Vanguard Natural Resources, Inc. - FORM 10-K

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EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.	exhibit32-2x2015xq4x10k.htm
EX-4.12 - EXHIBIT 4.12 - Vanguard Natural Resources, Inc.	exhibit4-12to10xkxfourthsu.htm
EX-21.1 - EXHIBIT 21.1 - Vanguard Natural Resources, Inc.	exhibit21-1x2015xq4x10k.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.	exhibit31-2x2015xq4x10k.htm
EX-4.3 - EXHIBIT 4.3 - Vanguard Natural Resources, Inc.	exhibit4-3secondsupplement.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.	exhibit31-1x2015xq4x10k.htm
EX-23.2 - EXHIBIT 23.2 - Vanguard Natural Resources, Inc.	exhibit232dmconsent2015.htm
EX-23.1 - EXHIBIT 23.1 - Vanguard Natural Resources, Inc.	exhibit231bdoconsent2015.htm
EX-12.1 - EXHIBIT 12.1 - Vanguard Natural Resources, Inc.	exh12-1ratioofearningstofi.htm
EX-99.1 - EXHIBIT 99.1 - Vanguard Natural Resources, Inc.	ex991-dm2015auditletter.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.	exhibit32-1x2015xq4x10k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



(Mark One)
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2015

Or

p		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		The NASDAQ Global Select Market
7.875% Series A Cumulative Redeemable Perpetual Preferred Units		The NASDAQ Global Select Market
7.625% Series B Cumulative Redeemable Perpetual Preferred Units		The NASDAQ Global Select Market
7.75% Series C Cumulative Redeemable Perpetual Preferred Units		The NASDAQ Global Select Market

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

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



		Yes o		No x

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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.



				o

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



Large accelerated filer x		Accelerated filer o
Non-accelerated filer o		Smaller reporting company o
(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 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, 2015, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1,262,296,407 based upon the closing price reported for such date on the NASDAQ Global Select Market.

As of March 3, 2016, 130,481,279 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 2016 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, 2015 (this “Annual Report”). Such proxy statement will be filed with the Securities and Exchange Commission within 120 days of the registrant’s fiscal year ended December 31, 2015.

Vanguard Natural Resources, LLC

TABLE OF CONTENTS



	Caption	Page

Glossary of Terms
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	53
Item 2.	Properties	53
Item 3.	Legal Proceedings	54
Item 4.	Mine Safety Disclosures	55

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	55
Item 6.	Selected Financial Data	58
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	65
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	87
Item 8.	Financial Statements and Supplementary Data	94
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	139
Item 9A.	Controls and Procedures	139
Item 9B.	Other Information	140

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	141
Item 11.	Executive Compensation	141
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	141
Item 13.	Certain Relationships and Related Transactions, and Director Independence	141
Item 14.	Principal Accounting Fees and Services	141

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	141
	Signatures	147

Forward-Looking Statements

Certain statements and information in this Annual Report may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”). All statements other than historical facts, including, without limitation, statements regarding the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of us, and plans and objectives of management for future operations, are forward-looking statements. When used in this Annual Report, words such as we “may,” “can,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “predict,” “project,” “foresee,” “believe,” “will” or “should,” “would,” “could,” or the negative thereof or variations thereon or similar terminology are generally intended to identify forward-looking statements. It is uncertain whether the events anticipated will transpire, or if they do occur what impact they will have on our results of operations and financial condition. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results, the ability to generate sales, income or cash flow, to service debt or to resume cash distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine actual results are beyond our ability to control or predict. These risks and uncertainties include, but are not limited to:


•	risks relating to any of our unforeseen liabilities;


•	further declines in oil, natural gas liquids (“NGLs”) or natural gas prices;


•	the level of success in exploitation, development and production activities;


•	adverse weather conditions that may negatively impact development or production activities;


•	the timing of exploitation and development expenditures;


•	inaccuracies of reserve estimates or assumptions underlying them;


•	revisions to reserve estimates as a result of changes in commodity prices


•	impacts to financial statements as a result of impairment write-downs;


•	risks related to level of indebtedness and periodic redeterminations of the borrowing base under our credit agreements;


•	ability to comply with covenants contained in the agreements governing our indebtedness;


•	ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget;


•	ability to generate sufficient cash flows to resume cash distributions;


•	ability to obtain external capital to finance exploitation and development operations and acquisitions;


•	federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing;


•	failure of properties to yield oil or gas in commercially viable quantities;


•	uninsured or underinsured losses resulting from oil and gas operations;


•	inability to access oil and gas markets due to market conditions or operational impediments;


•	the impact and costs of compliance with laws and regulations governing oil and gas operations;


•	ability to replace oil and natural gas reserves;


•	any loss of senior management or technical personnel;


•	competition in the oil and gas industry;


•	risks arising out of hedging transactions;


•	the costs and effects of litigation;


•	sabotage, terrorism or other malicious intentional acts (including cyber-attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance;


•	change to tax treatment; and


•	other risks described under the caption “Risk Factors” in this Annual Report on Form 10-K.

Reservoir engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Unless expressly stated otherwise, forward-looking statements are based on the expectations and beliefs of our management, based on information currently available, concerning future events affecting us. Although we believe that these forward-looking statements are based on reasonable assumptions, they are subject to uncertainties and factors related to our operations and business environments, all of which are difficult to predict and many of which are beyond our control. Any or all of the forward-looking statements in this Annual Report on Form 10-K may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. The foregoing list of factors should not be construed to be exhaustive. Many factors mentioned in this Annual Report on Form 10-K, including the risks outlined under the caption “Risk Factors” will be important in determining future results, and actual future results may vary materially.

There is no assurance that the actions, events or results of the forward-looking statements will occur, or, if any of them do, when they will occur or what effect they will have on our results of operations, financial condition, cash flows or distributions. In view of these uncertainties, readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of their dates. Except as required by law, we do not intend to update or revise our 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

Bcfe	= billion cubic feet equivalents	MMBOE	= million barrels of oil equivalent

BOE	= barrel of oil equivalent	MMBtu	= million British thermal units

Btu	= British thermal unit	MMcf	= million cubic feet

MBbls	= thousand barrels	MMcfe	= million cubic feet equivalent

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 natural gas with quantities of oil and NGLs 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 “us,” “we,” “our,” the “Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG”), VNR Holdings, LLC (“VNRH”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Clear Fork Pipeline LLC, Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Energy Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Energy Acquisition Partnership II, L.P. (“ERAP II”).

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 monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of December 31, 2015, we own properties and oil and natural gas reserves primarily located in ten operating basins:


•	the Green River Basin in Wyoming;


•	the Permian Basin in West Texas and New Mexico;


•	the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Piceance Basin in Colorado;


•	the Big Horn Basin in Wyoming and Montana;


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our Series A, Series B and Series C Cumulative Preferred units are also listed on the NASDAQ under the symbols “VNRAP”, “VNRBP” and “VNRCP,” respectively. For financial information regarding Vanguard, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this Annual Report.

