exceed the greater of (i) $50.0 million and (ii) 5% of Vanguard’s Adjusted Consolidated Net Tangible Assets determined on the date of such incurrence or issuance.

Vanguard will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of Vanguard or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes or the applicable Note Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of Vanguard or any Guarantor solely by virtue of being unsecured or by virtue of being secured on a junior priority basis.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (16) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, Vanguard will be permitted to divide, classify and reclassify such item of Indebtedness on the date of its incurrence, or later redivide or reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. Indebtedness under Credit Facilities outstanding on the date on which notes are first issued and authenticated under the indenture will initially be deemed to

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have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest or Preferred Stock dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness not secured by a Lien in the form of additional Indebtedness with the same terms, the reclassification of Preferred Stock as Indebtedness due to a change in accounting principles, and the payment of dividends on Preferred Stock or Disqualified Stock in the form of additional securities of the same class of Preferred Stock or Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Preferred Stock or Disqualified Stock for purposes of this covenant; provided that the amount thereof is included in Fixed Charges of Vanguard as accrued to the extent required by the definition of such term.

The amount of any Indebtedness outstanding as of any date will be:

(1)  the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

(2)  the principal amount of the Indebtedness, in the case of any other Indebtedness; and

(3)  in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:

(a)  the Fair Market Value of such assets at the date of determination; and

(b)  the amount of the Indebtedness of the other Person.

Liens

Vanguard will not and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness upon any of their property or assets, now owned or hereafter acquired, unless the notes or any Note Guarantee of such Restricted Subsidiary, as applicable, is secured on an equal and ratable basis with the Indebtedness so secured until such time as such Indebtedness is no longer secured by a Lien.

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

Vanguard will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1)  pay dividends or make any other distributions on its Capital Stock to Vanguard or any of its Restricted Subsidiaries, or pay any indebtedness owed to Vanguard or any of its Restricted Subsidiaries; provided that the priority that any series of Preferred Stock of a Restricted Subsidiary has in receiving dividends or liquidating distributions before dividends or liquidating distributions are paid in respect of common stock of such Restricted Subsidiary shall not constitute a restriction on the ability to make dividends or distributions on Capital Stock for purposes of this covenant;

(2)  make loans or advances to Vanguard or any of its Restricted Subsidiaries (it being understood that the subordination of loans or advances made to Vanguard or any Restricted Subsidiary to other Indebtedness incurred by Vanguard or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3)  sell, lease or transfer any of its properties or assets to Vanguard or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1)  agreements governing Existing Indebtedness and Credit Facilities as in effect on the date of the indenture and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture;

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(2)  the indenture, the notes and the Note Guarantees;

(3)  agreements governing other Indebtedness permitted to be incurred under the provisions of the covenant described above under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the restrictions therein are not materially more restrictive, taken as a whole, than those contained in the indenture, the notes and the Note Guarantees or the Credit Agreement as in effect on the date of the indenture;

(4)  applicable law, rule, regulation, order, approval, license, permit or similar restriction;

(5)  any instrument governing Indebtedness or Capital Stock of a Person acquired by Vanguard or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(6)  customary non-assignment provisions in Hydrocarbon purchase and sale or exchange agreements or similar operational agreements or in licenses, easements or leases, in each case, entered into in the ordinary course of business;

(7)  purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;

(8)  any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(9)  Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

(10)  Liens permitted to be incurred under the provisions of the covenant described above under the caption “— Certain Covenants — Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(11)  provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements (including agreements entered into in connection with a Restricted Investment) entered into with the approval of Vanguard’s Board of Directors, which limitation is applicable only to the assets or property that is the subject of such agreements;

(12)  any agreement or instrument relating to any property or assets acquired after the date of the indenture, so long as such encumbrance or restriction relates only to the property or assets so acquired and is not and was not created in anticipation of such acquisition;

(13)  encumbrances or restrictions on cash, Cash Equivalents or other deposits or net worth imposed by customers or lessors under contracts or leases entered into in the ordinary course of business;

(14)  the issuance of Preferred Stock by a Restricted Subsidiary of Vanguard or the payment of dividends thereon in accordance with the terms thereof; provided that issuance of such Preferred Stock is permitted pursuant to the covenant described above under the caption “— Certain Covenants —  Incurrence of Indebtedness and Issuance of Preferred Stock” and the terms of such Preferred Stock do not expressly restrict the ability of a Restricted Subsidiary of Vanguard to pay dividends or make any other distributions on its Equity Interests (other than requirements to pay dividends or liquidation preferences on such Preferred Stock prior to paying any dividends or making any other distributions on such other Equity Interests);

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(15)  in the case of any Foreign Subsidiary, any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was incurred if either (a) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (b) Vanguard determines that any such encumbrance of restriction will not materially affect Vanguard’s ability to make principal or interest payments on the notes, as determined in good faith by the Board of Directors of Vanguard, whose determination shall be conclusive; or

(16)  any Permitted Investment.

Merger, Consolidation or Sale of Assets

Neither of the Issuers may, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not such Issuer is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:

(1)  either: (a) such Issuer is the surviving Person; or (b) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made is a Person organized or existing under the laws of the United States, any state of the United States or the District of Columbia; provided, however, that Finance Corp. may not consolidate or merge with or into any Person other than a corporation satisfying such requirement so long as Vanguard is not a corporation;

(2)  the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or the Person to which such sale, assignment, transfer, conveyance, lease or other disposition has been made assumes all the obligations of such Issuer under the notes and the indenture pursuant to a supplemental indenture in a form reasonably satisfactory to the trustee;

(3)  immediately after such transaction, no Default or Event of Default exists;

(4)  in the case of a transaction involving Vanguard and not Finance Corp., either (a) immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, either (i) Vanguard or the Person formed by or surviving any such consolidation or merger (if other than Vanguard), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “— Certain Covenants —  Incurrence of Indebtedness and Issuance of Preferred Stock” or (ii) the Fixed Charge Coverage Ratio of Vanguard or the Person formed by or surviving any such consolidation or merger (if other than Vanguard), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, is equal to or greater than the Fixed Charge Coverage Ratio of Vanguard immediately prior to such transaction; or (b) immediately after giving effect to such transaction on a pro forma basis, the Consolidated Net Worth of Vanguard would be greater than the Consolidated Net Worth of Vanguard immediately prior to such transaction; and

(5)  such Issuer has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture, if any, comply with the indenture.

Notwithstanding the restrictions described in the foregoing clause (4), any Restricted Subsidiary of Vanguard (other than Finance Corp.) may consolidate with, merge into or dispose of all or part of its properties or assets to Vanguard, and Vanguard will not be required to comply with the preceding clause (5) in connection with any such consolidation, merger or disposition.

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Notwithstanding the second preceding paragraph, Vanguard may reorganize as any other form of entity in accordance with the following procedures provided that:

(1)  the reorganization involves the conversion (by merger, sale, contribution or exchange of assets or otherwise) of Vanguard into a form of entity other than a limited liability company formed under Delaware law;

(2)  the entity so formed by or resulting from such reorganization is an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia;

(3)  the entity so formed by or resulting from such reorganization assumes all the obligations of Vanguard under the notes and the indenture pursuant to a supplemental indenture in a form reasonably satisfactory to the trustee;

(4)  immediately after such reorganization no Default (other than a Reporting Default) or Event of Default exists; and

(5)  such reorganization is not materially adverse to the holders or Beneficial Owners of the notes (for purposes of this clause (5) a reorganization will not be considered materially adverse to the holders or Beneficial Owners of the notes solely because the successor or survivor of such reorganization (a) is subject to federal or state income taxation as an entity or (b) is considered to be an “includible corporation” of an affiliated group of corporations within the meaning of Section 1504(b) of the Code or any similar state or local law).

For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the properties or assets of one or more Restricted Subsidiaries of Vanguard, the Capital Stock of which constitutes all or substantially all of the properties or assets of Vanguard, shall be deemed to be the transfer of all or substantially all of the properties or assets of Vanguard.

Upon any consolidation or merger or any sale, assignment, transfer, conveyance, lease or other disposition of all or substantially all of the properties or assets of an Issuer in accordance with the foregoing in which such Issuer is not the surviving entity, the surviving Person formed by such consolidation or into or with which such Issuer is merged or to which such sale, assignment, transfer, conveyance, lease or other disposition is made shall succeed to, and be substituted for, and may exercise every right and power of, such Issuer under the indenture with the same effect as if such surviving Person had been named as such Issuer in the indenture, and thereafter (except in the case of a lease of all or substantially all of such Issuer’s properties or assets), such Issuer will be relieved of all obligations and covenants under the indenture and the notes.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

Transactions with Affiliates

Vanguard will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of Vanguard (each, an “Affiliate Transaction”), unless:

(1)  the Affiliate Transaction is on terms that are no less favorable to Vanguard or the relevant Restricted Subsidiary than those that could have been obtained in a comparable transaction by Vanguard or such Restricted Subsidiary with an unrelated Person or, if in the good faith judgment of the Vanguard’s Board of Directors, no comparable transaction is available with which to compare such Affiliate Transaction, such Affiliate Transaction is otherwise fair to Vanguard or the relevant Restricted Subsidiary from a financial point of view; and

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(2)  Vanguard delivers to the trustee:

(a)  with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $20.0 million, an officers’ certificate certifying that such Affiliate Transaction or series of related Affiliate Transactions complies with this covenant; and

(b)  with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $40.0 million, a resolution of the Board of Directors of Vanguard set forth in an officers’ certificate certifying that such Affiliate Transaction or series of related Affiliate Transactions complies with this covenant and that such Affiliate Transaction or series of related Affiliate Transactions has been approved by either the Conflicts Committee of the Board of Directors of Vanguard (so long as the members of the Conflicts Committee approving the Affiliate Transaction or series of related Affiliate Transactions are disinterested) or a majority of the disinterested members of the Board of Directors of Vanguard, if any.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1)  any employment agreement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by Vanguard or any of its Restricted Subsidiaries in the ordinary course of business and payments pursuant thereto;

(2)  transactions between or among Vanguard and/or its Restricted Subsidiaries;

(3)  transactions with a Person (other than an Unrestricted Subsidiary of Vanguard) that is an Affiliate of Vanguard solely because Vanguard owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

(4)  payment of reasonable and customary fees and reimbursements of expenses (pursuant to indemnity arrangements or otherwise) of officers, directors, employees or consultants of Vanguard or any of its Restricted Subsidiaries;

(5)  any issuance of Equity Interests (other than Disqualified Stock) of Vanguard to Affiliates of Vanguard;

(6)  any Permitted Investments or Restricted Payments that are permitted by the provisions of the indenture described above under the caption “— Certain Covenants — Restricted Payments”;

(7)  transactions between Vanguard or any of its Restricted Subsidiaries and any Person that would not otherwise constitute an Affiliate Transaction except for the fact that one director of such other Person is also a director of Vanguard or such Restricted Subsidiary, as applicable; provided that such director abstains from voting as a director of Vanguard or such Restricted Subsidiary, as applicable, on any matter involving such other Person;

(8)  any transaction in which Vanguard or any of its Restricted Subsidiaries, as the case may be, delivers to the trustee a letter from an accounting, appraisal, advisory or investment banking firm of national standing stating that such transaction is fair to Vanguard or such Restricted Subsidiary from a financial point of view or that such transaction meets the requirements of clause (1) of the preceding paragraph;

(9)  (a) guarantees by Vanguard or any of its Restricted Subsidiaries of performance of obligations of Vanguard’s Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Indebtedness in respect of borrowed money, and (b) pledges by Vanguard or any Restricted Subsidiary of Vanguard of Equity Interests in Unrestricted Subsidiaries for the benefit of lenders or other creditors of Vanguard’s Unrestricted Subsidiaries;

(10)  any Affiliate Transaction with a Person in its capacity as a holder of Indebtedness or Capital Stock of Vanguard or any Restricted Subsidiary of Vanguard if such Person is treated no more favorably than the other holders of Indebtedness or Capital Stock of Vanguard or such Restricted Subsidiary;

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(11)  transactions with Unrestricted Subsidiaries, customers, clients, suppliers or purchasers or sellers of goods or services, or lessors or lessees of property, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture which are, in the aggregate (taking into account all the costs and benefits associated with such transactions), not materially less favorable to Vanguard and its Restricted Subsidiaries than those that would have been obtained in a comparable transaction by Vanguard or such Restricted Subsidiary with an unrelated person, in the good faith determination of Vanguard’s Board of Directors or any officer of Vanguard involved in or otherwise familiar with such transaction, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party; and

(12)  in the case of contracts for exploring for, producing, marketing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, or other operational contracts, any such contracts entered into in the ordinary course of business and otherwise in compliance with the terms of the indenture which are fair to Vanguard and its Restricted Subsidiaries, in the reasonable determination of the Board of Directors of Vanguard or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party.

Limitations on Finance Corp. Activities

Finance Corp. may not incur Indebtedness unless (1) Vanguard is a co-issuer or guarantor of such Indebtedness or (2) the net proceeds of such Indebtedness are loaned to Vanguard or its other Restricted Subsidiaries, used to acquire outstanding debt securities issued by Vanguard or used to repay Indebtedness of Vanguard or its other Restricted Subsidiaries as permitted under the covenant described above under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” Finance Corp. may not engage in any business not related directly or indirectly to obtaining money or arranging financing for Vanguard or its Restricted Subsidiaries.

Additional Note Guarantees

If, after the date of the indenture, any Restricted Subsidiary of Vanguard that is not already a Guarantor guarantees any other Indebtedness of either of the Issuers or any Guarantor in excess of the De Minimis Guaranteed Amount, or any Domestic Subsidiary, if not then a Guarantor, incurs any Indebtedness under any Credit Facility, then in either case that Subsidiary will become a Guarantor by executing a supplemental indenture and delivering it to the trustee within 20 business days of the date on which it guaranteed or incurred such Indebtedness, as the case may be; provided, however, that the preceding shall not apply to Subsidiaries of Vanguard that have properly been designated as Unrestricted Subsidiaries in accordance with the indenture for so long as they continue to constitute Unrestricted Subsidiaries. Notwithstanding the preceding, any Note Guarantee of a Restricted Subsidiary that was incurred pursuant to this paragraph shall provide by its terms that it shall be automatically and unconditionally released at such time as such Guarantor ceases both (a) to guarantee any other Indebtedness of either of the Issuers and any Indebtedness of any other Guarantor (except as a result of payment under any such other guarantee) and (b) to be an obligor with respect to any Indebtedness under any Credit Facility.

Designation of Restricted and Unrestricted Subsidiaries

At the time the notes are originally issued, all of the Subsidiaries of Vanguard will be Restricted Subsidiaries.

The Board of Directors of Vanguard may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by Vanguard and its Restricted Subsidiaries in the Subsidiary designated as Unrestricted will be deemed to be either an Investment made as of the time of the designation that will reduce the amount available for Restricted Payments under the covenant described above under the caption “— Certain Covenants —  Restricted Payments” or represent a Permitted Investment under one or more clauses of the definition of Permitted Investments, as determined by Vanguard. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

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Any designation of a Subsidiary of Vanguard as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “— Certain Covenants — Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of Vanguard as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,” Vanguard will be in default of such covenant.

The Board of Directors of Vanguard may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of Vanguard; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of Vanguard of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the applicable reference period; and (2) no Default or Event of Default would be in existence following such designation.

Reports

Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, Vanguard will furnish to the holders of notes or cause the trustee to furnish to the holders of notes (or file with the SEC for public availability), within the time periods specified in the SEC’s rules and regulations applicable to an accelerated filer:

(1)  all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if Vanguard were required to file such reports, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual report only, a report on Vanguard’s consolidated financial statements by Vanguard’s certified independent accountants; and

(2)  all current reports that would be required to be filed with the SEC on Form 8-K if Vanguard were required to file such reports.

The availability of the foregoing reports on the SEC’s EDGAR filing system will be deemed to satisfy the foregoing delivery requirements.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports.

If, notwithstanding the foregoing, the SEC will not accept Vanguard’s filings for any reason, Vanguard will post the reports referred to in the preceding paragraphs on its website within the time periods applicable to an accelerated filer that would apply if Vanguard were required to file those reports with the SEC.

If Vanguard has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraphs will include, to the extent material, a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of Vanguard and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of Vanguard.

Any and all Defaults or Events of Default arising from a failure to furnish or file in a timely manner a report or certification required by this covenant shall be deemed cured (and Vanguard shall be deemed to be in compliance with this covenant) upon furnishing or filing such report or certification as contemplated by this covenant (but without regard to the date on which such report or certification is so furnished or filed); provided that such cure shall not otherwise affect the rights of the holders under “— Events of Defaults and

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Remedies” if the principal, premium, if any, and interest have been accelerated in accordance with the terms of the Indenture and such acceleration has not been rescinded or cancelled prior to such cure.

Events of Default and Remedies

Each of the following is an “Event of Default”:

(1)  default for 30 days in the payment when due of interest on the notes;

(2)  default in the payment when due (at Stated Maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;

(3)  failure by the Issuers to comply with the provisions described under the captions “— Repurchase at the Option of Holders — Change of Control,” “— Repurchase at the Option of Holders — Asset Sales” or “— Certain Covenants — Merger, Consolidation or Sale of Assets”;

(4)  failure by Vanguard for 180 days after notice from the trustee or holders of at least 25% in aggregate principal amount of the notes then outstanding to comply with the provisions described under “— Certain Covenants — Reports”;

(5)  failure by the Issuers for 60 days after notice to Vanguard by the trustee or the holders of at least 25% in aggregate principal amount of the notes then outstanding to comply with any of their other agreements in the indenture;

(6)  default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by Vanguard or any of its Restricted Subsidiaries (or the payment of which is guaranteed by Vanguard or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the date of the indenture, if that default:

(a)  is caused by a failure to pay principal of, premium on, if any, or interest, if any, on, such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

(b)  results in the acceleration of such Indebtedness prior to its express maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $15.0 million or more; provided, however, if, prior to any acceleration of the notes, (i) any such Payment Default is cured or waived, (ii) any such acceleration is rescinded, or (iii) such Indebtedness is repaid during the 60 day period commencing upon the end of any applicable grace period for such Payment Default or the occurrence of such acceleration, as the case may be, any Default or Event of Default (but not any acceleration of the notes) caused by such Payment Default or acceleration shall be automatically rescinded, so long as such rescission does not conflict with any judgment, decree or applicable law;

(7)  failure by Vanguard or any of its Restricted Subsidiaries to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $15.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid, discharged or stayed, for a period of 60 days;

(8)  except as permitted by the indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee, except, in each case, by reason of the release of such Note Guarantee in accordance with the indenture; and

(9)  certain events of bankruptcy or insolvency described in the indenture with respect to Finance Corp., Vanguard or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of its Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

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In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to Vanguard, any Restricted Subsidiary of Vanguard that is a Significant Subsidiary or any group of Restricted Subsidiaries of Vanguard that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all the notes to be due and payable immediately.

Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or premium or interest, if any, on, the notes.

The holders of a majority in aggregate principal amount of the then outstanding notes by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture, if the rescission would not conflict with any judgment or decree, except a continuing Default or Event of Default in the payment of principal of, or premium or interest, if any, on, the notes.

The Issuers are required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon any officer of Vanguard or Finance Corp. becoming aware of any Default or Event of Default, the Issuers are required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Unitholders

No past, present or future director, officer, partner, employee, incorporator, manager, unitholder or other owner of the Capital Stock of the Issuers or any Guarantor, as such, will have any liability for any obligations of the Issuers or the Guarantors under the notes, the indenture or the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

The Issuers may at any time, at the option of their respective Boards of Directors evidenced by a resolution set forth in an officers’ certificate, elect to have all of their obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees (“Legal Defeasance”) except for:

(1)  the rights of holders of outstanding notes to receive payments in respect of the principal of, or premium or interest, if any, on, such notes when such payments are due from the trust referred to below;

(2)  the Issuers’ obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3)  the rights, powers, trusts, duties and immunities of the trustee under the indenture, and the Issuers’ and the Guarantors’ obligations in connection therewith; and

(4)  the Legal Defeasance provisions of the indenture.

In addition, the Issuers may, at their option and at any time, elect to have their obligations and the obligations of the Guarantors released with respect to certain covenants (including Vanguard’s obligation to make Change of Control Offers and Asset Sale Offers) that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, all Events of Default described under “— Events of Default and Remedies” (except those relating to payments on the notes or bankruptcy or insolvency events) will no longer constitute an Event of Default with respect to the notes.

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In order to exercise either Legal Defeasance or Covenant Defeasance:

(1)  the Issuers must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, and premium and interest, if any, on, the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and the Issuers must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;

(2)  in the case of Legal Defeasance, the Issuers must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that

(a)  the Issuers have received from, or there has been published by, the Internal Revenue Service a ruling or

(b)  since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3)  in the case of Covenant Defeasance, the Issuers must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4)  no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit (and any similar concurrent deposit relating to other Indebtedness), and the granting of Liens to secure such borrowings);

(5)  such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture and the agreements governing any other Indebtedness being defeased, discharged or replaced) to which Vanguard or any of its Subsidiaries is a party or by which Vanguard or any of its Subsidiaries is bound;

(6)  the Issuers must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Issuers with the intent of preferring the holders of notes over the other creditors of the Issuers with the intent of defeating, hindering, delaying or defrauding any creditors of the Issuers or others; and

(7)  the Issuers must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the indenture, the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a tender offer or exchange offer for, or purchase of, the notes), and any existing Default or Event of Default (other than a Default or Event of Default in the payment of the principal of, or premium or interest, if any, on, the notes, except a payment default resulting from an acceleration that has been rescinded) or compliance with any provision of the indenture, the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation,

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additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1)  reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2)  reduce the principal of or change the fixed maturity of any note or alter or waive any of the provisions with respect to the redemption or repurchase of the notes (except those provisions relating to the covenants described above under the caption “— Repurchase at the Option of Holders”);

(3)  reduce the rate of or change the time for payment of interest, including default interest, on any note;

(4)  waive a Default or Event of Default in the payment of principal of, or premium or interest, if any, on, the notes (except a rescission of acceleration of the notes by the holders of a majority in aggregate principal amount of the then outstanding notes and a waiver of the payment default that resulted from such acceleration);

(5)  make any note payable in money other than that stated in the notes;

(6)  make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or premium or interest, if any, on, the notes (other than as permitted by clause (7) below);

(7)  waive a redemption or repurchase payment with respect to any note (other than a payment required by one of the covenants described above under the caption “— Repurchase at the Option of Holders”);

(8)  release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9)  make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

(1)  to cure any ambiguity, defect or inconsistency;

(2)  to provide for uncertificated notes in addition to or in place of certificated notes;

(3)  to provide for the assumption of the Issuers’ or a Guarantor’s obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of the Issuers’ or such Guarantor’s properties or assets, as applicable;

(4)  to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any holder;

(5)  to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(6)  to conform the text of the indenture, the notes or the Note Guarantees to any provision of this “Description of Notes”;

(7)  to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture as of the date of the indenture;

(8)  to secure the notes or the Note Guarantees pursuant to the requirements of the covenant described above under the subheading “— Certain Covenants — Liens”;

(9)  to add any additional Guarantor or to evidence the release of any Guarantor from its Note Guarantee, in each case as provided in the indenture; or

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(10)  to evidence or provide for the acceptance of appointment under the indenture of a successor trustee.

(11)  The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment, supplement or waiver. It is sufficient if such consent approves the substance of the proposed amendment, supplement or waiver. After an amendment, supplement or waiver under the indenture requiring the approval of the holders becomes effective, Vanguard will mail to the holders a notice briefly describing the amendment, supplement or waiver. However, the failure to give such notice, or any defect in the notice, will not impair or affect the validity of the amendment, supplement or waiver.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the indenture), when:

(1)  either:

(a)  all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Issuers, have been delivered to the trustee for cancellation; or

(b)  all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and either an Issuer or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the notes not delivered to the trustee for cancellation for principal of, or premium or interest, if any, on, the notes to the date of Stated Maturity or redemption;

(2)  in respect of clause (1)(b), no Event of Default has occurred and is continuing on the date of the deposit (other than an Event of Default resulting from the borrowing of funds to be applied to such deposit and any similar deposit relating to other Indebtedness and, in each case, the granting of Liens to secure such borrowings) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which either Issuer or any Guarantor is a party or by which either Issuer or any Guarantor is bound (other than with respect to the borrowing of funds to be applied concurrently to make the deposit required to effect such satisfaction and discharge and any similar concurrent deposit relating to other Indebtedness, and in each case the granting of Liens to secure such borrowings);

(3)  the Issuers have paid or caused to be paid all other sums payable by the Issuers under the indenture; and

(4)  the Issuers have delivered irrevocable instructions to the trustee to apply the deposited money toward the payment of the notes at Stated Maturity or on the redemption date, as the case may be.

In addition, the Issuers must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

U.S. Bank National Association will be the trustee under the indenture. Such bank is a lender under our Credit Agreement.

If the trustee becomes a creditor of the Issuers or any Guarantor, the indenture will limit the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.

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The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. In case an Event of Default has occurred and is continuing, the trustee will be required, in the exercise of its powers, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee reasonable indemnity or security satisfactory to it against any loss, liability or expense.

Governing Law

The indenture, the notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Additional Information

Anyone who receives this prospectus supplement may obtain a copy of each of the base indenture and the supplemental indenture without charge by writing to Vanguard Natural Resources 5847 San Felipe, Suite 3000, Houston, Texas 77057, Attention: Chief Financial Officer.

Book-Entry, Delivery and Form

The notes will initially be issued in registered, global form without interest coupons (the “Global Notes”) in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. Notes will be issued at the closing of this offering only against payment in immediately available funds. The Global Notes will be deposited upon issuance with the trustee as custodian for DTC, and registered in the name of DTC or its nominee, for credit to an account of a direct or indirect participant in DTC as described below.

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Only in the limited circumstances described below may beneficial interests in the Global Notes be exchanged for definitive notes in registered certificated form (“Certificated Notes”) in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. See “— Exchange of Global Notes for Certificated Notes.” Notes will be issued at the closing of this offering only against payment in immediately available funds.

Transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”)), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. The Issuers take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised the Issuers that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

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DTC has also advised the Issuers that, pursuant to procedures established by it:

(1)  upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2)  ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).

All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some jurisdictions may require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of Certificated Notes and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, or premium or interest, if any, on, a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, the Issuers, the Guarantors and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Issuers, the Guarantors, the trustee nor any agent of the Issuers, the Guarantors or the trustee has or will have any responsibility or liability for:

(1)  any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or

(2)  any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised the Issuers that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee, the Issuers or the Guarantors. Neither the Issuers, the Guarantors nor the trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and the Issuers, the Guarantors and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

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Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised the Issuers that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for Certificated Notes, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. None of the Issuers, the Guarantors, the trustee or any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1)  DTC (a) notifies the Issuers that it is unwilling or unable to continue as depositary for the Global Note or (b) has ceased to be a clearing agency registered under the Exchange Act and, in either case, the Issuers fail to appoint a successor depositary within 90 days;

(2)  the Issuers, at their option but subject to DTC’s requirements, notify the trustee in writing that they elect to cause the issuance of the Certificated Notes; or

(3)  there has occurred and is continuing an Event of Default, and DTC notifies the trustee of its decision to exchange such Global Note for Certificated Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of DTC (in accordance with its customary procedures).

Neither the Issuers nor the trustee will be liable for any delay by DTC, its nominee or any Participant or Indirect Participant in identifying the beneficial owners of interests in Global Notes, and the Issuers and the trustee may conclusively rely on, and will be protected in relying on, instructions from DTC or its nominee for all purposes, including with respect to the registration and delivery, and the respective principal amounts, of the Certificated Notes to be issued.

Same Day Settlement and Payment

The Issuers will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, and interest, if any) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. The Issuers will make all payments of principal, premium, if any, and interest, if any, with respect to Certificated Notes in the manner described above under “— Methods of Receiving Payments on the Notes.” The notes represented by the Global Notes are expected to be eligible to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in

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such notes will, therefore, be required by DTC to be settled in immediately available funds. The Issuers expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised the Issuers that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Certain Definitions

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

“Acquired Debt” means, with respect to any specified Person:

(1)  Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

(2)  Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Additional Assets” means:

(1)  any assets used or useful in the Oil and Gas Business, other than Indebtedness or Capital Stock;

(2)  the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by Vanguard or any of its Restricted Subsidiaries; or

(3)  Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” means (without duplication), as of the date of determination,

(1)  the sum of:

(a)  the discounted future net revenues from proved oil and natural gas reserves of Vanguard and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of Vanguard’s most recently completed fiscal year, as increased by, as of the date of determination, the estimated discounted future net revenues from:

(i)  estimated proved oil and natural gas reserves of Vanguard and its Restricted Subsidiaries acquired since the date of such year-end reserve report, and

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(ii)  estimated proved oil and natural gas reserves of Vanguard and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior period end) since the date of such year-end reserve report due to exploration, development or exploitation, production or other activities which would, in accordance with standard industry practice, cause such revisions,

anddecreased by, as of the date of determination, the estimated discounted future net revenue attributable to:

(iii)  estimated proved oil and natural gas reserves of Vanguard and its Restricted Subsidiaries reflected in such reserve report produced or disposed of since the date of such year-end reserve report, and

(iv)  reductions in estimated proved oil and natural gas reserves of Vanguard and its Restricted Subsidiaries reflected in such reserve report attributable to downward revisions of estimates of proved oil and natural gas reserves since such year-end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis;

in the case of the preceding clauses (i) through (iv), calculated in accordance with SEC guidelines (utilizing the prices utilized in Vanguard’s year-end reserve report) and estimated by Vanguard’s petroleum engineers or any independent petroleum engineers engaged by Vanguard for that purpose;

(b)  the capitalized costs that are attributable to oil and natural gas properties of Vanguard and its Restricted Subsidiaries to which no proved oil and natural gas reserves are attributable, based on Vanguard’s books and records as of a date no earlier than the last day of Vanguard’s most recent quarterly or annual period for which internal financial statements are available;

(c)  the Consolidated Net Working Capital of Vanguard and its Restricted Subsidiaries as of a date no earlier than the last day of Vanguard’s most recent quarterly or annual period for which internal financial statements are available; and

(d)  the greater of:

(i)  the net book value and

(ii)  the appraised value, as estimated by independent appraisers, of other tangible assets (including Investments in unconsolidated Subsidiaries)

in each case, of Vanguard and its Restricted Subsidiaries as of a date no earlier than the last day of the date of Vanguard’s most recent quarterly or annual period for which internal financial statements are available; provided that if no such appraisal has been performed, Vanguard shall not be required to obtain such an appraisal and only clause (d)(i) of this definition shall apply,

minus, to the extent not otherwise taken into account in the immediately preceding clause (a),

(2)  the sum of

(a)  minority interests,

(b)  any net natural gas balancing liabilities of Vanguard and its Restricted Subsidiaries as of the last day of Vanguard’s most recent annual or quarterly period for which internal financial statements are available;

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(c)  to the extent included in clause (1)(a) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in Vanguard’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of Vanguard and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto, and

(d)  the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in clause (1)(a) above, would be necessary to fully satisfy the payment obligations of Vanguard and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Applicable Premium” means, with respect to any note on any redemption date, the greater of:

(1)  1.0% of the principal amount of the note; or

(2)  the excess of:

(a)  the present value at such redemption date of (i) the redemption price of the note at     , 2016 (such redemption price being set forth in the table appearing above under the caption “— Optional Redemption”) plus (ii) all required interest payments due on the note through     , 2016 (excluding accrued but unpaid interest to, the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over

(b)  the principal amount of the note.

