Grizzly Energy 10K 2011 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


(Mark One)
x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the fiscal year ended December 31, 2011

		Or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the transition period from to .

Commission File Number 001-33756

Vanguard Natural Resources, LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware		61-1521161
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

5847 San Felipe, Suite 3000 Houston, Texas		77057
(Address of Principal Executive Offices)		(Zip Code)

Telephone Number: (832) 327-2255

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class		Name of Each Exchange on which Registered

Common Units		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x

No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o

No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),

and (2) has been subject to such filing requirements for the past 90 days.

Yes x

No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x

No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in

Part III of this Form 10-K or any amendment to this Form 10-K.

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


Large accelerated filero		Accelerated filerx
Non-accelerated filero		Smaller reporting companyo
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o

No x

The aggregate market value of Vanguard Natural Resources, LLC common units held by non-affiliates of the registrant as of June 30, 2011 was approximately $675,664,323 based upon the New York Stock Exchange composite transaction closing price.

As of March 1, 2012 53,469,703 of the registrant’s common units remained outstanding.

Documents Incorporated by Reference:

Portions of the registrant’s proxy statement to be furnished to unitholders in connection with its 2012 Annual Meeting of Unitholders are incorporated by reference in Part III— Items 10-14 of this annual report on Form 10-K for the year ending December 31, 2011 (“this Annual Report”).

Vanguard Natural Resources, LLC

TABLE OF CONTENTS

	Caption	Page

Glossary of Terms
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	40
Item 2.	Properties	40
Item 3.	Legal Proceedings	40
Item 4.	Mine Safety Disclosures	41

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6.	Selected Financial Data	43
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 8.	Financial Statements and Supplementary Data	70
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	107
Item 9A.	Controls and Procedures	107
Item 9B.	Other Information	109

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	109
Item 11.	Executive Compensation	109
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	109
Item 13.	Certain Relationships and Related Transactions, and Director Independence	109
Item 14.	Principal Accounting Fees and Services	109

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	110
	Signatures	113

Forward-Looking Statements

Certain statements and information in this Annual Report may constitute “forward-looking statements.” 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 are those described in “Item 1A. Risk Factors” and those described elsewhere in this Annual Report.

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.

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

Bcf	= billion cubic feet	MMBbls	= million barrels

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 oil and NGLs 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.

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 (“VNG”), 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.

PART I

ITEM 1. 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, 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.

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 Vanguard 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 our independent reserve engineers, DeGolyer & MacNaughton, 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 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

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.

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”). This 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, 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 “Second Lien Term Loan”). The loans under the Second Lien 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 Second Lien Term Loan. As of March 1, 2012 we had $57.0 million in borrowings outstanding under the Second Lien Term Loan.

Borrowings under each of the reserve-based credit facility and the Second Lien 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 “Item 7. Management’s Discussion and Analysis and Results of Operations—Capital Resources and Liquidity—Debt and Credit Facilities” for additional information regarding our credit facilities.

Organizational Structure

The following diagram depicts our organizational structure as of March 5, 2012:

Proved Reserves

Based on reserve reports prepared by our independent reserve engineers, DeGolyer and MacNaughton, or “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 operated wells accounted for approximately 62% of our total estimated proved reserves at December 31, 2011.Our average net daily production for the year ended December 31, 2011 was 13,405 BOE/day. Our average net 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, we have identified 442 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. 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 natural gas and 65% was proved developed. This transaction is expected to close in March 2012.

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:

·	Manage our oil and natural gas assets with a focus on maintaining cash flow levels;

Replace reserves either through the development of our extensive inventory of proved undeveloped locations or make accretive acquisitions of oil and natural gas properties in the known producing basins of the continental United States characterized by a high percentage of producing reserves, long-life, stable production and step-out development opportunities;

·	Maintain a conservative capital structure to ensure financial flexibility for opportunistic acquisitions; and

·	Use hedging strategy to reduce the volatility in our revenues resulting from changes in oil, natural gas and NGLs prices.

Properties

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

					Net
					Estimated
		2011 Net			Proved
	Operator	Production			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
Appalachian Basin (2)	Vinland Energy Operations, LLC		533			6,171
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.
(2)		In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

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 comprised of assets in Wyoming, including the Gooseberry field, and the Elk Basin field in south central Montana. 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.

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, 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.

Appalachian Basin Properties

Our properties in Appalachia are operated by Vinland and are located in southeastern Kentucky and northeastern Tennessee. Our working interest ranges from 40% to 100% for most of the approximate 922 wells. Most of the production is high BTU gas that produces primarily from the Maxon, Big Lime and Devonian Shales from a depth ranging from approximately 1,500 feet to 4,500 feet.

During 2011, the properties in Appalachia produced approximately 533 MBOE, of which 83% was natural gas. These properties accounted for approximately 6,171 MBOE or 8% of our total estimated proved reserves at year end, of which 4,020 MBOE were proved developed and 2,151 MBOE were proved undeveloped. As of December 31, 2011, our Appalachian Basin properties consisted of 130,191 gross (65,559 net) acres.

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.

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.

The Appalachian Basin is a mature, producing region with well known geologic characteristics. Reserves in the Appalachian Basin typically have a high degree of step-out development success. Specifically, as development progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category, and additional adjacent locations are added to proved undeveloped reserves. As a result, the cumulative amount of total proved reserves tends to increase as development progresses. Wells in the Appalachian Basin generally produce little or no water, contributing to a low cost of operation. Natural gas produced in the Appalachian Basin typically sells for a premium to NYMEX natural gas prices due to the proximity to major consuming markets in the northeastern United States. For the year ended December 31, 2011, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin on the Columbia Gas Transmission system was $0.11 per MMBtu. In addition, most of our natural gas production has historically had a high Btu content, resulting in an additional premium to NYMEX natural gas prices. For the year ended December 31, 2011, our average realized natural gas prices in Appalachia (before hedging), represented a $0.64 per Mcfe premium to NYMEX natural gas prices, which accounts for both the basis differential and the Btu adjustments.