Organizational Structure

The following diagram depicts our organizational structure as of March 7, 2016:

Recent Developments

2015 Mergers

LRE Merger

On October 5, 2015, we completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), by and among us, Lighthouse Merger Sub, LLC, our wholly owned subsidiary (“LRE Merger Sub”), Lime Rock Management LP (“LR Management”), Lime Rock Resources A, L.P. (“LRR A”), Lime Rock Resources B, L.P. (“LRR B”), Lime Rock Resources C, L.P. (“LRR C”), Lime Rock Resources II-A, L.P. (“LRR II-A”), Lime Rock Resources II-C, L.P. (“LRR II-C”), and, together with LRR A, LRR B, LRR C, LRR II-A and LR Management, the “GP Sellers”), LRR Energy, L.P. (“LRE”) and LRE GP, LLC (“LRE GP”), the general partner of LRE.

Pursuant to the terms of the LRE Merger Agreement, LRE Merger Sub was merged with and into LRE, with LRE continuing as the surviving entity and as our wholly owned subsidiary (the “LRE Merger”), and, at the same time, we acquired all of the limited liability company interests in LRE GP from the GP Sellers in exchange for common units representing limited liability company interests in Vanguard. Under the terms of the LRE Merger Agreement, each common unit representing interests in LRE (the “LRE common units”) was converted into the right to receive 0.550 newly issued Vanguard common units.

As consideration for the LRE Merger, Vanguard issued approximately 15.4 million common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. The Vanguard common units issued include 12,320 Vanguard common units issued as consideration for our purchase of the limited liability company interests in LRE GP. As of December 31, 2015, based on internal reserve estimates, properties acquired in the LRE Merger had estimated total net proved reserves of 126.1 MMcfe, of which 49% was natural gas reserves and 85% was proved developed producing.

Following the closing of the LRE Merger, LRE merged with and into VO and LRE GP merged with and into VNG, and LRE and LRE GP ceased to exist.

Eagle Rock Merger

On October 8, 2015, we completed the transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”), by and among us, Talon Merger Sub, LLC, our wholly owned subsidiary (“Eagle Rock Merger Sub”), Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and Eagle Rock Energy GP, L.P. (“Eagle Rock GP”). Pursuant to the terms of the Eagle Rock Merger Agreement, Eagle Rock Merger Sub was merged with and into Eagle Rock with Eagle Rock continuing as the surviving entity and as our wholly owned subsidiary (the “Eagle Rock Merger”).

Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock common unit”) was converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (without interest and rounded up to the nearest whole cent). We issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price of $9.31 at October 8, 2015 and assumed $156.6 million in debt in connection with the Eagle Rock Merger. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of the Eagle Rock Merger. As of December 31, 2015, based on internal reserve estimates, properties acquired in the Eagle Rock Merger had estimated total net proved reserves of 390.6 MMcfe, of which 52% was natural gas reserves and 65% was proved developed producing.

Following the closing of the Eagle Rock Merger, Eagle Rock and Eagle Rock GP merged with and into VO, and Eagle Rock and Eagle Rock GP ceased to exist.

Debt Exchange

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”) in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued to certain eligible holders of Senior Notes due 2020 who validly tendered and did not validly withdraw their Senior Notes due 2020 pursuant to the terms of our exchange offer. Interest on the Senior Secured Second Lien Notes is payable on February 15 and August 15 of each year, beginning on August 15, 2016. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023.

Proved Reserves

Our total estimated proved reserves at December 31, 2015 were 2,288.9 Bcfe, of which approximately 17% were oil reserves, 68% were natural gas reserves and 15% were NGLs reserves. Of these total estimated proved reserves, approximately 72% were classified as proved developed. At December 31, 2015, estimated future cash inflows from estimated future production of proved reserves were computed using the average oil, natural gas and NGLs price based upon the 12-month average price of $50.20 per barrel of crude oil, $2.62 per MMBtu for natural gas, and $16.14 per barrel of NGLs.

At December 31, 2015, we owned working interests in 14,459 gross (5,285 net) productive wells. Our operated wells accounted for approximately 56% of our total estimated proved reserves at December 31, 2015. Our average net daily production was 415,343 Mcfe/day for the year ended December 31, 2015 and was 511,119 Mcfe/day for the fourth quarter of 2015. Our average proved reserves-to-production ratio, or average reserve life, is approximately 12 years based on our total proved reserves as of December 31, 2015 and our fourth quarter 2015 annualized production.

Additionally, we own approximately 881,508 gross undeveloped leasehold acres surrounding our existing wells. As of December 31, 2015, we have identified 1,591 proved undeveloped drilling locations and over 5,013 other drilling locations on our leasehold acreage.

Business Strategies

Our primary business objective is to generate stable cash flows to allow us to make monthly 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 and/or production 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 capital structure which affords financial flexibility for opportunistic acquisitions; and


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

Properties

As of December 31, 2015, through certain of our subsidiaries, we own interests in oil and natural gas properties located in ten operating basins. The following table presents the production for the year ended December 31, 2015 and the estimated proved reserves for each operating area:



	2015 Net Production
	Natural Gas	Oil	NGLs	Total	Net Estimated Proved Reserves	PV-10 Value
	(MMcf)	(MBbls)	(MBbls)	(MMcfe)	(MMcfe)	(in millions)
Green River Basin	41,431	364	796	48,394	684,194	$	340.7
Permian Basin	4,296	1,164	390	13,617	232,234	$	290.5
Gulf Coast Basin	6,886	589	403	12,838	264,336	$	288.6
Anadarko Basin	2,242	211	230	4,890	280,171	$	245.0
Piceance Basin	23,678	239	1,353	33,230	425,819	$	232.3
Big Horn Basin	217	884	98	6,107	89,125	$	139.1
Arkoma Basin	17,200	73	208	18,887	246,006	$	135.2
Williston Basin	188	472	5	3,051	27,272	$	34.4
Wind River Basin	2,930	12	6	3,040	23,944	$	11.6
Powder River Basin	7,547	—	—	7,547	15,832	$	5.1
Total	106,615	4,008	3,489	151,601	2,288,933	1,722.5

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

Green River Basin Properties

Our Green River Basin properties are comprised of assets in the Pinedale and Jonah fields of southwestern Wyoming. Production in the Green River Basin is dominated by natural gas and NGLs from tight sands formations. The Pinedale field lies at depths anywhere between 11,000 to 14,000 feet with similar depths in the adjacent Jonah field. Additionally, we have Green River Basin properties located in the Hay Reservoir, Great Divide, Siberia Ridge, Wamsutter, Echo Springs and Standard Draw fields in southwestern Wyoming. These gas/condensate fields produce from stacked cretaceous aged tight sandstones within the Lewis and Almond/Mesaverde intervals between 8,000 and 12,000 feet deep. Our properties located in south central Wyoming

in the Sierra Madre field produce predominately oil from fractured cretaceous aged Niobrara limestone (between 5,000 and 6,000 feet) and conventional Shannon sandstone (between 3,500 and 4,000 feet). As of December 31, 2015, our Green River Basin properties consisted of 126,420 gross (35,170 net) leasehold acres. During 2015, the Green River Basin properties produced approximately 48,394 MMcfe of which 86% was natural gas. At December 31, 2015, the properties had total proved reserves of approximately 684,194 MMcfe or 30% of our total estimated proved reserves at year end, of which 56% were proved developed and 87% were natural gas.

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 Permian Basin properties are located in several counties which extend from Eddy County, New Mexico to Eastland County, Texas and encompass hundreds of fields with multiple producing intervals. The majority of our producing wells in the Permian Basin are mature oil wells that also produce high-Btu casinghead gas with significant NGLs content. These properties primarily produce at depths ranging from 2,000 feet to 12,000 feet. As of December 31, 2015, our Permian Basin properties consisted of 326,183 gross (250,715 net) leasehold acres. During 2015, our Permian Basin operations produced approximately 13,617 MMcfe, of which 68% was oil, condensate and NGLs. At December 31, 2015, these properties accounted for approximately 232,234 MMcfe or 10% of our total estimated proved reserves at year end, of which 93% were proved developed and 65% were oil, condensate and NGLs.