“Asset Sale” means:

(1)  the sale, lease, conveyance or other disposition of any assets or rights by Vanguard or any of Vanguard’s Restricted Subsidiaries; provided that the sale, lease, conveyance or other disposition of all or substantially all of the properties or assets of Vanguard and its Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “— Repurchase at the Option of Holders — Change of Control” and/or the provisions described above under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sales covenant; and

(2)  the issuance of Equity Interests by any of Vanguard’s Restricted Subsidiaries or the sale by Vanguard or any of Vanguard’s Restricted Subsidiaries of Equity Interests in any of Vanguard’s Subsidiaries (in either case other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than Vanguard or a Restricted Subsidiary).

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1)  any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $10.0 million;

(2)  a transfer of assets between or among Vanguard and its Restricted Subsidiaries;

(3)  an issuance or sale of Equity Interests by a Restricted Subsidiary of Vanguard to Vanguard or to a Restricted Subsidiary of Vanguard;

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(4)  the sale, lease or other disposition of products, services or accounts receivable in the ordinary course of business and any sale or other disposition of damaged, worn-out or obsolete assets in the ordinary course of business (including the abandonment or other disposition of intellectual property that is, in the reasonable judgment of Vanguard, no longer economically practicable to maintain or useful in the conduct of the business of Vanguard and its Restricted Subsidiaries taken as whole);

(5)  the farm-out, lease or sublease of developed or undeveloped oil or natural gas properties owned or held by Vanguard or any of its Restricted Subsidiaries in the ordinary course of business;

(6)  licenses and sublicenses by Vanguard or any of its Restricted Subsidiaries of software or intellectual property in the ordinary course of business;

(7)  any surrender or waiver of contract rights or settlement, release, recovery on or surrender of contract, tort or other claims in the ordinary course of business;

(8)  the granting of Liens not prohibited by the covenant described above under the caption “— Certain Covenants — Liens” and dispositions in connection with Permitted Liens;

(9)  the sale or other disposition of cash or Cash Equivalents or other financial instruments (other than Oil and Gas Hedging Contracts);

(10)  a disposition of assets that constitutes (or results in by virtue of the consideration received for such disposition) either a Restricted Payment that does not violate the covenant described above under the caption “— Certain Covenants — Restricted Payments” or a Permitted Investment;

(11)  a sale or other disposition of Hydrocarbons or other mineral products in the ordinary course of business;

(12)  an Asset Swap;

(13)  dispositions of crude oil and natural gas properties, provided that at the time of any such disposition such properties do not have associated with them any proved reserves; and

(14)  any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to Vanguard or a Restricted Subsidiary, shall have been created, incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto.

“Asset Swap” means any substantially contemporaneous (and in any event occurring within 180 days of each other) purchase and sale or exchange of any assets or properties used or useful in the Oil and Gas Business between Vanguard or any of its Restricted Subsidiaries and another Person; provided, that the Fair Market Value of the properties or assets traded or exchanged by Vanguard or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the Fair Market Value of the properties or assets (together with any cash) to be received by Vanguard or such Restricted Subsidiary, and provided further, that any net cash received must be applied in accordance with the provisions described above under the caption “— Repurchase at the Option of Holders — Asset Sales” if then in effect.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided, however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Available Cash” has the meaning assigned to such term in the Limited Liability Company Agreement, as in effect on the date of the indenture.

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“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning. For purposes of this definition, a Person shall be deemed not to Beneficially Own securities that are the subject of a stock purchase agreement, merger agreement, amalgamation agreement, arrangement agreement or similar agreement until consummation of the transactions or, as applicable, series of related transactions contemplated thereby.

“Board of Directors” means:

(1)  with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2)  with respect to a partnership, the Board of Directors of the general partner of the partnership;

(3)  with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

(4)  with respect to any other Person, the board or committee of such Person serving a similar function.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty. Notwithstanding the foregoing, any lease (whether entered into before or after the date of the indenture) that would have been classified as an operating lease pursuant to GAAP as in effect on the date of the indenture will be deemed not to represent a Capital Lease Obligation.

“Capital Stock” means:

(1)  in the case of a corporation, corporate stock;

(2)  in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3)  in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

(4)  any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.

“Cash Equivalents” means:

(1)  United States dollars;

(2)  securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than one year from the date of acquisition;

(3)  marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of “A” or better from either S&P or Moody’s;

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(4)  certificates of deposit, demand deposits and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $100.0 million or that is a lender under the Credit Agreement;

(5)  repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2), (3) and (4) above entered into with any financial institution meeting the qualifications specified in clause (4) above;

(6)  commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and, in each case, maturing within one year after the date of acquisition;

(7)  money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (6) of this definition; and

(8)  with respect to any Foreign Subsidiary of Vanguard, investments denominated in local currency that are similar to the items specified in clauses (1) through (7) above.

“Change of Control” means the occurrence of any of the following:

(1)  the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of Vanguard and its Subsidiaries taken as a whole to any Person (including any “person” (as that term is used in Section 13(d)(3) of the Exchange Act));

(2)  the adoption of a plan relating to the liquidation or dissolution of Vanguard;

(3)  the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” (as defined above) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of Vanguard, measured by voting power rather than number of shares, units or the like; or

(4)  the first day on which a majority of the members of the Board of Directors of Vanguard are not Continuing Directors.

Notwithstanding the preceding, a conversion of Vanguard or any of its Restricted Subsidiaries from a limited partnership, corporation, limited liability company or other form of entity to a limited liability company, corporation, limited partnership or other form of entity or an exchange of all of the outstanding Equity Interests in one form of entity for Equity Interests in another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of Vanguard immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock of such entity, or continue to Beneficially Own sufficient Equity Interests in such entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity or its general partner, as applicable, and, in either case no “person” Beneficially Owns more than 50% of the Voting Stock of such entity or its general partner, as applicable.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:

(1)  an amount equal to any extraordinary expenses or loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such expenses or losses were deducted in computing such Consolidated Net Income; plus

(2)  provision for taxes based on income or profits (including state franchise taxes accounted for as income taxes in accordance with GAAP) of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

(3)  the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus

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(4)  depreciation, depletion, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment, non-cash equity based compensation expense and other non-cash charges and expenses (excluding any such non-cash charge or expense to the extent that it represents an accrual of or reserve for cash charges or expenses in any future period or amortization of a prepaid cash charge or expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization, impairment and other non-cash charges or expenses were deducted in computing such Consolidated Net Income; plus

(5)  if such Person accounts for its oil and gas operations using successful efforts or a similar method of accounting, consolidated exploration expense of such Person and its Restricted Subsidiaries; minus

(6)  non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business; and minus

(7)  to the extent increasing such Consolidated Net Income for such period, the sum of (a) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments,

in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the net income (loss) of such Person and its Restricted Subsidiaries for such period, on a consolidated basis determined in accordance with GAAP and without any reduction in respect of Preferred Stock dividends; provided that:

(1)  the net income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included, but only to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2)  the net income of any Restricted Subsidiary of such Person will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members;

(3)  the cumulative effect of a change in accounting principles will be excluded;

(4)  any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of such Person or its consolidated Restricted Subsidiaries (including pursuant to any sale or leaseback transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person will be excluded;

(5)  to the extent deducted in the calculation of Consolidated Net Income, any non-cash or other charges relating to any premium or penalty paid, write off of deferred financing costs or other financial recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity will be excluded;

(6)  any “ceiling limitation” on Oil and Gas Properties or other asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines will be excluded; and

(7)  any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of FASB ASC Topic No. 815, Derivatives and Hedging).

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“Consolidated Net Working Capital” means (a) all current assets of Vanguard and its Restricted Subsidiaries except current assets from Oil and Gas Hedging Contracts, less (b) all current liabilities of Vanguard and its Restricted Subsidiaries, except (i) current liabilities included in Indebtedness, (ii) current liabilities associated with asset retirement obligations relating to oil and natural gas properties and (iii) any current liabilities from Oil and Gas Hedging Contracts, in each case as set forth in the consolidated financial statements of Vanguard prepared in accordance with GAAP (excluding any adjustments made pursuant to FASB ASC 815).

“Consolidated Net Worth” means, with respect to any specified Person as of any date, the sum of:

(1)  the consolidated equity of the common stockholders of, or the consolidated capital of the unitholders of, such Person and its consolidated Subsidiaries as of such date; plus

(2)  the respective amounts reported on such Person’s balance sheet as of such date with respect to any series of Preferred Stock (other than Disqualified Stock) that by its terms is not entitled to the payment of dividends unless such dividends may be declared and paid only out of net earnings in respect of the year of such declaration and payment, but only to the extent of any cash received by such Person upon issuance of such Preferred Stock.

“continuing” means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of Vanguard who:

(1)  was a member of such Board of Directors on the date of the indenture; or

(2)  was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.

“Credit Agreement” means that certain Third Amended and Restated Credit Agreement, dated as of September 30, 2011, by and among Vanguard Natural Gas, LLC, as borrower, Citibank N.A., as administrative agent, and certain financial institutions, as lenders, providing for up to $1.5 billion of revolving credit borrowings, including any related notes, Guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Credit Facilities” means one or more debt facilities (including, without limitation, the Credit Agreement), indentures or commercial paper facilities, in each case, with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, capital market financings, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables), letters of credit or other borrowings, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including refinancing with any capital markets transaction or otherwise by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Customary Recourse Exceptions” means, with respect to any Non-Recourse Debt of an Unrestricted Subsidiary, exclusions from the exculpation provisions with respect to such Non-Recourse Debt for the voluntary bankruptcy of such Unrestricted Subsidiary, fraud, misapplication of cash, environmental claims, waste, willful destruction and other circumstances customarily excluded by lenders from exculpation provisions or included in separate indemnification agreements in non-recourse financings.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“De Minimis Guaranteed Amount” means a principal amount of Indebtedness that does not exceed $5.0 million.

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“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require Vanguard to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if (x) the terms of such Capital Stock provide that Vanguard may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “— Certain Covenants — Restricted Payments,” or (y) the terms of such Capital Stock provide that Vanguard may not repurchase or redeem any such Capital Stock pursuant to such provisions prior to Vanguard’s purchase of the notes as is required to be purchased pursuant to the provisions of the indenture. The amount (or principal amount) of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that Vanguard and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of Vanguard that was formed under the laws of the United States or any state of the United States or the District of Columbia.

“Equity Interests” of any Person means (1) any and all Capital Stock of such Person and (2) all rights to purchase, warrants or options (whether or not currently exercisable), participations or other equivalents of or interests in (however designated) such Capital Stock of such Person, but excluding from all of the foregoing any debt securities convertible into Equity Interests, regardless of whether such debt securities include any right of participation with Equity Interests.

“Equity Offering” means a sale of Equity Interests of Vanguard (other than Disqualified Stock and other than to a Subsidiary of Vanguard) made for cash on a primary basis by Vanguard after the date of the indenture.

“Existing Indebtedness” means all Indebtedness of Vanguard and its Subsidiaries (other than Indebtedness under the Credit Agreement) in existence on the date of the indenture, until such amounts are repaid.

“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of Vanguard in the case of amounts of $25.0 million or more and otherwise by an officer of Vanguard (unless otherwise provided in the indenture).

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of Preferred Stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period. If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the Calculation Date had been the applicable rate for the entire period (taking into account any interest Hedging

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Obligation applicable to such Indebtedness, but if the remaining term of such interest Hedging Obligation is less than twelve months, then such interest Hedging Obligation shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of such Person, the interest rate shall be calculated by applying such option rate chosen by such Person. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or if none, then based upon such optional rate chosen as such Person may designate.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1)  acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers, consolidations or otherwise (including acquisitions of assets used or useful in the Oil and Gas Business), or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including all related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date, or that are to be made on the Calculation Date, will be given pro forma effect as if they had occurred on the first day of the four-quarter reference period, and the Consolidated Cash Flow for such reference period will be calculated giving pro forma effect to any expense and cost reductions or synergies that have occurred or are reasonably expected to occur, in the reasonable judgment Vanguard’s principal financial or accounting officer (regardless of whether those cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the Commission related thereto);

(2)  the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;

(3)  the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(4)  any Person that is a Restricted Subsidiary of the specified Person on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

(5)  any Person that is not a Restricted Subsidiary of the specified Person on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

(6)  interest income reasonably anticipated by such Person to be received during the applicable four-quarter period from cash or Cash Equivalents held by such Person or any Restricted Subsidiary of such Person, which cash or Cash Equivalents exist on the Calculation Date or will exist as a result of the transaction giving rise to the need to calculate the Fixed Charge Coverage Ratio, will be included.

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1)  the consolidated interest expense (less interest income) of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (excluding (i) any interest attributable to Dollar-Denominated Production Payments, (ii) write-off of deferred financing costs and (iii) accretion of interest charges on future plugging and abandonment obligations, future retirement benefits and other obligations that do not constitute Indebtedness, but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions,

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discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus

(2)  the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3)  any interest on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus

(4)  all dividends, whether paid or accrued and whether or not in cash, on any series of Disqualified Stock of such Person or any series of Preferred Stock of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of such Person (other than Disqualified Stock) or to such Person or a Restricted Subsidiary of such Person,

(5)  in each case, on a consolidated basis and determined in accordance with GAAP.

“Foreign Subsidiary” means any Restricted Subsidiary of Vanguard that is not a Domestic Subsidiary.

“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time.

“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise). When used as a verb, “Guarantee” has a correlative meaning.

“Guarantors” means any Subsidiary of Vanguard that Guarantees the Notes in accordance with the provisions of the indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under any (a) Interest Rate Agreement and (b) Oil and Gas Hedging Contract.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:

(1)  in respect of borrowed money;

(2)  evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3)  in respect of bankers’ acceptances;

(4)  representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

(5)  representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or

(6)  representing any Hedging Obligations,

if and to the extent any of the preceding items (other than letters of credit, Attributable Debt and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and,

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to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person (including, with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment, but excluding other contractual obligations of such Person with respect to such Production Payment). Subject to the preceding sentence, neither Dollar-Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1)  such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);

(2)  such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a “Joint Venture General Partner”); and

(3)  there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a)  the lesser of (i) the net assets of the Joint Venture General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b)  if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount and the related interest expense shall be included in Fixed Charges to the extent actually paid by such Person or its Restricted Subsidiaries.

“Interest Rate Agreement” means any interest rate swap agreement (whether from fixed to floating or from floating to fixed), interest rate cap agreement, interest rate collar agreement or other similar agreement or arrangement designed to protect Vanguard or any of its Restricted Subsidiaries against fluctuations in interest rates and is not for speculative purposes.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding (1) commission, travel and similar advances to officers and employees made in the ordinary course of business and (2) advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the lender), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities (excluding any interest in an oil or natural gas leasehold to the extent constituting a security under applicable law), together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If Vanguard or any Restricted Subsidiary of Vanguard sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of Vanguard such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of Vanguard, Vanguard will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of Vanguard’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” The acquisition by Vanguard or any Restricted Subsidiary of Vanguard of a Person that holds an Investment in a third Person will be deemed to be an Investment by Vanguard or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value or write-ups, write-downs or write-offs with respect to such Investment.

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“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement respecting a lease not intended as a security agreement.

“Limited Liability Company Agreement” means that certain Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC, dated as of October 29, 2007 as in effect on the date of the indenture.

“Moody’s” means Moody’s Investors Service, Inc. and any successor to the ratings business thereof.

“Net Proceeds” means the aggregate cash proceeds and Cash Equivalents received by Vanguard or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash or Cash Equivalents received upon the sale or other disposition of any non-cash consideration received in any Asset Sale but excluding any non-cash consideration deemed to be cash for purposes of the “Asset Sales” provisions of the indenture), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, and amounts required to be applied to the repayment of Indebtedness, other than revolving credit Indebtedness under a Credit Facility, secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment or indemnification obligations in respect of the sale price of such asset or assets established in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

(1)  as to which neither Vanguard nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise, except for Customary Recourse Exceptions; and

(2)  as to which the lenders have been notified in writing that they will not have any recourse to the Capital Stock or assets of Vanguard or any of its Restricted Subsidiaries (other than the Equity Interests of an Unrestricted Subsidiary), except for Customary Recourse Exceptions.

“Note Guarantee” means the Guarantee by each Guarantor of the Issuers’ obligations under the indenture and the notes, as provided in the indenture.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

“Oil and Gas Business” means (i) the acquisition, exploration, development, production, operation and disposition of interests in oil, gas and other Hydrocarbon properties, (ii) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from such interests or properties, (iii) any business relating to exploration for or development, production, treatment, processing (but not refining), storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith and (iv) any activity that is, in Vanguard’s reasonable judgment, ancillary, complementary or incidental to or necessary or appropriate for the activities described in clauses (i) through (iii) of this definition.

“Oil and Gas Hedging Contracts” means any puts, cap transactions, floor transactions, collar transactions, forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons to be used, produced, processed or sold by Vanguard or any of its Restricted Subsidiary that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbons prices and not for speculative purposes.

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“Oil and Gas Properties” means all properties, including equity or other ownership interest therein, owned by such Person or any of its Restricted Subsidiaries which contain or are believed to contain “proved oil and gas reserves” as defined in Rule 4-10 of Regulation S-X of the Securities Act.

“Permitted Acquisition Indebtedness” means Indebtedness or Disqualified Stock of Vanguard or any of its Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock of any other Person existing at the time (a) such Person became a Restricted Subsidiary of Vanguard or (b) such Person was merged or consolidated with or into Vanguard or any of its Restricted Subsidiaries, provided that on the date such Person became a Restricted Subsidiary or the date such Person was merged or consolidated with or into Vanguard or any of its Restricted Subsidiaries, as applicable, any of:

(1)  immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, Vanguard or such Person (if Vanguard is not the survivor in the transaction) would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;

(2)  immediately after giving effect to such transaction and any related financing transaction on a pro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, the Fixed Charge Coverage Ratio of Vanguard or such Person (if Vanguard is not the survivor in the transaction) is equal to or greater than the Fixed Charge Coverage Ratio of Vanguard immediately prior to such transaction; or

(3)  immediately after giving effect to such transaction on a pro forma basis, the Consolidated Net Worth of Vanguard would be greater than the Consolidated Net Worth of Vanguard immediately prior to such transaction.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, processing, gathering, marketing or transporting oil and natural gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation, (i) ownership interests in oil, natural gas, other Hydrocarbon properties or any interest therein or gathering, transportation, processing, storage or related systems, (ii) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, developments agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements with third parties, and (iii) direct or indirect ownership interests in drilling rigs, fracturing units and other related equipment.

“Permitted Investments” means:

(1)  any Investment in Vanguard (including, without limitation, through the purchase of any notes) or in a Restricted Subsidiary of Vanguard;

(2)  any Investment in Cash Equivalents;

(3)  any Investment by Vanguard or any Restricted Subsidiary of Vanguard in a Person, if as a result of such Investment:

(a)  such Person becomes a Restricted Subsidiary of Vanguard; or

(b)  such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, Vanguard or a Restricted Subsidiary of Vanguard;

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(4)  any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales,” including pursuant to an Asset Swap;

(5)  any acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of Vanguard;

(6)  any Investments received in compromise or resolution of (a) obligations of trade creditors or customers that were incurred in the ordinary course of business of Vanguard or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (b) litigation, arbitration or other disputes;

(7)  Investments represented by Hedging Obligations;

(8)  Investments in any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other deposits made in the ordinary course of business by Vanguard or any of its Restricted Subsidiaries;

(9)  loans or advances to officers, directors or employees made in the ordinary course of business of Vanguard or any Restricted Subsidiary of Vanguard;

(10)  repurchases of the notes;

(11)  any Guarantee of Indebtedness permitted to be incurred by the covenant entitled “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” other than a Guarantee of Indebtedness of an Affiliate of Vanguard that is not a Restricted Subsidiary of Vanguard;

(12)  any Investment existing on, or made pursuant to binding commitments existing on, the date of the indenture and any Investment consisting of an extension, modification or renewal of any Investment existing on, or made pursuant to a binding commitment existing on, the date of the indenture; provided that the amount of any such Investment may be increased (a) as required by the terms of such Investment as in existence on the date of the indenture or (b) as otherwise permitted under the indenture;

(13)  Investments acquired after the date of the indenture as a result of the acquisition by Vanguard or any Restricted Subsidiary of Vanguard of another Person, including by way of a merger, amalgamation or consolidation with or into Vanguard or any of its Restricted Subsidiaries in a transaction that is not prohibited by the covenant described above under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets” after the date of the indenture to the extent that such Investments were not made in contemplation of such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation;

(14)  Permitted Business Investments;

(15)  Investments received as a result of a foreclosure by, or other transfer of title to, Vanguard or any of its restricted subsidiary with respect to any secured Investment in default; and

(16)  other Investments in any Person having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (16) that are at the time outstanding that do not exceed the greater of (a) $50.0 million and (b) 5% of Adjusted Consolidated Net Tangible Assets; provided, however, that if any Investment pursuant to this clause (16) is made in any Person that is not a Restricted Subsidiary of Vanguard at the date of the making of such Investment and such Person becomes a Restricted Subsidiary of Vanguard after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (16) for so long as such Person continues to be a Restricted Subsidiary of Vanguard.

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“Permitted Liens” means:

(1)  Liens on assets of the Issuers or any Guarantor securing Indebtedness and other Obligations under Credit Facilities that was permitted by the terms of the indenture to be incurred pursuant to the covenant described under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;

(2)  Liens in favor of Vanguard or the Guarantors;

(3)  Liens on property of a Person existing at the time such Person becomes a Restricted Subsidiary of Vanguard or is merged with or into or consolidated with Vanguard or any Restricted Subsidiary of Vanguard; provided that such Liens were in existence prior to the contemplation of such Person becoming a Restricted Subsidiary of Vanguard or such merger or consolidation and do not extend to any assets other than those of the Person that becomes a Restricted Subsidiary of Vanguard or is merged with or into or consolidated with Vanguard or any Restricted Subsidiary of Vanguard;

(4)  Liens on property (including Capital Stock) existing at the time of acquisition of the property by Vanguard or any Subsidiary of Vanguard; provided that such Liens were in existence prior to such acquisition and not incurred in contemplation of, such acquisition;

(5)  Liens to secure the performance of statutory obligations, insurance, surety or appeal bonds, workers’ compensation obligations, bid, plugging and abandonment and performance bonds or other obligations of a like nature incurred in the ordinary course of business (including Liens to secure letters of credit issued to assure payment of such obligations);

(6)  Liens on any asset or property acquired, constructed or improved by Vanguard or any of its Restricted Subsidiaries; provided that (a) such Liens are in favor of the seller of such asset or property, in favor of the Person or Persons developing, constructing, repairing or improving such asset or property, or in favor of the Person or Persons that provided the funding for the acquisition, development, construction, repair or improvement cost, as the case may be, of such asset or property, (b) such Liens are created within 360 days after the acquisition, development, construction, repair or improvement, (c) the aggregate principal amount of the Indebtedness secured by such Liens is otherwise permitted to be incurred under the indenture and does not exceed the greater of (i) the cost of the asset or property so acquired, constructed or improved plus related financing costs and (ii) the fair market value of the asset or property so acquired, constructed or improved, measured at the date of such acquisition, or the date of completion of such construction or improvement, and (d) such Liens are limited to the asset or property so acquired, constructed or improved (including the proceeds thereof, accessions thereto, upgrades thereof and improvements thereto);

(7)  Liens existing on the date of the indenture;

(8)  Liens created for the benefit of (or to secure) the notes (or the Note Guarantees);

(9)  Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by Vanguard or any Restricted Subsidiary of Vanguard to the extent securing Non-Recourse Debt or other Indebtedness of such Unrestricted Subsidiary or Joint Venture;

(10)  Liens on pipelines or pipeline facilities that arise by operation of law;

(11)  Liens reserved in oil and natural gas mineral leases for bonus or rental payments and for compliance with the terms of such leases;

(12)  Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture; provided, however, that:

(a)  the new Lien is limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

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(b)  the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged with such Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;

(13)  Liens on insurance policies and proceeds thereof, or other deposits, to secure insurance premium financings;

(14)  filing of Uniform Commercial Code financing statements as a precautionary measure in connection with operating leases;

(15)  bankers’ Liens, rights of setoff, Liens arising out of judgments or awards not constituting an Event of Default and notices of lis pendens and associated rights related to litigation being contested in good faith by appropriate proceedings and for which adequate reserves have been made;

(16)  Liens on cash, Cash Equivalents or other property arising in connection with the defeasance, discharge or redemption of Indebtedness;

(17)  Liens on specific items of inventory or other goods (and the proceeds thereof) of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created in the ordinary course of business for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(18)  grants of software and other technology licenses in the ordinary course of business;

(19)  Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into in the ordinary course of business;

(20)  Liens in respect of Production Payments and Reserve Sales; provided, that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales;

(21)  Liens arising under oil and natural gas leases or subleases, assignments, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, licenses, sublicenses and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(22)  Liens to secure performance of Hedging Obligations of Vanguard or any of its Restricted Subsidiaries entered into in the ordinary course of business and not for speculative purposes;

(23)  Liens incurred in the ordinary course of business of Vanguard or any Restricted Subsidiary of Vanguard with respect to Indebtedness that does not exceed in aggregate principal amount of $25.0 million at any one time outstanding; and

(24)  any Lien renewing, extending, refinancing or refunding a Lien permitted by clauses (1) through (24) above, provided that (a) the principal amount of the Indebtedness secured by such Lien is not increased except by an amount equal to a reasonable premium or other reasonable amount paid, and fees and expenses reasonably incurred, in connection therewith and by an amount equal to any existing commitments unutilized thereunder and (b) no assets encumbered by any such Lien other than the assets permitted to be encumbered immediately prior to such renewal, extension, refinance or refund are encumbered thereby (other than improvements thereon, accessions thereto and proceeds thereof).

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“Permitted Refinancing Indebtedness” means any Indebtedness of Vanguard or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness of Vanguard or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1)  the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);

(2)  such Permitted Refinancing Indebtedness has a final maturity date that is (a) later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged or (b) more than 90 days after the final maturity date of the notes;

(3)  if the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the notes or the Note Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the notes or the Note Guarantees, as applicable, on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and

(4)  such Indebtedness is not incurred (other than by way of a Guarantee) by a Restricted Subsidiary of Vanguard (other than Finance Corp.) if Vanguard is the issuer or other primary obligor on the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Preferred Stock” means, with respect to any Person, any and all preferred or preference stock or other similar Equity Interests (however designated) of such Person whether outstanding or issued after the date of the indenture.

“Production Payments” means Dollar-Denominated Production Payments and Volumetric Production Payments, collectively.

“Production Payments and Reserve Sales” means the grant or transfer by Vanguard or any of its Restricted Subsidiaries to any Person of a royalty, overriding royalty, net profits interest, Production Payment, partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to Vanguard or any of its Restricted Subsidiaries.

“Reporting Default” means a Default described in clause (4) under “— Events of Default and Remedies.”

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“S&P” means Standard & Poor’s Ratings Services and any successor to the ratings business thereof.

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“Senior Debt” means

(1)  all Indebtedness of Vanguard or any of its Restricted Subsidiaries outstanding under Credit Facilities and all obligations under Hedging Obligations with respect thereto;

(2)  any other Indebtedness of Vanguard or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Note Guarantee; and

(3)  all Obligations with respect to the items listed in the preceding clauses (1) and (2).

Notwithstanding anything to the contrary in the preceding sentence, Senior Debt will not include:

(1)  any intercompany Indebtedness of Vanguard or any of its Restricted Subsidiaries to Vanguard or any of its Affiliates; or

(2)  any Indebtedness that is incurred in violation of the indenture.

For the avoidance of doubt, “Senior Debt” will not include any trade payables or taxes owed or owing by Vanguard or any of its Restricted Subsidiaries.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subsidiary” means, with respect to any specified Person:

(1)  any corporation, association or other business entity (other than a partnership or limited liability company) of which more than 50% of the total voting power of its Voting Stock is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2)  any partnership or limited liability company of which (a) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, and (b) such Person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

“Treasury Management Arrangement” means any agreement or other arrangement governing the provision of treasury or cash management services, including deposit accounts, overdraft, credit or debit card, funds transfer, automated clearinghouse, zero balance accounts, returned check concentration, controlled disbursement, lockbox, account reconciliation and reporting and trade finance services and other cash management services.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to     , 2016; provided, however, that if the period from the redemption date to     , 2016, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used. Vanguard will (a) calculate the Treasury Rate on the second business day preceding the

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applicable redemption date and (b) prior to such redemption date file with the trustee an officers’ certificate setting forth the Applicable Premium and the Treasury Rate and showing the calculation of each in reasonable detail.

“Unit Exchange Agreement” means that certain Unit Exchange Agreement, dated as of February 21, 2012, among Majeed S. Nami Personal Endowment Trust and Majeed S. Nami Irrevocable Trust (the “Nami Parties”), on the one hand, Vanguard Natural Gas, LLC and Vanguard (the “Vanguard Parties”), on the other, providing for the exchange of 1,900,000 common units of Vanguard held by the Nami Parties, for certain interests in Trust Energy Company, LLC and Ariana Energy, LLC held by Vanguard Natural Gas, LLC, as such agreement is in effect on the date of the indenture.

“Unrestricted Subsidiary” means any Subsidiary of Vanguard (excluding Finance Corp. but including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) that is designated by the Board of Directors of Vanguard as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:

(1)  has no Indebtedness other than Non-Recourse Debt owing to any Person other than Vanguard or any of its Restricted Subsidiaries;

(2)  except as permitted by the covenant described above under the caption “— Certain Covenants — Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with Vanguard or any Restricted Subsidiary of Vanguard unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to Vanguard or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of Vanguard;

(3)  is a Person with respect to which neither Vanguard nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4)  has not Guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of Vanguard or any of its Restricted Subsidiaries, except to the extent such Guarantee would be released upon such designation.

All Subsidiaries of an Unrestricted Subsidiary shall also be Unrestricted Subsidiaries.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person entitling the holders thereof (whether at all times or only so long as no senior class of Capital Stock has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1)  the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2)  the then outstanding principal amount of such Indebtedness.

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CERTAIN UNITED STATES FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS

The following discussion summarizes certain U.S. federal income tax considerations that may be relevant to the acquisition, ownership and disposition of the notes. This discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), applicable U.S. Treasury Regulations promulgated thereunder, judicial authority and administrative interpretations, as of the date of this document, all of which are subject to change or different interpretations, possibly with retroactive effect. We cannot assure you that the Internal Revenue Service, or IRS, will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the U.S. federal tax consequences of acquiring, holding or disposing of the notes.

This discussion is limited to holders who purchase the notes in this offering for a price equal to the issue price of the notes (i.e., the first price at which a substantial amount of the notes is sold for cash other than to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers) and who hold the notes as capital assets (generally, property held for investment). This discussion does not address the tax considerations arising under other U.S. federal tax laws (such as gift tax consequences, estate tax consequences to U.S. holders (as defined below)) or the laws of any foreign, state, local or other jurisdiction or any income tax treaty. In addition, this discussion does not address all tax considerations that may be important to a particular holder in light of the holder’s circumstances, or to certain categories of investors that may be subject to special rules, such as:

• dealers in securities or currencies;

• traders in securities that have elected the mark-to-market method of accounting for their securities;

• U.S. holders (as defined below) whose functional currency is not the U.S. dollar;

• persons holding notes as part of a hedge, straddle, conversion or other “synthetic security” or risk reduction transaction;

• U.S. expatriates;

• U.S. Holders (as defined below) that hold their Notes through non-U.S. brokers or other non-U.S. intermediaries;

• financial institutions;

• insurance companies;

• regulated investment companies;

• real estate investment trusts;

• persons subject to the alternative minimum tax;

• entities that are tax-exempt for U.S. federal income tax purposes; and

• partnerships and other pass-through entities and holders of interests therein.

If an entity treated as a partnership for U.S. federal income tax purposes holds notes, the tax treatment of a partner of a partnership generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership considering an investment in the notes, you are urged to consult your own tax advisor about the U.S. federal income tax consequences of acquiring, holding and disposing of the notes.