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 $11.67 per barrel in Appalachia and the average 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.

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.”

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, based on reserve reports prepared by D&M. Copies of their summary reports are included as exhibits to this 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.

Reserve Data:
Estimated net proved reserves:
Crude oil (MBbls)		44,803
Natural gas (Bcf)		163
NGLs (MBbls)		7,385
Total (MMBOE)		79.3
Proved developed (MMBOE)		68.2
Proved undeveloped (MMBOE)		11.1
Proved developed reserves as % of total proved reserves		86	%
Standardized Measure (in millions) (1)(2)	$	1,476.2
Representative Oil and Natural Gas Prices (3):
Oil—WTI per Bbl	$	96.24
Natural gas—Henry Hub per MMBtu	$	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.”

(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 “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

(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.

The following tables set forth certain information with respect to our estimated proved reserves 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	Oil	NGLs	Total	Natural Gas	Oil	NGLs	Total	Total
	(Bcf)	(MMBbls)	(MMBbls)	(MMBOE)	(Bcf)	(MMBbls)	(MMBbls)	(MMBOE)	(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
Appalachian Basin (1)	21.2	0.5	—	4.0	12.9	—	—	2.1	6.1
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	131.5	40.1	6.2	68.2	31.4	4.8	1.2	11.1	79.3

(1)

In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.


	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
Appalachian Basin (2)		46.7		(5.8	)		40.9
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	$	1,341.1	$	135.1		$	1,476.2


(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 “Item 8. Financial Statements and Supplementary Data” of this Annual Report.


(2)		In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

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 “Item 1A. 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”), 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, 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.

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 Annual Report 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.

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.

(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 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
Appalachian Basin (1)		869		759		53		44		922		803
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		1,958		1,298		2,942		947		4,900		2,245

(1)

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2011 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
Appalachian Basin (5)		20,900		18,966		109,291		46,593		130,191		65,559
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		227,821		179,695		151,759		70,158		379,580		249,853

(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.

(5) In February 2012, we entered into a Unit Exchange Agreement to transfer our ownership interests in these properties. See “Subsequent Events” in the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

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.

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. In Appalachia, most of our wells are drilled to depths ranging from 2,000 feet to 4,500 feet. Many of our wells are completed to multiple producing zones and production from these zones may be commingled. The average well in Appalachia takes approximately 10 days to drill and most of our wells are producing and connected to pipeline within 30 days after completion. In general, our producing wells in Appalachia have stable production profiles and long-lived production, often with total projected economic lives in excess of 50 years. During 2011, we drilled three oil wells in this area.

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.

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 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.

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	)

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;

·	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 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 Annual Report, 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.

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 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 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;

	·	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 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 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.

Offices

Our principal executive office is located at 5847 San Felipe, Suite 3000, Houston, Texas 77057. Our main telephone number is (832) 327-2255.

Available Information

Our website address is www.vnrllc.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report. We make available on our website under "Investor Relations-SEC Filings," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website at www.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.

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

• Audit Committee Charter;

• Nominating and Corporate Governance Committee Charter;

• Compensation Committee Charter;

• Conflicts Committee Charter;

• Code of Business Conduct and Ethics; and

• Corporate Governance Guidelines.

ITEM 1A. RISK FACTORS

Risks Related to Our Business

We may not have sufficient cash from operations to pay quarterly distributions on our common units following establishment of cash reserves and payment of operating costs.

We may not have sufficient cash flow from operations each quarter to pay distributions. 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 collectibility 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.

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 this 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 future cash distributions will be dependent to a substantial extent upon our ability to prudently acquire, manage and develop such properties.

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 pay distributions.

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;

·	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 distributions to our unitholders, all of which can affect the value of our units.

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 distributions to our unitholders.

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, investors in our units should consider the cash distributions that are paid on the units not merely as a “yield” on the units, but as a combination of both a return of capital and a return on investment. Investors in our units will have to obtain the return of capital invested out of cash flow derived from their investments in units during the period when reserves can be economically recovered. Accordingly, we give no assurances that the distributions our unitholders receive over the life of their investment will meet or exceed their initial capital investment.

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 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 oilof $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 cash distributions to our unitholders 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 for distribution to our unitholders depends primarily upon our cash flow and not our profitability.

The amount of cash that we have available for distribution 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 pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses.

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 cash distributions to unitholders.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves and adversely affect our ability to make distributions to our unitholders.

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 for distribution. 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 are 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 for distribution.

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 for distribution.

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 for distribution.

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 cash distributions to our unitholders.

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 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 distributions. 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 for distribution 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 for distribution 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 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 “Item 1. Business—Operations—Environmental and Occupational Health 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.

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 pay future cash distributions at expected levels.

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 pay distributions.

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, we have identified 442 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 pay distributions to our unitholders.

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;

	·	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.

Our price risk management activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to pay distributions to our unitholders.

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 “Item 1. Business— Operations— Price Risk and Interest Rate Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Our actual future production may be significantly higher or lower than we estimate at the time we enter into 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 distributions to our unitholders.

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 pay distributions to our unitholders.

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 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 “Item1. Business—Operations—Environmental and Occupational Health and Safety Matters” and “Item 1. Business—Operations—Other Regulation of the Oil and Natural Gas Industry” 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 available for distribution.

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 for distribution.

Risks Related to Our Structure

We may issue additional units without unitholder approval, which would dilute their existing ownership interests.

We may issue an unlimited number of limited liability company interests of any type, including units, without the approval of our unitholders.