Gulf Coast Basin Properties

Our Gulf Coast Basin properties include properties in the onshore Gulf Coast area, North Louisiana, Alabama, East Texas, South Texas and Mississippi.

Production from our North Louisiana properties comes from the East Haynesville and Cotton Valley fields. These properties include multiple productive zones including Cotton Valley, James Lime, Pettet, Haynesville, Smackover and Hosston. East Haynesville is located in Claiborne Parish, Louisiana and lies at a depth of approximately 9,000 to 11,000 feet. The Cotton Valley field is located in Webster Parish, Louisiana and produces from an average depth of 11,000 feet.

Our Alabaman properties include the Big Escambia Creek, Flomaton and Fanny Church fields located in Escambia County, Alabama. These fields produce from either the Smackover or Norphlet formations at depths ranging from approximately 15,000 to 16,000 feet. The Fanny Church field is located two miles east of Big Escambia Creek. The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet. The Smackover and Norphlet reservoirs are sour gas condensate reservoirs which produce gas and fluids containing a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Company-operated Big Escambia Creek Treating facility and the effluent gas is further processed for the removal of natural gas liquids in the Big Escambia Creek Gas Processing facility. The operation of the wells and the facility is closely connected, and we are the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and NGLs, we also market elemental sulfur.

Most of our South Texas producing properties are located in Dewitt, Hidalgo, LaSalle, Live Oak and Webb Counties. Our average working interest is approximately 82%. Most of the production is high Btu gas that is produced from the Olmos and Escondido sand formations from a depth averaging 7,500 feet.

Our East Texas producing properties include the Fairway (James Lime Unit) field in Henderson and Anderson counties, which is produced from an average depth of 10,000 feet. Other East Texas properties produce from the Smackover formation at an average depth of 13,500 feet and are located in Henderson, Rains, Van Zandt and Wood Counties.

We operate the majority of our Mississippi properties which are located in the Mississippi Salt Basin. Most of our production comes from the Parker Creek field in Jones County, Mississippi, where our working interest is approximately 60%. Our production is mainly oil that produces from the Hosston Formation from a depth ranging from approximately 13,000 feet to 15,000 feet. Our other Mississippi properties are located in Covington, Jasper, Clarke, Leflore, Jefferson Davis, Wayne and Walthall Counties.

Production from our properties in the onshore Gulf Coast Basin comes from the Silsbee Field in Hardin County, Texas. Most of the Silsbee production is oil produced from the Yegua formation.

As of December 31, 2015, our Gulf Coast Basin properties consisted of 206,693 gross (107,027 net) leasehold acres. During 2015, the Gulf Coast Basin properties produced approximately 12,838 MMcfe, of which 47% were oil, condensate and NGLs. At December 31, 2015, these properties accounted for approximately 264,336 MMcfe or 12% of our total estimated proved reserves at year end, of which 75% were proved developed and 53% were natural gas.

Anadarko Basin Properties

The Anadarko Basin consists of operated and non-operated properties in the Golden Trend field, Cana (Woodford) shale play, Verden field, and other fields located in the Anadarko Basin of western Oklahoma. Within the Anadarko Basin, our assets can generally be characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than our other operating areas. Properties in in the Anadarko Basin include mature fields with long production histories.

Our largest producing field in the region is the Golden Trend field, which extends across Grady, McClain and Garvin Counties in Oklahoma. The field is a large structural trap, discovered in 1947, that produces from the shallow Pennsylvanian Deese formation to the deep Ordovician Arbuckle formation. Most of our current production is from the Bromide formation and the “Big Four” interval consisting of the Viola, Hunton, Woodford and Sycamore formations. We typically drill through all these formations and perform multi-stage fracture stimulation completions in the Bromides and “Big Four” interval.

We have a significant ownership position in the expanding Cana (Woodford) shale, Springer shale and Southeast Cana shale plays in western Oklahoma. Our net acres in these plays extend across Canadian, Blaine, Dewey, Grady, Garvin, McClain and Stephens Counties in Oklahoma. The Cana and Southeast Cana Shale produce from horizontal wells drilled to vertical depths of 11,000 to 16,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet. The horizontal laterals are fracture stimulated in multiple stages to optimize production from the shale reservoir.

As of December 31, 2015, our Anadarko Basin properties consisted of 221,121 gross (55,554 net) leasehold acres. During 2015, the Anadarko Basin properties produced approximately 4,890 MMcfe, of which 54% were oil, condensate and NGLs. At December 31, 2015, these properties accounted for approximately 280,171 MMcfe or 12% of our total estimated proved reserves at year end, of which 58% were proved developed and 57% were natural gas.

Piceance Basin Properties

The Piceance Basin is located in northwestern Colorado. Our Piceance Basin properties, which we operate, are located in the Gibson Gulch. The Gibson Gulch area is a basin-centered gas play along the north end of the Divide Creek anticline near the eastern limits of the Piceance Basin’s productive Mesaverde (Williams Fork) trend at depths of approximately 6,000 to 8,000 feet. As of December 31, 2015, our Piceance Basin properties consisted of 24,040 gross (16,075 net) leasehold acres. During 2015, our properties in the Piceance Basin produced approximately 33,230 MMcfe, of which 71% was natural gas. At December 31, 2015, the Piceance Basin properties accounted for approximately 425,819 MMcfe or 19% of our total estimated proved reserves at year end, of which 74% were proved developed and 74% were natural gas.

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 Elk Basin field is located in Park County, Wyoming and Carbon County, Montana. We operate all of our 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. Currently, we still use flue gas injection to maintain and improve production within this formation. Our wells in the Embar-Tensleep formation of the Elk Basin field are drilled to a depth of 5,100 to 6,600 feet.

Madison Formation. We plan to concentrate on implementing an injection program to enhance production in the Madison formation. The wells in the Madison formation of the Elk Basin field are drilled to a depth of 4,400 to 7,000 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 1,400 to 2,700 feet.

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 also operate and own 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.

Our Big Horn Basin properties are comprised of assets in Wyoming and the Elk Basin field in south central Montana. We own working interests ranging from 25% to 100% in our Big Horn Basin properties, which consisted of 24,512 gross (15,632 net) leasehold acres as of December 31, 2015. During 2015, our properties in the Big Horn Basin produced approximately 6,107 MMcfe, of which 87% was oil. At December 31, 2015, the Big Horn Basin properties accounted for approximately 89,125 MMcfe or 4% of our total estimated proved reserves at year end, of which 100% were proved developed and 96% were oil, condensate and NGLs.

Arkoma Basin Properties

Our Arkoma Basin properties include properties in the Woodford Shale, located in eastern Oklahoma, the Fayetteville Shale, located in Arkansas, and royalty interests and non-operated working interest in both states. As of December 31, 2015, our Arkoma Basin properties consisted of 398,628 gross (185,668 net) leasehold acres. During 2015, the Arkoma Basin properties produced approximately 18,887 MMcfe, of which 91% was natural gas. At December 31, 2015, the properties had total proved reserves of approximately 246,006 MMcfe or 11% of our total estimated proved reserves at year end, of which 90% were proved developed and 89% were natural gas.