In certain circumstances (see “Description of Notes — Optional Redemption” and “Description of Notes — Repurchase at the Option of Holders — Change of Control”), we may be obligated to pay amounts on the notes that are in excess of stated interest or principal on the notes. We do not intend to treat the possibility of paying such additional amounts as causing the notes to be treated as contingent payment debt instruments. However, additional income will be recognized if any such additional payment is made. It is possible that the IRS may take a different position, in which case a holder might be required to accrue interest income at a higher rate than the stated interest rate and to treat as ordinary interest income any gain realized on the taxable disposition of the note. The remainder of this discussion assumes that the notes will not be

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treated as contingent payment debt instruments. Prospective investors should consult their own tax advisors regarding the possible application of the contingent payment debt instrument rules to the notes.

INVESTORS CONSIDERING THE PURCHASE OF NOTES ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE PARTICULAR U.S. FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE NOTES AS WELL AS ANY PROPOSED CHANGE IN APPLICABLE LAWS.

Tax Consequences to U.S. Holders

You are a “U.S. holder” for purposes of this discussion if you are a beneficial owner of a note and you are for U.S. federal income tax purposes:

• an individual who is a U.S. citizen or U.S. resident alien;

• a corporation that was created or organized under the laws of the United States, any state thereof or the District of Columbia;

• an estate whose income is subject to U.S. federal income taxation regardless of its source; or

• a trust (1) if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or (2) that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person.

Interest on the Notes

Interest on the notes generally will be taxable to you as ordinary income at the time it is received or accrued in accordance with your regular method of accounting for United States federal income tax purposes.

Original Issue Discount

For U.S. federal income tax purposes, if the difference between the principal amount of the notes and their issue price is equal to or greater than a specified de minimis amount (an amount equal to 0.25% of the principal amount of the notes multiplied by the number of complete years to maturity of the notes), the notes will be treated as issued with OID in an amount equal to such difference. If the notes are treated as issued with OID, you must generally include such OID in gross income as it accrues over the term of the notes at a constant yield without regard to your regular method of accounting for U.S. federal income tax purposes and in advance of the receipt of cash payments attributable to that income.

The amount of OID that you must include in income will generally equal the sum of the “daily portions” of OID with respect to the note for each day during the taxable year or portion of the taxable year in which such note was held (“accrued OID”). The daily portion is determined by allocating to each day in any “accrual period” a pro rata portion of the OID allocable to that accrual period. The “accrual period” for a note may be of any length and may vary in length over the term of the note, provided that each accrual period is no longer than one year and each scheduled payment of principal and interest occurs on the first day or the final day of an accrual period. The amount of OID allocable to any accrual period other than the final accrual period is an amount equal to the excess, if any, of (i) the product of the note’s adjusted issue price at the beginning of such accrual period and its yield to maturity (determined on the basis of compounding at the close of each accrual period and properly adjusted for the length of the accrual period) over (ii) the aggregate of all stated interest allocable to the accrual period. OID allocable to a final accrual period is the difference between the amount payable at maturity (other than a payment of stated interest) and the adjusted issue price of the note at the beginning of the final accrual period. The “adjusted issue price” of a note at the beginning of any accrual period is generally equal to its issue price increased by the accrued OID for each prior accrual period.

You may elect to treat all interest on a note as OID and calculate the amount includible in gross income under the constant yield method described above. The election is to be made for the taxable year in which the note was acquired, and may not be revoked without the consent of the IRS. U.S. Holders should consult their own tax advisors about this election.

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Disposition of the Notes

You will generally recognize capital gain or loss on the sale, redemption, exchange, retirement or other taxable disposition of a note equal to the difference, if any, between the proceeds you receive (excluding any proceeds attributable to accrued but unpaid interest, which will be taxable as ordinary interest income to the extent you have not previously included such amounts in income) and your adjusted tax basis in the notes. The proceeds you receive will include the amount of any cash and the fair market value of any other property received for the note increased by any OID that has accrued on the note. Your adjusted tax basis in the note will generally equal the amount you paid for the note. Any gain or loss will be long-term capital gain or loss if you held the note for more than one year at the time of the sale, redemption, exchange, retirement or other disposition. Long-term capital gains of individuals, estates and trusts generally are subject to a reduced rate of U.S. federal income tax. The deductibility of capital losses may be subject to limitations.

Information Reporting and Backup Withholding

Information reporting will apply to payments of interest (and accruals of OID) on, and the proceeds of the sale, exchange or other disposition (including a redemption or retirement) of, notes held by you, and backup withholding may apply to such amounts unless you provide the appropriate intermediary with a taxpayer identification number, certified under penalties of perjury, as well as certain other information or otherwise establish an exemption from backup withholding. Backup withholding is not an additional tax. Any amount withheld under the backup withholding rules is allowable as a credit against your U.S. federal income tax liability, if any, and a refund may be obtained if the amounts withheld exceed your actual U.S. federal income tax liability and you timely provide the required information and appropriate claim form to the IRS.

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Tax Consequences to Non-U.S. Holders

You are a “non-U.S. holder” for purposes of this discussion if you are a beneficial owner of notes that, for U.S. federal income tax purposes, is an individual, corporation, estate or trust and is not a U.S. holder.

Interest on the Notes

Payments to you of interest (including for purposes of the discussion below, any OID) on the notes generally will be exempt from withholding of U.S. federal income tax under the “portfolio interest” exemption if you properly certify as to your foreign status, as described below, and:

• you do not own, actually or constructively, 10% or more of our capital or profits interests;

• you are not a “controlled foreign corporation” that is related to us (actually or constructively);

• you are not a bank whose receipt of interest on the notes is in connection with an extension of credit made pursuant to a loan agreement entered into in the ordinary course of your trade or business; and

• interest on the notes is not effectively connected with your conduct of a U.S. trade or business.

The portfolio interest exemption and several of the special rules for non-U.S. holders described below generally apply only if you appropriately certify as to your foreign status. You can generally meet this certification requirement by providing a properly executed IRS Form W-8BEN or appropriate substitute form to the withholding agent. If you hold the notes through a financial institution or other agent acting on your behalf, you may be required to provide appropriate certifications to the agent. Your agent will then generally be required to provide appropriate certifications to the applicable withholding agent, either directly or through other intermediaries. Special rules apply to foreign estates and trusts, and in certain circumstances certifications as to foreign status of partners, trust owners or beneficiaries may have to be provided to the withholding agent. In addition, special rules apply to qualified intermediaries that enter into withholding agreements with the IRS.

If you cannot satisfy the requirements described above, payments of interest made to you will be subject to U.S. federal withholding tax at a 30% rate, unless you provide the withholding agent with a properly executed IRS Form W-8BEN (or successor form) claiming an exemption from (or a reduction of) withholding under the benefits of an income tax treaty, or the payments of interest are effectively connected with your conduct of a trade or business in the United States and you meet the certification requirements described below. (See “— Income or Gain Effectively Connected With a U.S. Trade or Business.”)

Disposition of the Notes

You generally will not be subject to U.S. federal income tax on any gain realized on the sale, redemption, exchange, retirement or other taxable disposition of a note unless:

• the gain is effectively connected with the conduct by you of a U.S. trade or business; or

• you are an individual who has been present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met.

If your gain is described in the first bullet point above, you generally will be subject to U.S. federal income tax in the manner described under “— Income or Gain Effectively Connected With a U.S. Trade or Business,” unless an applicable income tax treaty provides otherwise. If you are a non-U.S. holder described in the second bullet point above, you will generally be subject to U.S. federal income tax at a flat rate of 30% (or lower applicable treaty rate) on the gain derived from the sale or other disposition, which may be offset by U.S. source capital losses.

Income or Gain Effectively Connected with a U.S. Trade or Business

If any interest (including any OID) on the notes or gain from the sale, exchange or other taxable disposition of the notes is effectively connected with a U.S. trade or business conducted by you (and, if required by an applicable income tax treaty, is treated as attributable to a permanent establishment maintained by you in the United States), then such interest income or gain will be subject to U.S. federal income tax at regular graduated income tax rates, unless an applicable income tax treaty provides otherwise. Effectively

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connected income will not be subject to U.S. withholding tax if you satisfy certain certification requirements by providing to us or our paying agent a properly executed IRS Form W-8ECI (or IRS Form W-8BEN if a treaty exemption applies) or successor form. If you are a corporation, that portion of your earnings and profits that is effectively connected with your U.S. trade or business may also be subject to a “branch profits tax” at a 30% rate, unless an applicable income tax treaty may provides for a lower rate.

Information Reporting and Backup Withholding

Payments to you of interest on a note, and amounts withheld from such payments, if any, generally will be required to be reported to the IRS and to you.

United States backup withholding generally will not apply to payments to you of interest (including any OID) on a note if the statement described in “— Tax Consequences to Non-U.S. Holders — Interest on the Notes” is duly provided or you otherwise establish an exemption, provided that we do not have actual knowledge or reason to know that you are a United States person.

Payment of the proceeds of a disposition of a note (including a redemption or retirement) effected by the U.S. office of a U.S. or foreign broker will be subject to information reporting requirements and backup withholding unless you properly certify under penalties of perjury as to your foreign status and certain other conditions are met or you otherwise establish an exemption. Information reporting requirements and backup withholding generally will not apply to any payment of the proceeds of the disposition of a note effected outside the United States by a foreign office of a broker. However, unless such a broker has documentary evidence in its records that you are a non-U.S. holder and certain other conditions are met, or you otherwise establish an exemption, information reporting will apply to a payment of the proceeds of the disposition of a note effected outside the United States by such a broker if the broker is a U.S. person or has certain relationships with the United States.

Backup withholding is not an additional tax. Any amount withheld under the backup withholding rules is allowable as a credit against your U.S. federal income tax liability, if any, and a refund may be obtained if the amounts withheld exceed your actual U.S. federal income tax liability and you timely provide the required information and appropriate claim form to the IRS.

U.S. Federal Estate Tax

If you are an individual and are not a resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of your death, the notes will not be included in your estate for U.S. federal estate tax purposes provided that at the time of your death, interest on the notes owned by you qualifies for the portfolio interest exemption under the rules described above (without regard to the certification requirement required to qualify for the portfolio interest exemption).

Legislation Involving Payments to Certain Foreign Entities

On March 18, 2010, President Obama signed the Hiring Incentives to Restore Employment Act (the “HIRE Act”) into law. The HIRE Act adds a new chapter 4 to the Code, which provides that, effective for payments made after December 31, 2013 (in the case of interest (including any OID) payments) and December 31, 2014 (in the case of proceeds from disposition or retirement), our paying agent (in its capacity as such) is required to deduct and withhold a tax equal to 30% of any payments made on our obligations to a foreign financial institution or non-financial foreign entity (including, in some cases, when such foreign institution or entity is acting as an intermediary), and requires any person having the control, receipt, custody, disposal, or payment of any gross proceeds of sale or other disposition of our obligations to deduct and withhold a tax equal to 30% of any such proceeds, unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are foreign entities with U.S. owners), and (ii) in the case of a non-financial foreign entity, such entity provides the withholding agent with a certification identifying the direct and indirect U.S. owners of the entity. Under certain circumstances, a Non-U.S. Holder might be eligible for refunds or credits of such taxes. Payments with respect to obligations (such as the Notes) outstanding on March 18, 2012 are not subject to

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these HIRE Act rules, and proposed regulations not yet in effect would, if adopted, extend this grandfathering date to January 1, 2013. Prospective investors are encouraged to consult with their own tax advisors regarding the possible implications of this legislation on an investment in the Notes.

Additional Tax Relating to Net Investment Income

For taxable years beginning after December 31, 2012, an additional 3.8% tax will be imposed on the “net investment income” of certain United States citizens and resident aliens, and on the undistributed “net investment income” of certain estates and trusts. Among other items, “net investment income” will generally include gross income from interest (including any OID), and net gain from the disposition of property, such as the notes, less certain deductions. Prospective investors should consult their tax advisors with respect to the imposition of this additional tax.

THE PRECEDING DISCUSSION OF CERTAIN U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS IS FOR GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. WE URGE EACH PROSPECTIVE INVESTOR TO CONSULT ITS OWN TAX ADVISOR REGARDING THE PARTICULAR FEDERAL, STATE, LOCAL AND FOREIGN TAX CONSEQUENCES OF PURCHASING, HOLDING AND DISPOSING OF OUR NOTES, INCLUDING THE CONSEQUENCES OF ANY PROPOSED CHANGE IN APPLICABLE LAWS.

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UNDERWRITING

Citigroup Global Markets Inc. and Credit Agricole Securities (USA) Inc. are acting as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the principal amount of notes set forth opposite the underwriter’s name.

Underwriter	Principal Amount of Notes
Citigroup Global Markets Inc.	$
Credit Agricole Securities (USA) Inc.
RBC Capital Markets, LLC
RBS Securities Inc.
UBS Securities LLC
Wells Fargo Securities, LLC
BMO Capital Markets Corp.
Capital One Southcoast, Inc.
Comerica Securities, Inc.
Scotia Capital (USA) Inc.
Lloyds Securities Inc.
Natixis Securities Americas LLC
U.S. Bancorp Investments, Inc.
Total	$	300,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase the notes included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the notes if they purchase any of the notes.

Notes sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus supplement. Any notes sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $       per note. Any such securities dealers may resell any notes purchased from the underwriters to certain other brokers or dealers at a discount from the initial public offering price not to exceed $       per note. If all the notes are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms.

We have agreed that, for a period of 60 days from the date of this prospectus supplement, we will not, without the prior written consent of Citigroup Global Markets Inc., offer, sell, or contract to sell, or otherwise dispose of, directly or indirectly, or announce the offering of, any debt securities issued or guaranteed by us. Citigroup Global Markets Inc. in its sole discretion may release any of the securities subject to these lock-up agreements at anytime without notice.

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering (expressed as a percentage of the principal amount of the notes).

	Paid by Vanguard Natural Resources, LLC
Per note		%

We estimate that our total expenses for this offering will be $300,000.

In connection with the offering, the underwriters may purchase and sell notes in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions and stabilizing purchases.

• Short sales involve secondary market sales by the underwriters of a greater number of notes than they are required to purchase in the offering.

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• Covering transactions involve purchases of notes in the open market after the distribution has been completed in order to cover short positions.

• Stabilizing transactions involve bids to purchase notes so long as the stabilizing bids do not exceed a specified maximum.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the underwriters, in covering short positions or making stabilizing purchases, repurchase notes originally sold by that syndicate member.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the notes. They may also cause the price of the notes to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

Neither we nor any of the underwriters makes 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 notes. In addition, neither we nor any of the underwriters makes any representation that the underwriters will engage in such transactions or that such transactions, once commenced, will not be discontinued without notice.

The notes are offered for sale only in those jurisdictions where it is legal to offer them.

There is no public market for the notes. The notes will not be listed on any securities exchange or included in any automated quotation system. The underwriters have advised us that, following completion of the offering of the notes, they intend to make a market in the notes, as permitted by applicable law. The underwriters are not obligated, however, to make a market in the notes, and may discontinue any market-making activities at any time without notice, in their sole discretion. If the underwriters cease to act as a market-maker for the notes for any reason, there can be no assurance that another firm or person will make a market in the notes. Accordingly, we cannot assure you as to the development or liquidity of any market for these notes.

Affiliations/Conflicts of Interest/FINRA Rules

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The underwriters and their respective affiliates have in the past performed commercial banking, investment banking and advisory services for us from time to time for which they have received customary fees and reimbursement of expenses and may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. In particular, an affiliate of Citigroup Global Markets Inc. is the administrative agent under our Reserve-Based Credit Facility and our Facility Term Loan, for which it receives customary compensation and indemnity. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments. In addition, affiliates of all of the underwriters are lenders under our Reserve-Based Credit Facility and/or our Facility Term Loan and will receive a portion of the proceeds from this offering through the repayment of indebtedness under those credit facilities.

Because the Financial Industry Regulatory Authority, or FINRA, views our common units as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

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Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of notes described in this prospectus supplement may not be made to the public in that relevant member state other than:

• to any legal entity which is a qualified investor as defined in the Prospectus Directive;

• to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by us for any such offer; or

• in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state) and includes any relevant implementing measure in each relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

The sellers of the notes have not authorized and do not authorize the making of any offer of notes through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the notes as contemplated in this prospectus supplement. Accordingly, no purchaser of the notes, other than the underwriters, is authorized to make any further offer of the notes on behalf of the sellers or the underwriters.

Notice to Prospective Investors in the United Kingdom

This prospectus supplement and the accompanying prospectus are only being distributed to, and are only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a “relevant person”). This prospectus supplement and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

This prospectus supplement and the accompanying prospectus are only being distributed in the United Kingdom to, and are only directed at, (a) investment professionals falling within both Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) and Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “General Promotion Order”), and (b) high net worth companies and other persons falling with both Article 22(2)(a) to (d) of the CIS Promotion Order and Article 49(2)(a) to (d) of the General Promotion Order (all such persons together being referred to as “relevant persons”).

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Notice to Prospective Investors in France

Neither this prospectus supplement nor any other offering material relating to the notes described in this prospectus supplement has been submitted to the clearance procedures of theAutorité des Marchés Financiers or of the competent authority of another member state of the European Economic Area and notified to theAutorité des Marchés Financiers. The notes have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus supplement nor any other offering material relating to the notes has been or will be:

• released, issued, distributed or caused to be released, issued or distributed to the public in France; or

• used in connection with any offer for subscription or sale of the notes to the public in France.

Such offers, sales and distributions will be made in France only:

• to qualified investors (investisseurs qualifiés) and/or to a restricted circle of investors (cercle restreint d’investisseurs), in each case investing for their own account, all as defined in, and in accordance with, articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the FrenchCode monétaire et financier;

• to investment services providers authorized to engage in portfolio management on behalf of third parties; or

• in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the FrenchCode monétaire et financierand article 211-2 of the General Regulations (Règlement Général) of theAutorité des Marchés Financiers, does not constitute a public offer (appel public à l’épargne).

The notes may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the FrenchCode monétaire et financier.

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LEGAL MATTERS

The validity of the notes offered in this prospectus supplement will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the notes offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas. Members of Vinson & Elkins L.L.P. involved in this offering own an aggregate of 2,200 of our common units

EXPERTS

The consolidated financial statements of Vanguard Natural Resources, LLC and its subsidiaries as of December 31, 2011, 2010 and 2009 and for each of the three years in the period ended December 31, 2011, management’s assessment of the effectiveness of Vanguard Natural Resources, LLC and its subsidiaries’ internal control over financial reporting as of December 31, 2011, the statements of revenues and direct operating expenses of the properties Vanguard acquired from a private seller for each of the years in the two-year period ended December 31, 2009, which appear in Vanguard’s Current Report on Form 8-K/A filed with the SEC on May 12, 2010, and the statement of revenues and direct operating expenses of the oil and gas properties purchased from a private seller for the year ended December 31, 2010, which appear in Vanguard’s Current report on Form 8-K/A filed with SEC on September 16, 2011, incorporated by reference in this Prospectus have been so incorporated in reliance on the reports of BDO USA, LLP (formerly known as BDO Seidman, LLP), an independent registered public accounting firm, incorporated herein by reference, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of Encore Energy Partners LP as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010, appearing in Vanguard Natural Resources LLC’s Current Report on Form 8-K/A filed with the SEC on January 9, 2012, have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon, included therein, and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The information incorporated herein by reference regarding estimated quantities of our proved reserves as of December 31, 2011, was prepared or derived from estimates prepared by DeGolyer and MacNaughton, independent reserve engineers. These estimates are incorporated herein by reference in reliance upon the authority of such firm as experts in these matters.

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WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on the operation of the SEC’s public reference room. Our SEC filings are available on the SEC’s web site atwww.sec.gov. We also make available free of charge on our website, atwww.vnrllc.com, all materials that we file electronically with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports, as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. Additionally, you can obtain information about us through the New York Stock Exchange,www.nyse.com, on which our common units are listed.

The SEC allows us to “incorporate by reference” the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus supplement by referring you to other documents filed separately with the SEC. These other documents contain important information about us, our financial condition and results of operations. The information incorporated by reference is an important part of this prospectus supplement and the accompanying prospectus. Information that we file later with the SEC will automatically update and may replace information in this prospectus supplement and information previously filed with the SEC.

We incorporate by reference in this prospectus supplement the documents listed below, excluding information deemed to be furnished and not filed with the SEC:

• Our Annual Report on Form 10-K for the fiscal year ended December 31, 2011;

• Our Current Reports on Form 8-K filed on January 24, 2012 and February 29, 2012;

• Our Current Reports on Form 8-K/A filed on January 9, 2012 and March 26, 2012;

• All documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of Exchange Act between the date of this prospectus supplement and before the termination of this offering.

You may obtain any of the documents incorporated by reference in this prospectus supplement or the accompanying prospectus from the SEC through the SEC’s website at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus supplement and the accompanying prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website atwww.vnrllc.com, or by writing or calling us at the address set forth below. Information on our website is not incorporated into this prospectus supplement, the accompanying prospectus or our other securities filings and is not a part of this prospectus supplement or the accompanying prospectus.

Vanguard Natural Resources, LLC
5847 San Felipe, Suite 3000
Houston, Texas 77057
Attention: Investor Relations
Telephone: (832) 327-2255

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INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Statements of Operations		F-3
Consolidated Statements of Comprehensive Income (Loss)		F-4
Consolidated Balance Sheets		F-5
Consolidated Statements of Members’ Equity		F-6
Consolidated Statements of Cash Flows		F-7
Notes to Consolidated Financial Statements		F-9
Supplemental Selected Quarterly Financial Information (Unaudited)		F-42
Supplemental Oil and Natural Gas Information (Unaudited)		F-43

All schedules are omitted as the required information is not applicable or the information is presented in the Consolidated Financial Statements and related notes.

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Members
Vanguard Natural Resources, LLC
Houston, Texas

We have audited the accompanying consolidated balance sheets of Vanguard Natural Resources, LLC as of December 31, 2011 and 2010 and the related consolidated statements of operations, comprehensive income (loss), members’ equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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. 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 presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vanguard Natural Resources, LLC at December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Vanguard Natural Resources, LLC’s internal control over financial reporting as of December 31, 2011, based on criteria established inInternal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report date March 5, 2012 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas
March 5, 2012

F-2

Vanguard Natural Resources, LLC and Subsidiaries
  
Consolidated Statements of Operations
For the Years Ended December 31,
(in thousands, except per unit data)

	2011			2010			2009
Revenues:
Oil, natural gas and NGLs sales	$	312,842		$	85,357		$	46,035
Loss on commodity cash flow hedges		(3,071	)		(2,832	)		(2,380	)
Realized gain on other commodity derivative contracts		10,276			24,774			29,993
Unrealized loss on other commodity derivative contracts		(470	)		(14,145	)		(19,043	)
Total revenues		319,577			93,154			54,605
Costs and expenses:
Production:
Lease operating expenses		63,944			18,471			12,652
Production and other taxes		28,621			6,840			3,845
Depreciation, depletion, amortization and accretion		84,857			22,231			14,610
Impairment of oil and natural gas properties		—			—			110,154
Selling, general and administrative expenses		19,779			10,134			10,644
Total costs and expenses		197,201			57,676			151,905
Income (loss) from operations		122,376			35,478			(97,300	)
Other income (expense):
Other income		77			1			—
Interest expense		(28,994	)		(5,766	)		(4,276	)
Realized loss on interest rate derivative contracts		(2,874	)		(1,799	)		(1,903	)
Unrealized gain (loss) on interest rate derivative contracts		(2,088	)		(349	)		763
Net gain (loss) on acquisition of oil and natural gas properties		(367	)		(5,680	)		6,981
Total other income (expense)		(34,246	)		(13,593	)		1,565
Net income (loss)		88,130			21,885			(95,735	)
Less: Net income attributable to non-controlling interest		(26,067	)		—			—
Net income (loss) attributable to Vanguard unitholders	$	62,063		$	21,885		$	(95,735	)
Net income (loss) per Common and Class B units –  basic & diluted	$	1.95		$	1.00		$	(6.74	)
Weighted average units outstanding:
Common units – basic		31,370			21,500			13,791
Common units – diluted		31,430			21,538			13,791
Class B units – basic & diluted		420			420			420

 
 
See accompanying notes to consolidated financial statements.

F-3

Vanguard Natural Resources, LLC and Subsidiaries
  
Consolidated Statements of Comprehensive Income (Loss)
For the Years Ended December 31,
(in thousands)

	2011		2010		2009
Net income (loss)	$	88,130	$	21,885	$	(95,735	)
Net income from derivative contracts:
Reclassification adjustments for settlements		3,032		2,485		2,288
Other comprehensive income		3,032		2,485		2,288
Comprehensive income (loss)	$	91,162	$	24,370	$	(93,447	)

 
 
See accompanying notes to consolidated financial statements.

F-4

Vanguard Natural Resources, LLC and Subsidiaries
  
Consolidated Balance Sheets
As of December 31,
(in thousands, except unit data)

	2011			2010
Assets
Current assets
Cash and cash equivalents	$	2,851		$	1,828
Trade accounts receivable, net		48,046			32,961
Derivative assets		2,333			16,523
Other currents assets		3,462			1,474
Total current assets		56,692			52,786
Oil and natural gas properties, at cost		1,549,821			1,312,107
Accumulated depletion, amortization and impairment		(331,836	)		(248,704	)
Oil and natural gas properties evaluated, net – full cost method		1,217,985			1,063,403
Other assets
Goodwill		420,955			420,955
Other intangible asset, net		8,837			9,017
Derivative assets		1,105			1,479
Deferred financing costs		6,723			5,649
Other assets		4,066			1,903
Total assets	$	1,716,363		$	1,555,192
Liabilities and members’ equity
Current liabilities
Accounts payable:
Trade	$	7,867		$	3,156
Affiliates		718			668
Accrued liabilities:
Lease operating		5,828			5,156
Developmental capital		563			996
Interest		103			310
Production and other taxes		12,768			11,793
Derivative liabilities		12,774			6,209
Deferred swap premium liability		275			1,739
Oil and natural gas revenue payable		505			2,241
Other		4,437			8,202
Current portion, long-term debt		—			175,000
Total current liabilities		45,838			215,470
Long-term debt		771,000			410,500
Derivative liabilities		20,553			30,384
Asset retirement obligations		34,776			29,434
Other long-term liabilities		275			11
Total liabilities		872,442			685,799
Commitments and contingencies (Note 9)
Members’ equity
Members’ capital, 48,320,104 and 29,666,039 common units issued and outstanding at December 31, 2011 and 2010, respectively		839,714			318,597
Class B units, 420,000 issued and outstanding at December 31, 2011 and 2010		4,207			5,166
Accumulated other comprehensive loss		—			(3,032	)
Total VNR members’ equity		843,921			320,731
Non-controlling interest in subsidiary		—			548,662
Total members’ equity		843,921			869,393
Total liabilities and members’ equity	$	1,716,363		$	1,555,192

 
 
See accompanying notes to consolidated financial statements.

F-5

Vanguard Natural Resources, LLC and Subsidiaries
  
Consolidated Statements of Members’ Equity
For the Years Ended December 31, 2011, 2010 and 2009
(in thousands, except per unit data)

	Common Units			Common Units Amount			Class B Units		Class B Units Amount			Accumulated Other Comprehensive Loss			Non-Controlling Interest			Total Members’ Equity
Balance, December 31, 2008		12,146		$	88,550			420	$	4,606		$	(7,805	)	$	—		$	85,351
Distributions to members ($0.50 per unit to unitholders of record January 30, 2009, April 30, 2009, July 31, 2009 and November 6, 2009, respectively)		—			(26,258	)		—		(840	)		—			—			(27,098	)
Issuance of common units, net of offering costs of $613		6,520			97,627			—		—			—			—			97,627
Redemption of common units		(250	)		(4,305	)		—		—			—			—			(4,305	)
Unit-based compensation		—			(6	)		—		2,164			—			—			2,158
Net loss		—			(95,735	)		—		—			—			—			(95,735	)
Settlement of cash flow hedges in other comprehensive income		—			—			—		—			2,288			—			2,288
Balance at December 31, 2009		18,416		$	59,873			420	$	5,930		$	(5,517	)	$	—		$	60,286
Distributions to members ($0.525 per unit to unitholders of record February 5, 2010 and May 7, 2010 and $0.55 per unit to unitholders of record August 6, 2010 and November 5, 2010, respectively)		—			(45,747	)		—		(903	)		—			—			(46,650	)
Issuance of common units, net of offering costs of $530		8,263			193,541			—		—			—			—			193,541
Issuance of common units in connection with the ENP Purchase		3,137			93,020			—		—			—			—			93,020
Redemption of common units		(150	)		(3,651	)		—		—			—			—			(3,651	)
Unit-based compensation		—			(324	)		—		139			—			—			(185	)
Net income		—			21,885			—		—			—			—			21,885
Settlement of cash flow hedges in other comprehensive income		—			—			—		—			2,485			—			2,485
Non-controlling interest in subsidiary		—			—			—		—			—			548,662			548,662
Balance at December 31, 2010		29,666		$	318,597			420	$	5,166		$	(3,032	)	$	548,662		$	869,393
Distributions to members ($0.56 per unit to unitholders of record February 7, 2011, $0.57 per unit to unitholders of record May 6, 2011, $0.575 per unit to unitholders of record August 5, 2011, $0.5775 per unit to unitholders of record November 7, 2011)		—			(68,068	)		—		(959	)		—			—			(69,027	)
Issuance of common units in connection with the ENP Merger and equity offering, net of merger costs of $2,503 and offering costs of $126		18,439			524,697			—		—			—			(527,326	)		(2,629	)
Unit-based compensation		215			2,425			—		—			—			—			2,425
Net income		—			62,063			—		—			—			26,067			88,130
Settlement of cash flow hedges in other comprehensive income		—			—			—		—			3,032			—			3,032
ENP cash distribution to non-controlling interest		—			—			—		—			—			(47,403	)		(47,403	)
Balance at December 31, 2011		48,320		$	839,714			420	$	4,207		$	—		$	—		$	843,921

 
 
See accompanying notes to consolidated financial statements.

F-6

Vanguard Natural Resources, LLC and Subsidiaries
  
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(in thousands)

	2011			2010			2009
Operating activities
Net income (loss)	$	88,130		$	21,885		$	(95,735	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		84,857			22,231			14,610
Impairment of oil and natural gas properties		—			—			110,154
Amortization of deferred financing costs		4,208			1,373			639
Unit-based compensation		2,557			847			2,483
Unrealized fair value of phantom units granted to officers		469			179			393
Amortization of premiums paid on derivative contracts		11,346			1,950			3,502
Amortization of value on derivative contracts acquired		169			1,995			3,619
Unrealized losses on other commodity and interest rate derivative contracts		2,558			14,494			18,280
Net (gain) loss on acquisitions of oil and natural gas properties		367			5,680			(6,981	)
Changes in operating assets and liabilities:
Trade accounts receivable		(15,085	)		(1,844	)		(1,942	)
Payables to affiliates		50			(817	)		(1,168	)
Price risk management activities, net		(1,621	)		(341	)		94
Other receivables		—			610			539
Other current assets		(202	)		(105	)		(536	)
Accounts payable		2,972			765			(410	)
Accrued expenses		(4,440	)		2,672			4,739
Other assets		(3	)		3			(125	)
Net cash provided by operating activities		176,332			71,577			52,155
Investing activities
ENP Purchase, net of cash acquired		—			(298,620	)		—
Additions to property and equipment		(935	)		(198	)		(57	)
Additions to oil and natural gas properties		(34,096	)		(15,277	)		(4,960	)
Acquisitions of oil and natural gas properties		(205,222	)		(115,832	)		(103,923	)
Proceeds from sale of property and equipment		5,231			—			—
Deposits and prepayments of oil and natural gas properties		(1,328	)		(67	)		(375	)
Net cash used in investing activities		(236,350	)		(429,994	)		(109,315	)
Financing activities
Proceeds from borrowings		1,073,500			480,700			80,349
Repayment of debt		(888,000	)		(259,000	)		(85,549	)
Proceeds from equity offerings, net		—			193,541			97,627
Redemption of common units		—			(3,651	)		(4,305	)
Distributions to members		(69,027	)		(46,650	)		(27,098	)
ENP distributions to non-controlling interest		(47,403	)		—			—
Financing costs		(5,282	)		(3,724	)		(3,055	)
Offering costs		(2,747	)		(37	)		—
Purchases of units for issuance as unit-based compensation		—			(1,421	)		(325	)
Net cash provided by financing activities		61,041			359,758			57,644
Net increase in cash and cash equivalents		1,023			1,341			484
Cash and cash equivalents, beginning of year		1,828			487			3
Cash and cash equivalents, end of year	$	2,851		$	1,828		$	487

 
 
See accompanying notes to consolidated financial statements.