The issuance of additional units or other equity securities may have the following effects:

·	the proportionate ownership interest of unitholders in us may decrease;

·	the amount of cash distributed on each unit may decrease;

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

·	the market price of the units may decline.

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our units.

Our limited liability company agreement restricts the voting rights of 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. Our limited liability agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Our limited liability company agreement provides for a limited call right that may require unitholders to sell their units at an undesirable time or price.

If, at any time, any person owns more than 90% of the units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining units then outstanding at a price not less than the then-current market price of the units. As a result, unitholders may be required to sell their units at an undesirable time or price and therefore may receive a lower or no return on their investment. Unitholders may also incur tax liability upon a sale of their units.

The price of our common units could be subject to wide fluctuations, unitholders could lose a significant part of their investment.

During 2011, our unit price fluctuated from a closing high of $33.09 on April 29, 2011 to a closing low of $23.29 on October 4, 2011. The market price of our common units is subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

·	fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

·	changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry;

·	changes in securities analysts’ recommendations and their estimates of our financial performance;

·	the public’s reaction to our press releases, announcements and our filings with the SEC;

·	changes in market valuations of similar companies;

·	departures of key personnel;

·	commencement of or involvement in litigation;

·	variations in our quarterly results of operations or those of other oil and natural gas companies;

·	variations in the amount of our quarterly cash distributions; and

·	future issuances and sales of our units.

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

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act, or the “Delaware Act,” we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, members or unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a member or unitholder is liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.

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

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

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation 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 distribution to unitholders.

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

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. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us or ENP as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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. Any such changes could negatively impact the value of an investment in our units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax which is assessed on Texas sourced taxable margin 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. If any other state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced.

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

We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners in us for federal income tax purposes to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decreases the tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation deductions. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholders sells their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning units that may result in adverse tax consequences to them.

Investment in units by tax-exempt entities, including employee benefit plans, individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.

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

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. 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 also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax election and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our units.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We currently own property and conduct business in Kentucky, New Mexico, Tennessee, Texas, Mississippi, Montana, North Dakota, Oklahoma, Arkansas and Wyoming. Each of these states, other than Texas and Wyoming, imposes an income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

A description of our properties is included in “Item 1. Business,” and is incorporated herein by reference.

We have offices in Houston, Ft. Worth and Odessa, Texas; and Powell, Wyoming. As of December 31, 2011, the lease for the Houston office covered approximately 21,428 square feet of office space and runs through February 28, 2013. Our leases for the Ft. Worth and Odessa offices cover approximately 7,315 square feet and 3,250 square feet of office space, respectively, and run through December 31, 2015 and August 31, 2014, respectively. The total annual costs of our office leases for 2011 was approximately $0.9 million.

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. �� LEGAL PROCEEDINGS

The Company is a defendant in legal proceedings 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 any action 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 discussed below. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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. The O’Neal, Morgan, and Rower lawsuits were consolidated on June 5, 2011 as John 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 consolidated O’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.

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 caption In 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 captioned Goldstein 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 as amended (the “Exchange Act”) 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 captioned Hysong 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 Exchange Act 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. Vanguard, ENP and the other defendants named in these lawsuits intend to defend vigorously against these and any other actions.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are traded on the New York Stock Exchange under the symbol “VNR.” On March 1, 2012, there were 53,469,703 common units outstanding and approximately twenty seven unitholders, which does not include beneficial owners whose units are held by a clearing agency, such as a broker or a bank. On March 1, 2012, the market price for our common units was $27.79 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $1.4 billion. The following table presents the high and low sales price for our common units during the periods indicated.

	Common Units
	High		Low
2011
Fourth Quarter	$	29.50	$	21.86
Third Quarter	$	31.75	$	22.79
Second Quarter	$	33.67	$	26.10
First Quarter	$	33.41	$	28.23
2010
Fourth Quarter	$	29.76	$	24.98
Third Quarter	$	26.46	$	19.05
Second Quarter	$	25.27	$	16.94
First Quarter	$	25.55	$	19.27

Stock Performance Graph. The performance graph below compares total unitholder return on our units, with the total return of the Standard & Poor’s 500 Index, or “S&P 500 Index,” and our Peer Group Index, a weighted composite of five, nine and eight oil and natural gas production publicly traded partnerships for 2009, 2008 and 2007, respectively. For 2011 and 2010, the Peer Group Index was a weighted composite of six natural gas and oil production publicly traded partnerships, which were paying a distribution for all of 2011 and 2010. Total return includes the change in the market price, adjusted for reinvested dividends or distributions, for the period shown on the performance graph and assumes that $100 was invested in VNR at the last reported sale price of units as reported by New York Stock Exchange ($18.94) on October 24, 2007 (the day trading of units commenced), and in the S&P 500 Index and our peer group index on the same date. The results shown in the graph below are not necessarily indicative of future performance. The following performance graph and related information shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Exchange Act, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

	10/24/07		12/31/07			12/31/08			12/31/09			12/31/10			12/31/11
Vanguard Natural Resources, LLC	$	100.00	$	84.48	(1)	$	35.37	(1)	$	154.88	(1)	$	226.94	(1)	$	228.13	(1)
Peer Group Index	$	100.00	$	90.76		$	42.75		$	119.50		$	155.81		$	169.49
S&P 500 Index	$	100.00	$	96.87		$	59.59		$	73.56		$	82.96		$	82.96

(1)	Based on the last reported sale price of VNR units as reported by New York Stock Exchange on December 31, 2007 ($16.00), 2008 ($5.90), 2009 ($22.07), 2010 ($29.65) and 2011 ($27.63).