Williston Basin Properties

Our Williston Basin properties are located in North Dakota and Montana, which include, among others, the Horse Creek field, the Charlson Madison Unit and the Elk field. The Horse Creek field is located in Bowman County, North Dakota and has producing oil wells from multiple horizons in the Red River formation. The Charlson Madison Unit produces from the unitized Madison formation. The Elk field is operated and produces from wells in McKenzie County, North Dakota. As of December 31, 2015, our Williston Basin properties consisted of 550,996 gross (71,960 net) leasehold acres. During 2015, the properties produced approximately 3,051 MMcfe, of which 93% was oil. Our Williston Basin properties had estimated proved reserves at December 31, 2015 of 27,272 MMcfe or 1% of our total estimated proved reserves at year end, of which 100% were proved developed and 95% were oil.

Wind River Basin Properties

The Wind River Basin is located in central Wyoming. Our activities are concentrated primarily in the eastern Wind River Basin, along the greater Waltman Arch. Our natural gas production in this basin is gathered through our own gathering systems and delivered to markets through pipelines owned by Kinder Morgan Interstate and Colorado Interstate Gas (“CIG”). As of December 31, 2015, our Wind River Basin properties consisted of 188,018 gross (156,994 net) leasehold acres. During 2015, our Wind River Basin properties produced approximately 3,040 MMcfe, of which 96% was natural gas. At December 31, 2015, the properties had total proved reserves of approximately 23,944 MMcfe or 1% of our total estimated proved reserves, of which 100% were proved developed and 97% were natural gas.

Powder River Basin Properties

The Powder River Basin is primarily located in northeastern Wyoming. Our development operations are conducted in our coalbed methane (“CBM”) fields. CBM wells are drilled to 1,500 feet on average, targeting the Big George Coals, typically producing water in a process called dewatering. This process lowers reservoir pressure, allowing the gas to desorb from the coal and flow to the well bore. As the reservoir pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a CBM well can range from five to eleven years depending on the coal seam. Our natural gas production in this basin is gathered through gathering and pipeline systems owned by Fort Union Gas Gathering, LLC and Thunder Creek Gas Services, L.L.C.. As of December 31, 2015, our Powder River Basin properties consisted of 114,287 gross (66,866 net) leasehold acres. During 2015, the properties produced approximately 7,547 MMcfe, which was 100% natural gas. At December 31, 2015, the properties had total proved reserves of approximately 15,832 MMcfe or 1% of our total estimated proved reserves at year end, of which 100% were proved developed.

Oil, Natural Gas and NGLs Prices

We analyze the prices we realize from sales of our oil and natural gas production and the impact on those prices of differences in market-based index prices and the effects of our derivative activities. We market our oil and natural gas production to a variety of purchasers based on regional pricing. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The West Texas Intermediate Cushing, (“WTI”) price of crude oil is a widely used benchmark in the pricing of domestic and imported oil in the United States. The relative value of crude oil is mainly determined by its quality and location. In the case of WTI pricing, the crude oil is light and sweet, meaning that it has a higher specific gravity (lightness) measured in degrees of API (“American Petroleum Institute”) gravity and low sulfur content, and is priced for delivery at Cushing, Oklahoma. In general, higher quality crude oils (lighter and sweeter) with fewer transportation requirements result in higher realized pricing for producers.

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 outlet of the processing plant, we report residue 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, before deductions for gathering, transportation and processing fees, for natural gas sold under certain contracts during 2015 increased to a level above NYMEX.

The average realized prices described below include deductions for gathering, transportation and processing fees, however, these prices do not include the impact of our hedges.

Production in the Green River Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed natural gas is subject to a processing agreement with Western Gas Resources in their Granger Plant facility where we take our residue natural gas in-kind for sales and NGLs are taken in-kind and sold pursuant to a liquids purchase agreement. We market our Green River Basin residue natural gas into the Rockies market through the use of multiple pipeline connections. During 2015, we received the average NYMEX price less $0.66 per Mcf in the Green River Basin. Due to the decline in the ethane price which began in 2014 and has continued into 2016, the Granger Plant made an economic decision to reject ethane effective January 2015 and is expected to continue ethane rejection through 2016.

In the Permian Basin, most of our natural gas production is casinghead natural 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 natural 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, 2015, we received the average NYMEX price less $0.23 per Mcf in the Permian Basin. Our oil production is sold under month-to-month sales contracts with purchasers that take delivery of the oil volumes at the tank batteries adjacent to the producing wells. We sell oil production from our operated Permian Basin properties at the wellhead to third party gathering and marketing companies. During 2015, we received the average WTI price less $5.33 per barrel in the Permian Basin.

In the Gulf Coast Basin, our natural gas production has a high Btu content and requires processing prior to sale to third parties. Our proportionate share of the natural gas volumes are sold at the tailgate of the processing plant at the Houston Ship Channel and Waha Gas index pricing which typically results in a discount to NYMEX prices. For the year ended December 31, 2015, we received the average NYMEX price plus $0.02 per Mcf.

Our Anadarko Basin production in Oklahoma consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third party entities. The lean natural gas is gathered by Enable Gathering & Processing LLC and sold to market at Enable Oklahoma Intrastate Transmission LLC’s West pool at the Panhandle, TX-Okla. index pricing. The high Btu gas is sold at the wellhead to various third party entities. The majority is sold to Oneok Field Services Company LLC and DCP Midstream LP under gas purchase contracts subject to percent of proceeds pricing for all products. During 2015, we received the average NYMEX price less $0.86 per Mcf in the Anadarko Basin.

Production in the Piceance Basin is predominantly natural gas and is processed for the recovery of NGLs. The processed gas is subject to a processing agreement with Enterprise Gas Processing LLC, in their Meeker Plant facility. We market our natural gas production into the Rockies market at the Northwest Rockies index pricing. During 2015, we received the average NYMEX price less $1.04 per Mcf in the Piceance Basin.

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 with other 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 2015, we received the average NYMEX price less $7.57 per barrel in the Big Horn Basin. Effective March 2015, we entered into a sales contract under Western Canadian Select (“WCS”) index pricing, which provides the opportunity for us to enter into hedges for our Elk Basin production and therefore reduce our exposure to price volatility.

Our Arkoma Basin production in the southeastern Oklahoma Woodford Shale consists predominately of natural gas with a mix of high Btu processed natural gas and unprocessed lean natural gas. The natural gas production is gathered by multiple third party entities with the processed natural gas ultimately delivered to the Targa Resources, Inc. natural gas processing complex. The processed natural gas is subject to a processing agreement with Targa Resources, Inc., where we take our residue natural gas in-kind for sales, and NGLs are sold pursuant to the terms of the processing agreement. The lean natural gas is primarily delivered directly to market. The natural gas is marketed into the Enable Gas: East index and Transcontinental Gas Pipeline Corp: Zone 4 index via a firm transportation contract that was in place prior to our acquisition of these natural gas properties. For the year ended December 31, 2015, we received the average NYMEX price less $1.28 per Mcf.

In the Williston Basin, we produce a combination of sweet and legacy sour oil. This oil is both connected to oil pipelines as well as trucked out for sales and there is minimal natural gas associated with this production. During 2015, we received the average NYMEX price less $10.48 per barrel in the Williston Basin.