F-7

	2011		2010		2009
Supplemental cash flow information:
Cash paid for interest	$	25,021	$	4,430	$	3,894
Non-cash financing and investing activities:
Asset retirement obligations	$	4,844	$	558	$	2,163
Derivatives assumed in acquisition of oil and natural gas properties	$	130	$	—	$	4,128
Deferred swap liability	$	—	$	—	$	3,072
Non-monetary exchange of oil and natural gas properties	$	—	$	—	$	2,660
Issuance of common units for the ENP Merger	$	527,326	$	—	$	—
ENP Acquisition:
Assets acquired:
Oil and natural gas properties	$	—	$	786,524	$	—
Goodwill	$	—	$	420,955	$	—
Other long-term assets	$	—	$	9,731	$	—
Long-term debt assumed	$	—	$	234,000	$	—
Asset retirement obligations assumed	$	—	$	25,092	$	—
Common units issued	$	—	$	93,020	$	—
Non-controlling interest in subsidiary	$	—	$	548,662	$	—

 
 
See accompanying notes to consolidated financial statements.

F-8

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

Description of the Business:

Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Through our operating subsidiaries, we own properties and oil and natural gas reserves primarily located in seven operating areas:

• the Permian Basin in West Texas and New Mexico;

• the Big Horn Basin in Wyoming and Montana;

• the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee;

• South Texas;

• the Williston Basin in North Dakota and Montana;

• Mississippi; and

• the Arkoma Basin in Arkansas and Oklahoma.

References in this report to (1) “us,” “we,” “our,” “the Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC, Trust Energy Company, LLC (“TEC”), VNR Holdings, LLC (“VNRH”), Ariana Energy, LLC (“Ariana Energy”), Vanguard Permian, LLC (“Vanguard Permian”), VNR Finance Corp. (“VNRF”), Encore Energy Partners GP LLC (“ENP GP”), Encore Energy Partners LP (“ENP”), Encore Energy Partners Operating LLC (“OLLC”), Encore Energy Partners Finance Corporation (“ENPF”), Encore Clear Fork Pipeline LLC (“ECFP”) and (2) “Predecessor,” “our operating subsidiary” or “VNG” are to Vanguard Natural Gas, LLC.

We were formed in October 2006 and effective January 5, 2007, Vanguard Natural Gas, LLC (formerly Nami Holding Company, LLC) was separated into our operating subsidiary and Vinland Energy Eastern, LLC (“Vinland”). As part of the separation, we retained all of our Predecessor’s proved producing wells and associated reserves. We also retained 40% of our Predecessor’s working interest in the known producing horizons in approximately 95,000 gross undeveloped acres and a contract right to receive approximately 99% of the net proceeds from the sale of production from certain producing gas and oil wells. In the separation, Vinland was conveyed the remaining 60% of our Predecessor’s working interest in the known producing horizons in this acreage, and 100% of our Predecessor’s working interest in depths above and 100 feet below our known producing horizons. Vinland operates all of our existing wells in Appalachia and all of the wells that we drilled in Appalachia. In October 2007, we completed our initial public offering (“IPO”) of 5.25 million units representing limited liability interests in VNR at $19.00 per unit for net proceeds of $92.8 million after deducting underwriting discounts and fees of $7.0 million. In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these Appalachia properties. See Note 13.Subsequent Events for further discussion.

On December 31, 2010, we acquired (the “ENP Purchase”) all of the member interests in ENP GP, the general partner of ENP, and 20,924,055 common units representing limited partnership interests in ENP (the “ENP Units”), together representing a 46.7% aggregate equity interest in ENP at the date of the ENP Purchase, from Denbury Resources Inc. (“Denbury”). As consideration for the purchase, we paid $300.0 million in cash and issued 3,137,255 VNR common units, valued at $93.0 million at December 31, 2010.

On December 1, 2011, we acquired the remaining 53.4% of the ENP Units not held by us through a merger (the “ENP Merger”) with one of our wholly owned subsidiaries. In connection with the ENP Merger, ENP’s public unitholders received 0.75 VNR common units in exchange for each ENP common unit they owned at the effective date of the ENP Merger, which resulted in the issuance of approximately 18.4 million

F-9

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

VNR common units valued at $511.4 million at December 1, 2011. We refer to the ENP Purchase and ENP Merger collectively as the “ENP Acquisition.”

In connection with closing of the ENP Purchase, VNG entered into a Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, with ENP, ENP GP, Encore Operating, L.P. (“Encore Operating”), OLLC and Denbury (the “Services Agreement”). The Services Agreement was amended solely to add VNG as a party and provide for VNG to assume the rights and obligations of Encore Operating and Denbury under the previous administrative services agreement going forward.

Pursuant to the Services Agreement, VNG provided certain general and administrative services to ENP, ENP GP and OLLC (collectively, the “ENP Group”) in exchange for a quarterly fee of $2.06 per BOE of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee was paid by ENP (the “Administrative Fee”). The Administrative Fee was subject to certain index-related adjustments on an annual basis. Effective April 1, 2011, the Administrative Fee decreased from $2.06 per BOE of ENP’s production to $2.05 per BOE as the Council of Petroleum Accountants Societies (“COPAS”) Wage Index Adjustment decreased 0.7 percent. ENP also was obligated to reimburse VNG for all third-party expenses it incurred on behalf of the ENP Group. These terms were identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement. The Services Agreement was terminated upon the completion of the ENP Merger.

1. Summary of Significant Accounting Policies

(a)Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of and for the years ended December 31, 2011, 2010 and 2009 include the accounts of VNR and its subsidiaries. As of December 31, 2010, we consolidated ENP as we had the ability to control the operating and financial decisions and policies of ENP through our ownership of ENP GP and reflected the non-controlling interest as a separate element of members’ equity on our consolidated balance sheet. On December 1, 2011, ENP became a wholly owned subsidiary of VNG.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and include the accounts of all subsidiaries after the elimination of all significant intercompany accounts and transactions. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity.

(b)Recently Adopted Accounting Pronouncements:

In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-29, “Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations (a consensus of the FASB Emerging Issues Task Force),” which includes amendments that affect any public entity as defined by Accounting Standards Codification (“ASC”) Topic 805 “Business Combinations” (“ASC Topic 805”), that enters into business combinations that are material on an individual or aggregate basis. The amendments in this guidance specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments were effective for us on January 1, 2011. As this guidance provides only disclosure requirements, the adoption of this standard did not impact our results of operations, cash flows or financial position.

F-10

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” intended to improve the comparability, consistency and transparency of financial reporting. The guidance is also intended to increase the prominence of items reported in other comprehensive income and to facilitate convergence of GAAP and International Financial Reporting Standards by eliminating the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. Under this guidance, entities are given two options for presenting other comprehensive income. The statement of other comprehensive income can be included with the statement of net income, which together will comprise the statement of total comprehensive income. Alternatively, the statement of other comprehensive income can be presented separate from the statement of net income. However, the guidance requires that the statement of other comprehensive income should immediately follow the statement of net income. The guidance also requires entities to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement where the components of net income and the components of other comprehensive income are presented. The guidance is effective for each reporting entity for interim and annual periods beginning after December 15, 2011. Early adoption is permitted, because compliance with the amendments is already permitted.

In December 2011, the FASB issued ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” to defer the changes in ASU No. 2011-05 that relate to the presentation of reclassification adjustments. The amendments are being made to allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. With the implementation of ASU No. 2011-12, entities should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU No. 2011-05. All other requirements in ASU No. 2011-05 are not affected by ASU No. 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements.

We have adopted ASU No. 2011-05 early except for the amendments to the presentation of reclassification of items out of accumulated other comprehensive income, the effective date of which have been deferred under ASU No. 2011-12 for fiscal years, and interim periods within those years, beginning after December 15, 2011. As the guidance under ASU No. 2011-12 provides only presentation requirements, the adoption of this standard will not have any impact on our results of operations, cash flows or financial position.

(c)New Pronouncements Issued But Not Yet Adopted:

In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” to achieve common fair value measurement and disclosure requirements in GAAP and IFRS. The guidance changes the wording used to describe the requirements in GAAP for measuring fair value and disclosures about fair value. The guidance includes clarification of the application of existing fair value measurements and disclosure requirements related to a) the application of highest and best use and valuation premise concepts; b) measuring the fair value of an instrument classified in a reporting entity’s stockholders’ equity; and c) disclosure of quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. Additionally, the guidance changes particular principles or requirements for measuring fair value and disclosing information about fair value measurements related to a) measuring the fair value of financial instruments that are managed within a portfolio; b) application of premiums and discounts in a fair value measurement; and c) additional requirements to expand the disclosures about fair value measurements. The guidance is effective for each reporting entity for interim

F-11

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

and annual periods beginning after December 15, 2011. The adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

In September 2011, the FASB issued ASU No. 2011-08, “Intangibles — Goodwill and Other (Topic 350): Testing Goodwill for Impairment,” intended to simplify how entities, both public and nonpublic, test goodwill for impairment. The guidance permits an entity to first assess qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in ASC Topic 350, “Intangibles — Goodwill and Other.” The more-likely-than-not threshold is defined as having a likelihood of more than 50%. The guidance is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted, including for annual and interim goodwill impairment tests performed as of a date before September 15, 2011, if an entity’s financial statements for the most recent annual or interim period have not yet been issued. As this guidance only provides changes in the procedures for testing the impairment of goodwill, the adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

In December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities,” which requires entities to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments under this guidance for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. As this guidance only requires changes in disclosures about offsetting assets and liabilities, the adoption of this standard is not expected to have any impact on our results of operations, cash flows or financial position.

(d)Cash Equivalents:

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.

(e)Accounts Receivable and Allowance for Doubtful Accounts:

Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. We establish provisions for losses on accounts receivable if we determine that it is likely that we will not collect all or part of the outstanding balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.

(f)Inventory:

Materials, supplies and commodity inventories are valued at the lower of cost or market. The cost is determined using the first-in, first-out method. Inventories are included in other current assets in the accompanying Consolidated Balance Sheets.

(g)Oil and Natural Gas Properties:

The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.

F-12

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values.

Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the Consolidated Statements of Operations as an impairment charge. Ceiling test calculations include the effects of the portion of oil and natural gas derivative contracts that have been recorded in other comprehensive income. We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2009 of $110.2 million. The impairment for the first quarter 2009 was $63.8 million as a result of a decline in natural gas prices at the measurement date, March 31, 2009. This impairment was calculated based on prices of $3.65 per MMBtu for natural gas and $49.64 per barrel of crude oil. The SEC’s Final Rule, “Modernization of Oil and Gas Reporting,” which became effective December 31, 2009, changed the price used to calculate oil and gas reserves to a 12-month average price rather than a period-end price. As a result of declines in oil and natural gas prices based upon the 12-month average price, we recorded an additional impairment of $46.4 million in the fourth quarter of 2009. This impairment was calculated using the 12-month average prices for oil and natural gas of $ 61.04 per barrel of crude oil and $3.87 per MMBtu for natural gas. No ceiling test impairment was required during 2010 or 2011.

When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.

(h)Goodwill and Other Intangible Assets:

We account for goodwill and other intangible assets under the provisions of the ASC Topic 350, “Intangibles — Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist. As discussed further in Note 2, all goodwill recognized in acquisitions other than the ENP Purchase has been determined to be impaired and written off. On October 1, 2011 we performed our annual impairment test for the goodwill recognized in the ENP Purchase, and we updated it on the date of the completion of the ENP Merger on December 1, 2011. The goodwill test is performed at the reporting unit level. We determined that we had two reporting units, which are Vanguard’s historical oil and natural gas operations in the United States and ENP’s oil and natural gas operations in the United States. At December 1, 2011, all goodwill was assigned to the reporting unit comprised of ENP’s oil and natural gas operations in the United States. If the fair value of the reporting unit is determined to be less than its carrying value, an impairment charge is recognized for the amount by which the carrying value of goodwill exceeds its implied fair value.

F-13

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

We utilize a market approach to determine the fair value of our reporting units. Our analysis concluded that there was no impairment of goodwill as of October 1, or December 1, 2011. Significant decreases in the prices of oil and natural gas or significant negative reserve adjustments subsequent to December 1, 2011 could change our estimate of the fair value of the reporting unit and could result in an impairment charge.

Intangible assets with definite useful lives are amortized over their estimated useful lives. We evaluate the recoverability of intangible assets with definite useful lives whenever events or changes in circumstances indicate that the carrying value of the asset may not be fully recoverable. An impairment loss exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount.

We are a party to a contract allowing us to purchase a certain amount of natural gas at a below market price for use as field fuel. As of December 31, 2011, the net carrying value of this contract was $9.0 million. The carrying value is shown as “Other intangible asset, net” on the accompanying Consolidated Balance Sheets and is amortized on a straight-line basis over the estimated life of the field. The estimated aggregate amortization expense for each of the next five fiscal years is $0.2 million per year.

(i)Asset Retirement Obligations:

We record a liability for asset retirement obligations at fair value in the period in which the liability is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. Our recognized asset retirement obligation exclusively relates to the plugging and abandonment of oil and natural gas wells and decommissioning of our Elk Basin gas plant. Management periodically reviews the estimates of the timing of well abandonments as well as the estimated plugging and abandonment costs, which are discounted at the credit adjusted risk free rate. These retirement costs are recorded as a long-term liability on the Consolidated Balance Sheets with an offsetting increase in oil and natural gas properties. An ongoing accretion expense is recognized for changes in the value of the liability as a result of the passage of time, which we record in depreciation, depletion, amortization and accretion expense in the Consolidated Statements of Operations.

(j)Revenue Recognition and Gas Imbalances:

Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. We sell oil, natural gas and NGLs on a monthly basis. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil, natural gas or NGL, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGL fluctuates to remain competitive with other available oil, natural gas and NGL supplies. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets.

The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at December 31, 2011 and 2010.

F-14

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

(k)Concentrations of Credit Risk:

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative contracts. We control our exposure to credit risk associated with these instruments by (i) placing our assets and other financial interests with credit-worthy financial institutions, (ii) maintaining policies over credit extension that include the evaluation of customers’ financial condition and monitoring payment history, although we do not have collateral requirements and (iii) netting derivative assets and liabilities for counterparties where we have a legal right of offset.

At December 31, 2011 and 2010, the cash and cash equivalents were concentrated in four financial institutions. We periodically assess the financial condition of these institutions and believe that any possible credit risk is minimal.

The following purchasers accounted for 10% or more of the Company’s oil, natural gas and NGLs sales for the years ended December 31:

	2011			2010			2009
Marathon Oil Company		22	%		—			—
Plains Marketing L.P		11	%		19	%		7	%
Shell Trading (US) Company		8	%		11	%		2	%
Seminole Energy Services		3	%		20	%		35	%

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.

(l)Use of Estimates:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties, the fair value of assets and liabilities acquired in business combinations, goodwill, derivative contracts, asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

(m)Price and Interest Rate Risk Management Activities:

We have entered into derivative contracts with counterparties that are lenders under our financing arrangements to hedge price risk associated with a portion of our oil and natural gas production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Under fixed-priced commodity swap agreements, the Company receives a fixed price on a notional quantity in exchange for paying a variable price based on a market index, such as the Columbia Gas Appalachian Index (“TECO Index”), Henry Hub, Houston Ship Channel, West Texas (“Waha Index”), El Paso Natural Gas Company (Permian Basin) or Colorado Interstate Gas Company (Rocky Mountains) for natural gas production and the West Texas Intermediate Light Sweet, Louisiana Light Sweet, Flint Hills Bow River and Imperial Bow River for oil production. In addition, we sell calls, purchase puts or provide options to counterparties under swaption agreements to extend the swaps into subsequent years. Under put option agreements, we pay the counterparty an option premium, equal to the fair value of the option at the purchase date. At settlement date we receive the excess, if any, of the fixed floor over the floating rate. We also enter into basis swap contracts which guarantee a price differential between the NYMEX prices and our physical

F-15

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

pricing points. We receive a payment from the counterparty or make a payment to the counterparty for the difference between the settled price differential and amounts stated under the terms of the contract. Under collar contracts, we pay the counterparty if the market price is above the ceiling price and the counterparty pays us if the market price is below the floor price on a notional quantity. Put options for natural gas are settled based on the NYMEX price for natural gas at Henry Hub and collars are settled based on a market index selected by us at inception of the contract. We also may enter into three-way collar contracts which combine a long put, a short put and a short call. The use of the long put combined with the short put allows us to sell a call at a higher price, thus establishing a higher ceiling and limiting our exposure to future settlement payments while also restricting our downside risk to the difference between the long put and the short put if the price of NYMEX West Texas Intermediate (“WTI”) crude oil drops below the price of the short put. This allows us to settle for WTI market price plus the spread between the short put and the long put in a case where the market price has fallen below the short put fixed price. We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our financing arrangements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.

Any premiums paid on derivative contracts and the fair value of derivative contracts acquired in connection with our acquisitions, are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or the contracts are assumed. Over time, as the derivative contracts settle, the premiums paid or fair value of contracts acquired are amortized and recognized as a realized gain or loss on other commodity or interest rate derivate contracts and reflected as non-cash adjustments to net income or loss in our consolidated statement of cash flows.

Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the Consolidated Balance Sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) in the equity section of the Consolidated Balance Sheets to the extent the hedge is effective. Gains and losses on cash flow hedges included in accumulated other comprehensive income (loss) are reclassified to gains (losses) on commodity cash flow hedges or gains (losses) on interest rate derivative contracts in the period that the related production is delivered or the contract settles. The realized and unrealized gains (losses) on derivative contracts that do not qualify for hedge accounting treatment are recorded as gains (losses) on other commodity derivative contracts or gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations.

We have elected not to designate our current portfolio of derivative contracts as hedges. Therefore, changes in fair value of these derivative instruments are recognized in earnings and included as unrealized gains (losses) on other commodity derivative contracts or gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations.

(n)Income Taxes:

The Company is treated as a partnership for federal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federal and state income tax. Its taxable income or loss, which may vary substantially from the net income or net loss reported in the Consolidated Statements of Operations, is included in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for the operations of the Company. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does

F-16

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

1. Summary of Significant Accounting Policies  – (continued)

not have access to information about each unitholders’ tax attributes in the Company. However, the tax basis of our net assets exceeded the net book basis by $41.9 million and $32.2 million at December 31, 2011 and 2010, respectively.

Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. The Company recorded a current tax liability of $0.7 million, $0.2 million and $0.1 million during the years ended December 31, 2011, 2010 and 2009, respectively, and a deferred tax asset of $0.2 million and $0.1 during the years ended December 31, 2011 and 2010, respectively. Tax provisions of $0.6 million and $0.2 million are included in our Consolidated Statements of Operations for the years ended December 31, 2011 and 2010, respectively, as a component of production and other taxes. For the year ended December 31, 2009, a benefit of $0.2 million is included in our Consolidated Statements of Operations as a component of production and other taxes.

2. Acquisitions

On July 17, 2009, we entered into a Purchase and Sale Agreement with Segundo for the acquisition of certain oil and natural gas properties located in the Sun TSH Field in La Salle County, Texas. We refer to this acquisition as the “Sun TSH Acquisition.” The purchase price for said assets was $52.3 million with an effective date of July 1, 2009. We completed this acquisition on August 17, 2009 for an adjusted purchase price of $50.8 million, after consideration of purchase price adjustments of approximately $1.8 million. This acquisition was funded with borrowings under our reserve-based credit facility and proceeds from the Company’s public equity offering of 3.9 million common units completed on August 17, 2009. Upon closing this transaction, we assumed natural gas puts and swaps based on NYMEX pricing for approximately 61% of the estimated gas production from existing producing wells in the acquired properties for the period beginning August 2009 through December 2010, which had a fair value of $4.1 million on the closing date.

In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Sun TSH Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $5.9 million, calculated in the following table. The gain resulted from the changes in oil and natural gas prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the Consolidated Statements of Operations.

	(in thousands)
Fair value of assets and liabilities acquired:
Oil and natural gas properties	$	54,942
Derivative assets		4,128
Other currents assets		187
Accrued expenses		(298	)
Asset retirement obligations		(2,254	)
Total fair value of assets and liabilities acquired		56,705
Fair value of consideration transferred		50,827
Gain on acquisition of oil and natural gas properties	$	5,878

F-17

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

2. Acquisitions  – (continued)

On November 27, 2009, we entered into a Purchase and Sale Agreement, Lease Amendment and Lease Royalty Conveyance Agreement and a Conveyance Agreement to acquire certain producing oil and natural gas properties located in Ward County, Texas in the Permian Basin from private sellers, referred to as the “Ward County Acquisition.” This transaction had an effective date of October 1, 2009 and was closed on December 2, 2009 for $55.0 million. This acquisition was initially funded with borrowings under our reserve-based credit facility with borrowings being reduced by $40.3 million shortly thereafter with the proceeds from a 2.6 million common unit offering. In an effort to support stable cash flows from this transaction, we entered into crude oil swaps based on NYMEX pricing for approximately 90% of the estimated oil production from existing producing wells in the acquired properties for the period beginning January 2010 through December 2013.

In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Ward County Acquisitions as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $1.1 million, calculated in the following table. The gain resulted from the changes in oil and natural gas prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the consolidated statement of operations.

	(in thousands)
Fair value of assets and liabilities acquired:
Oil and natural gas properties	$	56,347
Other currents assets		25
Asset retirement obligations		(248	)
Total fair value of assets and liabilities acquired		56,124
Fair value of consideration transferred		55,021
Gain on acquisition of oil and natural gas properties	$	1,103

On April 30, 2010, we entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Mississippi, Texas and New Mexico. We refer to this acquisition as the “Parker Creek Acquisition.” The purchase price for said assets was $113.1 million with an effective date of May 1, 2010. We completed this acquisition on May 20, 2010. The adjusted purchase price of $114.3 million considered final purchase price adjustments of approximately $1.2 million. The purchase price was funded from the approximate $71.5 million in net proceeds from our May 2010 equity offering and with borrowings under the Company’s existing reserve-based credit facility. In conjunction with the acquisition, we entered into crude oil hedges covering approximately 56% of the estimated production from proved producing reserves through 2013 at a weighted average price of $91.70 per barrel.

In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Parker Creek Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $5.7 million, calculated in the following table, which was immediately impaired and recorded as a loss. The loss resulted from a decrease in oil prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the consolidated statement of operations.

	(in thousands)
Fair value of assets and liabilities acquired:
Oil and natural gas properties	$	107,598
Other assets		1,505
Asset retirement obligations		(500	)
Total fair value of assets and liabilities acquired		108,603
Fair value of consideration transferred		114,283
Loss on acquisition of oil and natural gas properties	$	(5,680	)

F-18

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

2. Acquisitions  – (continued)

On December 12, 2011, we acquired additional working interest in the same oil properties acquired in the Parker Creek Acquisition located in Mississippi. We completed this acquisition on December 22, 2011 for a purchase price of $14.4 million. The effective date of this acquisition was December 1, 2011. The acquisition of additional working interest was funded with borrowings under the Company’s reserve-based credit facility.

In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the additional working interests acquired in the Parker Creek properties as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $0.4 million. The gain resulted from the changes in oil and natural gas prices used to value the reserves which has been recognized in current period earnings and classified in other income and expense in the Consolidated Statement of Operations.

As previously discussed, on December 31, 2010, we completed the ENP Purchase. The acquisition was accounted for under the acquisition method of accounting in accordance with ASC Topic 805. The acquisition method requires the assets and liabilities acquired to be recorded at their fair values at the date of acquisition. No results of operations were recorded in the consolidated statement of operations for the year ended December 31, 2010. Transaction costs related to the acquisition were approximately $3.6 million, which were expensed as incurred and recorded as “Selling, general and administrative expenses” in the consolidated statement of operations for the year ended December 31, 2010. The estimate of fair values as of December 31, 2010 are as follows (in thousands):

Consideration and non-controlling interest
Cash payment to acquire Encore Interests	$	300,000
Market value of Vanguard’s common units issued to Denbury(1)		93,020
Market value of non-controlling interest of Encore(2)		548,662
Consideration and non-controlling interest of Encore	$	941,682
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	$	18,048
Oil and natural gas payable		1,730
Current derivative liabilities		11,122
Other current liabilities		1,228
Long-term debt		234,000
Asset retirement obligations		24,385
Long-term derivative liabilities		25,331
Long-term deferred tax liability		11
Amount attributable to liabilities assumed	$	315,855
Less: fair value of assets acquired
Cash	$	1,380
Trade and other receivables		22,795
Current derivative assets		10,196
Other current assets		470
Oil and natural gas properties – proved		786,524
Long-term derivative assets		5,486
Other long-term assets		9,731
Amount attributable to assets acquired	$	836,582
Goodwill	$	420,955

F-19

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

2. Acquisitions  – (continued)

(1) Approximately 3.1 million Vanguard common units at $29.65 per unit were issued to Denbury to acquire the Encore Interests. The per unit price is the closing price of Vanguard’s common units at December 31, 2010.

(2) Represents approximate market value of the non-controlling interest of Encore (based on 24.4 million Encore common units outstanding as of December 31, 2010) at $22.47 per Encore common unit (closing price as of December 31, 2010).

As previously discussed, on December 1, 2011, we completed the ENP Merger and accounted for it as an equity transaction in accordance with ASC Topic 810 Subtopic 10, “Consolidations — Capital Changes of Subsidiaries” (“ASC Topic 810-10”). In accordance with ASC Topic 810-10, the difference of $16.0 million between the value of Vanguard common units issued for the exchange and the carrying amount of the non-controlling interest of $527.3 million at December 1, 2011 was recognized in equity.

On April 28, 2011, we entered into a purchase and sale agreement with a private seller for the acquisition of certain oil and natural gas properties located in Texas and New Mexico. We refer to this acquisition as the “Newfield Acquisition.” The purchase price for the assets was $9.1 million with an effective date of April 1, 2011. We completed this acquisition on May 12, 2011 for an adjusted purchase price of $9.2 million, subject to customary post-closing adjustments to be determined. This acquisition was funded with borrowings under our existing reserve-based credit facility. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Newfield Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $0.9 million, which was immediately impaired and recorded as a loss. The loss resulted from the changes in oil prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

On June 22, 2011, pursuant to two purchase and sale agreements, we and ENP agreed to acquire producing oil and natural gas assets in the Permian Basin in West Texas (the “Purchased Assets”) from a private seller. We and ENP agreed to purchase 50% of the Purchased Assets for an aggregate of $85.0 million and each paid the seller a non-refundable deposit of $4.25 million. We refer to this acquisition as the “Permian Basin Acquisition I.” The effective date of this acquisition is May 1, 2011. This acquisition was completed on July 29, 2011 for an aggregate adjusted purchase price of $81.4 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under financing arrangements existing at that time. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Permian Basin Acquisition I as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in goodwill of $0.7 million, subject to a 53.4% non-controlling interest which was immediately impaired and recorded as a loss. The loss resulted from the changes in oil prices used to value the reserves and has been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

On August 8, 2011, ENP entered into assignment agreements and completed the acquisition of certain oil and natural gas properties located in the Permian Basin of West Texas from a private seller. We refer to this acquisition as the “Permian Basin Acquisition II.” The adjusted purchase price for the assets was $14.8 million with an effective date of May 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Permian Basin Acquisition II approximates the fair value of consideration transferred, and therefore no gain or goodwill resulted from the acquisition.

F-20

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

2. Acquisitions  – (continued)

On August 15, 2011, ENP entered into a definitive agreement with a private seller for the acquisition of certain oil and natural gas properties located in Wyoming. We refer to this acquisition as the “Wyoming Acquisition.” The purchase price for the assets was $28.5 million with an effective date of June 1, 2011. ENP completed this acquisition on September 1, 2011 for an adjusted purchase price of $27.7 million, subject to customary post-closing adjustments to be determined. The purchase price was funded with borrowings under financing arrangements existing at that time. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Wyoming Acquisition as compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $1.1 million. The gain resulted from the changes in oil and natural gas prices used to value the reserves which has been recognized in current period earnings and classified in other income and expense in the Consolidated Statement of Operations.

On August 31, 2011, ENP entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the Texas and Louisiana onshore Gulf Coast area from a private seller. We refer to this acquisition as the “Gulf Coast Acquisition.” The adjusted purchase price for the assets was $47.6 million with an effective date of August 1, 2011. This acquisition was funded with borrowings under financing arrangements existing at that time. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the Gulf Coast Acquisition approximates the fair value of consideration transferred, and therefore no gain or goodwill resulted from the acquisition. As a result of post-closing adjustments, we recognized a loss of $0.3 million related to this acquisition.

On December 1, 2011, we entered into a definitive agreement and completed the acquisition of certain non-operated working interests in mature producing oil and natural gas properties located in the North Dakota from a private seller. We refer to this acquisition as the “North Dakota Acquisition.” The adjusted purchase price for the assets was $7.6 million with an effective date of September 1, 2011. This acquisition was funded with borrowings under our reserve-based credit facility. In accordance with the guidance contained within ASC Topic 805, the measurement of the fair value at acquisition date of the assets acquired in the North Dakota acquisition approximates the fair value of consideration transferred, and therefore no gain or goodwill resulted from the acquisition.