Distributions Declared. The following table shows the amount per unit, record date and payment date of the quarterly cash distributions we paid on each of our common units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.

	Cash Distributions
	Per Unit		Record Date	Payment Date
2011
Fourth Quarter	$	0.5875	February 7, 2012	February 14, 2012
Third Quarter	$	0.5775	November 7, 2011	November 14, 2011
Second Quarter	$	0.575	August 5, 2011	August 12, 2011
First Quarter	$	0.570	May 6, 2011	May 13, 2011
2010
Fourth Quarter	$	0.560	February 7, 2011	February 14, 2011
Third Quarter	$	0.550	November 5, 2010	November 12, 2010
Second Quarter	$	0.550	August 6, 2010	August 13, 2010
First Quarter	$	0.525	May 7, 2010	May 14, 2010

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. Available cash generally means, for any quarter ending prior to liquidation:

(a) the sum of:

	(i)	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

	(ii)	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,

(b) 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:

	(i)	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);

	(ii)	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

	(iii)	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.

Equity Compensation Plans. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" for information regarding our equity compensation plans as of December 31, 2011.

ITEM 6. SELECTED FINANCIAL DATA

Set forth below is our summary of our consolidated financial and operating data for the periods indicated for Vanguard Natural Resources, LLC.

The selected financial data should be read together with “ Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” included in this Annual Report.

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 “—Non-GAAP Financial Measure.”

	Year Ended December 31, (5)
(in thousands, except per unit data)	2011 (6)			2010			2009			2008			2007
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 to Vanguard unitholders unitholdersg interest (4)	$	164,603		$	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 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 the IPO on October 28, 2007 through December 31, 2007, resulting in a distribution of $0.291 per unit for the period.

(4)		See “—Non-GAAP Financial Measure” below.

(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, South Texas and Mississippi. The operating results of these properties were included with ours 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,
(in thousands)	2011		2010 (1)		2009		2008		2007
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 acquired with these properties were included with ours 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.

Summary Reserve and Operating Data

The following tables show estimated net proved reserves based on a reserve report prepared by our independent petroleum engineers, D&M, and certain summary unaudited information with respect to our production and sales of oil, natural gas and NGLs. You should refer to “Item 1A. Risk Factors,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 1. Business—Oil, Natural Gas and NGLs Data—Estimated Proved Reserves” and “—Production and Price History” included in this Annual Report in evaluating the material presented below.

	As of December 31, 2011
Reserve Data:
Estimated net proved reserves:
Crude oil (MBbls)		44,803
Natural gas (Bcf)		163
NGLs (MBbls)		7,385
Total (MMBOE)		79.3
Proved developed (MMBOE)		68.2
Proved undeveloped (MMBOE)		11.1
Proved developed reserves as % of total proved reserves		86	%
Standardized Measure (in millions) (1)(2)	$	1,476.2
Representative Oil and Natural Gas Prices (3):
Oil—WTI per Bbl	$	96.24
Natural gas—Henry Hub per MMBtu	$	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 “Item 1. Business— Operations—Price Risk and Interest Rate Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

(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 “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

(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.

	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 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.

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.

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

	Year Ended December 31,
(in thousands)	2011 (1)			2010 (2)			2009			2008			2007
Net income (loss) attributable to Vanguard unitholders	$	62,063		$	21,885		$	(95,735	)	$	(3,752	)	$	2,649
Net income attributable to non-controlling interest		26,067			—			—			—			—
Net income (loss)		88,130			21,885			(95,735	)		(3,752	)		2,649
Plus:
Interest expense, including realized losses on interest rate derivative contracts		31,868			7,565			6,179			5,597			8,135
Loss on extinguishment of debt		—			—			—			—			2,502
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			—
Bad debt expense		—			—			—			—			1,007
Amortization of premiums paid on derivative contracts		11,346			1,950			3,502			4,493			4,274
Amortization of value on derivative contracts acquired		169			1,995			3,619			733			—
Unrealized (gains) losses on other commodity and interest rate derivative contracts (3)		2,558			14,494			18,280			(35,851	)		—
Net (gain) loss on acquisitions of oil and natural gas properties		367			5,680			(6,981	)		—			—
Deferred taxes		261			(12	)		(302	)		177			—
Unit-based compensation expense		2,557			847			2,483			3,577			2,132
Realized loss on cancelled derivatives		—			—			—			—			777
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			—			17			62
Adjusted EBITDA before non-controlling interest	$	224,601		$	80,396		$	56,202		$	48,754		$	30,395
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		$	48,754		$	30,395

(1)	Results of operations from oil and natural gas properties acquired in 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.
(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.

ITEM 7.

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

The following discussion and analysis should be read in conjunction with “Item 6. Selected Financial Data” and the accompanying financial statements and related notes included elsewhere in this Annual Report. 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 this 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. 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.

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.

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. 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 Mississippi. The operating results of these properties are included with ours from the date of 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)			Percentage Increase (Decrease)
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.
	(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 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 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)		Percentage Increase (Decrease)
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, as well as additional interests in these 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 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 $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 “Item 8. Financial Statements and Supplementary Data” of this Annual Report 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 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 oilof $3.87 per MMBtu for natural gas and $61.04 per barrel of crude oil.

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 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.

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 have $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 borrowing base is $765.0 million and the next scheduled redetermination is in April 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.

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 “Item 1. Business—Operations—Price Risk and Interest Rate Management Activities” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” 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.

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 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 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 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 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 Second Lien Term Loan.

Debt and Credit Facilities

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 an initial 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 the this reserve-based credit facility and the Second Lien Term Loan (as discussed below) were used to fully repay outstanding borrowings from the ENP Credit agreement and Vanguard’s $175.0 million Term Loan also 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 facility to refinance our debt under the Second Lien Term Loan, (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.