Our Wind River Basin properties are predominantly natural gas plays with approximately two-thirds of the production being processed at natural gas plants for the extraction of NGLs at our election. Our residue natural gas is sold into the Rockies market at the CIG index price while the NGLs are sold to a third-party natural gas processor pursuant to a processing agreement.

Our Powder River natural gas production is classified as CBM gas and, as it is a very dry gas, is sold directly into the market upon being handled with conventional separation, treating, and transportation. The CBM gas is sold into the Rockies market at the CIG index price as well. During 2015, we received the average NYMEX price less $0.56 per Mcf in the Wind River Basin while we received the average NYMEX price less $1.66 per Mcf in the Powder River Basin.

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, 2015, as estimated by our internal reservoir engineers. 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. Please see “Reserves Estimation Process” below and the “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 for additional information regarding our estimated proved reserves.



Reserve Data:
Estimated net proved reserves:
Crude oil (MMBbls)	64.1
Natural gas (Bcf)	1,554.2
NGLs (MMBbls)	58.4
Total (Bcfe)	2,288.9
Proved developed (Bcfe)	1,652.4
Proved undeveloped (Bcfe)	636.5
Proved developed reserves as % of total proved reserves	72		%
Standardized Measure (in millions) ⁽¹⁾⁽²⁾	$	1,722.5
Representative Oil and Natural Gas Prices ⁽³⁾:
Oil—WTI per Bbl	$	50.20
Natural gas—Henry Hub per MMBtu	$	2.62
NGLs—Volume-weighted average price per Bbl	$	16.14

(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 Securities and Exchange Commission (“SEC”) (using the 12-month unweighted average of first-day-of-the-month price, 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 2015, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using the differentials to the WTI price per Bbl of $50.20.

The following tables set forth certain information with respect to our estimated proved reserves by operating basin as of December 31, 2015:



	Estimated Proved Developed Reserve Quantities				Estimated Proved Undeveloped Reserve Quantities				Estimated Proved Reserve Quantities
	Natural Gas (Bcf)	Oil (MMBbls)	NGLs (MMBbls)	Total (Bcfe)	Natural Gas (Bcf)	Oil (MMBbls)	NGLs (MMBbls)	Total (Bcfe)	Total (Bcfe)
Operating Basin
Green River Basin	335.1	3.0	5.2	384.1	261.2	2.4	4.1	300.1	684.2
Permian Basin	75.1	16.1	7.3	215.3	7.3	0.9	0.7	16.9	232.2
Gulf Coast Basin	92.0	11.3	6.4	198.4	47.4	2.6	0.5	65.9	264.3
Anadarko Basin	88.6	4.9	7.4	162.1	70.1	2.3	5.6	118.1	280.2
Piceance Basin	232.5	1.8	11.8	313.8	81.1	0.9	4.2	112.0	425.8
Big Horn Basin	4.1	12.3	1.9	89.1	—	—	—	—	89.1
Arkoma Basin	202.3	1.2	2.2	222.5	17.1	—	1.1	23.5	246.0
Williston Basin	1.3	4.3	—	27.3	—	—	—	—	27.3
Wind River Basin	23.2	0.1	—	24.0	—	—	—	—	24.0
Powder River Basin	15.8	—	—	15.8	—	—	—	—	15.8
Total	1,070.0	55.0	42.2	1,652.4	484.2	9.1	16.2	636.5	2,288.9



	PV-10 Value ⁽¹⁾
	Developed		Undeveloped		Total
Operating Basin	(in millions)
Green River Basin	$	265.8	$	74.9	$	340.7
Permian Basin	285.3		5.2		290.5
Gulf Coast Basin	242.5		46.1		288.6
Anadarko Basin	210.7		34.3		245.0
Piceance Basin	192.2		40.1		232.3
Big Horn Basin	139.1		—		139.1
Arkoma Basin	130.6		4.6		135.2
Williston Basin	34.4		—		34.4
Wind River Basin	11.6		—		11.6
Powder River Basin	5.1		—		5.1
Total	$	1,517.3	$	205.2	$	1,722.5

(1)

PV-10 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, PV-10 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.

The data in the above tables represent estimates only. Oil, natural gas and NGLs reservoir 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 internal reservoir 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, 2015 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 the timing of future production, which may prove to be inaccurate.

From time to time, we engage reservoir engineers to prepare a reserve and economic evaluation of properties that we are considering purchasing. Neither the reservoir 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 2015, we paid DeGolyer and MacNaughton (“D&M”) approximately $0.2 million for all reserve and economic evaluations.

Proved Undeveloped Reserves

Our proved undeveloped reserves at December 31, 2015, as estimated by our internal reservoir engineers, were 636.5 Bcfe, consisting of 9.1 MMBbls of oil, 484.2 Bcf of natural gas and 16.2 MMBbls of NGLs. Our proved undeveloped reserves decreased by 17.2 Bcfe during the year ended December 31, 2015, as compared to our proved undeveloped reserves as of December 31, 2014. The following table represents a summary of our proved undeveloped reserves activity during the year ended December 31, 2015:



	Bcfe
PUDs at January 1, 2015	653.7
Acquisitions	123.4
Revisions of prior estimates	(62.2	)
Conversion to developed	(78.4	)
PUDs at December 31, 2015	636.5

Acquisitions. The decrease in our proved undeveloped reserves during 2015 was offset by an increase of 123.4 Bcfe which resulted primarily from our acquisitions of oil and natural gas properties completed during 2015. As described below, 34.5 Bcfe of our proved undeveloped reserves acquired during 2015 were drilled in place of proved undeveloped reserves scheduled to be drilled as part of our year end drilling program.

Revisions. The decrease in proved undeveloped reserves during 2015 resulted from (i) a decrease of 64.7 Bcfe due to changes in prices and (ii) a decrease of 69.6 Bcfe due to revisions in the timing of our drilling development plan, primarily in the Arkoma, Permian and Powder River Basins, and the re-allocation of drilling of capital expenditures to more promising drilling opportunities. These decreases were offset by a net increase of 72.1 Bcfe due to revisions of previous volume estimates and decreases in capital costs and lease operating expenses.

Conversions. During the year ended December 31, 2015, we developed approximately 78.4 Bcfe of our total proved undeveloped reserves booked as of December 31, 2014 through the drilling of 160 gross (10.62 net) wells. We also converted 41.3 Bcfe of volumes to proved developed producing which were not booked as proved undeveloped reserves at December 31, 2014. Approximately 34.5 Bcfe of these reserves were proved undeveloped reserves acquired during 2015 which were drilled during the year ended December 31, 2015. The remaining 6.8 Bcfe were attributed to reserves not recognized as proved undeveloped reserves in our December 31, 2014 reserve report.

Development Plans. We expect to spend approximately 68% of our planned five year future development costs within the next three years as reflected in our reserve report. During the year ended December 31, 2015, we spent $63.6 million or approximately 57% of our 2015 proved undeveloped reserves capital expenditures budget converting 100.1 Bcfe of proved undeveloped reserves recorded at December 31, 2014 of which 78.4 Bcfe was fully converted to the developed category and the remainder of which is in progress and expected to be converted in 2016. Based on our 2014 year-end reserve report, we expected to spend $110.9 million developing 101.9 Bcfe of proved undeveloped reserves during 2015. Our 2015 actual proved undeveloped reserves capital expenditures differed from our 2015 proved undeveloped reserves capital expenditures budget at

December 31, 2014 because during 2015, we spent $25.6 million converting 41.3 Bcfe of volumes to proved developed producing which were not booked as proved undeveloped reserves at December 31, 2014, of this, $15.2 million related to converting 34.5 Bcfe of volumes attributable to development drilling in Oklahoma on acreage acquired in the Eagle Rock Merger.