The following unaudited pro forma results for the years ended December 31, 2011, 2010 and 2009 show the effect on our consolidated results of operations as if (1) all of our and ENP’s acquisitions in 2011, including the ENP Merger, had occurred on January 1, 2010 (2) the Parker Creek Acquisition and ENP Purchase had occurred on January 1, 2010 and January 1, 2009 and (2) the Sun TSH and Ward County Acquisitions had occurred on January 1, 2009. The gains recognized on the Sun TSH and Ward County Acquisitions of $5.9 and $1.1 million, respectively, were excluded from the pro forma results for the year ended December 31, 2009, the loss recognized on the Parker Creek acquisition of $5.7 million was excluded from the pro forma results for the years ended December 31, 2010 and 2009, and the net loss on all of our and ENP’s acquisitions during 2011 of $0.4 million was excluded from the pro forma results for the years ended December 31, 2011 and 2010. The pro forma results reflect the results of combining our Consolidated Statements of Operations with the revenues and direct operating expenses of the oil and gas properties acquired in the Sun TSH, Ward County and Parker Creek Acquisitions, and all of our and ENP’s acquisitions in 2011 adjusted for (1) assumption of asset retirement obligations and accretion expense for the properties acquired, (2) depletion expense applied to the adjusted basis of the properties acquired using the acquisition method of accounting, (3) interest expense on additional borrowings necessary to finance the acquisitions, (4) non-cash impairment charge, and (5) the impact of additional common units issued in connection with our equity offerings completed at the time of the Ward County and Parker Creek Acquisitions. Additionally, the pro forma results reflect the results of combining our Consolidated Statements of Operations with ENP’s adjusted for (a) the conversion of ENP’s method of accounting for oil and natural gas properties from the

F-21

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

2. Acquisitions  – (continued)

successful efforts method of accounting to the full cost method of accounting, (b) the interest expense on additional borrowings necessary to finance the ENP Purchase, (c) the impact of additional common units issued in connection with the ENP Acquisition and (d) as it relates to the ENP Purchase, the allocable portion of ENP’s historical net income (loss) and the impact of adjustments (a) – (b) to earnings relating to the non-controlling interest of ENP for the year ended December 31, 2009. The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:

	Year Ended December 31,
	2011 Pro forma		2010 Pro forma		2009 Pro forma
	(in thousands, except per unit amounts) (unaudited)
Total revenues	$	355,654	$	322,591	$	185,259
Net income (loss)	$	103,153	$	58,722	$	(149,750	)
Net income (loss) attributable to non-controlling interest		—		—	$	(22,946	)
Net income (loss) attributable to VNR	$	103,153	$	58,722	$	(126,804	)
Net income (loss) per unit:
Common & Class B units – basic & diluted	$	2.12	$	1.22	$	(4.25	)

The amount of revenue and excess of revenues over direct operating expenses included in our 2011, 2010 and 2009 Consolidated Statements of Operations for each of our acquisitions mentioned above are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

	Year Ended December 31,
	2011		2010		2009
	(in thousands)
Sun TSH
Revenues	$	11,263	$	11,740	$	4,739
Excess of revenues over direct operating expenses	$	7,640	$	6,723	$	3,460
Ward County
Revenues	$	17,831	$	15,438	$	1,059
Excess of revenues over direct operating expenses	$	14,227	$	9,631	$	640
Parker Creek
Revenues	$	21,944	$	11,472	$	—
Excess of revenues over direct operating expenses	$	19,759	$	9,722	$	—
Newfield
Revenues	$	1,353	$	—	$	—
Excess of revenues over direct operating expenses	$	684	$	—	$	—
Permian Basin Acquisition I
Revenues	$	4,554	$	—	$	—
Excess of revenues over direct operating expenses	$	2,605	$	—	$	—
North Dakota
Revenues	$	278	$	—	$	—
Excess of revenues over direct operating expenses	$	232	$	—	$	—

F-22

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

2. Acquisitions  – (continued)

The amount of revenues and earnings included in our 2011 Consolidated Statements of Operations for the ENP Acquisition, including ENP’s acquisitions completed during 2011, are shown in the table that follows (in thousands). As the ENP Purchase was completed on December 31, 2010, no results of operations were included for the year ended December 31, 2010.

	Year Ended December 31, 2011
ENP
Revenues	$	213,610
Net income	$	65,718

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for ENP’s acquisitions completed during 2011, including the Permian Basin Acquisition I, Permian Basin Acquisition II, Wyoming Acquisition and Gulf Coast Acquisition are shown in the table that follows (in thousands). Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

	Year Ended December 31, 2011
Permian Basin Acquisition I
Revenues	$	4,554
Excess of revenues over direct operating expenses	$	2,605
Permian Basin Acquisition II
Revenues	$	1,013
Excess of revenues over direct operating expenses	$	371
Wyoming Acquisition
Revenues	$	2,437
Excess of revenues over direct operating expenses	$	2,102
Gulf Coast Acquisition
Revenues	$	4,109
Excess of revenues over direct operating expenses	$	2,973

3. Accounts Receivable and Allowance for Doubtful Accounts

In May 2007, we established an approximate $1.0 million allowance for a loss on the entire amount due from a customer which filed for protection under Chapter 11 of the Bankruptcy Code. The account receivable was due from oil sales through December 2006 at which time we ceased selling oil to the customer. As the amount of any potential recovery is uncertain, we elected to reserve the entire balance and it is reflected as bad debt expense on our consolidated statement of operations for the year ended December 31, 2007. We began selling our oil production to a new customer beginning in March 2007. As the accounts receivable was deemed uncollectible, we wrote off the receivable against the allowance during the year ended December 31, 2009.

F-23

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

4. Long-Term Debt

Our financing arrangements consisted of the following:

	Interest Rate			Maturity Date		Amount Outstanding
						December 31,
Description						2011		2010
						(in thousands)
Senior secured reserve-based credit facility		Variable	(1)		October 31, 2016	$	671,000	$	176,500
Second Lien Term Loan		Variable	(2)		May 30, 2017		100,000		—
Term Loan		Variable	(3)		December 31, 2011		—		175,000
ENP’s Credit Agreement		Variable	(4)		March 7, 2012		—		234,000
Total debt							771,000		585,500
Less: current obligations							—		(175,000	)
Total long term debt						$	771,000	$	410,500

(1) Variable interest rate was 2.55% and 3.0% at December 31, 2011 and 2010, respectively.

(2) Variable interest rate was 5.8% at December 31, 2011

(3) Variable interest rate was 5.77% at December 31, 2010.

(4) Weighted average interest rate was 2.79% at December 31, 2010.

Senior Secured Reserve-Based Credit Facility

On September 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) with a maximum facility of $1.5 billion (the “reserve-based credit facility”) and an initial borrowing base of $765.0 million. The Credit Agreement provides for the (1) extension of the maturity date by five years maturing on October 31, 2016, (2) increase in the number of lenders from eight to twenty, (3) increase in the percentage of future production that can be hedged, (4) increase in the permitted debt to EBITDA coverage ratio from 3.5x to 4.0x, (5) elimination of the required interest coverage ratio, (6) elimination of the ten percent liquidity requirement to pay distributions to unitholders, and (7) ability to incur unsecured debt. Borrowings from this reserve-based credit facility and the Second Lien Term Loan Facility (as discussed below) were used to fully repay outstanding borrowings from the ENP Credit Agreement and Vanguard’s $175.0 million Term Loan (as discussed below). In November 2011, we entered into the First Amendment to the Third Amended and Restated Credit Agreement, which included amendments to (a) specify the effective date of November 30, 2011, (b) allow us to use the proceeds from our reserve-based credit facility to refinance our debt under the Term Loan Facility, (c) include the current maturities under the Second Lien Term Loan in determining the consolidated current ratio, and (d) provide a cap on the amount of outstanding debt under the Second Lien Term Loan. Our obligations under the reserve-based credit facility are secured by mortgages on our oil and natural gas properties and other assets and are guaranteed by all of our operating subsidiaries.

On December 31, 2011 there were $671.0 million of outstanding borrowings and $94.0 million of borrowing capacity under the reserve-based credit facility.

F-24

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

4. Long-Term Debt  – (continued)

Interest rates under the reserve-based credit facility are based on Euro-Dollars (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At December 31, 2011, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage	<25%			25% <50%			50% <75%			75% <90%			90%
Eurodollar Loans Margin		1.50	%		1.75	%		2.00	%		2.25	%		2.50	%
ABR Loans Margin		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%
Commitment Fee Rate		0.50	%		0.50	%		0.375	%		0.375	%		0.375	%
Letter of Credit Fee		0.50	%		0.75	%		1.00	%		1.25	%		1.50	%

Our reserve-based credit facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. At December 31, 2011, we were in compliance with all of our debt covenants.

Our reserve-based credit facility requires us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production. See Note 5.Price and Interest Rate Risk Management Activities for further discussion.

Senior Secured Second Lien Term Loan

On November 30, 2011, we entered into a $100.0 million senior secured second lien term loan facility (the “Second Lien Term Loan”) with seven banks that are lenders in the reserve-based credit facility, with a maturity date of May 30, 2017. Our obligations under the Second Lien Term Loan are secured by a second priority lien on all of our oil and natural gas properties and other assets and are guaranteed by all of our operating subsidiaries.

Borrowings under the Second Lien Term Loan are comprised entirely of Eurodollar Loans. Interest on borrowings under the Second Lien Term Loan is payable quarterly on the last day of each March, June, September and December and accrues at a rate per annum equal to the sum of the applicable margin plus the Adjusted LIBO Rate in effect on such day. The applicable margin increases based upon the number of days after the effective date of the Second Lien Term Loan as follows:

	Days after effective date
	1 – 180			181 – 360			360+
Applicable Margin		5.50	%		6.00	%		8.50	%

The effective dates of the increase in the applicable margins will accelerate if we are unable to comply with the requirements under the Second Lien Term Loan agreement as it relates to title covering oil and natural gas properties included in our reserve reports as indicated below:

	Until 1/15/12			1/16/12 –  5/30/12			5/31/12 and thereafter
Applicable Margin		5.50	%		6.00	%		8.50	%

F-25

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

4. Long-Term Debt  – (continued)

Our Second Lien Term Loan facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. At December 31, 2011, we were in compliance with all of our debt covenants.

Term Loan

Concurrent with the ENP Purchase, VNG entered into a $175.0 million term loan (the “Term Loan”) with BNP Paribas to fund a portion of the consideration for the acquisition. Borrowings from the reserve-based credit facility and the Second Lien Term Loan were used to fully repay outstanding borrowings from the Term Loan in December 2011.

ENP’s Credit Agreement

ENP was a party to a five-year credit agreement (the “ENP Credit Agreement”) dated March 7, 2007 with a maturity date of March 7, 2012. All outstanding debt under this facility was repaid in full from proceeds under our reserve-based credit facility.

5. Price and Interest Rate Risk Management Activities

In December 2009, in an effort to support stable cash flows from the Ward County Acquisition, we entered into crude oil swaps based on NYMEX pricing for approximately 90% of the estimated oil production from existing producing wells in the acquired properties for the period beginning January 2010 through December 2013. In addition, we entered into NYMEX oil swap and collar derivative contracts for the period from January 1, 2012 through December 31, 2013 in order to support the cash flow to be received from oil production in other regions.

In May 2010, in connection with the Parker Creek Acquisition, we entered into crude oil hedges covering approximately 56% of the estimated production from proved producing reserves through 2013 at a weighted average price of $91.70 per barrel.

In June 2011, in connection with the Permian Basin I Acquisition, we entered into natural gas swaps based on NYMEX pricing for approximately 100% of the estimated gas production from existing producing wells for the period beginning January 2012 through December 2013 at significantly higher prices than current market by selling gas swaptions and calls in 2014. Additionally, we entered into oil swaps covering 100% of the oil production for the period beginning August 2011 through December 2012 at higher prices than current market by selling oil swaptions and calls in 2013. Also, because production from the acquired properties is primarily NGLs, we entered into three-way oil collars covering 50% of the production for the period from August 2011 through December 2013.

In August 2011, in an effort to support stable cash flows from the Permian Basin II Acquisition, we entered into crude oil swaps based on NYMEX pricing for approximately 90% of the estimated oil production from existing producing wells in the acquired properties for the period beginning January 2012 through December 2014.

In September 2011, in connection with the Wyoming Acquisition, we entered into crude oil hedges in the form of three-way collars covering approximately 55% of the estimated NGLs production from proved producing reserves for the period beginning October 2011 through December 2013. In addition, we entered into NYMEX natural gas swaps and gas basis swaps on approximately 85% of the proved producing gas reserves for the period beginning October 2011 through the end of June 2014. Also in September 2011, in connection with the Gulf Coast Acquisition, we entered into crude oil three-way collars covering 55% of the estimated oil production from proved producing reserves for October 2011 through December 2013.

F-26

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

5. Price and Interest Rate Risk Management Activities  – (continued)

Additionally, to protect the premium to WTI received on the oil production, we entered into oil basis swaps covering approximately 70% of the oil production from proved producing reserves for the period beginning September 2011 to December 2013.

In December 2011, in connection with the North Dakota Acquisition, we entered into crude oil three-way collars covering 100% of the production from proved producing reserves for the period beginning January 2012 through December 2014. Concurrently, we entered into crude oil three-way collars covering 100% of the production from proved producing reserves for the additional working interests acquired in the Parker Creek Acquisition for the period beginning January 2012 through December 2014. In both instances, we were able to hedge a small portion of our base production that exceeded the current production from these acquisitions.

In addition, through the course of the year, we entered into NYMEX oil swaps, three-way collar contracts and NYMEX gas swaps for periods ranging from January 1, 2012 through December 31, 2014 in order to support the cash flow to be received from production in other regions.

At December 31, 2011, the Company had open commodity derivative contracts covering our anticipated future production as follows:

Swap Agreements

	Gas				Oil
Contract Period	MMBtu		Weighted Average Fixed Price		Bbls		WTI Price
January 1, 2012 – December 31, 2012		5,929,932	$	5.51		1,487,790	$	87.95
January 1, 2013 – December 31, 2013		6,460,500	$	5.24		1,423,500	$	89.17
January 1, 2014 – December 31, 2014		452,500	$	4.80		1,414,375	$	89.91

Swaptions

Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:

	Gas				Oil
Contract Period	MMBtu		Weighted Average Fixed Price		Bbls		Weighted Average Fixed Price
January 1, 2012 – December 31, 2012		—		—		137,250	$	100.00
January 1, 2013 – December 31, 2013		—		—		196,350	$	100.73
January 1, 2014 – December 31, 2014		1,642,500	$	5.69		127,750	$	95.00
January 1, 2015 – December 31, 2015		—		—		328,500	$	95.56

Basis Swaps

As of December 31, 2011, the Company had the following open basis swap contracts:

	Gas					Oil
Contract Period	MMBtu		Weighted Avg. Basis Differential(1)			Bbls		Weighted Avg Basis Differential(2)
January 1, 2012 – December 31, 2012		915,000	$	(0.32	)		84,000	$	15.15
January 1, 2013 – December 31, 2013		912,500	$	(0.32	)		84,000	$	9.60
January 1, 2014 – December 31, 2014		452,500	$	(0.32	)		—	$	—

F-27

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

5. Price and Interest Rate Risk Management Activities  – (continued)

(1) Natural gas basis swap contracts represent a weighted average differential between prices against Rocky Mountains (CIGC) and NYMEX Henry Hub prices.

(2) Oil basis swap contracts represent a weighted average differential between prices against Light Louisiana Sweet Crude (LLS) and NYMEX WTI prices.

Collars

	Oil
Production Period	Bbls		Floor		Ceiling
January 1, 2012 – December 31, 2012		411,750	$	80.89	$	99.47
January 1, 2013 – December 31, 2013		82,125	$	88.89	$	107.34
January 1, 2014 – December 31, 2014		12,000	$	100.00	$	116.20

Three-Way Collars

	Oil
Production Period	Bbls		Floor		Ceiling		Put Sold
January 1, 2012 – December 31, 2012		640,500	$	85.14	$	101.70	$	67.14
January 1, 2013 – December 31, 2013		688,650	$	90.91	$	104.01	$	65.57
January 1, 2014 – December 31, 2014		164,250	$	93.33	$	105.00	$	70.00

Puts

	Gas
Contract Period	MMBtu		Weighted Average Fixed Price
January 1, 2012 – December 31, 2012		328,668	$	6.76

Interest Rate Swaps

We enter into interest rate swap agreements, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.

In August 2010 we entered into two new interest rate swap agreements which fixed the LIBOR rate at 2.09% on $25.0 million of borrowings for the period of August 6, 2012 to August 6, 2014 and 2.25% on $30.0 million from August 6, 2012 to August 5, 2015. Under this second agreement the counterparty has the option to extend the 2015 termination date to August 5, 2018. In June and July 2011, we amended three existing interest rate swap agreements. The first amended agreement reset the notional amount from $20.0 million to $40.0 million, extended the term an additional 2 years to January 31, 2015 and also reduced the rate from 2.66% to 1.75%. In addition, the second amended agreement reduced the fixed LIBOR rate from 3.35% to 2.60% on $20.0 million and the maturity was extended two additional years to December 10, 2014. The third amended agreement reduced the fixed LIBOR rate from 2.38% to 1.89% on $20.0 million and the maturity was extended two additional years to January 31, 2015. In September 2011, we entered into three new agreements which fixed the LIBOR rate at 1.15% on $25.0 million of borrowings each for a total of $75.0 million for 5 years beginning on September 23, 2011. In addition, in September 2011 we amended an existing agreement that was set to expire in March 2012. We reset the notional amount from $50.0 million to $75.0 million, extended the term an additional 4 years to March 7, 2016 and also reduced the rate from 2.42% to 1.08%, effective October 7, 2011. In November 2011, we entered into an agreement where we sold the option to the counterparty to put us into a $25.0 million swap at 1.25% for the period of September 7, 2012 to September 7, 2016 for $180,000 paid to us. The counterparty must decide whether to exercise this option on September 5, 2012.

F-28

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

5. Price and Interest Rate Risk Management Activities  – (continued)

At December 31, 2011, the Company had open interest rate derivative contracts as follows (in thousands):

	Notional Amount		Fixed Libor Rates
Period:
January 1, 2012 to December 10, 2014	$	20,000		2.60	%
January 1, 2012 to January 31, 2015	$	40,000		1.75	%
January 1, 2012 to January 31, 2015	$	20,000		1.89	%
January 1, 2012 to September 23, 2016	$	75,000		1.15	%
August 6, 2012 to August 6, 2014	$	25,000		2.09	%
August 6, 2012 to August 5, 2015(1)	$	30,000		2.25	%
January 1, 2012 to March 7, 2016	$	75,000		1.08	%
September 7, 2012 to September 7, 2016	$	25,000		1.25	%

(1) The counterparty has the option to extend the termination date of a contract for a notional amount of $30.0 million at 2.25% to August 5, 2018.

Balance Sheet Presentation

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following summarizes the fair value of derivatives outstanding on a gross basis.

	December 31,
	2011			2010
	(in thousands)
Assets:
Commodity derivatives	$	42,504		$	33,435
Interest rate swaps		504			97
	$	43,008		$	33,532
Liabilities:
Commodity derivatives	$	(66,129	)	$	(48,008	)
Interest rate swaps		(6,768	)		(4,115	)
	$	(72,897	)	$	(52,123	)

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. Our counterparties are participants in our reserve-based credit facility (See Note 4. Long-Term Debt for further discussion) which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $43.0 million at December 31, 2011.

We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments only with counterparties that are also lenders in our reserve-based credit facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of December 31, 2011.

F-29

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

5. Price and Interest Rate Risk Management Activities  – (continued)

Gain (Loss) on Derivatives

Realized gains (losses) represent amounts related to the settlement of other commodity and interest rate derivative contracts. Unrealized gains (losses) represent the change in fair value of other commodity and interest rate derivative contracts that will settle in the future and are non-cash items.

The following presents our reported gains and losses on derivative instruments at December 31:

	2011			2010			2009
	(in thousands)
Realized gains (losses):
Other commodity derivatives	$	10,276		$	24,774		$	29,993
Interest rate swaps		(2,874	)		(1,799	)		(1,903	)
	$	7,402		$	22,975		$	28,090
Unrealized gains (losses):
Other commodity derivatives	$	(470	)	$	(14,145	)	$	(19,043	)
Interest rate swaps		(2,088	)		(349	)		763
	$	(2,558	)	$	(14,494	)	$	(18,280	)
Total gains (losses):
Other commodity derivatives	$	9,806		$	10,629		$	10,950
Interest rate swaps		(4,962	)		(2,148	)		(1,140	)
	$	4,844		$	8,481		$	9,810

6. Fair Value Measurements

We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the consolidated balance sheet, as well as to supplemental fair value information about financial instruments not carried at fair value.

The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts as discussed below:

Cash and cash equivalents, accounts receivable, other current assets, accounts payable, payables to affiliates and accrued expense.  The carrying amounts approximate fair value due to the short maturity of these instruments.

Financing arrangements.  The carrying amounts of our borrowings outstanding under reserve-based credit facility and Second Lien Term Loan approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings.

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis. This includes oil, natural gas and interest rate derivatives contracts. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding

F-30

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

6. Fair Value Measurements  – (continued)

fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. These assumptions include certain factors not consistently provided for previously by those companies utilizing fair value measurement; examples of such factors would include our own credit standing (when valuing liabilities) and the buyer’s risk premium. In adopting ASC Topic 820, we determined that the impact of these additional assumptions on fair value measurements did not have a material effect on our financial position or results of operations.

ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as lowest) of significant input to the fair value estimation process.

The standard describes three levels of inputs that may be used to measure fair value:

Level 1 Quoted prices for identical instruments in active markets.

Level 2 Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.

Level 3 Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of external corroboration as to the inputs used.

As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Our commodity derivative instruments consist of fixed-price swaps, basis swaps, swaptions, put options, NYMEX collars and three-way collars. We estimate the fair values of the swaps and swaptions based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings, collars and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest rate swap market data. To extrapolate future cash flows,

F-31

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

6. Fair Value Measurements  – (continued)

discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows. We have classified the fair values of all of our derivative contracts as Level 2.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below:

	December 31, 2011
	Fair Value Measurements Using							Assets/Liabilities at Fair value
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Commodity price derivative contracts	$	—	$	3,438		$	—	$	3,438
Interest rate derivative contracts		—		—			—		—
Total derivative instruments	$	—	$	3,438		$	—	$	3,438
Liabilities:
Commodity price derivative contracts	$	—	$	(27,063	)	$	—	$	(27,063	)
Interest rate derivative contracts		—		(6,264	)		—		(6,264	)
Total derivative instruments	$	—	$	(33,327	)	$	—	$	(33,327	)

	December 31, 2010
	Fair Value Measurements Using							Assets/Liabilities at Fair value
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Commodity price derivative contracts	$	—	$	29,601		$	—	$	29,601
Interest rate derivative contracts		—		643			—		643
Total derivative instruments	$	—	$	30,244		$	—	$	30,244
Liabilities:
Commodity price derivative contracts	$	—	$	(44,173	)	$	—	$	(44,173	)
Interest rate derivative contracts		—		(4,662	)		—		(4,662	)
Total derivative instruments	$	—	$	(48,835	)	$	—	$	(48,835	)

Our nonfinancial assets and liabilities, that are initially measured at fair value are comprised primarily of asset retirement costs and obligations. These assets and liabilities are recorded at fair value when incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 7, in accordance with ASC Topic 410-20. During the year ended December 31, 2011, in connection with oil and natural gas properties acquired in all of our and ENP’s 2011 acquisitions, and as well as new wells drilled during the year, we incurred and recorded asset retirement obligations totaling $4.9 million at fair value. During the year ended December 31, 2010, in connection with oil and natural gas properties acquired in the Parker Creek and ENP Purchase, as well as new wells drilled during the year, we incurred and recorded asset retirement obligations totaling $25.7 million at fair value. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.8% and 7.0%; and (4) the average inflation factor (2.3%).

F-32

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

7. Asset Retirement Obligations

The asset retirement obligations as of December 31 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the year ended December 31, were as follows:

	2011			2010
	(in thousands)
Asset retirement obligation at January 1,	$	30,202		$	4,420
Liabilities added during the current period		4,934			25,663
Accretion expense		874			132
Revisions of estimate		(90	)		(13	)
Total asset retirement obligation at December 31,		35,920			30,202
Less: current obligations		(1,144	)		(768	)
Long-term asset retirement obligation at December 31,	$	34,776		$	29,434

Accretion expense for the years ended December 31, 2011, 2010 and 2009 was $0.9 million, $0.1 million and $0.1 million, respectively.

8. Related Party Transactions

In Appalachia, we rely on Vinland to execute our drilling program, operate our wells and gather our natural gas. We reimburse Vinland $60.00 per well per month (in addition to normal third party operating costs) for operating our current natural gas and oil properties in Appalachia under a Management Services Agreement (“MSA”) which costs are reflected in our lease operating expenses. Pursuant to an amendment to the MSA, we reimbursed Vinland $95.00 per well per month for the period from March 1, 2009 through December 31, 2009. Under a Gathering and Compression Agreement (“GCA”), Vinland receives a $0.25 per Mcf transportation fee on existing wells drilled at December 31, 2006 and $0.55 per Mcf transportation fee on any new wells drilled after December 31, 2006 within the area of mutual interest or “AMI.” The GCA was amended for the period beginning March 1, 2009 through December 31, 2009, to provide for a temporary fee based upon the actual costs incurred by Vinland to provide gathering and transportation services plus a $0.05 per mcf margin. The amendments to the MSA and the GCA expired on December 31, 2009 and all the terms of the agreements reverted back to the original agreements. In June 2010, we began discussions with Vinland regarding an amendment to the GCA to go into effect beginning on July 1, 2010. The amended agreement would provide gathering and compression services based upon actual costs plus a margin of $.055 per mcf. We and Vinland agreed in principle to this change effective July 1, 2010 and we have jointly operated on this basis since then, however, no formal agreement between us and Vinland has been signed. Under the GCA, the transportation fee that we pay to Vinland only encompasses transporting the natural gas to third party pipelines at which point additional transportation fees to natural gas markets would apply. These transportation fees are outlined in the GCA and are reflected in our lease operating expenses. For the years ended December 31, 2011, 2010 and 2009, costs incurred under the MSA were $1.9 million, $1.9 million and $1.6 million, respectively and costs incurred under the GCA were $1.8 million, $1.4 million and $1.2 million, respectively. A payable of $0.5 million and $0.6 million, respectively, is included in our December 31, 2011 and 2010 Consolidated Balance Sheets in connection with these agreements and direct expenses incurred by Vinland related to the drilling of new wells and operations of all of our existing wells in Appalachia.

On April 1, 2009, we and our wholly-owned subsidiary, TEC, exchanged several wells and lease interests (the “Asset Exchange”) with Vinland, Appalachian Royalty Trust, LLC, and Nami Resources Company, L.L.C. (collectively, the “Nami Companies”). Each of the Nami Companies is beneficially owned by Majeed S. Nami, who, as of December 31, 2011, beneficially owned 3.0% of our common units representing limited liability company interests. In the Asset Exchange, we assigned well, strata and leasehold interests with internal estimated future cash flows of approximately $2.7 million discounted at 10%, and received well, strata, and leasehold interests with an approximately equal value; therefore no gain or loss was recognized.

F-33

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

8. Related Party Transactions  – (continued)

In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these Appalachia properties. See Note 13.Subsequent Events for further discussion.

In connection with closing of the ENP Purchase, VNG entered into a Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, with ENP, ENP GP, Encore Operating, L.P. (“Encore Operating”), OLLC and Denbury (the “Services Agreement”). The Services Agreement was amended solely to add VNG as a party and provide for VNG to assume the rights and obligations of Encore Operating and Denbury under the previous administrative services agreement going forward.

Pursuant to the Services Agreement, as amended, VNG provided certain general and administrative services to ENP, ENP GP and OLLC (collectively, the “ENP Group”) in exchange for a quarterly fee of $2.06 per BOE of the ENP Group’s total net oil and gas production for the most recently-completed quarter, which fee is paid by ENP (the “Administrative Fee”). The Administrative Fee was subject to certain index-related adjustments on an annual basis. Effective April 1, 2011, the Administrative Fee decreased from $2.06 per BOE of ENP’s production to $2.05 per BOE as the Council of Petroleum Accountants Societies (“COPAS”) Wage Index Adjustment decreased 0.7 percent. ENP was also obligated to reimburse VNG for all third-party expenses it incurred on behalf of the ENP Group. These terms were identical to the terms under which Denbury and Encore Operating provided administrative services to the ENP Group prior to the second amendment and restatement of the Services Agreement. During the year ended December 31, 2011, VNG received administrative fees amounting to $6.1 million, COPAS recovery amounting to $5.1 million and reimbursements of third-party expenses amounting to $5.8 million. In December 2011, the Services Agreement was terminated pursuant to the ENP Merger.

9. Commitments and Contingencies

The Company is a defendant in a legal proceeding arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow.

We are also currently a party to pending litigation related to the ENP Merger. On March 29, 2011, John O’Neal, a purported unitholder of ENP, filed a putative class action petition in the 125th Judicial District of Harris County, Texas on behalf of unitholders of ENP. Similar petitions were filed on April 4, 2011 by Jerry P. Morgan and on April 5, 2011 by Herbert F. Rower in other Harris County district courts. TheO’Neal,Morgan, andRower lawsuits were consolidated on June 5, 2011 asJohn O’Neal v. Encore Energy Partners, L.P., et al., Case Number 2011-19340, which is pending in the 125th Judicial District Court of Harris County. On July 28, 2011, Michael Gilas filed a class action petition in intervention. On July 26, 2011, the current plaintiffs in the consolidatedO’Neal action filed an amended putative class action petition against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action petition and Gilas’s petition in intervention both allege that the named defendants are (i) violating duties owed to ENP’s public unitholders by, among other things, failing to properly value ENP and failing to protect against conflicts of interest or (ii) are aiding and abetting such breaches. Plaintiffs seek an injunction prohibiting the merger from going forward and compensatory damages if the merger is consummated. On October 3, 2011, the Court appointed Bull & Lifshitz, counsel for plaintiff-intervenor Gilas, as interim lead counsel on behalf of the putative class. On October 21, 2011, the court signed an order staying this lawsuit pending resolution of the Delaware State Court Action (defined below), subject to plaintiffs’ right to seek to lift the stay for good cause. The defendants named in the Texas lawsuits intend to defend vigorously against them.

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Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

9. Commitments and Contingencies  – (continued)

On April 5, 2011, Stephen Bushansky, a purported unitholder of ENP, filed a putative class action complaint in the Delaware Court of Chancery on behalf of the unitholders of ENP. Another purported unitholder of ENP, William Allen, filed a similar action in the same court on April 14, 2011. The Bushansky and Allen actions have been consolidated under the captionIn re: Encore Energy Partners LP Unitholder Litigation, C.A. No. 6347-VCP (the “Delaware State Court Action”). On December 28, 2011, those plaintiffs jointly filed their second amended consolidated class action complaint naming as defendants ENP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard. That putative class action complaint alleges, among other things, that defendants breached the partnership agreement by recommending a transaction that is not fair and reasonable. Plaintiffs seek compensatory damages. Vanguard has filed a motion to dismiss this lawsuit and it intends to defend vigorously against this lawsuit.

On August 28, 2011, Herman Goldstein, a purported unitholder of ENP, filed a putative class action complaint against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard in the United States District Court for the Southern District of Texas on behalf of the unitholders of ENP. That lawsuit is captionedGoldstein v. Encore Energy Partners LP. et al., United States District Court for the Southern District of Texas, 4:11-cv-03198. Goldstein alleges that the named defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder by disseminating a false and materially misleading proxy statement in connection with the merger. Plaintiff seeks an injunction prohibiting the proposed merger from going forward. Currently, the parties are awaiting the appointment of a lead plaintiff in this lawsuit. The defendants named in this lawsuit intend to defend vigorously against it.

On September 6, 2011, Donald A. Hysong, a purported unitholder of ENP, filed a putative class action complaint against ENP, ENP GP, Scott W. Smith, Richard A. Robert, Douglas Pence, W. Timothy Hauss, John E. Jackson, David C. Baggett, Martin G. White, and Vanguard on behalf of the unitholders of ENP in the United States District Court for the District of Delaware that is captionedHysong v. Encore Energy Partners LP. et al., 1:11-cv-00781-SD. Hysong alleged that the named defendants violated either Section 14(a) of the Securities Exchange Act of 1934 and Rule 14a-9 promulgated thereunder or Section 20(a) of the Securities Exchange Act of 1934 by disseminating a false and materially misleading proxy statement in connection with the merger. On September 14, 2011, in accordance with recent practice in Delaware, that case was assigned to Judge Stewart Dalzell of the Eastern District of Pennsylvania. On November 10, 2011, Judge Dalzell entered an order dismissing the lawsuit and entering judgment in the defendants’ favor.

Vanguard cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of this filing, nor can Vanguard predict the amount of time and expense that will be required to resolve these lawsuits, therefore Vanguard has not accrued a liability related to these lawsuits. Vanguard, ENP and the other defendants named in these lawsuits intend to defend vigorously against these and any other actions.

10. Common Units and Net Income (Loss) per Unit

Basic earnings per unit is computed in accordance with ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”), by dividing net income (loss) attributable to Vanguard unitholders by the weighted average number of units outstanding during the period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. As of December 31, 2011, we have two classes of units outstanding: (i) units representing limited liability company interests (“common units”) listed on NYSE under the symbol VNR and (ii) Class B units, issued to management and an employee as discussed in Note 11.Unit-Based Compensation. The Class B units participate in distributions and no forfeiture is expected; therefore, all Class B units were considered in the computation of basic earnings per unit. The 175,000 options granted to officers under our long-term incentive plan had a dilutive effect for the year ended December 31, 2011 and

F-35

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

10. Common Units and Net Income (Loss) per Unit  – (continued)

2010; therefore, they have been included in the computation of diluted earnings per unit. However, these options did not have a dilutive effect for the year ended December 31, 2009; therefore, they have been excluded in the computation of diluted earnings per unit. In addition, the phantom units granted to officers under our long-term incentive plan did not have a dilutive effect for the years ended December 31, 2011, 2010 and 2009; therefore, they have also been excluded in the computation of diluted earnings per unit.