At December 31, 2011, we had $671.0 million 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. 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 decreases in our borrowing base availability in the future. As of March 1, 2012, we have $184.0 million available to be borrowed under our reserve-based credit facility.

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;

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;

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 agreement, the lenders will be able to accelerate the maturity of the credit agreement 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 “Second Lien Term Loan”) with seven banks from the reserve-based credit facility, with a maturity date of May 30, 2017.

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%

Amounts outstanding under the Second Lien 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 Second Lien 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 Second Lien 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 Second Lien Term Loan also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

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 Second Lien 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 Second Lien 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.

ENP incurred a quarterly commitment fee at a rate of 0.5% per year on the unused portion of the ENP Credit Agreement. In addition, loans under the ENP Credit Agreement were subject to varying rates of interest based on (1) outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Such loans had interest at the applicable margin indicated in the following table:

Ratio of Outstanding Borrowings to Borrowing Base	<50%	>50% <75%	>75% <90%	>90%
Eurodollar Loans Margin	2.25%	2.50%	2.75%	3.00%
ABR Loans Margin	1.25%	1.50%	1.75%	2.00%

The “Eurodollar rate” for any interest period (either one, two, three, or six months, as selected by us) is the rate equal to the British Bankers Association LIBOR for deposits in dollars for a similar interest period. The “Base Rate” is calculated as the highest of: (1) the annual rate of interest announced by Bank of America, N.A. as its “prime rate”; (2) the Federal Funds Effective Rate plus 0.5 %; or (3) except during a “LIBOR Unavailability Period,” the Eurodollar rate (for dollar deposits for a one-month term) for such day plus 1.0 %.

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 “Item 8. Financial Statements and Supplementary Data” 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” and Note 5 of the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” 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 “Item 8. Financial Statements and Supplementary Data” for additional information regarding our long-term debt.
	(4)	Represents authorized purchases for work in process.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGLs prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Conditions sometimes arise where actual production is less than estimated, which has, and could result in overhedged volumes.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, natural gas and NGLs production. Realized pricing for natural gas production is primarily driven by the Columbia Gas Appalachian Index (“TECO Index”), Henry Hub, Houston Ship Channel, West Texas (“Waha Index”), El Paso Natural Gas Company (Permian Basin) and Colorado Interstate Gas Company (Rocky Mountains) prices. As for oil production, realized pricing is primarily driven by the West Texas Intermediate Light Sweet, Louisiana Light Sweet, Flint Hills Bow River and Imperial Bow River prices. Pricing for oil, natural gas and NGLs production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control. In addition, the potential exists that if commodity prices decline to a certain level, the borrowing base can be decreased at the borrowing base redetermination date to an amount lower than the amount of debt currently outstanding and, because it would be uneconomical, production could decline to levels below our hedged volumes.

Furthermore, 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, write downs may occur if we experience substantial downward adjustments to our estimated proved reserves, or if estimated future 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 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 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. Additionally, 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. This sensitivity analysis is calculated using natural gas price of $3.12 per MMBTU ($4.12 year-end price less $1.00 (or 24%)) and oil price of $90.24 per barrel of crude oil ($96.24 year-end price less $6.00 (or 6%)).

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 75% to 85% of projected production for a three 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 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.

At December 31, 2011, the fair value of commodity derivative contracts was a liability of approximately $23.6 million, of which $8.5 million liabilities settle during the next twelve months. A 10% increase in the gas and oil index price above the December 31, 2011 price would result in a decrease in the fair value of all of our commodity derivative contracts of approximately $64.7 million; conversely, a 10% decrease in the gas and oil index price would result in an increase of approximately $57.2 million. This sensitivity analysis measures the current value of the commodity derivative contracts using forward price curves and volatility surfaces under a proprietary system and then increases or decreases, as applicable, the forward price curve to determine the fair value of the commodity derivative contracts under the assumed oil and natural gas price indexes.

The following table summarizes 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		—		—
Fixed Price ($/MMBtu)	$	6.76	$	—	$	—
Total Gas Positions:
Notional Volume (MMBtu)		6,258,600		6,460,500		452,500
Floor 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.

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

Interest Rate Risks

At December 31, 2011, we had debt outstanding of $771.0 million. The amount outstanding under our reserve-based credit facility at December 31, 2010 of $671.0 million is subject to interest at floating rates based on LIBOR. If the debt remains the same, a 10% increase in LIBOR would result in an estimated $0.1 million increase in annual interest expense after consideration of the interest rate swaps discussed below. There was no interest rate derivatives hedging the interest rates associated with the amount outstanding under our Second Lien Term Loan at December 31, 2011 of $100.0 million.

We enter 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 Company records changes in the fair value of its interest rate derivatives in current earnings under unrealized gains (losses) on interest rate derivative contracts. During 2008, the company chose to de-designate its interest rate swaps as cash flow hedges as the terms of new contracts entered into in August 2008 no longer matched the terms of the original contracts, thus causing the interest rate hedges to be ineffective. The net unrealized gain related to the de-designated cash flow hedges is reported in accumulated other comprehensive income and later reclassified to earnings in the month in which the transactions settle.

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.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index

Below is an index to the items contained in this “Item 8— Financial Statements and Supplementary Data.”

	Page
Report of Independent Registered Public Accounting Firm	71
Consolidated Statements of Operations	72
Consolidated Statements of Comprehensive Income (Loss)	73
Consolidated Balance Sheets	74
Consolidated Statements of Members’ Equity	75
Consolidated Statements of Cash Flows	76
Notes to Consolidated Financial Statements	77
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)	103
Supplemental Oil and Natural Gas Information (Unaudited)	104

All schedules are omitted as the required information is not applicable or the information is presented in the Consolidated Financial Statements and related notes.