We historically approach the development of our undeveloped reserves at a measured pace, in order to hold our production rate fairly constant or slightly increasing. Our development plan for drilling proved undeveloped wells includes the drilling of 253 net wells before the end of 2020 at an estimated cost of $576.3 million. This development plan calls for the drilling of 22 net wells during 2016, 65 net wells during 2017, 70 net wells during 2018, 59 net wells during 2019 and 37 net wells during 2020. Additionally, the expected plan of development of our natural gas proved undeveloped reserves, which represent 76% of our total proved undeveloped reserves at December 31, 2015, over the next five years is as follows:



	Percent of Natural Gas Proved Undeveloped Reserves Expected to be Converted
2016	11%
2017	30%
2018	26%
2019	21%
2020	12%
Total	100%

At December 31, 2015, none of our proved undeveloped properties are scheduled to be drilled on a date more than five years from the date the reserves were initially booked as proved undeveloped. Additionally, none of our proved undeveloped reserves at December 31, 2015 have remained undeveloped for more than five years since the date of initial booking as proved undeveloped reserves.

Our development plan discussed above for drilling proved undeveloped wells represents the final investment decision to drill these proved undeveloped reserves at the time the applicable proved undeveloped reserves are booked. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as (i) changes in commodity prices, (ii) anticipated cash flows and projected rate of return, (iii) access to capital, (iv) new opportunities with better returns on investment that were not known at the time of the reserve report, (v) asset acquisitions and/or sales and (vi) actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped reserves that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped reserves development, in favor of projects with a more attractive rate of return, leading us to deviate from our original development plan.

Substantially all of our developed and undeveloped leasehold acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The leases in which we hold an interest that are not held by production are not material to us since these leases have no proved undeveloped reserves assigned. As of December 31, 2015, approximately 94,530 net acres are scheduled to expire in future periods and no proved undeveloped reserves are scheduled to be drilled after expiration. Of the total expiring acreage approximately 14,051 net acres expire in 2016, 71,615 net acres expire in 2017, 3,460 net acres expire in 2018 and 5,404 net acres expire in 2020.

Reserve Estimation Process

Estimates of proved reserves at December 31, 2015 were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. Our reserve estimation process is a collaborative effort coordinated by our reservoir engineers in compliance with our internal controls for such process. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including crude oil, natural gas and NGLs prices, production costs, future capital expenditures and our net ownership percentages are obtained from other departments within the Company. Our internal reservoir engineers perform review procedures with respect to such non-technical inputs. Reserve variances are discussed among the internal reservoir engineers and the Executive Vice President of Operations.

We use technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, production data, well test data, geologic maps, electrical logs and radioactivity logs. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

Our reservoir engineering group is directly responsible for our reserve evaluation process and consists of four professionals, two of whom hold, at a minimum, bachelor’s degrees in engineering. Within our Company, Michael Egerman, Reserves and Budget Manager, is the technical person primarily responsible for overseeing the preparation of the reserve estimates. Mr. Egerman has over 10 years of experience and graduated from the University of Texas at Austin with a Bachelor of Science degree in Petroleum Engineering in 2004. He is a member of the Society of Petroleum Engineers.

The technical persons responsible for preparing the reserve 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.

Independent Audit of Reserves

We engage independent petroleum engineers to audit a substantial portion of our reserve estimates. Our audit procedures require the independent engineers to prepare their own estimates of proved reserves for properties comprising at least 80% of our year-end proved reserves. Our board of directors requires that the independent petroleum engineers’ estimate of reserve quantities for the properties audited by the independent petroleum engineers are within 10% of our internal estimate. Once completed, our year-end reserves are presented to senior management, including the President and Chief Executive Officer, the Executive Vice President and Chief Financial Officer, and the Executive Vice President of Operations, for approval.

For the year ended December 31, 2015, we engaged D&M, an independent petroleum engineering firm, to perform reserve audit services. The opinion by D&M for the year ended December 31, 2015 covered producing areas containing 80.1% of our proved reserves on a net-equivalent-barrel-of-oil basis. D&M’s opinion indicates that the estimates of proved reserves prepared by our internal reservoir engineers for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M. Such estimates by D&M in the aggregate were within our 10% variation tolerance when compared to those prepared by our reservoir engineering group. The report prepared by D&M was developed utilizing geological and engineering data we provided. The report of D&M dated January 29, 2016, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M’s technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K and incorporated herein by reference.

Within D&M, the lead technical person primarily responsible for overseeing the audit of our reserves is Mr. Gregory K. Graves. Mr. Graves is a Senior Vice President with D&M and has over 30 years of experience in oil and gas reservoir studies and reserves evaluations. He graduated from the University of Texas at Austin in 1984 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. Graves 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.

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. Information for fields with greater than 15% of our total proved reserves have been listed separately in the table below for the years ended December 31, 2015 and 2014. None of our fields had proved reserves that were greater than 15% of our total proved reserves during 2013.



	Net Production⁽¹⁾						Average Realized Sales Prices ⁽²⁾						Production Cost ⁽³⁾
	Crude Oil Bbls/day		Natural Gas Mcf/day		NGLs Bbls/day		Crude Oil Per Bbl		Natural Gas Per Mcf		NGLs Per Bbl		Per Mcfe
Year Ended December 31, 2015
Pinedale (Green River Basin)	804		98,266		1,932		$	58.87	$	2.37	$	0.26	$	0.54
Mamm Creek (Piceance Basin)	649		58,764		3,701		$	49.30	$	1.96	$	12.18	$	0.43
All other fields	9,529		135,065		3,927		$	57.24	$	2.07	$	21.71	$	1.41
Total	10,982		292,095		9,560		$	56.89	$	3.13	$	13.68	$	0.96

Year Ended December 31, 2014
Pinedale (Green River Basin)	659		72,090		3,028		$	77.76	$	3.96	$	13.76	$	0.43
Mamm Creek (Piceance Basin)	288		32,455		1,424		$	72.85	$	3.33	$	25.71	$	0.71
All other fields	8,096		122,953		3,107		$	83.66	$	3.27	$	37.14	$	1.54
Total	9,043		227,498		7,559		$	82.88	$	3.50	$	25.62	$	1.11

Year Ended December 31, 2013
All other fields	8,462	53,695	137,632	84	4,047	45.11	$	82.26	$	3.39	$	33.76	$	1.36


(1)	Average daily production for 2015, 2014 and 2013 calculated based on 365 days and includes production for all of our acquisitions from the closing dates of these acquisitions.

(2)

Average realized sales prices include the impact of hedges but exclude the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. The average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31, 2015 Compared to Year Ended December 31, 2014” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Year Ended December 31, 2014 compared to Year Ended December 31, 2013.”


(3)	Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).

Productive Wells

The following table sets forth information at December 31, 2015 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
Green River Basin	2,851	410	22	20	2,873	430
Permian Basin	1,089	688	3,176	1,096	4,265	1,784
Gulf Coast Basin	963	450	201	94	1,164	544
Anadarko Basin	1,092	221	351	57	1,443	278
Piceance Basin	1,183	1,030	3	3	1,186	1,033
Big Horn Basin	5	3	298	215	303	218
Arkoma Basin	1,763	373	222	18	1,985	391
Williston Basin	197	8	197	76	394	84
Wind River Basin	144	132	11	10	155	142
Powder River Basin	691	381	—	—	691	381
Total	9,978	3,696	4,481	1,589	14,459	5,285

Developed and Undeveloped Leasehold Acreage

The following table sets forth information as of December 31, 2015 relating to our leasehold acreage.