In accordance with ASC Topic 260, dual presentation of basic and diluted earnings per unit has been presented in the Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009 including each class of units issued and outstanding at that date: common units and Class B units. Net income (loss) per unit is allocated to the common units and the Class B units on an equal basis.

11. Unit-Based Compensation

In April 2007, the sole member at that time reserved 460,000 restricted Class B units in VNR for issuance to employees. Certain members of management were granted 365,000 restricted VNR Class B units in April 2007, which vested in April 2009, two years from the date of grant. In addition, another 55,000 restricted VNR Class B units were issued in August 2007 to two other employees that were hired in April and May of 2007, which vested in April and May 2010, three years after the date of grant. The remaining 40,000 restricted VNR Class B units were not granted and are not expected to be granted in the future. In October 2007, two officers were granted options to purchase an aggregate of 175,000 units under the Vanguard Natural Resources, LLC Long-Term Incentive Plan (“the VNR LTIP”) with an exercise price equal to the initial public offering price of $19.00, which vested immediately upon being granted and had a fair value of $0.1 million on the date of grant. These options expire on October 29, 2012. The grant date fair value for these option awards was calculated in accordance with ASC Topic 718, “Compensation — Stock Compensation,” by calculating the Black-Scholes value of each option, using a volatility rate of 12.18%, an expected dividend yield of 8.95% and a discount rate of 5.12%, and multiplying the Black-Scholes value by the number of options awarded. In determining a volatility rate of 12.18%, we, due to a lack of historical data regarding our common units, used the historical volatility of the Citigroup MLP Index over the 365 day period prior to the date of grant.

In February 2010, we and VNRH entered into second amended and restated executive employment agreements (the “February Amended Agreements”) with two executives. The February Amended Agreements were effective January 1, 2010 and will continue until January 1, 2013, with subsequent one year renewals in the event that neither we, VNRH nor the executives have given notice to the other parties that the February Amended Agreements should not be extended. Also in June 2010, we and VNRH entered into a second amended and restated executive employment agreement (the “June Amended Agreement” and together with the February Amended Agreements, the “Amended Agreements”) with one executive. The June Amended Agreement was effective May 15, 2010 and will continue until May 15, 2013, with subsequent one year renewals in the event that neither we, VNRH nor the executive have given notice to the other parties that the agreement should not be extended. The Amended Agreements provide for an annual base salary and include an annual bonus structure for the executives. The annual bonus will be calculated based upon two company performance elements, absolute target distribution growth and relative unit performance to peer group, as well as a third discretionary element to be determined by our board of directors for the February Amended Agreements and by the Chief Executive Officer for the June Amended Agreement. Each of the three components will be weighted equally in calculating the respective executive officer’s annual bonus. The annual bonus does not require a minimum payout, although the maximum payout may not exceed two times the respective executive’s annual base salary. At December 31, 2011, an accrued liability $1.2 million and compensation expense of $2.3 million was recognized in the selling, general and administrative expenses line item in the consolidated statement of operations.

F-36

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

11. Unit-Based Compensation  – (continued)

The February Amended Agreements also provide for each executive to receive 15,000 restricted units granted pursuant to the VNR LTIP and the June Amended Agreement provides for the executive to receive an annual grant of 12,500 restricted units granted pursuant to the VNR LTIP. During the years ended December 31, 2011 and 2010, executives were granted restricted common units amounting to 87,500 units and 49,000 units, respectively, in accordance with the Amended Agreements and other board resolutions. The restricted units are subject to a vesting period of three years. One-third of the aggregate number of the restricted units will vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with us. In the event the executives are terminated without “Cause,” or the executive resigns for “Good Reason” (as such terms are defined in the Amended Agreements), or the executive is terminated due to his death or “Disability” (as each such term is defined in the Amended Agreement), all unvested outstanding restricted units shall receive accelerated vesting. Where the executive is terminated for “Cause,” all restricted units, whether vested or unvested, will be forfeited. Upon the occurrence of a “Change of Control” (as defined in the VNR LTIP), all unvested outstanding restricted units shall vest.

In addition, the February Amended Agreements provide for each executive to receive an annual grant of 15,000 phantom units granted pursuant to the VNR LTIP and the June Amended Agreement provides for the executive to receive an annual grant of 12,500 phantom units granted pursuant to the VNR LTIP. The phantom units are also subject to a three-year vesting period, although the vesting is not pro-rata, but a one-time event which shall occur on the three-year anniversary of the date of grant so long as the executive remains continuously employed with us during such time. The phantom units are accompanied by dividend equivalent rights, which entitle the executives to receive the value of any distributions made by us on our units generally with respect to the number of phantom shares that the executive received pursuant to this grant. In the event the executive is terminated for “Cause” (as such term is defined in the Amended Agreements), all phantom units, whether vested or unvested, will be forfeited. The phantom units, once vested, shall be settled upon the earlier to occur of (a) the occurrence of a “Change of Control” (as defined in the VNR LTIP), or (b) the executive’s separation from service. The amount to be paid in connection with these phantom units, can be paid in cash or in units at the election of the officers and will be equal to the appreciation in value of the units from the date of the grant until the determination date (December 31, 2013). As of December 31, 2011, an accrued liability of $0.6 million has been recorded and non-cash unit-based compensation expense of $0.5 million and $0.2 million has been recognized in the selling, general and administrative expense line item in the Consolidated Statement of Operations for years ended December 31, 2011 and 2010, respectively.

In 2011, VNR employees were granted a total of 142,661 common units which will vest equally over a four-year period. In May 2011, four board members were granted 11,884 common units which will vest one year from the date of grant. All of these grants have distribution equivalent rights that provide the grantee with a payment equal to the distribution on unvested units. In July 2011, one board member was granted 2,228 common units which vested immediately upon being granted.

The common units, Class B units, options and phantom units were granted as partial consideration for services to be performed under employment contracts and thus will be subject to accounting for these grants under ASC Topic 718. The fair value of restricted units issued is determined based on the fair market value of common units on the date of the grant. This value is amortized over the vesting period as referenced above.

In September 2007, the board of directors of ENP GP adopted the Encore Energy Partners GP LLC Long-Term Incentive Plan (the “ENP LTIP”), which provided for the granting of options, restricted units, phantom units, unit appreciation rights, distribution equivalent rights, other unit-based awards, and unit awards. All employees, consultants, and directors of ENP GP and its affiliates who performed services for or on behalf of ENP and its subsidiaries were eligible to be granted awards under the ENP LTIP. The ENP LTIP was administered by the board of directors of ENP GP or a committee thereof, referred to as the plan administrator.

F-37

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

11. Unit-Based Compensation  – (continued)

In January and February 2011, ENP issued 140,007 restricted units under the LTIP to Vanguard field employees performing services on ENP’s properties. These awards vest equally over a four-year period but have distribution equivalent rights that provide the employees with a bonus equal to the distribution on unvested units. The weighted average grant date fair value of these units was $22.21 per unit and the total fair value was approximately $3.1 million on the date of grant.

In February 2011, ENP issued 7,980 units under the ENP LTIP to three of the members of the board of directors of ENP GP which will vest within one year but have distribution equivalent rights that provide the board members with a bonus equal to the distribution on unvested units. The fair value of these units was approximately $0.2 million on the date of grant.

These common units and restricted units were granted as partial consideration for services to be performed under employment contracts and thus the grants were recorded in accordance with ASC Topic 718. The fair value of restricted units issued was determined based on the fair market value of common units on the date of the grant. This value is amortized over the vesting period as referenced above.

As a result of the ENP Merger, on December 1, 2011, all obligations under the ENP LTIP were assumed by VNR and all non-vested units under ENP’s LTIP were substituted with Vanguard common units at an exchange ratio of 0.75 Vanguard common unit for each ENP non-vested unit. A summary of the status of the non-vested units under the ENP LTIP as of the date of Merger is presented below:

	Number of Non-vested Units			Weighted Average Grant Date Fair Value
Non-vested units at December 31, 2010		—		$	—
Granted		147,987		$	22.25
Forfeited		(4,721	)	$	22.19
Vested		—		$	—
Non-vested units at December 1, 2011, substituted with 107,449 VNR common units		143,266		$	22.26

During the eleven months ended November 30, 2011, $0.8 million of non-cash unit-based compensation expense were recorded related to units granted under the ENP LTIP.

As of December 31, 2011, a summary of the status of the non-vested units under the VNR LTIP is presented below:

	Number of Non-vested Units			Weighted Average Grant Date Fair Value
Non-vested units at December 31, 2010		66,719		$	22.18
Granted		244,273		$	28.25
Forfeited		(21,824	)	$	(29.34	)
Vested		(29,947	)	$	(23.03	)
Non-vested ENP LTIP units substituted with VNR units		107,449		$	29.67
Non-vested units at December 31, 2011		366,670		$	27.92

At December 31, 2011, there was approximately $7.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 2.5 years. Our Consolidated Statements of Operations reflects non-cash compensation of $3.0 million, $1.0 million and $2.5 million in the selling, general and administrative expenses line item for the years ended December 31, 2011, 2010 and 2009, respectively.

F-38

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

12. Shelf Registration Statements

2009 Shelf Registration Statement and Related Offerings

During the third quarter 2009, we filed a registration statement with the SEC which registered offerings of up to $300.0 million (the “2009 shelf registration statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of each offering of securities issued under the 2009 shelf registration statement is determined at the time of such offering. The 2009 shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2009 shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In August 2009, we completed a public offering of 3.9 million of our common units. The units were offered to the public at a price of $14.25 per unit. We received net proceeds of approximately $53.2 million from the offering, after deducting underwriting discounts of $2.4 million and offering costs of $0.5 million. In December 2009, we completed a public offering of 2.6 million of our common units. The common units were offered to the public at a price of $18.00 per unit. We received net proceeds of approximately $44.4 million from the offering, after deducting underwriting discounts of $2.0 million and offering costs of $0.1 million. We paid $4.3 million of the proceeds from this offering to redeem 250,000 common units from our founding unitholder.

In May 2010, we completed a public offering of 3.3 million of our common units. The units were offered to the public at a price of $23.00 per unit. We received proceeds of approximately $71.5 million from the offering, after deducting underwriting discounts of $3.2 million and offering costs of $0.1 million.

In August 2010, we entered into an Equity Distribution Program Distribution Agreement (the “2010 Distribution Agreement”) relating to our common units representing limited liability company interests having an aggregate offering price of up to $60.0 million. In accordance with the terms of the 2010 Distribution Agreement we may offer and sell up to the maximum dollar amount of our common units from time to time through our sales agent. Sales of the common units, if any, may be made by means of ordinary brokers’ transactions through the facilities of the NYSE at market prices. Our sales agent will receive from us a commission of 1.25% based on the gross sales price per unit for any units sold through it as agent under the 2010 Distribution Agreement. Through December 31, 2011, we have received net proceeds of approximately $6.3 million from the sales of 240,111 common units, after commissions, under the 2010 Distribution Agreement. Sales made pursuant to the 2010 Distribution Agreement were made through a prospectus supplement to our 2009 shelf registration statement.

On September 9, 2011, we entered into an amended and restated Equity Distribution Program Distribution Agreement (the “2011 Distribution Agreement”) which extended, for an additional three years, the existing agreement with our sales agent to act as our exclusive distribution agent with respect to the issuance and sale of our common units up to an aggregate gross sales price of $200.0 million. Of the $200.0 million common units under the 2011 Distribution Agreement, $115.0 million common units may be offered through a prospectus supplement to our 2009 shelf registration statement. The additional $85.0 million common units may be offered pursuant to a new prospectus supplement to one of our other effective shelf registration statements or a new shelf registration statement to be filed when the 2009 shelf registration statement expires in August of 2012. Through December 31, 2011, we sold 18,700 common units under the 2011 Distribution Agreement and proceeds of approximately $0.5 million were settled in January 2012.

2010 Shelf Registration Statement and Related Offerings

In July 2010, we filed a registration statement with the SEC which registered offerings of up to $800.0 million (the “2010 shelf registration statement”) of any combination of debt securities, common units and guarantees of debt securities by our subsidiaries. Net proceeds, terms and pricing of each offering of

F-39

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

12. Shelf Registration Statements  – (continued)

securities issued under the 2010 shelf registration statement are determined at the time of such offerings. The 2010 shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2010 shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.

In October 2010, we completed a public offering of 4.8 million of our common units. The units were offered to the public at a price of $25.40 per unit. We received net proceeds of approximately $115.8 million from the offering, after deducting underwriting discounts of $5.1 million and offering costs of $0.3 million. We paid $3.7 million of the proceeds of this offering to redeem 150,000 common units from our founding unitholder. The remaining net proceeds of $112.1 million were used to pay down outstanding borrowings under our reserve-based credit facility.

As a result of these offerings, as of December 31, 2011, we have approximately $116.2 million and $678.8 million remaining available under our 2009 and 2010 shelf registration statements, respectively.

Subsidiary Guarantors

We and VNR Finance Corp., our wholly-owned finance subsidiary, may co-issue securities pursuant to the registration statements discussed above. VNR has no independent assets or operations. Debt securities that we may offer may be guaranteed by our subsidiaries. We contemplate that if we offer debt securities, the guarantees will be full and unconditional and joint and several, and any subsidiaries of Vanguard that do not guarantee the securities will be minor. There are no restrictions on our ability to obtain funds from our subsidiaries by dividend or loan.

2012 Shelf Registration Statement and Related Offerings

We filed a shelf registration statement with the SEC and completed a public offering in January 2012. See Note 13.Subsequent Eventsfor further discussion.

13. Subsequent Events

On January 18, 2012, our board of directors declared a cash distribution attributable to the fourth quarter of 2011 of $0.5875 per unit that was paid on February 14, 2012 to unitholders of record as of the close of business on February 7, 2012.

In January 2012, we filed a registration statement (the “2012 shelf registration statement”) with the SEC, which in part registered offerings of up to approximately 3.1 million common units representing limited liability company interests in VNR held by certain selling unitholders. By means of the same registration statement, we also registered an indeterminate amount of common units, debt securities and guarantees of debt securities. Net proceeds, terms and pricing of each offering of securities issued under the 2012 shelf registration statement are determined at the time of such offerings. The 2012 shelf registration statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the 2012 shelf registration statement for the purpose of issuing, from time to time, any combination of debt securities or common units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us and the selling unitholder named therein.

In January 2012, we completed an offering of 7,137,255 of our common units at a price of $27.71 per unit. The 7,137,255 common units offering included 4.0 million of our common units (“primary units”) and 3,137,255 common units (“secondary units”) offered by Denbury Onshore, LLC (“selling unitholder”). Offers were made pursuant to a prospectus supplement to the 2012 shelf registration statement. The secondary units were obtained by the selling unitholder as partial consideration for the ENP Purchase. We received proceeds of approximately $106.4 million from the offering of primary units, after deducting underwriting discounts of $4.3 million and offering costs of $0.2 million. We did not receive any proceeds from the sale of the

F-40

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

13. Subsequent Events  – (continued)

secondary units. In addition, we received proceeds of approximately $28.5 million, after deducting underwriting discounts of $1.2 million, from the sale of additional 1,070,588 of our common units that were offered to the underwriters to cover over-allotments pursuant to this offering. We used the net proceeds from this offering to repay indebtedness outstanding under our reserve-based credit facility and our Second Lien Term Loan.

In February 2012, we entered into a Unit Exchange Agreement with our founding unitholder to transfer our ownership interests in natural gas and oil properties in the Appalachian Basin in exchange for 1.9 million VNR common units with an effective date of January 1, 2012. As of December 31, 2011, based on a reserve report prepared by our independent reserve engineers, these interests had estimated total net proved reserves of 6.2 MMBOE, of which 92% was gas and 65% was proved developed. This transaction is expected to close in March 2012.

F-41

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter is summarized below.

	Quarters Ended
	March 31			June 30			September 30			December 31			Total
	(in thousands, except per unit amounts)
2011
Oil, natural gas and NGLs sales	$	72,039		$	80,371		$	74,429		$	86,003		$	312,842
Loss on commodity cash flow hedges		(1,071	)		(601	)		(635	)		(764	)		(3,071	)
Realized gain on other commodity derivative contracts		1,379			1,193			1,902			5,802			10,276
Unrealized gain (loss) on other commodity derivative contracts		(72,560	)		31,546			109,639			(69,095	)		(470	)
Total revenues	$	(213	)	$	112,509		$	185,335		$	21,946		$	319,577
Total costs and expenses(1)	$	43,257		$	51,421		$	49,835		$	52,688		$	197,201
Net gain (loss) on acquisition of oil and natural gas properties	$	—		$	(870	)	$	487		$	16		$	(367	)
Net income (loss)	$	(50,050	)	$	51,970		$	125,945		$	(39,735	)	$	88,130
Net income (loss) attributable to non-controlling interest		(19,638	)		20,171			50,061			(24,527	)		26,067
Net income (loss) attributable to Vanguard unitholders	$	(30,412	)	$	31,799		$	75,884		$	(15,208	)	$	62,063
Net income (loss) per unit:
Common & Class B units – basic	$	(1.01	)	$	1.05		$	2.51		$	(0.42	)	$	1.95
Common & Class B units – diluted	$	(1.01	)	$	1.05		$	2.50		$	(0.42	)	$	1.95
2010
Oil, natural gas and NGLs sales	$	20,070		$	19,446		$	22,684		$	23,157		$	85,357
Loss on commodity cash flow hedges		(1,042	)		(517	)		(568	)		(705	)		(2,832	)
Realized gain on other commodity derivative contracts		5,214			6,547			6,513			6,500			24,774
Unrealized gain (loss) on other commodity derivative contracts		10,810			(90	)		(9,388	)		(15,477	)		(14,145	)
Total revenues	$	35,052		$	25,386		$	19,241		$	13,475		$	93,154
Total costs and expenses(1)	$	11,293		$	13,361		$	13,874		$	19,148		$	57,676
Loss on acquisition of oil and natural gas properties	$	—		$	(5,680	)	$	—		$	—		$	(5,680	)
Net income (loss)	$	21,703		$	3,905		$	1,912		$	(5,635	)	$	21,885
Net income (loss) per unit:
Common & Class B units – basic & diluted	$	1.15		$	0.19		$	0.09		$	(0.21	)	$	1.00

(1) Includes lease operating expenses, production and other taxes, depreciation, depletion, amortization and accretion, and selling, general and administration expenses.

F-42

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

Supplemental Oil and Natural Gas Information (Unaudited)

We are a publicly-traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States.

Capitalized costs related to oil, natural gas and NGLs producing activities and related accumulated depletion, amortization and accretion were as follows at December 31:

	2011			2010
	(in thousands)
Aggregate capitalized costs relating to oil, natural gas and NGLs producing activities	$	1,549,821		$	1,312,107
Aggregate accumulated depletion, amortization and impairment		(331,836	)		(248,704	)
Net capitalized costs	$	1,217,985		$	1,063,403
ASC Topic 410-20 asset retirement obligations (included above)	$	35,920		$	30,202

Costs incurred in oil, natural gas and NGLs producing activities, whether capitalized or expensed, were as follows for the years ended December 31:

	2011		2010		2009
	(in thousands)
Property acquisition costs	$	208,850	$	896,676	$	106,776
Development costs		34,096		15,662		5,825
Total cost incurred	$	242,946	$	912,338	$	112,601

No internal costs or interest expense were capitalized in 2011, 2010 or 2009.

F-43

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

Net quantities of proved developed and undeveloped reserves of oil and natural gas and changes in these reserves at December 31, 2011, 2010 and 2009 are presented below. Information in these tables is based on reserve reports prepared by our independent petroleum engineers, Netherland, Sewell & Associates, Inc. For 2009 and DeGolyer and MacNaughton in 2011 and 2010. Additionally, information in these tables includes the non-controlling interest in the ENP reserves of approximately 53.3% at December 31, 2010.

	Gas (in Mcf)			Oil (in Bbls)			NGL (in Bbls)
Net proved reserves
January 1, 2009		81,237,097			4,547,359			—
Revisions of previous estimates		(36,569,334	)		(764,361	)		764,176
Extensions, discoveries and other		3,190,928			66,227			—
Purchases of reserves in place		39,832,181			2,908,923			2,900,758
Production		(4,542,374	)		(345,400	)		(114,784	)
December 31, 2009		83,148,498			6,412,748			3,550,150
Revisions of previous estimates		(7,607	)		332,850			956,685
Extensions, discoveries and other		76,376			17,515			—
Purchases of reserves in place		75,715,424			32,040,203			1,210,687
Production		(4,990,017	)		(682,447	)		(209,531	)
December 31, 2010		153,942,674			38,120,869			5,507,991
Revisions of previous estimates		(9,154,293	)		4,823,593			(71,861	)
Extensions, discoveries and other		324,868			91,713			—
Purchases of reserves in place		28,202,483			4,577,786			2,380,284
Sales of reserves in place		(72,996	)		(85,086	)		—
Production		(10,413,161	)		(2,725,852	)		(431,550	)
December 31, 2011		162,829,575			44,803,023			7,384,864
Proved developed reserves
December 31, 2009		54,129,281			4,765,599			2,360,526
December 31, 2010		119,312,949			31,853,857			3,933,643
December 31, 2011		131,476,797			40,090,104			6,173,060
Proved undeveloped reserves
December 31, 2009		29,019,217			1,647,149			1,189,624
December 31, 2010		34,629,725			6,267,012			1,574,348
December 31, 2011		31,352,778			4,712,919			1,211,804

Revisions of previous estimates of reserves are a result of changes in oil and natural gas prices, production costs, well performance and the reservoir engineer’s methodology. The initial application of the new rules related to modernizing reserve calculations and disclosure requirements resulted in a downward adjustment of 1.8 MMBOE to our total proved reserves and a downward adjustment of $152.2 million to the standardized measure of discounted future net cash flows as of December 31, 2009. Approximately 2.4 MMBOE of this downward adjustment is attributable to the new requirement that 12-month average prices, instead of end-of-period prices, are used in estimating our quantities of proved oil and natural gas reserves. Additional proved undeveloped reserves of 0.6 MMBOE were added as a result of new SEC rules that allow for additional drilling locations to be classified as proved undeveloped reserves assuming such locations are supported by reliable technologies. No proved undeveloped reserves were removed that exceeded the five year development limitation on proved undeveloped reserves imposed by the new rules. The downward adjustment of 1.8 MMBOE to our total proved reserves due to the new SEC rules was more than offset by a 12.5 MMBOE increase in our reserves due to acquisitions completed during the year ended December 31, 2009. Our reserves

F-44

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

increased by 45.9 MMBOE during the year ended December 31, 2010 due primarily to the ENP and Parker Creek Acquisitions completed during 2010. Our reserves increased by 10.0 MMBOE during the year ended December 31, 2011 due primarily to the acquisitions completed during 2011.

There are numerous uncertainties inherent in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment. All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard of “reasonable certainty” be applied to proved reserve estimates. This concept of reasonable certainty implies that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision. Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties we own declines as reserves are depleted. Except to the extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 2011.

Our proved undeveloped reserves at December 31, 2011, as estimated by our independent reserve engineers, were 11.1 MMBOE, consisting of 4.8 million barrels of oil, 31.4 MMcf of natural gas and 1.2 million barrels of NGLs. In 2011, we developed approximately 13% of our total proved undeveloped reserves booked as of December 31, 2010 through the drilling of nine gross (6.9 net) wells at an aggregate capital cost of approximately $13.5 million. At December 31, 2011, we have proved undeveloped properties that are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped and therefore the reserves from these properties are not included in our year end reserve report prepared by our independent reserve engineers. These properties include nine locations with 0.4 MMBOE of proved undeveloped reserves in the Permian Basin, two locations with 0.2 MMBOE of proved undeveloped reserves in the Big Horn Basin, 33 locations with 0.3 MMBOE of proved undeveloped reserves in the Appalachian Basin and 50 locations with 1.7 MMBOE of proved undeveloped reserves in the South Texas area. None of our proved undeveloped reserves at December 31, 2011 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves.

F-45

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

Results of operations from producing activities were as follows for the years ended December 31:

	2011(1)			2010			2009
	(in thousands)
Production revenues(2)	$	320,047		$	107,299		$	73,648
Production costs(3)		(92,565	)		(24,858	)		(16,722	)
Depreciation, depletion, amortization and accretion		(84,205	)		(22,019	)		(14,440	)
Impairment of oil and natural gas properties		—			—			(110,154	)
Results of operations from producing activities	$	143,277		$	60,422		$	(67,668	)

(1) Results of operations from producing activities from the properties acquired in connection with the ENP Purchase during 2011 through the date of the completion of the ENP Merger on December 1, 2011 were subject to a 53.4% non-controlling interest in ENP.

(2) Production revenues include losses on commodity cash flow hedges and realized gains on other commodity derivative contracts in 2011, 2010 and 2009.

(3) Production cost includes lease operating expenses and production related taxes, including ad valorem and severance taxes.

The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at December 31 is as follows:

	2011			2010(1)			2009
	(in thousands)
Future cash inflows	$	5,102,442		$	3,670,000		$	846,196
Future production costs		(1,701,143	)		(1,266,940	)		(362,386	)
Future development costs		(143,156	)		(156,714	)		(95,297	)
Future net cash flows		3,258,143			2,246,346			388,513
10% annual discount for estimated timing of cash flows		(1,781,910	)		(1,127,898	)		(209,840	)
Standardized measure of discounted future net cash flows	$	1,476,233		$	1,118,448		$	178,673

(1) The standardized measure includes approximately $596.1 million attributable to the non-controlling interest of ENP as of December 31, 2010. The estimated future cash inflows from estimated future production of proved reserves for ENP were computed using the average natural gas and oil price based upon the 12-month average price of $79.43 per barrel of crude oil and $4.45 per MMBtu for natural gas, adjusted for quality, transportation fees and a regional price differential.

For the December 31, 2011, 2010, and 2009 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using the average natural gas and oil price based upon the 12-month average price of $96.24 per barrel, $79.40 per barrel, and $61.04 per barrel of crude oil, respectively, and $4.12 per MMBtu, $4.38 per MMBtu, and $3.87 per MMBtu for natural gas, respectively, adjusted for quality, transportation fees and a regional price differential. We may receive amounts different than the standardized measure of discounted cash flow for a number of reasons, including price changes and the effects of our hedging activities.

F-46

Vanguard Natural Resources, LLC and Subsidiaries
  
Notes to Consolidated Financial Statements
December 31, 2011

The following are the principal sources of change in our standardized measure of discounted future net cash flows:

	Year Ended December 31,(1)
	2011(2)			2010			2009
	(in thousands)
Sales and transfers, net of production costs	$	(220,277	)	$	(60,046	)	$	(29,313	)
Net changes in prices and production costs		325,906			91,799			(21,697	)
Extensions discoveries and improved recovery, less related costs		3,665			891			1,673
Changes in estimated future development costs		(8,283	)		(9,476	)		2,557
Previously estimated development costs incurred during the period		34,096			15,662			5,825
Revision of previous quantity estimates		70,777			16,728			(64,155	)
Accretion of discount		111,845			17,867			19,007
Purchases of reserves in place(3)		214,225			856,299			80,776
Sales of reserves in place		(2,707	)		—			—
Change in production rates, timing and other		(171,462	)		10,051			(6,073	)
Net change	$	357,785		$	939,775		$	(11,400	)

(1) This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

(2) Changes attributable to properties acquired in the ENP Purchase through the date of the completion of the ENP Merger on December 1, 2011 include the non-controlling interest in ENP of approximately 53.4%.

(3) The portion associated with the ENP Purchase includes the non-controlling interest in the ENP reserves of approximately 53.3% at December 31, 2010.

F-47

PROSPECTUS

Vanguard Natural Resources, LLC
VNR Finance Corp.

 

Common Units
Debt Securities

We may offer and sell the securities described in this prospectus from time to time in one or more classes or series and in amounts, at prices and on terms to be determined by market conditions at the time of our offerings. VNR Finance Corp. may act as co-issuer of the debt securities and other subsidiaries of Vanguard Natural Resources, LLC may guarantee the debt securities.

This prospectus covers the offering for resale from time to time, in one or more offerings, of up to 3,137,255 common units owned by the selling unitholder, Denbury Onshore, LLC, a subsidiary of Denbury Resources Inc. (“Denbury”). These common units were obtained by the selling unitholder as partial consideration for our acquisition of all of the member interests in Encore Energy Partners GP LLC, the general partner of Encore Energy Partners LP (“ENP”), and certain common units representing limited partnership interests in ENP from subsidiaries of Denbury. We will not receive any proceeds from the sale of these common units by the selling unitholder. For a more detailed discussion of the selling unitholder, please read “Selling Unitholder.”

We and the selling unitholder may offer and sell these securities to or through one or more underwriters, dealers and agents, or directly to purchasers, on a continuous or delayed basis. This prospectus describes the general terms of these common units and debt securities and the general manner in which we will offer the common units and debt securities. The specific terms of any common units and debt securities we offer will be included in a supplement to this prospectus. The prospectus supplement will also describe the specific manner in which we will offer the common units and debt securities.

Investing in our common units and debt securities involves risks. Limited liability companies are inherently different from corporations. You should carefully consider the risk factors described under “Risk Factors” beginning on page 15 of this prospectus before you make an investment in our securities.

Our common units are traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “VNR.” We will provide information in the prospectus supplement for the trading market, if any, for any debt securities we may offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is January 18, 2012.

TABLE OF CONTENTS

About This Prospectus		ii
Where You Can Find More Information		1
Forward-Looking Statements		2
About Vanguard Natural Resources, LLC and VNR Finance Corp.		4
Risk Factors		5
Use of Proceeds		6
Ratio of Earnings to Fixed Charges		7
Selling Unitholder		8
Description of Our Debt Securities		9
Description of Our Common Units		17
Cash Distribution Policy		19
Description of Our Limited Liability Company Agreement		20
Material Tax Consequences		28
Plan of Distribution		45
Legal Matters		48
Experts		48

In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus. We have not authorized anyone to provide you with any other information. If anyone provides you with different or inconsistent information, you should not rely on it.

You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. You should not assume that the information contained in the documents incorporated by reference in this prospectus is accurate as of any date other than the respective dates of those documents. Our business, financial condition, results of operations and prospects may have changed since those dates. We are required, under certain circumstances, to update, supplement or amend this prospectus to reflect material developments in our business, financial position and results of operations and may do so by an amendment to this prospectus, a prospectus supplement or a future filing with the Securities and Exchange Commission (the “SEC”) incorporated by reference in this prospectus.

i

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement on Form S-3 that we and VNR Finance Corp. have filed with the SEC using a “shelf” registration process. Under this shelf registration process, we may, over time, offer and sell any combination of the securities described in this prospectus in one or more offerings. This prospectus generally describes Vanguard Natural Resources, LLC and the securities. Each time we sell securities with this prospectus, we will provide you with a prospectus supplement that will contain specific information about the terms of that offering. Each time the selling unitholder sells any common units offered by this prospectus, the selling unitholder is required to provide you with this prospectus and the related prospectus supplement containing specific information about the selling unitholder and the terms of the common units being offered in the manner required by the Securities Act. Any prospectus supplement may also add to, update or change information contained in this prospectus. To the extent information in this prospectus is inconsistent with the information contained in a prospectus supplement, you should rely on the information in the prospectus supplement. The information in this prospectus is accurate as of its date. Additional information, including our financial statements and the notes thereto, is incorporated in this prospectus by reference to our reports filed with the SEC. Before you invest in our securities, you should carefully read this prospectus, including the “Risk Factors,” any prospectus supplement, the information incorporated by reference in this prospectus and any prospectus supplement (including the documents described under the heading “Where You Can Find More Information” in both this prospectus and any prospectus supplement), and any additional information you may need to make your investment decision.

ii

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement with the SEC under the Securities Act that registers the securities offered by this prospectus. The registration statement, including the attached exhibits, contains additional relevant information about us. The rules and regulations of the SEC allow us to omit some information included in the registration statement from this prospectus.