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 in Internal 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

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.

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.

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.

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.

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


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.

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.

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.

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.

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 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.

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.

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.

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.

(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 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 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

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	)

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


(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.

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 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	$	—	$	—

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.

4. Long-Term Debt

Our financing arrangements consisted of the following:

			Amount Outstanding
			December 31,
Description	Interest Rate	Maturity Date	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.

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.

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

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

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. 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)	—	$	—

(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.

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.

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 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, 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
	Level 1		Level 2			Level 3		at Fair value
	(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
	Level 1		Level 2			Level 3		at Fair value
	(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%).

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 $0.1million, 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.

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.

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. The O’Neal, Morgan, and Rower lawsuits were consolidated on June 5, 2011 as John 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 consolidated O’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.

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 captioned Goldstein 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 captioned Hysong 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 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.

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.

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.

12. Shelf Registration Statements

2009 Shelf Registration Statement and Related Offerings

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.

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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 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.

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 Events for 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.

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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 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.

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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.

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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.

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

104

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 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.

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.

105

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.

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.

106

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

(a)	Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2011 at the reasonable assurance level.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011, is set forth in Item 9A(b) below.

BDO USA, LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011, as stated in their report in Item 9A(d) below.

(b)	Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting, as defined by SEC rules adopted under the Exchange Act, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

·	Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

·	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Under the supervision and with the participation of management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2011. The effectiveness of our internal control over financial reporting as of December 31, 2011 has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report included herein.

107

(c)	Changes in Internal Control over Financial Reporting

Pursuant to the ENP Purchase, the functions of the ENP accounting department were transitioned to Houston and integrated with VNG’s, and ENP’s books and records were converted to a new accounting software. Additionally, the books and records of Vanguard and its subsidiaries were converted to the same accounting software, and Vanguard Permian’s production accounting functions, that had been previously outsourced to a third party, were brought in-house. As a result, our management is continuing to implement new processes and modify existing processes.

(d)	Attestation Report

Report of Independent Registered Public Accounting Firm

on Internal Control over Financial Reporting

Board of Directors and Members

Vanguard Natural Resources, LLC

Houston, Texas

We have audited Vanguard Natural Resources, LLC’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Vanguard Natural Resources LLC’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Vanguard Natural Resources, LLC maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 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 and our report date March 5, 2012 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 5, 2012

108

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Item 10 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. The Registrant expects to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 11.

EXECUTIVE COMPENSATION

Item 11 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. The Registrant expects to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Item 12 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. The Registrant expects to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Item 13 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. The Registrant expects to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2011.

ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

Item 14 will be incorporated by reference pursuant to Regulation 14A under the Exchange Act. The Registrant expects to file a definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2011.

109

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

Financial statements

The following consolidated financial statements are included in “Part II— Item 8, Financial Statements and Supplementary Data” of this Annual Report:


	Page

Report of Independent Registered Public Accounting Firm	71
Consolidated Statements of Operations	72
Consolidated Statements of Comprehensive Income (Loss)	73
Consolidated Balance Sheets	74
Consolidated Statements of Members’ Equity	75
Consolidated Statements of Cash Flows	76
Notes to Consolidated Financial Statements	77

(b) Exhibits

The following exhibits are incorporated by reference into the filing indicated or are filed herewith.