	Developed Acreage ⁽¹⁾		Undeveloped Acreage ⁽²⁾		Total Acreage ⁽³⁾
	Gross ⁽⁴⁾	Net ⁽⁵⁾	Gross ⁽⁴⁾	Net ⁽⁵⁾	Gross ⁽⁴⁾	Net ⁽⁵⁾
Green River Basin	60,730	24,837	65,690	10,333	126,420	35,170
Permian Basin	301,765	235,375	24,418	15,340	326,183	250,715
Gulf Coast Basin	184,486	94,364	22,207	12,663	206,693	107,027
Anadarko Basin	176,678	44,895	44,443	10,659	221,121	55,554
Piceance Basin	16,112	10,477	7,928	5,598	24,040	16,075
Big Horn Basin	23,392	14,559	1,120	1,073	24,512	15,632
Arkoma Basin	382,862	177,214	15,766	8,454	398,628	185,668
Williston Basin	65,270	35,280	485,726	36,680	550,996	71,960
Wind River Basin	22,989	21,026	165,029	135,968	188,018	156,994
Powder River Basin	65,106	37,868	49,181	28,998	114,287	66,866
Total	1,299,390	695,895	881,508	265,766	2,180,898	961,661


(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 leasehold acreage contains proved reserves.


(3)	As of December 31, 2015, approximately 94,530 net acres are scheduled to expire in future periods and no proved undeveloped reserves are scheduled to be drilled after expiration. Of the total expiring acreage approximately 14,051 net acres expire in 2016, 71,615 net acres expire in 2017, 3,460 net acres expire in 2018 and 5,404 net acres expire in 2020.


(4)	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.


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

Drilling Activity

The following is a description of the Company’s drilling and completion activities during the year ended December 31, 2015.

In the Green River Basin, we participated in the drilling of 164 gross wells and the completion of 121 gross wells in Sublette County in southwestern Wyoming. Our average working interest in these non-operated wells is 12.5%. These wells are directionally drilled from pads but are vertical through the 4,000 feet pay section. The average well depth is approximately 14,000 feet and is typically completed with 14 to 20 frac stages.

In the Gulf Coast Basin, we drilled and completed two vertical wells and one horizontal well in Claiborne Parish, Louisiana with a 100% working interest. The vertical wells were drilled to an average depth of 10,400 feet and the horizontal well was drilled to a depth of approximately 11,800 feet.

In the Anadarko Basin, we participated with a 7% working interest in the drilling of one horizontal well and in the completion of 24 horizontal wells (3.0 net) in the Cana shale, Southeast Cana shale and Golden Trend field in Oklahoma. These wells were drilled to vertical depths of 8,000 to 16,000 feet and extended with horizontal lateral lengths of approximately 5,000 to 10,000 feet. The wells completed were part of the properties acquired in the Eagle Rock Merger.

We have significantly reduced our capital expenditures budget for 2016. We currently anticipate a capital expenditures budget for 2016 of approximately $63.0 million, which is 44% less than the $112.6 million we spent in 2015. We expect to spend approximately 40% of the 2016 capital expenditures budget in the Green River Basin where we will participate as a non-operated partner in the drilling and completion of directional natural gas wells in the Pinedale Field. Additionally, we expect to spend approximately 21% of the 2016 capital expenditures budget in the Anadarko Basin on the newly acquired SCOOP and STACK assets, participating as a non-operated partner drilling standard length and extended length liquid rich horizontal gas and oil wells targeting the Woodford Shale and various stacked pay Mississippian reservoirs. The balance of the 2016 capital expenditures budget is related to recompletion and maintenance activities in our other operating areas. Due to our reduced capital spending in 2016 we anticipate our annual production will be 10% to 15% lower than our fourth quarter 2015 average daily production of 511,119 Mcfe per day.

The following table sets forth information with respect to wells completed during the years ended December 31, 2015, 2014 and 2013. Our drilling activity during these periods has consisted entirely of drilling development wells. We have not drilled any exploratory wells during these periods. 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,
	2015	2014	2013
Gross wells:
Productive	169	215	78
Dry	—	—	—
Total	169	215	78
Net Development wells:
Productive	23.6	27.2	6.9
Dry	—	—	—
Total	23.6	27.2	6.9

Operations

Principal Customers

For the year ended December 31, 2015, sales of oil, natural gas and NGLs to Mieco Inc., Marathon Oil Company, ConocoPhillips, Plains Marketing, L.P. and Targa Resources, Inc. accounted for approximately 20%, 7%, 7%, 7% and 6%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2015 therefore accounted for 47% 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 and upon similar terms and conditions.

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.

We generally sell our natural gas production from our operated properties on the spot market or under market-sensitive, short-term agreements with credit-worthy purchasers, including 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 market our own natural gas on some of our non-operated properties.

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 export 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.

Our natural gas is transported through our own and third-party gathering systems and pipelines, and we incur processing, gathering and transportation expenses to move our natural gas from the wellhead to a specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party gatherer, processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas shippers. While our ability to market our natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our cash flow from the affected properties could be adversely affected. In certain instances, we may enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our gas volumes. Currently, a majority of our existing firm transportation agreements were assumed in connection with acquisitions of oil and natural gas properties. These agreements have term delivery commitments of fixed and determinable quantities of natural gas. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contractual Obligations” for additional information regarding our long-term firm transportation contracts.

The following table sets forth information about material long-term firm transportation contracts for pipeline capacity, which typically require a demand charge. We source the gas to meet these commitments from our producing properties. We have certain commitments that we assumed as part of our acquisitions of oil and gas properties where the production from the acquired properties and the production of joint interest owners that we market were not adequate to meet the commitments resulting to us paying the set demand charge relating to the maximum daily quantity outlined in the contract. During the year ending December 31, 2016, our firm transportation contracts obligate us to deliver 97,300 MMBtu of natural gas per day.



Type of Arrangement	Pipeline System /Location	Deliverable Market	Gross Deliveries (MMBtu/d)	Term
Firm Transport	WIC Medicine Bow	Rocky Mountains	25,000	01/16 – 06/20
Firm Transport	Questar Pipeline	Rocky Mountains	12,000	01/16 – 10/16
Firm Transport	Colorado Interstate Gas	Rocky Mountains	8,200	01/16 – 06/17
Firm Transport	Cheyenne Plains	Midcontinent	9,000	01/16 – 05/17
Firm Transport	Cheyenne Plains	Midcontinent	5,000	06/17 – 05/18
Firm Transport	Rockies Express	Northeast	25,000	01/16 – 11/19
Firm Transport	Gulf Crossing Pipeline	Mississippi-Alabama	10,000	01/16 – 07/16
Firm Transport	Oasis Pipeline	Katy Hub	3,600	01/16 – 10/16
Firm Transport	East Tennessee Natural Gas	North Carolina	4,500	01/16 – 10/18