In addition, we file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on the operation of the SEC’s public reference room. Our SEC filings are available on the SEC’s web site athttp://www.sec.gov. We also make available free of charge on our website, athttp://www.vnrllc.com, all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC.

The SEC allows us to “incorporate by reference” the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus by referring you to other documents filed separately with the SEC. These other documents contain important information about us, our financial condition and results of operations. The information incorporated by reference is an important part of this prospectus. Information that we file later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC. We incorporate by reference the documents listed below and any future filings made by Vanguard Natural Resources, LLC with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 (excluding any information furnished and not filed with the SEC) on or after the date on which the registration statement that includes this prospectus was initially filed with the SEC and before the effectiveness of such registration statement until all offerings under the shelf registration statement are completed:

• Our Annual Report on Form 10-K for the fiscal year ended December 31, 2010;

• ENP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010;

• Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011, June 30, 2011 and September 30, 2011;

• Our Current Reports on Form 8-K filed on January 3, 2011, February 28, 2011, March 25, 2011, April 21, 2011, June 9, 2011, June 23, 2011 (as amended by our Current Reports on Form 8-K/A filed on August 3, 2011 and September 16, 2011), July 11, 2011, September 12, 2011, October 5, 2011 and December 2, 2011 (as amended by our Current Report on Form 8-K/A filed on January 9, 2012);

• Our Current Report on Form 8-K/A filed on May 12, 2010;

• Our Proxy Statement under Section 14(a) of the Exchange Act filed on October 31, 2011 with respect to the solicitation of proxies for the special meeting of unitholders; and

• The description of our common units in our Registration Statement on Form 8-A filed on May 6, 2009 and any subsequent amendment thereto filed for the purpose of updating such description.

You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s website at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website atwww.vnrllc.com, or by writing or calling us at the following address:

Vanguard Natural Resources, LLC
Attn.: Investor Relations
5847 San Felipe, Suite 3000
Houston, Texas 77057
832-327-2255
investorrelations@vnrllc.com

1

FORWARD-LOOKING STATEMENTS

The statements contained in or incorporated by reference into this prospectus, other than statements of historical fact, constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Such statements include, without limitation, all statements as to the production of oil, natural gas, natural gas liquids (“NGLs”), product price, oil, natural gas and NGLs reserves, drilling and completion results, capital expenditures and other such matters. These statements relate to events and/or future financial performance and involve known and unknown risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements or the industry in which we operate to be materially different from any future results, levels of activity, performance or achievements expressed or implied by the forward-looking statements.

These risks and other factors include those listed under the section entitled “Risk Factors” and those described elsewhere in this prospectus, as well Item 1A. “Risk Factors” in our most recent annual report on Form 10-K and Item 1A.of Part II “Risk Factors” in our subsequent quarterly reports on Form 10-Q.

In some cases, you can identify forward-looking statements by our use of terms such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “intends,” “predicts,” “potential” or the negative of these terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. In evaluating these statements, you should specifically consider various factors, including the risks outlined under “Risk Factors.” These factors may cause our actual results to differ materially from any forward-looking statement. Factors that could affect our actual results and could cause actual results to differ materially from those in forward-looking statements include, but are not limited to, the following:

• the volatility of realized oil, natural gas and NGLs prices;

• the potential for additional impairment due to future declines in oil, natural gas and NGLs prices;

• uncertainties about the estimated quantities of oil, natural gas and NGLs reserves, including uncertainties about the effects of the SEC’s rules governing reserve reporting;

• the conditions of the capital markets, liquidity, general economic conditions, interest rates and the availability of credit to support our business requirements;

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

• our business and financial strategy;

• our future operating results;

• our drilling locations;

• technology;

• our cash flow, liquidity and financial position;

• the timing and amount of our future production of oil, natural gas and NGLs;

• our operating expenses, general and administrative costs, and finding and development costs;

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

• our prospect development and property acquisitions;

• the marketing of oil, natural gas and NGLs;

• competition in the oil, natural gas and NGLs industry;

• the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters;

• governmental regulation of the oil, natural gas and NGLs industry;

• environmental regulations;

2

• the effect of legislation, regulatory initiatives and litigation related to climate change;

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

• our strategic plans, objectives, expectations and intentions for future operations.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of these forward-looking statements. We do not intend to update any of the forward-looking statements after the date of this prospectus to conform prior statements to actual results.

3

ABOUT VANGUARD NATURAL RESOURCES, LLC AND VNR FINANCE CORP.

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows to allow us to make quarterly cash distributions to our unitholders and, over time, to increase our quarterly cash distributions through the acquisition of new oil and natural gas properties. Our properties and oil and natural gas reserves are primarily located in seven operating areas:

• the Permian Basin in West Texas and New Mexico;

• South Texas;

• the southern portion of the Appalachian Basin, primarily in southeast Kentucky and northeast Tennessee;

• Mississippi;

• the Big Horn Basin in Wyoming and Montana;

• the Williston Basin in North Dakota and Montana; and

• the Arkoma Basin in Arkansas and Oklahoma.

VNR Finance Corp. was incorporated under the laws of the State of Delaware in October of 2007, is wholly owned by Vanguard Natural Resources, LLC, and has no material assets or any liabilities other than as a co-issuer of debt securities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto.

For purposes of this prospectus, unless the context clearly indicates otherwise, “we,” “us,” “our,” “Vanguard Natural Resources” and similar terms refer to Vanguard Natural Resources, LLC and its subsidiaries.

Our executive offices are located at 5847 San Felipe, Suite 3000, Houston, Texas 77057 and our telephone number is (832) 327-2255.

For additional information as to our business, properties and financial condition please refer to the documents cited in “Where You Can Find More Information.”

4

RISK FACTORS

An investment in our securities involves a high degree of risk. You should carefully consider the risk factors and all of the other information included in, or incorporated by reference into, this prospectus, including those in Item 1A. “Risk Factors” in our most recent annual report on Form 10-K and Item 1A. of Part II “Risk Factors” in our subsequent quarterly reports on Form 10-Q, in evaluating an investment in our securities. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our securities could decline and you could lose all or part of your investment. When we offer and sell any securities pursuant to a prospectus supplement, we may include additional risk factors relevant to such securities in the prospectus supplement.

5

USE OF PROCEEDS

Unless otherwise indicated to the contrary in an accompanying prospectus supplement, we will use the net proceeds from the sale of securities covered by this prospectus for general corporate purposes, which may include repayment of indebtedness, the acquisition of businesses and other capital expenditures and additions to working capital. We will not receive any proceeds from the sale of the selling unitholder’s common units.

Any specific allocation of the net proceeds of an offering of securities to a specific purpose will be determined at the time of the offering and will be described in a prospectus supplement.

6

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our historical consolidated ratio of earnings to fixed charges for the periods indicated:

	Nine Months Ended September 30,		Year Ended December 31,
	2011		2010		2009		2008		2007		2006
Ratio of Earnings to Fixed Charges		6.44		3.88		(a)		(a)		1.31		4.51

For purposes of computing the ratio of earnings to fixed charges, “earnings” consist of pretax income from continuing operations available to Vanguard unitholders plus fixed charges (excluding capitalized interest). “Fixed charges” represent interest incurred (whether expensed or capitalized), amortization of debt expense, and that portion of rental expense on operating leases deemed to be the equivalent of interest.

(a) In the years ended December 31, 2009 and 2008, earnings were inadequate to cover fixed charges by approximately $95.7 million and $3.8 million, respectively. The shortfalls for the years ended December 31, 2009 and 2008 were principally the result of non-cash natural gas and oil property impairment charges of $110.2 million and $58.9 million, respectively.

7

SELLING UNITHOLDER

This prospectus covers the offering for resale from time to time, in one or more offerings, of up to 3,137,255 common units owned by the selling unitholder, Denbury Onshore, LLC, a subsidiary of Denbury Resources Inc. (“Denbury”). These common units were obtained by the selling unitholder as partial consideration for our acquisition of all of the member interests in Encore Energy Partners GP LLC, the general partner of ENP, and certain common units representing limited partnership interests in ENP from subsidiaries of Denbury.

The following table sets forth information relating to the selling unitholder as of January 17, 2012, based on information supplied to us by the selling unitholder on or prior to that date. We have not sought to verify such information. Information concerning selling unitholders may change over time, including by the addition of additional selling unitholders. If necessary, we will supplement this prospectus accordingly. The selling unitholder may hold or acquire at any time common units in addition to those offered by this prospectus and may have acquired additional common units since the date on which the information reflected herein was provided to us. In addition, the selling unitholder may have sold, transferred or otherwise disposed of some or all of its common units since the date on which the information reflected herein was provided to us and may in the future sell, transfer or otherwise dispose of some or all of its common units in private placement transactions exempt from or not subject to the registration requirements of the Securities Act.

	Common Units Owned Prior to Offering					Common Units That May Be Offered		Common Units Owned After Offering
Selling Unitholder	Number of Common Units		Percentage(2)					Number of Common Units		Percentage(2)
Denbury Onshore, LLC.		3,137,255		6	%		3,137,255		—		—

(1) Assumes the sale of all common units held by such selling unitholder offered by this prospectus.

(2) Based on 48,343,604 common units outstanding as of January 17, 2012.

Each time the selling unitholder sells any common units offered by this prospectus, the selling unitholder is required to provide you with this prospectus and the related prospectus supplement containing specific information about the selling unitholder and the terms of the common units being offered in the manner required by the Securities Act. Such prospectus supplement will set forth the following information with respect to the selling unitholder:

• the name of the selling unitholder;

• the nature of any position, office or any other material relationship that the selling unitholder has had within the last three years with us or any of our affiliates;

• the number of common units owned by the selling unitholder prior to the offering;

• the number of common units to be offered for the selling unitholder’s account; and

• the number of and (if one percent or greater) the percentage of common units to be owned by the selling unitholder after the completion of the offering.

8

DESCRIPTION OF OUR DEBT SECURITIES

General

The debt securities will be:

• our direct general obligations, either secured or unsecured;

• either senior debt securities or subordinated debt securities; and

• issued under separate indentures among us, any subsidiary guarantors and a trustee.

Vanguard Natural Resources, LLC may issue debt securities in one or more series, and VNR Finance Corp. may be a co-issuer of one or more series of such debt securities. VNR Finance Corp. was incorporated under the laws of the State of Delaware in April 2009, is wholly owned by Vanguard Natural Resources, LLC and has no material assets or any liabilities other than as a co-issuer of our debt securities. Its activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto. When used in this section “Description of Debt Securities,” the terms “we,” “us,” “our” and “issuers” refer jointly to Vanguard Natural Resources, LLC and VNR Finance Corp., and the terms “Vanguard” and “VNR Finance” refer strictly to Vanguard Natural Resources, LLC and VNR Finance Corp., respectively.

If we offer senior debt securities, we will issue them under a senior indenture. If we issue subordinated debt securities, we will issue them under a subordinated indenture. A form of each indenture is filed as an exhibit to the registration statement of which this prospectus is a part. We have not restated either indenture in its entirety in this description. You should read the relevant indenture because it, and not this description, controls your rights as holders of the debt securities. Capitalized terms used in the summary have the meanings specified in the indentures.

Specific Terms of Each Series of Debt Securities in the Prospectus Supplement

A prospectus supplement and a supplemental indenture or authorizing resolutions relating to any series of debt securities being offered will include specific terms relating to the offering. These terms will include some or all of the following:

• the guarantors of the debt securities, if any;

• whether the debt securities are senior or subordinated debt securities;

• the title of the debt securities;

• the total principal amount of the debt securities;

• the denominations in which the debt securities are issuable, if other than $1,000 and any integral multiple thereof;

• the assets, if any, that are pledged as security for the payment of the debt securities;

• whether we will issue the debt securities in individual certificates to each holder in registered form, or in the form of temporary or permanent global securities held by a depositary on behalf of holders;

• the prices at which we will issue the debt securities;

• the portion of the principal amount that will be payable if the maturity of the debt securities is accelerated;

• the currency or currency unit in which the debt securities will be payable, if not U.S. dollars;

• the dates on which the principal of the debt securities will be payable;

• the interest rate (if any) that the debt securities will bear and the interest payment dates for the debt securities;

• any conversion or exchange provisions;

• any optional redemption provisions;

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• any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the debt securities;

• any changes to or additional events of default or covenants; and

• any other terms of the debt securities.

We may offer and sell debt securities, including original issue discount debt securities, at a substantial discount below their principal amount. The prospectus supplement will describe special U.S. federal income tax and any other considerations applicable to those securities. In addition, the prospectus supplement may describe certain special U.S. federal income tax or other considerations applicable to any debt securities that are denominated in a currency other than U.S. dollars.

Guarantees

If specified in the prospectus supplement respecting a series of debt securities, the subsidiaries of Vanguard specified in the prospectus supplement will unconditionally guarantee to each holder and the trustee, on a joint and several basis, the full and prompt payment of principal of, premium, if any, and interest on the debt securities of that series when and as the same become due and payable, whether at maturity, upon redemption or repurchase, by declaration of acceleration or otherwise. If a series of debt securities is guaranteed, such series will be guaranteed by substantially all of the domestic subsidiaries of Vanguard. The prospectus supplement will describe any limitation on the maximum amount of any particular guarantee and the conditions under which guarantees may be released.

The guarantees will be general obligations of the guarantors. Guarantees of subordinated debt securities will be subordinated to the Senior Indebtedness of the guarantors on the same basis as the subordinated debt securities are subordinated to the Senior Indebtedness of Vanguard.

Consolidation, Merger or Asset Sale

Each indenture will, in general, allow us to consolidate or merge with or into another domestic entity. It will also allow each issuer to sell, lease, transfer or otherwise dispose of all or substantially all of its assets to another domestic entity. If this happens, the remaining or acquiring entity must assume all of the issuer’s responsibilities and liabilities under the indenture, including the payment of all amounts due on the debt securities and performance of the issuer’s covenants in the indenture.

However, each indenture will impose certain requirements with respect to any consolidation or merger with or into an entity, or any sale, lease, transfer or other disposition of all or substantially all of an issuer’s assets, including:

• the remaining or acquiring entity must be organized under the laws of the United States, any state or the District of Columbia; provided that VNR Finance may not merge, amalgamate or consolidate with or into another entity other than a corporation satisfying such requirement for so long as Vanguard is not a corporation;

• the remaining or acquiring entity must assume our obligations under the indenture; and

• immediately after giving effect to the transaction, no Default or Event of Default (as defined under “— Events of Default and Remedies” below) may exist.

The remaining or acquiring entity will be substituted for the issuer in the indenture with the same effect as if it had been an original party to the indenture, and the issuer will be relieved from any further obligations under the indenture.

No Protection in the Event of a Change of Control

Unless otherwise set forth in the prospectus supplement, the debt securities will not contain any provisions that protect the holders of the debt securities in the event of a change of control of us or in the event of a highly leveraged transaction, whether or not such transaction results in a change of control of us.

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Modification of Indentures

We may supplement or amend an indenture if the holders of a majority in aggregate principal amount of the outstanding debt securities of all series issued under the indenture affected by the supplement or amendment consent to it. Further, the holders of a majority in aggregate principal amount of the outstanding debt securities of any series may waive past defaults under the indenture and compliance by us with our covenants with respect to the debt securities of that series only. Those holders may not, however, waive any default in any payment on any debt security of that series or compliance with a provision that cannot be supplemented or amended without the consent of each holder affected. Without the consent of each outstanding debt security affected, no modification of the indenture or waiver may:

• reduce the percentage in principal amount of debt securities of any series whose holders must consent to an amendment, supplement or waiver;

• reduce the principal of or extend the fixed maturity of any debt security;

• reduce the premium payable upon redemption or change the time of the redemption of the debt securities;

• reduce the rate of or extend the time for payment of interest on any debt security;

• waive a Default or an Event of Default in the payment of principal of or premium, if any, or interest on the debt securities or a Default of Event of Default in respect of a provision that cannot be amended without the consent of each affected holder;

• except as otherwise permitted under the indenture, release any security that may have been granted with respect to the debt securities;

• make any debt security payable in currency other than that stated in such debt security;

• in the case of any subordinated debt security, make any change in the subordination provisions that adversely affects the rights of any holder under those provisions;

• make any change in the provisions of the indenture relating to waivers of past Defaults or Event of Default; or the rights of holders of debt securities to receive payments of principal of or premium, if any, or interest on the debt securities;

• make any change in the preceding amendment, supplement and waiver provisions (except to increase any percentage set forth therein).

We may supplement or amend an indenture without the consent of any holders of the debt securities in certain circumstances, including:

• to provide for the assumption of an issuer’s or guarantor’s obligations to holders of debt securities in the case of a merger or consolidation or disposition of all or substantially all of such issuer’s or guarantor’s assets;

• to add any additional covenants and related Events of Default;

• to cure any ambiguity, defect or inconsistency;

• to secure the debt securities and/or the guarantees;

• in the case of any subordinated debt security, to make any change in the subordination provisions that limits or terminates the benefits applicable to any holder of Senior Indebtedness of Vanguard;

• to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

• to add or release guarantors pursuant to the terms of the indenture;

• to make any changes that do not adversely affect the rights under the indenture of any holder of debt securities;

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• to evidence or provide for the acceptance of appointment under the indenture of a successor trustee; or

• to establish the form of terms of any series of debt securities.

Events of Default and Remedies

“Event of Default,” when used in an indenture, will mean any of the following with respect to the debt securities of any series:

• failure to pay when due the principal of or any premium on any debt security of that series, whether or not, in the case of subordinated debt securities, the subordination provisions of the indenture prohibit such payment;

• failure to pay, within 30 days of the due date, interest on any debt security of that series, whether or not, in the case of subordinated debt securities, the subordination provisions of the indenture prohibit such payment;

• failure to pay when due any sinking fund payment with respect to any debt securities of that series, whether or not, in the case of subordinated debt securities, the subordination provisions of the indenture prohibit such payment;

• failure on the part of the issuers to comply with the covenant described under “— Consolidation, Merger or Asset Sale”;

• failure to perform any other covenant in the indenture that continues for 60 days after written notice is given to the issuers;

• certain events of bankruptcy, insolvency or reorganization of an issuer; or

• any other Event of Default provided under the terms of the debt securities of that series.

An Event of Default for a particular series of debt securities will not necessarily constitute an Event of Default for any other series of debt securities issued under an indenture. The trustee may withhold notice to the holders of debt securities of any default (except in the payment of principal, premium, if any, or interest) if it considers such withholding of notice to be in the best interests of the holders.

If an Event of Default described in the sixth bullet point above occurs, the entire principal of, premium, if any, and accrued interest on, all debt securities then outstanding will be due and payable immediately, without any declaration or other act on the part of the trustee or any holders. If any other Event of Default for any series of debt securities occurs and continues, the trustee or the holders of at least 25% in aggregate principal amount of the debt securities of the series may declare the entire principal of, and accrued interest on, all the debt securities of that series to be due and payable immediately. If this happens, subject to certain conditions, the holders of a majority in the aggregate principal amount of the debt securities of that series can rescind the declaration.

Other than its duties in case of a default, a trustee is not obligated to exercise any of its rights or powers under either indenture at the request, order or direction of any holders, unless the holders offer the trustee reasonable security or indemnity. If they provide this reasonable security or indemnification, the holders of a majority in aggregate principal amount of any series of debt securities may direct the time, method and place of conducting any proceeding or any remedy available to the trustee, or exercising any power conferred upon the trustee, for that series of debt securities.

No Limit on Amount of Debt Securities

Neither indenture will limit the amount of debt securities that we may issue, unless we indicate otherwise in a prospectus supplement. Each indenture will allow us to issue debt securities of any series up to the aggregate principal amount that we authorize.

Registration of Notes

We will issue debt securities of a series only in registered form, without coupons, unless otherwise indicated in the prospectus supplement.

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Minimum Denominations

Unless the prospectus supplement states otherwise, the debt securities will be issued only in principal amounts of $1,000 each or an integral multiple thereof.

No Personal Liability

None of the past, present or future partners, incorporators, managers, members, directors, officers, employees, unitholders or stockholders of either issuer or any guarantor will have any liability for the obligations of the issuers or any guarantors under either indenture or the debt securities or for any claim based on such obligations or their creation. Each holder of debt securities by accepting a debt security waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the debt securities. The waiver may not be effective under federal securities laws, however, and it is the view of the SEC that such a waiver is against public policy.

Payment and Transfer

The trustee will initially act as paying agent and registrar under each indenture. The issuers may change the paying agent or registrar without prior notice to the holders of debt securities, and the issuers or any of their subsidiaries may act as paying agent or registrar.

If a holder of debt securities has given wire transfer instructions to the issuers, the issuers will make all payments on the debt securities in accordance with those instructions. All other payments on the debt securities will be made at the corporate trust office of the trustee, unless the issuers elect to make interest payments by check mailed to the holders at their addresses set forth in the debt security register.

The trustee and any paying agent will repay to us upon request any funds held by them for payments on the debt securities that remain unclaimed for two years after the date upon which that payment has become due. After payment to us, holders entitled to the money must look to us for payment as general creditors.

Exchange, Registration and Transfer

Debt securities of any series will be exchangeable for other debt securities of the same series, the same total principal amount and the same terms but in different authorized denominations in accordance with the applicable indenture. Holders may present debt securities for exchange or registration of transfer at the office of the registrar. The registrar will effect the transfer or exchange when it is satisfied with the documents of title and identity of the person making the request. We will not charge a service charge for any registration of transfer or exchange of the debt securities. We may, however, require the payment of any tax or other governmental charge payable for that transaction.

We will not be required to:

• issue, register the transfer of, or exchange any debt securities of a series either during a period of 15 days prior to the mailing of notice of redemption of that series; or

• register the transfer of or exchange any debt security called for redemption, except the unredeemed portion of any debt security we are redeeming in part.

Provisions Relating only to the Senior Debt Securities

The senior debt securities will rank equally in right of payment with all of our other senior and unsubordinated debt. The senior debt securities will be effectively subordinated, however, to all of our secured debt to the extent of the value of the collateral for that debt. We will disclose the amount of our secured debt in the prospectus supplement.

Provisions Relating only to the Subordinated Debt Securities

Subordinated Debt Securities Subordinated to Senior Indebtedness

The subordinated debt securities will rank junior in right of payment to all of our Senior Indebtedness. The definition of “Designated Senior Indebtedness” and “Senior Indebtedness” will be set forth in the prospectus supplement. If the subordinated debt securities are guaranteed by any of the subsidiaries of Vanguard, then the guarantees will be subordinated on like terms.

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Payment Blockages

The subordinated indenture will provide that no payment of principal, interest and any premium on the subordinated debt securities may be made in the event:

• we or our property (or any guarantor or its property) is involved in any liquidation, bankruptcy or similar proceeding;

• we fail to pay the principal, interest, any premium or any other amounts on any of our Senior Indebtedness within any applicable grace period or the maturity of such Senior Indebtedness is accelerated following any other default, subject to certain limited exceptions set forth in the subordinated indenture; or

• any other default on any of our Designated Senior Indebtedness occurs that permits immediate acceleration of its maturity, in which case a payment blockage on the subordinated debt securities will be imposed for a maximum of 179 days at any one time.

No Limitation on Amount of Senior Debt

The subordinated indenture will not limit the amount of Senior Indebtedness that we or any guarantor may incur, unless otherwise indicated in the prospectus supplement.

Book Entry, Delivery and Form

The debt securities of a particular series may be issued in whole or in part in the form of one or more global certificates that will be deposited with the trustee as custodian for The Depository Trust Company, New York, New York (“DTC”). This means that we will not issue certificates to each holder, except in the limited circumstances described below. Instead, one or more global debt securities will be issued to DTC, who will keep a computerized record of its participants (for example, your broker) whose clients have purchased the debt securities. The participant will then keep a record of its clients who purchased the debt securities. Unless it is exchanged in whole or in part for a certificated debt security, a global debt security may not be transferred, except that DTC, its nominees and their successors may transfer a global debt security as a whole to one another.

Beneficial interests in global debt securities will be shown on, and transfers of global debt securities will be made only through, records maintained by DTC and its participants.

DTC has provided us the following information: DTC, the world’s largest securities depository, is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds and provides asset servicing for over 3.5 million issues of U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments (from over 100 countries) that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post-trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct Participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (“Indirect Participants”). DTC has Standard & Poor’s Rating Services’ highest rating: AAA. The DTC rules applicable to its Direct Participants are on file with the SEC.

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We will wire all payments on the global debt securities to DTC’s nominee. We and the trustee will treat DTC’s nominee as the owner of the global debt securities for all purposes. Accordingly, we, the trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global debt securities to owners of beneficial interests in the global debt securities.

We understand that it is DTC’s current practice, upon receipt of any payment on the global debt securities, to credit Direct Participants’ accounts on the payment date according to their respective holdings of beneficial interests in the global debt securities as shown on DTC’s records. In addition, it is DTC’s current practice to assign any consenting or voting rights to Direct Participants whose accounts are credited with debt securities on a record date, by using an omnibus proxy. Payments by Direct and Indirect Participants to owners of beneficial interests in the global debt securities, and voting by Direct and Indirect Participants, will be governed by the customary practices between the Direct and Indirect Participants and owners of beneficial interests, as is the case with debt securities held for the account of customers registered in “street name.” However, payments will be the responsibility of the Direct and Indirect Participants and not of DTC, the trustee or us.

Debt securities represented by a global debt security will be exchangeable for certificated debt securities with the same terms in authorized denominations only if:

• DTC notifies us that it is unwilling or unable to continue as depositary or if DTC ceases to be eligible or in good standing under applicable law and in either event a successor depositary is not appointed by us within 90 days; or

• an Event of Default occurs and DTC notifies the trustee of its decision to exchange the global debt security for certificated debt securities.

Satisfaction and Discharge; Defeasance

Each indenture will be discharged and will cease to be of further effect as to all outstanding debt securities of any series issued thereunder, when:

(a)  either:

(1)  all outstanding debt securities of that series that have been authenticated (except lost, stolen or destroyed debt securities that have been replaced or paid and debt securities for whose payment money has theretofore been deposited in trust and thereafter repaid to us) have been delivered to the trustee for cancellation; or

(2)  all outstanding debt securities of that series that have not been delivered to the trustee for cancellation have become due and payable by reason of the giving of a notice of redemption or otherwise or will become due and payable at their stated maturity within one year or are to be called for redemption within one year under arrangements satisfactory to the trustee and in any case we have irrevocably deposited or caused to be irrevocably deposited with the trustee as trust funds in trust cash sufficient to pay and discharge the entire indebtedness of such debt securities not delivered to the trustee for cancellation, for principal, premium, if any, and accrued interest to the date of such deposit (in the case of debt securities that have been due and payable) or the stated maturity or redemption date;

(b)  we have paid or caused to be paid all other sums payable by us under the indenture with respect to that series; and

(c)  we have delivered an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

The debt securities of a particular series will be subject to legal or covenant defeasance to the extent, and upon the terms and conditions, set forth in the prospectus supplement.

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Governing Law

Each indenture and all of the debt securities will be governed by the laws of the State of New York.

The Trustee

We will enter into the indentures with a trustee that is qualified to act under the Trust Indenture Act of 1939, as amended, and with any other trustees chosen by us and appointed in a supplemental indenture for a particular series of debt securities. We may maintain a banking relationship in the ordinary course of business with our trustee and one or more of its affiliates.

Resignation or Removal of Trustee

If the trustee has or acquires a conflicting interest within the meaning of the Trust Indenture Act, the trustee must either eliminate its conflicting interest or resign, to the extent and in the manner provided by, and subject to the provisions of, the Trust Indenture Act and the applicable indenture. Any resignation will require the appointment of a successor trustee under the applicable indenture in accordance with the terms and conditions of such indenture.

The trustee may resign or be removed by us with respect to one or more series of debt securities and a successor trustee may be appointed to act with respect to any such series. The holders of a majority in aggregate principal amount of the debt securities of any series may remove the trustee with respect to the debt securities of such series.

Limitations on Trustee if It Is Our Creditor

Each indenture will contain certain limitations on the right of the trustee, in the event that it becomes a creditor of an issuer or a guarantor, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise.

Certificates and Opinions to Be Furnished to Trustee

Each indenture will provide that, in addition to other certificates or opinions that may be specifically required by other provisions of an indenture, every application by us for action by the trustee must be accompanied by a certificate of certain of our officers and an opinion of counsel (who may be our counsel) stating that, in the opinion of the signers, all conditions precedent to such action have been complied with by us.

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DESCRIPTION OF OUR COMMON UNITS

Our common units represent limited liability company interests in us. The holders of common units are entitled to participate in cash distributions and exercise the rights or privileges available to unitholders under our limited liability company agreement.

Our outstanding common units are listed on the NYSE under the ticker symbol “VNR.” Any additional common units we issue will also be listed on the NYSE. The transfer agent and registrar for our common units is Computershare Trust Company, N.A., or Computershare.

Our Limited Liability Company Agreement

Holders of our common units are entitled to participate in cash distributions and exercise the rights or privileges available to them under our limited liability company agreement. A copy of our limited liability company agreement is included in our other SEC filings and incorporated by reference in this prospectus.

Cash Distribution Policy

Our limited liability company agreement, as amended, provides for the distribution of available cash on a quarterly basis. Available cash for any quarter consists of cash on hand at the end of that quarter, plus working capital borrowings made after the end of the quarter, less cash reserves, which may include reserves to provide for our future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. The amount of available cash is determined by our board of directors for each calendar quarter of our operations. Our limited liability company agreement may only be amended with the approval of a unit majority.

Timing of Distributions

We pay distributions on our common units approximately 45 days after March 31, June 30, September 30 and December 31 to unitholders of record on the applicable record date.

Issuance of Additional Units

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and rights to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of the unitholders. It is possible that we will fund acquisitions or other initiatives through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units and holders of other equity securities entitled to participate in our distributions of available cash. In addition, the issuance of additional common units or other equity 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 limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting rights to which the common units are not entitled. The holders of common units do not have preemptive rights to acquire additional common units or other securities.

Voting Rights

Our common unitholders have the right to vote with respect to the election of our board of directors, certain amendments to our limited liability company agreement, the merger of our company or the sale of all or substantially all of our assets, and the dissolution of our company.

Transfer Agent and Registrar

Computershare serves as registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of common units, except the following fees that will 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 holder of a unit; and

• other similar fees or charges.

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There will be no charge to holders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, 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.

The transfer agent may at any time 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, we are authorized to 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 limited liability company agreement, each transferee of common units shall be admitted as a unitholder with respect to the common units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of common units:

• becomes the record holder of the common units;

• automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our limited liability company agreement;

• represents that the transferee has the capacity, power and authority to enter into the limited liability company agreement;

• grants powers of attorney to our officers and the liquidator of our company as specified in the limited liability company agreement; and

• makes the consents and waivers contained in our limited liability company agreement.

An assignee will become a unitholder of our company for the transferred common units upon the recording of the name of the assignee on our books and records.

Until a unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, 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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CASH DISTRIBUTION POLICY

Distributions of Available Cash

Our limited liability company agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash reserves established by our board of directors to:

• provide for the proper conduct of our business (including reserves for acquisitions of additional oil and natural gas properties, future capital expenditures, future debt service requirements and anticipated credit needs);

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

• provide funds for distribution to our unitholders for any one or more of the next four quarters;

plus all cash 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 for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our reserve based credit facility and in all cases are used solely for working capital purposes or to pay distributions to unitholders.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with our limited liability company 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, 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.