Exhibit No.	Exhibit Title	Incorporated by Reference to the Following
1.1	Amended and Restated Equity Distribution Agreement, dated September 9, 2011, by and among Vanguard Natural Resources, LLC and Knight Capital Americas, L.P.	Form 8-K, filed September 12, 2011 (File No. 001-33756)
3.1	Certificate of Formation of Vanguard Natural Resources, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
3.2	Second Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC (including specimen unit certificate for the units)	Form 8-K, filed November 2, 2007 (File No. 001-33756)
10.1+	Vanguard Natural Resources, LLC Long-Term Incentive Plan	Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.2+	Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant Agreement	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.3+	Vanguard Natural Resources, LLC Class B Unit Plan	Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.4+	Form of Vanguard Natural Resources, LLC Class B Unit Plan Restricted Class B Unit Grant	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.5	Management Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.6	Participation Agreement, effective January 5, 2007, by and between Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.7	Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.8	Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy Company	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.9	Gathering and Compression Agreement, effective January 5, 2007, by and between Vinland Energy Gathering, LLC and Nami Resources Company, L.L.C.	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.10	Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.11	Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.12	Well Services Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC and Nami Resources Company, L.L.C.	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.13	Amended and Restated Operating Agreement by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC, dated October 2, 2007 and effective as of January 5, 2007	Form S-1/A, filed October 22, 2007 (File No. 333-142363)
10.14	Operating Agreement, effective January 5, 2007, by and between Vinland Energy Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company, LLC	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.15	Amended and Restated Indemnity Agreement by and between Nami Resources Company, L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard Natural Gas, LLC and Vanguard Natural Resources, LLC, dated September 11, 2007	Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.16	Revenue Payment Agreement by and between Nami Resources Company, L.L.C. and Trust Energy Company, dated April 18, 2007 and effective as of January 5, 2007	Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.17	Gas Supply Agreement, dated April 18, 2007, by and between Nami Resources Company, L.L.C. and Trust Energy Company	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.18	Registration Rights Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC and the private investors named therein	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.19	Purchase Agreement, dated April 18, 2007, between Vanguard Natural Resources, LLC, Majeed S. Nami and the private investors named therein	Form S-1/A, filed April 25, 2007 (File No. 333-142363)
10.20	Omnibus Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and Trust Energy Company, LLC	Form 8-K, filed November 2, 2007 (File No. 001-33756)
10.21+	Employment Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings, LLC and Vanguard Natural Resources, LLC	Form S-1/A, filed July 5, 2007 (File No. 333-142363)
10.22	Natural Gas Contract, dated May 26, 2003, between Nami Resources Company, Inc. and Osram Sylvania Products, Inc.	Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.23	Natural Gas Purchase Contract, dated December 16, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.	Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.24	Natural Gas Purchase Contract, dated December 28, 2004, between Nami Resources Company, LLC and Dominion Field Services, Inc.	Form S-1/A, filed August 21, 2007 (File No. 333-142363)
10.25+	Director Compensation Agreement	Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.26	Purchase and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC and Apache Corporation	Form 8-K/A, filed February 13, 2008 (File No. 001-33756)
10.27	Amended Purchase and Sale Agreement, dated January 31, 2008, among Vanguard Permian, LLC and Apache Corporation	Form 8-K/A, filed February 4, 2008 (File No. 001-33756)
10.28	Amended and Restated Credit Agreement, dated February 14, 2008, by and between Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C issuer and the lenders party thereto	Previously filed with our Form 10-K on March 31, 2008 (File No. 001-33756)
10.29	Purchase and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and Segundo Navarro Drilling, Ltd.	Form 8-K, filed July 21, 2008 (File No. 001-33756)
10.30+	Form of Indemnity Agreement dated August 7, 2008	Previously filed with our Quarterly report on Form 10-Q on August 13, 2008 (File No. 001-33756)
10.31	Second Amendment to First Amended and Restated Credit Agreement, dated October 22, 2008, by and between Vanguard Natural Gas, LLC, BBVA Compass Bank, as lender, and Citibank, N.A., as administrative agent	Previously filed with our Quarterly report on Form 10-Q on November 14, 2008 (File No. 001-33756)
10.32	First Amendment to First Amended and Restated Credit Agreement, dated May 15, 2008, by and between Vanguard Natural Gas, LLC, lenders party thereto, and Citibank, N.A., as administrative agent	Previously filed with our Form 10-K on March 11, 2009 (File No. 001-33756)
10.33	Third Amendment to First Amended and Restated Credit Agreement, dated February 18, 2009, by and between Vanguard Natural Gas, LLC, lenders party thereto, and Citibank, N.A., as administrative agent	Previously filed with our Form 10-K on March 11, 2009 (File No. 001-33756)
10.34	First Amendment to Gathering and Compression Agreement, dated May 8, 2009, effective March 1, 2009, by and between Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy Company, LLC	Previously filed with our Quarterly report on Form 10-Q on May 11, 2009 (File No. 001-33756)
10.35	First Amendment to Management Services Agreement, dated May 8, 2009, effective March 1, 2009, by and between Vinland Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy, LLC	Previously filed with our Quarterly report on Form 10-Q on May 11, 2009 (File No. 001-33756)
10.36	Fourth Amendment to First Amended and Restated Credit Agreement, dated June 26, 2009, by and between Vanguard Natural Gas, LLC, lenders party thereto, and Citibank, N.A., as administrative agent	Previously filed with our Quarterly report on Form 10-Q on July 31, 2009 (File No. 001-33756)