Adjustments to Capital Accounts

We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders in the same manner as we allocate gain or loss upon liquidation.

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DESCRIPTION OF OUR LIMITED LIABILITY COMPANY AGREEMENT

The following is a summary of the material provisions of our limited liability company agreement. We will provide prospective investors with a copy of the form of this agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

• with regard to distributions of available cash, please read “Cash Distribution Policy.”

• with regard to the transfer of units, please read “Description of our Common Units — Transfer of Common Units.”

• with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization

Our company was formed in October 2006 and will remain in existence until dissolved in accordance with our limited liability company agreement.

Purpose

Under our limited liability company agreement, we are permitted to engage, directly or indirectly, in any activity that our board of directors approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that our board of directors shall not cause us to engage, directly or indirectly, in any business activities that it 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 board of directors has the ability to cause us and our operating subsidiaries to engage in activities other than the exploitation, development and production of oil and natural gas reserves, our board of directors has no current plans to do so. Our board of directors is authorized in general to perform all acts it deems to be necessary or appropriate to carry out our purposes and to conduct our business.

Fiduciary Duties

Our limited liability company agreement provides that our business and affairs shall be managed under the direction of our board of directors, which shall have the power to appoint our officers. Our limited liability company agreement further provides that the authority and function of our board of directors and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the Delaware General Corporation Law, or DGCL. Finally, our limited liability company agreement provides that except as specifically provided therein, the fiduciary duties and obligations owed by our officers and directors to us and to our members shall be the same as the respective duties and obligations owed by officers and directors of a corporation organized under the DGCL to their corporation and stockholders, respectively. Our limited liability company agreement permits affiliates of our directors to invest or engage in other businesses or activities that compete with us. In addition, our limited liability company agreement establishes a conflicts committee of our board of directors, consisting solely of independent directors, which will upon referral from our board of directors be authorized to review transactions involving potential conflicts of interest. If the conflicts committee approves such a transaction, or if a transaction is on terms generally available from third parties or an action is taken that is fair and reasonable to the company, you will not be able to assert that such approval constituted a breach of fiduciary duties owed to you by our directors and officers.

Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

By purchasing a common unit in us, you will be admitted as a unitholder of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Pursuant to our limited liability company agreement, each unitholder and each person who acquires a unit from a unitholder grants to our board of directors (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 board of directors the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement.

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Limited Liability

Unlawful Distributions.  The Delaware Limited Liability Company Act, or the Delaware Act, provides that a unitholder 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 company for the amount of the distribution for three years. Under the Delaware Act, a limited liability company may not make a distribution to a unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders on account of their membership interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, 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 company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the Delaware Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business.  Our subsidiaries conduct business only in the states of Arkansas, Kentucky, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Tennessee, Texas and Wyoming. In the future, we may decide to conduct business in other states, and maintenance of limited liability for us, as a member of our operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that our board of directors considers reasonable and necessary or appropriate to preserve the limited liability of our unitholders.

Voting Rights

The following matters require the unitholder vote specified below:

Election of members of the board of directors	We currently have five directors. Our limited liability company agreement provides that we shall maintain a board of not less than three members. Holders of our units, voting together as a single class, elect our directors. Please read “— Election of Members of Our Board of Directors.”
Issuance of additional units	No approval right.
Amendment of the limited liability company agreement	Certain amendments may be made by our board of directors without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of Our Limited Liability Company Agreement.”
Merger of our company or the sale of all or substantially all of our assets	Unit majority. Please read “— Merger, Sale or Other Disposition of Assets.”
Dissolution of our company	Unit majority. Please read “— Termination and Dissolution.”

Matters requiring the approval of a “unit majority” require the approval of a majority of the outstanding units.

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Issuance of Additional Securities

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and authorizes us to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting or other rights to which the units are not entitled.

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

Election of Members of Our Board of Directors

At our annual meeting of unitholders, members of our board of directors were elected by our unitholders and will be subject to re-election on an annual basis at our next annual meeting of unitholders.

Removal of Members of Our Board of Directors

Any director may be removed, with or without cause, by the holders of a majority of the outstanding units then entitled to vote at an election of directors.

Amendment of Our Limited Liability Company Agreement

General.  Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of directors. To adopt a proposed amendment, other than the amendments discussed below, our board of directors is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of our unitholders 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 unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected;

• provide that we are not dissolved upon an election to dissolve our company by our board of directors that is approved by a unit majority;

• change the term of existence of our company; or

• give any person the right to dissolve our company other than our board of directors’ right to dissolve our company with the approval of a unit majority.

The provision of our limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding units, voting together as a single class.

No Unitholder Approval.  Our board of directors may generally make amendments to our limited liability company agreement without the approval of any unitholder or assignee to reflect:

• a change in our name, the location of our principal place of our business, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of members in accordance with our limited liability company agreement;

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• a change that our board of directors determines to be necessary or appropriate for us to qualify or continue our qualification as a company in which our members have limited liability under the laws of any state or to ensure that neither we, our operating subsidiaries 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, members of our board, or our 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, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

• an amendment that our board of directors determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;

• any amendment expressly permitted in our limited liability company agreement to be made by our board of directors acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our limited liability company agreement;

• any amendment that our board of directors 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 limited liability company agreement;

• a change in our fiscal year or taxable year and related changes;

• a merger, conversion or conveyance effected in accordance with the limited liability company agreement; and

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our board of directors may make amendments to our limited liability company agreement without the approval of any unitholder or assignee if our board of directors determines that those amendments:

• do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) 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 units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading, compliance with any of which our board of directors deems to be in the best interests of us and our unitholders;

• are necessary or appropriate for any action taken by our board of directors relating to splits or combinations of units under the provisions of our limited liability company agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

Opinion of Counsel and Unitholder Approval.  Our board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “— No Unitholder Approval” should occur. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder of our company.

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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 is required to be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

Our board of directors is generally prohibited, 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, provided that our board of directors may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our board of directors may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in the limited liability company agreement are satisfied, our board of directors may merge our company or any of its subsidiaries into, or convey all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a company until terminated under our limited liability company agreement. We will dissolve upon: (1) the election of our board of directors to dissolve us, if approved by the holders of a unit majority; (2) the sale, exchange or other disposition of all or substantially all of the assets and properties of our company and our subsidiaries; or (3) the entry of a decree of judicial dissolution of our company.

Liquidation and Distribution of Proceeds

Upon our dissolution, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of directors that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “Cash Distribution Policy — 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 unitholders in kind if it determines that a sale would be impractical or would cause undue loss to our unitholders.

Anti-Takeover Provisions

Our limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of our company without the approval of our board of directors. Specifically, our limited liability company agreement provides that we will elect to have Section 203 of the DGCL apply to transactions in which an interested common unitholder (as described below) seeks to enter into a merger or business combination with us. Under this provision, such a holder will not be permitted to enter into a merger or business combination with us unless:

• prior to such time, our board of directors approved either the business combination or the transaction that resulted in the common unitholder’s becoming an interested common unitholder;

• upon consummation of the transaction that resulted in the common unitholder becoming an interested common unitholder, the interested common unitholder owned at least 85% of our outstanding common units at the time the transaction commenced, excluding for purposes of determining the number of common units outstanding those common units owned:

• by persons who are directors and also officers; and

• by employee common unit plans in which employee participants do not have the right to determine confidentially whether common units held subject to the plan will be tendered in a tender or exchange offer; or

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• at or subsequent to such time the business combination is approved by our board of directors and authorized at an annual or special meeting of our common unitholders, and not by written consent, by the affirmative vote of the holders of at least 66 2/3% of our outstanding voting common units that are not owned by the interested common unitholder.

Section 203 defines “business combination” to include:

• any merger or consolidation involving the company and the interested common unitholder;

• any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested common unitholder;

• subject to certain exceptions, any transaction that results in the issuance or transfer by the company of any common units of the company to the interested common unitholder;

• any transaction involving the company that has the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested common unitholder; or

• the receipt by the interested common unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, by reference to Section 203, an “interested common unitholder” is any person or entity that beneficially owns (or within three years did own) 15% or more of the outstanding common units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

The existence of this provision would be expected to have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for common units held by common unitholders.

Our limited liability agreement also restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than persons who acquire such units with the prior approval of the board of directors, cannot vote on any matter.

Limited Call Right

If at any time any person owns more than 90% of the then-issued and outstanding membership interests of any class, such person will have the right, 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 remaining membership interests of the class held by unaffiliated persons as of a record date to be selected by our management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under the limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or

• the closing market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in our company may have his membership interests purchased at an undesirable time or price. Please read “Risk Factors — Risks Related to Our Structure.” The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material Tax Consequences — Disposition of Units.”

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Meetings; Voting

All notices of meetings of unitholders shall be sent or otherwise given in accordance with Section 11.4 of our limited liability company agreement not less than 10 nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of directors, at the time of giving the notice, intends to present for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the board of directors intends to present for election. Any previously scheduled meeting of the unitholders may be postponed, and any special meeting of the unitholders may be cancelled, by resolution of the board of directors upon public notice given prior to the date previously scheduled for such meeting of unitholders.

Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a unitholder, shall be voted at the written direction of the record holder by a proxy designated by our board of directors. Absent direction of this kind, the units will not be voted, except that units held by us on behalf of non-citizen assignees shall be voted in the same ratios as the votes of unitholders on other units are cast.

Any action required or permitted to be taken by our unitholders must be effected at a duly called annual or special meeting of unitholders and may not be effected by any consent in writing by such unitholders.

Meetings of the unitholders may only be called by a majority of our board of directors. 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 shall 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 shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional units having special voting rights could be issued. Please read “— Issuance of Additional Securities.” Units held in nominee or street name accounts 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 its nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our limited liability company agreement will be delivered to the record holder by us or by the transfer agent.

Non-Citizen Assignees; Redemption

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, we may redeem, upon 30 days’ advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, our board of directors may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our board of directors determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

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Indemnification

Under our limited liability company agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of any or our affiliates. Additionally, we shall indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person is or was an employee (other than an officer) or agent of our company.

Any indemnification under our limited liability company agreement will only be out of our assets. We are authorized to 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 limited liability company agreement.

Books and Reports

We are required to keep appropriate books of our business at our principal offices. The books are 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 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 unitholders 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 limited liability company agreement provides that a unitholder can, for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

• a current list of the name and last known address of each unitholder;

• 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 unitholder and the date on which each became a unitholder;

• copies of our limited liability company agreement, the certificate of formation of the company, related amendments and powers of attorney under which they have been executed;

• information regarding the status of our business and financial condition; and

• any other information regarding our affairs as is just and reasonable.

Our board of directors may, and intends to, keep confidential from our unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of directors believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third-party to keep confidential.

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax consequences 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 Vinson & Elkins L.L.P., counsel to 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 of 1986, as amended (the “Code”), existing and proposed regulations promulgated thereunder (the “Treasury 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 Vanguard Natural Resources, LLC and our limited liability company operating subsidiaries.

This section does not address all federal income tax matters that affect unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), whose functional currency is the U.S. dollar and who hold units as capital assets (generally, property that is held for investment). This section has only limited applicability to corporations, partnerships (and entities treated as partnerships for U.S. federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts or mutual funds.Accordingly, we encourage each unitholder to consult, and depend upon, such unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. Tax consequences particular to that unitholder resulting from its ownership or disposition of its units.

We are relying on opinions and advice of Vinson & Elkins L.L.P. With respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the Internal Revenue Service (the “IRS”) or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which such units trade. In addition, the costs of any contest with the IRS will be borne indirectly by unitholders because the costs will reduce our cash available for distribution. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which might be retroactively applied.

All statements of law and legal conclusions, but no statement of fact, contained in this section, except as described below or otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether Vanguard’s 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 Vanguard’s method for taking into account Section 743 adjustments is sustainable in certain cases (please read “Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”); (4) 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); and (5) whether the deduction related to United States production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read “— Tax Treatment of Operations — Deduction for United States Production Activities”).

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Taxation of the Partnership

Partnership Status.  We expect to be treated as a partnership for federal income tax purposes and, therefore, generally will not be liable for federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing our federal income tax liability as if the unitholder had earned such income directly, even if no cash distributions are made to the unitholder. Distributions by us to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed to a unitholder exceeds the unitholder’s adjusted tax basis in its units.

Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for U.S. federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of crude oil, natural gas 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 its current gross income is not qualifying income; however, this estimate could change from time to time. The portion of our income that is qualifying income may 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 status or the status of the operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. On such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Code, its regulations, published revenue rulings and court decisions and the representations set forth below, we will be classified as a partnership and its operating subsidiaries will be disregarded as entities separate from us for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us. The representations made by us upon which Vinson & Elkins L.L.P. has relied include, without limitation:

(a)  Except for VNR Holdings, LLC, neither we nor any of our partnership or limited liability company subsidiaries have elected to be treated as a corporation for federal income tax purposes;

(b)  For each taxable year since the year of our initial public offering, more than 90% of our gross income has been income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code; and

(c)  Each hedging transaction that we treat as resulting in qualifying income has been appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been associated with crude oil, natural gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined generate qualifying income.

We believe that these representations have been true in the past and expect that these representations will be true in the future.

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 (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring 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 our unitholders in liquidation of their interests in us. That deemed contribution and liquidation should not result in the recognition of taxable income by us or our unitholders so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

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If for any reason we are taxable as a corporation, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Accordingly, our taxation as a corporation would materially reduce our cash distributions to our unitholders and thus would likely substantially reduce the value of our units. In addition, any distribution made to a unitholder would be treated as (i) a taxable dividend income to the extent of our current or accumulated earnings and profits then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in our units and thereafter (iii) taxable capital gain.

The remainder of this discussion is based upon the opinion of Vinson & Elkins L.L.P. That we will be treated as a partnership for federal income tax purposes.

Unitholder Status.  Unitholders who have become members of us will be treated as partners of us for federal income tax purposes. Also:

(a)  assignees who have executed and delivered transfer applications, and are awaiting admission as members, and

(b)  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 us for federal income tax purposes.

As there is no direct or indirect controlling authority addressing the federal tax treatment of assignees of common units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose its 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.”

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 appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in us for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income.  Subject to the discussion below under “— Entity Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we do not pay any federal income tax. Rather, each unitholder will be required to report on its income tax return its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units.  A unitholder’s initial tax basis for its units will be the amount it paid for the units plus its share of our nonrecourse liabilities. That initial basis generally will be (i) increased by the unitholder’s share of our income and by any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to it, by its share of our losses, by depletion deductions taken by it to the extent such deductions do not exceed its proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in its share of our nonrecourse liabilities and by its share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder’s share of our nonrecourse liabilities will generally be based on its share of our profits. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

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Treatment of Distributions.  Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder will recognize gain taxable in the manner described below under “— Disposition of Common Units.”

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease the unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “Disposition of Common Units.”

A non-pro rata distribution of money or property (including a deemed distribution described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion recapture, depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for an allocable portion of the non-pro rata distribution. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses.  The deduction by a unitholder of its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder who is an individual, estate, trust or corporation (if more than 50% of the corporation’s stock is owned directly or indirectly by or for five or fewer individuals or a specific type of tax exempt organization), the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. 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 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 common unitholder’s at-risk limitation with respect to us. If a common unitholder were required to compute his at-risk amount separately with respect to each oil or gas property we own, he might 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 common units as a whole

A unitholder subject to the basis and at risk limitation must recapture losses deducted in previous years to the extent that distributions cause the unitholder’s 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 as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain

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recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used.

In addition to the basis and at risk limitations, passive activity loss limitations generally limit the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only its passive income generated in the future and will not be available to offset income from other passive activities or investments, (including 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 natural 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 the unitholder disposes of all of its units 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 and basis limitations.

A unitholder’s share of our net income may be offset by any of our 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. Such term generally does not include qualified dividend income (if applicable) or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly-traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes.  If we are required or elects under applicable law to pay any federal, state, local or non-U.S. Tax on behalf of any current or former unitholder, we are authorized to pay those taxes and treat the payment as a distribution of cash to the relevant unitholder. Where the relevant unitholder’s identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our limited liability company 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 its limited liability company 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 a unitholder in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

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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 unitholders in accordance with their percentage interests in us. If we have a net loss, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units with the effect that purchasers in an offering will receive essentially the same allocations as if the tax bases of our assets were equal to their fair market value at the time of such offering (a “Book-Tax Disparity”). In connection with providing this benefit to any future unitholders, similar allocations will be made to all holders of partnership interests immediately prior to such other transactions to account for the differing between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders. 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 sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, generally must have “substantial economic effect” as determined under Treasury Regulations. If an allocation does not have substantial economic effect, it will be reallocated to our unitholders in accordance with the basis of their interests in us, which will be determined by taking into account all the facts and circumstances, including

• their relative contributions to us;

• the interests of all of our partners in profits and losses;

• the interest of all of our partners in cash flow; and

• the rights of all of our partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under Vanguard’s limited liability company agreement will be given effect for federal income tax purposes in determining a partner’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 treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period: (i) any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder; (ii) any cash distributions received by the unitholder as to those units would be fully taxable; and (iii) all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose units are loaned to a short seller to cover a short sale of our units. 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 and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “— Disposition of Units — Recognition of Gain or Loss.”

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Alternative Minimum Tax.  If a unitholder is subject to alternative minimum tax, such tax will apply to such unitholder’s distributive share of any items of our income, gain, loss or deduction. The current alternative minimum tax rate for non-corporate 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 with respect to the impact of an investment in our units on their alternative minimum tax liability.

Tax Rates.  Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 35% and 15%, respectively. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

A 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts will apply for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse) or $200,000 (if the unitholder is unmarried).

Section 754 Election.  We have made the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS unless there is a construction termination of the partnership for tax purposes. Please read “— Disposition of Common Units — Constructive Termination.” That election generally permits us to adjust the tax bases in our assets as to specific purchased units under Section 743(b) of the Code to reflect the unit purchase price. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values of our assets which may be higher or lower than their bases at the time of the relevant purchase. The Section 743(b) adjustment does not apply to a person who purchases units directly from us. For purposes of this discussion, a unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all unitholders (“common basis”) and (2) its Section 743(b) adjustment to that tax basis.

We have adopted the remedial allocation method as to all our properties. Under Treasury Regulations, a Section 743(b) adjustment attributable to property depreciable under Section 168 of the Code may be amortizable over the remaining cost recovery period for such property, while a Section 743(b) adjustment attributable to properties subject to depreciation under Section 167 of the Code, must be amortized straight-line or using the 150% declining balance method. As a result, if we owned any assets subject to depreciation under Section 167 of the Code, the amortization rates could give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders.

Under our limited liability company agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these or any other Treasury Regulations. Please read “— Uniformity of Units.” Consistent with this authority, we intend to treat properties depreciable under Section 167, if any, in the same manner as properties depreciable under Section 168 for this purpose. These positions are consistent with the methods employed by other publicly-traded partnerships but are inconsistent with the existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach.

The IRS may challenge the position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and 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.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

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A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or basis reduction is substantial if it exceeds $250,000.

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 Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax 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 it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year.  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 its share of our income, gain, loss and deduction for each taxable year ending within or with the unitholder’s taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include his share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than twelve months 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 (please read “— Limitations on Deductibility of Losses”), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our oil and gas interests. Although the Code requires each unitholder to compute its own depletion allowance and maintain records of its 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. Each unitholder, however, remains responsible for calculating its own depletion allowance and maintaining records of its share of the adjusted tax basis of the underlying property for depletion and other purposes.

Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the 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 average daily production of domestic crude oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and gas 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 unlimited.

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 oil and gas interests or the disposition by the unitholder of some or all of its units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax 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 common unitholder and not by us, 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 its tax advisor to determine whether percentage depletion would be available to the unitholder.

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 in respect of those IDCs 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 oil and gas 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 oil or gas properties 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 oil and gas products exceeding $5 million per year in the aggregate.

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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 tax 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 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 U.S. 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 9% of our qualified production activities income that is allocated to such unitholder, but not to exceed 50% of such unitholder’s IRS Form W-2 wages for the taxable year allocable to domestic production gross receipts.

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 its Section 199 deduction, each unitholder will aggregate its share of the qualified production activities income allocated to it from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account its distributive share of the expenses allocated to it 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 tax 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, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury Regulations 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 our 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 unitholder is encouraged to consult its tax advisor to determine whether the Section 199 deduction would be available to such unitholder.

Lease Acquisition Costs.  The cost of acquiring oil and gas leases 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 oil and gas 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 that are reasonable in amount.

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 these 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 an offering will be borne by our unitholders holding interests in us prior to that offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

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 its 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 we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, 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. 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 could change, and unitholders could 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.  A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to such units. Because the amount realized includes a unitholder’s share of our 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 unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, primarily depletion and depreciation recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on 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 loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

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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, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the 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 or loss 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 (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or any other extraordinary item of income, gain, loss or deduction will be allocated among our unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly-traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the safe harbor in the proposed regulations differs slightly from the proration method we have adopted because the safe harbor would allocate tax items among the months based on the relative number of days in each month and could require certain tax items which we may not consider extraordinary to be allocated to the month in which such items actually occur. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor 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

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authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units 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 the month of disposition but will not be entitled to receive a cash distribution for that quarter.

Notification Requirements.  A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction 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. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination.  We will be considered to have terminated for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. 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 other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 will result in us filing two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure the IRS may allow, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the 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 and for other reasons, 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. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not anticipated to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of our units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

Our limited liability company agreement permits the Board to take positions in filing our tax returns that preserve the uniformity of 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. Vinson & Elkins L.L.P. is unable to opine as to validity of such filing positions. A unitholder’s basis in units is reduced by its or her share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Units — Recognition of Gain or Loss” above and “— Tax Consequences of Unit Ownership — Section 754 Election” above. 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 our units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

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Tax-Exempt Organizations and Other Investors

Ownership of our units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-resident aliens and non-U.S. corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of their ownership of our units. Consequently, 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 income or gain. Moreover, under rules applicable to publicly-traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. 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 non-U.S. 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 non-U.S. corporation’s “U.S. Net equity,” that 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 non-U.S. corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a non-U.S. unitholder would be considered to be engaged in a trade or business in the U.S. By virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

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 its 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 each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

Neither we nor Vinson & Elkins, L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible, and such a contention could negatively affect the value of our 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

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result in an audit of its own 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.

Limited liability companies treated as partnerships for U.S. federal income tax purposes generally are treated as entities separate from their owners for purposes of federal income 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 Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our limited liability company agreement allows our board of directors to appoint one of our officers who is a unitholder to serve 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 in that action.

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:

(a)  the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b)  a statement regarding whether the beneficial owner is

(1)  a non-U.S. person,

(2)  a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(3)  a tax-exempt entity;

(c)  the amount and description of units held, acquired or transferred for the beneficial owner; and

(d)  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 U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to Vanguard. The nominee is required to supply the beneficial owner of the units with the information furnished to Vanguard.

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 Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

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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:

(1)  for which there is, or was, “substantial authority,” or

(2)  as to which there is a reasonable basis and the relevant 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 relevant facts on our returns. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the tax 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 tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposes is increased to 40%. There is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions.  If we engage in a “reportable transaction,” we (and possibly our unitholders 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 for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our unitholders’ tax returns) would be audited by the IRS. Please read “— Administrative Matters — Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following additional consequences:

• 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.”

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State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local 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. We currently conduct business and own property in several states, most of which impose an income tax on entities such as us. We may also own property or do business in other states in the future. Unitholders may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. Unitholders will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and unitholders may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states 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 state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may 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 of Unitholder Taxes.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

Tax Consequences of Ownership of Debt Securities

A description of the material federal income tax consequences of the acquisition, ownership and disposition of any series of debt securities will be set forth on the prospectus supplement relating to the offering of such debt securities.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in Vanguard. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in Vanguard. Vanguard strongly recommends that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all state and local, as well as U.S. federal tax returns that may be required of the unitholder.

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PLAN OF DISTRIBUTION

We may sell or distribute the securities included in this prospectus through underwriters, agents, dealers, in private transactions, at market prices prevailing at the time of sale, at prices related to the prevailing market prices, or at negotiated prices.

In addition, we may sell some or all of the securities included in this prospectus through:

• a block trade in which a broker-dealer may resell a portion of the block, as principal, in order to facilitate the transaction;

• purchases by a broker-dealer, as principal, and resale by the broker-dealer for its account; or

• ordinary brokerage transactions and transactions in which a broker solicits purchasers.

In addition, we may enter into option or other types of transactions that require us to deliver common units to a broker-dealer, who will then resell or transfer the common units under this prospectus. We may enter into hedging transactions with respect to our securities. For example, we may:

• enter into transactions involving short sales of the common units by broker-dealers;

• sell common units short themselves and deliver the units to close out short positions;

• enter into option or other types of transactions that require us to deliver common units to a broker-dealer, who will then resell or transfer the common units under this prospectus; or

• loan or pledge the common units to a broker-dealer, who may sell the loaned units or, in the event of default, sell the pledged units.

We are registering the common units on behalf of the selling unitholder. As used in this prospectus, “selling unitholder” includes donees and pledgees selling common units received from a named selling unitholder after the date of this prospectus.

Under this prospectus, the selling unitholder intends to offer common units to the public:

• through one or more broker-dealers;

• through underwriters; or

• directly to investors.

The selling unitholder may price the common units offered from time to time:

• at fixed prices;

• at market prices prevailing at the time of any sale under this registration statement;

• at prices related to prevailing market prices;

• at varying prices determined at the time of sale; or

• at negotiated prices.

We will pay all reasonable expenses of the registration and offering of the common units offered hereby. We will not pay any underwriting fees, discounts and selling commissions allocable to the selling unitholder’s sale of common units, which will be paid by the selling unitholder. Broker-dealers may act as agent or may purchase securities as principal and thereafter resell the securities from time to time:

• in or through one or more transactions (which may involve crosses and block transactions) or distributions;

• on the New York Stock Exchange or such other national exchange on which our common units are listed at such time;

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• through the writing of options;

• in the over-the-counter market; or

• in private transactions.

We may enter into derivative transactions with third parties, or sell securities not covered by this prospectus to third parties in privately negotiated transactions. If the applicable prospectus supplement indicates, in connection with those derivatives, the third parties may sell securities covered by this prospectus and the applicable prospectus supplement, including in short sale transactions. If so, the third party may use securities pledged by us or borrowed from us or others to settle those sales or to close out any related open borrowings of securities, and may use securities received from us in settlement of those derivatives to close out any related open borrowings of securities. The third party in such sale transactions will be an underwriter and, if not identified in this prospectus, will be identified in the applicable prospectus supplement (or a post-effective amendment). In addition, we may otherwise loan or pledge securities to a financial institution or other third party that in turn may sell the securities short using this prospectus. Such financial institution or other third party may transfer its economic short position to investors in our securities or in connection with a concurrent offering of other securities.

There is currently no market for any of the securities, other than our common units listed on the New York Stock Exchange. If the securities are traded after their initial issuance, they may trade at a discount from their initial offering price, depending on prevailing interest rates, the market for similar securities and other factors. While it is possible that an underwriter could inform us that it intends to make a market in the securities, such underwriter would not be obligated to do so, and any such market making could be discontinued at any time without notice. Therefore, we cannot assure you as to whether an active trading market will develop for these other securities. We have no current plans to list the debt securities on any securities exchange; any such listing with respect to any particular debt securities will be described in the applicable prospectus supplement.

Any broker-dealers or other persons acting on our behalf that participate with us in the distribution of the common units may be deemed to be underwriters and any commissions received or profit realized by them on the resale of the common units may be deemed to be underwriting discounts and commissions under the Securities Act. As of the date of this prospectus, we are not a party to any agreement, arrangement or understanding between any broker or dealer and us with respect to the offer or sale of the securities pursuant to this prospectus.

We may have agreements with agents, underwriters, dealers and remarketing firms to indemnify them against certain civil liabilities, including liabilities under the Securities Act. Agents, underwriters, dealers and remarketing firms, and their affiliates, may engage in transactions with, or perform services for, us in the ordinary course of business. This includes commercial banking and investment banking transactions.

At the time that any particular offering of securities is made, to the extent required by the Securities Act, a prospectus supplement will be distributed setting forth the terms of the offering, including the aggregate number of securities being offered, the purchase price of the securities, the initial offering price of the securities, the names of any underwriters, dealers or agents, any discounts, commissions and other items constituting compensation from us and any discounts, commissions or concessions allowed or reallowed or paid to dealers.

Underwriters or agents could make sales in privately negotiated transactions and/or any other method permitted by law, including sales deemed to be an “at the market” offering as defined in Rule 415 promulgated under the Securities Act, which includes sales made directly on or through the New York Stock Exchange, the existing trading market for our common units, or sales made to or through a market maker other than on an exchange.

Securities may also be sold directly by us. In this case, no underwriters or agents would be involved. If a prospectus supplement so indicates, underwriters, brokers or dealers, in compliance with applicable law, may engage in transactions that stabilize or maintain the market price of the securities at levels above those that might otherwise prevail in the open market.

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Pursuant to a requirement by the Financial Industry Regulatory Authority, or FINRA, the maximum commission or discount to be received by any FINRA member or independent broker/dealer may not be greater than eight percent (8%) of the gross proceeds received by us for the sale of any securities being registered pursuant to SEC Rule 415 under the Securities Act.

Because FINRA views our common units as interests in a direct participation program, any offering of common units under the registration statement of which this prospectus forms a part will be made in compliance with Rule 2310 of the FINRA Rules.

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LEGAL MATTERS

The validity of certain of the securities offered in this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Vinson & Elkins L.L.P. will also render an opinion on the material federal income tax considerations regarding the securities. The validity of certain guarantees with respect to the debt securities offered by this prospectus will be passed upon for us by Wyatt, Tarrant & Combs, LLP. If certain legal matters in connection with an offering of the securities made by this prospectus and a related prospectus supplement are passed on by counsel for the underwriters of such offering, that counsel will be named in the applicable prospectus supplement related to that offering.

EXPERTS

The consolidated financial statements of Vanguard Natural Resources, LLC and its subsidiaries as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010, management’s assessment of the effectiveness of Vanguard Natural Resources, LLC and its subsidiaries’ internal control over financial reporting as of December 31, 2010, the statements of revenues and direct operating expenses of the properties Vanguard acquired from a private seller for each of the years in the two-year period ended December 31, 2009, which appear in Vanguard’s Current Report on Form 8-K/A filed with the SEC on May 12, 2010, and the statement of revenues and direct operating expenses of the oil and gas properties purchased from a private seller for the year ended December 31, 2010, which appear in Vanguard’s Current report on Form 8-K/A filed with SEC on September 16, 2011, incorporated by reference in this Prospectus have been so incorporated in reliance on the reports of BDO USA, LLP (formerly known as BDO Seidman, LLP), an independent registered public accounting firm, incorporated herein by reference, given on the authority of said firm as experts in auditing and accounting.

The consolidated financial statements of Encore Energy Partners LP appearing in Encore Energy Partner LP’s Annual Report (Form 10-K) for the year ended December 31, 2010 have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon, included therein, and incorporated herein by reference. Such consolidated financial statements are incorporated herein by reference in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The information incorporated herein by reference regarding estimated quantities of our proved reserves and ENP’s proved reserves, each as of December 31, 2010, was prepared or derived from estimates prepared by DeGolyer and MacNaughton, independent reserve engineers. These estimates are incorporated herein by reference in reliance upon the authority of such firm as experts in these matters.

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$300,000,000

  % Senior Notes due 2020

 

PRELIMINARY PROSPECTUS SUPPLEMENT

      , 2012

 

Citigroup

Credit Agricole CIB

RBC Capital Markets

RBS

UBS Investment Bank

Wells Fargo Securities

BMO Capital Markets

Capital One Southcoast

Comerica Securities

Scotiabank

Lloyds Securities

Natixis

US Bancorp