110

10.37	Purchase and Sale Agreement, dated July 17, 2009, among Vanguard Permian, LLC and Segundo Navarro Drilling, Ltd.	Form 8-K, filed July 21, 2009 (File No. 001-33756)
10.38	Second Amended and Restated Credit Agreement dated August 31, 2009, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Form 8-K, filed September 1, 2009 (File No. 001-33756)
10.39	First Amendment to Second Amended and Restated Credit Agreement dated October 14, 2009, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Previously filed with our Quarterly report on Form 10-Q on November 4, 2009 (File No. 001-33756)
10.41	Purchase and Sale Agreement, Lease Amendment and Lease Royalty Conveyance Agreement and Conveyance Agreement, dated November 27, 2009, among Vanguard Permian, LLC and Fortson Production Company and Benco Energy, Inc.	Form 8-K, filed December 4, 2009 (File No. 001-33756)
10.41+	Second Amended and Restated Employment Agreement, effective January 1, 2010, by and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural Resources, LLC	Form 8-K, filed February 8, 2010 (File No. 001-33756)
10.42+	Second Amended and Restated Employment Agreement, effective January 1, 2010, by and between Richard A. Robert, VNR Holdings, LLC and Vanguard Natural Resources, LLC	Form 8-K, filed February 8, 2010 (File No. 001-33756)
10.43+	Restricted Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC. and Scott W. Smith	Form 8-K, filed February 8, 2010 (File No. 001-33756)
10.44+	Restricted Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC. and Richard A. Robert	Form 8-K, filed February 8, 2010 (File No. 001-33756)
10.45+	Phantom Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC. and Scott W. Smith	Form 8-K, filed February 8, 2010 (File No. 001-33756)
10.46+	Phantom Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC. and Richard A. Robert	Form 8-K, filed February 8, 2010 (File No. 001-33756)
10.47	Asset Purchase Agreement, dated April 30, 2010, by and between Alpine Gas Investors, LP and Vanguard Permian, LLC	Form 8-K, filed May 5, 2010 (File No. 001-33756)
10.48	Second Amendment to Second Amended and Restated Credit Agreement, dated June 1, 2010, among Vanguard Natural Gas, LLC, Citibank, N.A. , Existing Lenders (as defined therein), and Credit Agricole Corporate and Investment Bank	Form 8-K, filed June 4, 2010 (File No. 001-33756)
10.49+	Employment Agreement, dated June 18, 2010, by and between Britt Pence, VNR Holdings, LLC and Vanguard Natural Resources, LLC	Previously filed with our Quarterly report on Form 10-Q on August 4, 2010 (File No. 001-33756)
10.50+	Restricted Unit Award Agreement, by and between Vanguard Natural Resources, LLC and Britt Pence	Previously filed with our Quarterly report on Form 10-Q on August 4, 2010 (File No. 001-33756)
10.51+	Phantom Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC and Britt Pence	Previously filed with our Quarterly report on Form 10-Q on August 4, 2010 (File No. 001-33756)
10.52	Purchase and Sale Agreement, dated November 16, 2010 among Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Denbury Resources Inc., Encore Partners GP Holdings LLC, Encore Partners LP Holdings LLC and Encore Operating, L.P.	Form 8-K, filed November 17, 2010 (File No. 001-33756)
10.53	Term Loan, dated November 16, 2010 by and between Vanguard Natural Gas, LLC and BNP Paribas, as administrative agent, and the lenders party thereto	Form 8-K, filed November 17, 2010 (File No. 001-33756)
10.54	Third Amendment to Second Amended and Restated Credit Agreement, dated November 16, 2010 by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Form 8-K, filed November 17, 2010 (File No. 001-33756)
10.55	Registration Rights Agreement, dated December 31, 2010, by and between Vanguard Natural Resources, LLC and Encore Operating, L.P.	Form 8-K, filed January 3, 2011 (File No. 001-33756)
10.56	Second Amended and Restated Administrative Services Agreement, dated December 31, 2010, by and among Vanguard Natural Gas, LLC, Denbury Resources Inc., Encore Energy Partners GP LLC, Encore Energy Partners LP, Encore Operating, L.P. and Encore Energy Partners Operating LLC	Form 8-K, filed January 3, 2011 (File No. 001-33756)
10.57	First Amendment, dated December 31, 2010, to Term Loan Agreement among Vanguard Natural Gas, LLC, BNP Paribas, as Administrative Agent, and the Lenders party thereto	Form 8-K, filed January 3, 2011 (File No. 001-33756)
10.58	Fourth Amendment, dated December 31, 2010, to Second Amended and Restated Credit Agreement among Vanguard Natural Gas, LLC, the Guarantors named therein, Citibank, N.A., as Administrative Agent and L/C Issuer, and the Lenders party thereto	Form 8-K, filed January 3, 2011 (File No. 001-33756)
10.59	Purchase and Sale Agreement, dated June 22, 2011, by and among Vanguard Permian, LLC and Encore Energy Partners Operating, LLC and EnerVest Institutional Fund X-A, L.P. and EnerVest Institutional Fund X-WI, L.P.	Form 8-K, filed June 23, 2011 (File No. 001-33756)
10.60	Purchase and Sale Agreement, dated June 22, 2011, by and among Vanguard Permian, LLC and Encore Energy Partners Operating, LLC and EV Properties, L.P.	Form 8-K, filed June 23, 2011 (File No. 001-33756)
10.61	Agreement and Plan of Merger, dated July 10, 2011, by and among Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Vanguard Acquisition Company, LLC, Encore Energy Partners L.P. and Encore Energy Partners GP LLC	Form 8-K, filed July 11, 2011 (File No. 001-33756)

111

10.62	Voting Agreement dated as of July 10, 2011, by and among Vanguard Natural Resources, LLC, Vanguard Natural Gas, LLC, Vanguard Acquisition Company, LLC, Encore Energy Partners GP LLC and Encore Energy Partners LP.	Form 8-K, filed July 11, 2011 (File No. 001-33756)
10.63	Third Amended and Restated Credit Agreement dated September 30, 2011, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto	Form 8-K, filed October 5, 2011 (File No. 001-33756)
10.64	Confidentiality Agreement, dated April 27, 2011, by and among Vanguard Natural Resources, LLC, the Conflicts Committee of the Board of Directors of Encore Energy Partners GP LLC and Encore Energy Partners GP LLC.	Form S-4/A, filed September 6, 2011 (File No. 333-175944)
10.65	Standstill Agreement, dated April 29, 2011, by and between Vanguard Natural Resources, LLC and the Conflicts Committee of the Board of Directors of Encore Energy Partners GP LLC.	Form S-4/A, filed September 6, 2011 (File No. 333-175944)
10.66	First Amendment, dated November 30, 2011, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto.	Form 8-K, filed December 2, 2011 (File No. 001-33756)
10.67	Term Loan Agreement, dated November 30, 2011, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto.	Form 8-K, filed December 2, 2011 (File No. 001-33756)
21.1	List of subsidiaries of Vanguard Natural Resources, LLC	Filed herewith
23.1	Consent of BDO USA, LLP, Independent Registered Public Accounting Firm	Filed herewith
23.2	Consent of DeGolyer and MacNaughton, Independent Petroleum Engineers and Geologists	Filed herewith
24.1	Power of Attorney (included on signature page hereto)	Filed herewith
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Report of DeGolyer and MacNaughton, Independent Petroleum Engineers and Geologists	Filed herewith

+ Management Contract or Compensatory Plan or Arrangement required to be filed as an exhibit hereto pursuant to item 601 of Regulation S-K.

112

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 5th day of March, 2012.

VANGUARD NATURAL RESOURCES, LLC
	By	/s/ Scott W. Smith
		Scott W. Smith
		President and Chief Executive Officer

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Scott W. Smith and Richard A. Robert, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this Annual Report on Form 10-K, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

March 5, 2012	/s/ Scott W. Smith
	Scott W. Smith
	President, Chief Executive Officer and Director
	(Principal Executive Officer)


March 5, 2012	/s/ Richard A. Robert
	Richard A. Robert
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)


March 5, 2012	/s/ W. Richard Anderson
	W. Richard Anderson
	Director


March 5, 2012	/s/ Bruce W. McCullough
	Bruce W. McCullough
	Director


March 5, 2012	/s/ John R. McGoldrick
	John R. McGoldrick
	Director


March 5, 2012	/s/ Loren Singletary
	Loren Singletary
	Director

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