Price Risk and Interest Rate Management Activities

We routinely enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil, natural gas and NGLs price volatility on our cash flow from operations. Currently, we primarily use fixed-price swaps, basis swap contracts and other hedge option contracts 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. In addition, in the current commodity price environment, we are less likely to hedge future revenues to the same extent as our historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced. For a description of our derivative positions, please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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 Gulf Coast Basin, Piceance Basin and Big Horn Basin in East Texas. 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 increased 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. Our 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 operations; and


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

Failure to comply with these laws and regulations may result in the assessment of sanctions, including 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 and water management activities, or waste handling, disposal and 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, 2015, we did not incur any material capital expenditures for performance of remediation or installation of pollution control equipment at any of our facilities; however, we did incur capital expenditures in the ordinary course of business to comply with pollution control requirements. 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 2016 or that will otherwise have a material adverse 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 adverse 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 the “EPA,” individual states administer some or all of the federal provisions of RCRA, sometimes in conjunction with their own, more stringent state requirements. Drilling fluids, produced waters, and many other wastes associated with the exploitation, development, and production of crude oil, natural gas, or geothermal energy are currently regulated under RCRA’s less stringent non-hazardous waste provisions. However, by amendment of existing RCRA laws and regulations, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could increase our costs to manage and dispose of such generated wastes, which cost increase could be significant. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as RCRA hazardous wastes.

Hazardous Substance Releases. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA,” or “Superfund,” and analogous state laws, impose 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.

As of December 31, 2015, we have recorded $15.1 million for future remedial costs and abandonment liability for decommissioning the Big Escambia Creek, Elk Basin, and Fairway natural gas processing plants.

•

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 cease 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.


•	In addition, we also own and operate the Fairway natural gas processing plant in the Gulf Coast Basin, for which we have reserved abandonment costs.

•

We continue to operate a groundwater remediation project at our Big Escambia Creek gas plant. This release occurred when a prior owner operated the Big Escambia Creek gas plant. We are carrying out the cleanup under the supervision of the Alabama Department of Environmental Management, which has approved the risk assessment. We are currently evaluating alternative groundwater treatment technologies. Our current estimate of total remedial costs is no more than approximately $1.0 million.

Our estimates of the future remediation cost are subject to change, and the actual cost of these items could vary significantly from the above estimates. Due to the significant uncertainty associated with the known environmental liabilities at the gas plants, our estimate of the future abandonment liability includes a reserve.

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 the EPA or the relevant state with delegated authority. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure, or “SPCC,” requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by an oil spill or release. If an oil spill or release were to occur as a result of our operations, we expect that it would be contained and remediated in accordance with our SPCC plan together with the assistance of trained first responders and any oil spill response contractor that we may have engaged to address such spills and releases. The Clean Water Act and analogous state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges.

Fluids associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in below ground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control, or UIC, program established under the federal Safe Drinking Water Act, or SDWA, and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While we believe that our disposal well operations substantially comply with requirements under the UIC program, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into below ground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In

response to these concerns, in October 2014, the Texas Railroad Commission, or TRC, published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.

The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities, and onshore facilities, including exploration and production facilities that are the site of a release of oil into 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. We believe we are in substantial compliance with the Clean Water Act, OPA and analogous state laws.

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 targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years.


•	From time to time Congress has considered adopting legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.

•

Federal agencies have asserted regulatory authority over certain aspects of the process. The EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; issued in April 2015 a proposed rule that would establish effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in March 2015, the BLM issued a final rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands.

•

In addition, federal agency reviews are underway 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. In June 2015, the EPA released a draft assessment of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing activities.

Some states in which the Company operates, including Montana, North Dakota, 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. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. 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.

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 and control of well 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 sources through air emissions permitting programs 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 result in the emission of new or increased existing air pollutants, obtain and strictly comply with air permit requirements containing various emissions and operational limitations, or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. To date, we believe that no significant difficulties have been encountered in obtaining air permits. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air control equipment in connection with obtaining and maintaining operating permits and approvals for emissions of pollutants. For example, in October 2015, the EPA issued a final rule that strengthened the National Ambient Air Quality Standard, or “NAAQS,” for ozone from 75 parts per billion, or “ppb,” to 70 ppb for both the 8-hour primary and secondary standards. The lower ozone standard could result in states implementing new, more stringent regulations, which could apply to our operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.

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. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Climate Change. In response to findings made by the EPA 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 Clean Air Act that establish Title V operation and Prevention of Significant Deterioration, or “PSD,” construction permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which typically will be established by the states. 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 in the United States on an annual basis, which include certain of our operations. We are conducting monitoring of GHG emissions from certain of 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.

While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts 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. For example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

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. Still other scientists have concluded the sun may be entering an extended period of low-activity similar to the Maunder Minimum of the “Little Ice Age”. They believe this could have significant physical effects, such as increased periods of

extended cold including longer winters, shorter growing seasons and increased frequencies of cold snaps; if any such effects were to occur, they could have an adverse effect on our operations.

Endangered Species Act Considerations. Various federal and state statutes prohibit certain actions that adversely affect endangered and their habitats, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act, and the Clean Water Act. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service, or “FWS,” is required to make a determination on listing of numerous species as endangered or threatened under the ESA through the agency’s 2018 fiscal year.

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. If we were to cause harm to species or damages to wetlands, habitat or natural resources as a result of our operations, government entities or, at times, private parties could seek to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, the government could seek criminal penalties. 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.

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. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico, Colorado and Oklahoma, where we conduct operations, as a threatened species under the ESA. The FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies, or WAFWA, pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. We have been a party to a Conservation Easement governing nearly 50,000 of affected acreage pursuant to which we agree to adopt certain adaptive management principles and pay an acreage-based mitigation assessment. Calendar year 2016 is the final year during which we expect to pay such assessment.

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. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

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, orders and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. For example, on July 1, 2014, the North Dakota Industrial Commission adopted Order No. 24665, or the “July 2014 Order,” pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of 74% of natural gas produced in the State by October 1, 2014, 77% percent of such gas by January 1, 2015, 85% of such gas by January 1, 2016 and 90% of such gas by October 1, 2020. The July 2014 Order establishes an enforcement mechanism for policy recommendations that were previously adopted by the North Dakota Industrial Commission in March 2014. Those recommendations required all exploration and production operators applying for new drilling permits in the state after June 1, 2014 to develop Gas Capture Plans that provide measures for reducing the amount of natural gas flared by those operators so as to be consistent with the agency’s now-implemented gas capture percentage goals. In particular, the July 2014 Order provides that after an initial 90-day period, wells must meet or exceed the North Dakota Industrial Commission’s gas capture percentage goals on a per-well, per-field, county, or statewide basis. Failure to comply with the gas capture percentage goals will result in an operator having to restrict its production to 200 barrels of oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or 100 barrels of oil per day if less than 60% of such monthly volume of natural gas is captured. While we believe that we were in compliance with these requirements as of December 31, 2015 and expect to remain in compliance in the future, there is no assurance that we will be able to remain in

compliance in the future or that such future compliance will not have a material adverse effect on our business and operational results. 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 “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. In recent years, FERC has also issued rules prohibiting anticompetitive behavior by multiple affiliates of the same entity in the natural gas capacity release market, issued a policy statement providing natural gas pipelines a cost-recovery mechanism to recoup capital expenditures made to modernize pipeline infrastructure, and issued a rule adopting reforms to its scheduling rules to improve coordination between the natural gas and electric markets.

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, or “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 and oil 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.

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, Oklahoma 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 BLM 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 except for our Elk Basin and Fairway gas plants as well as for our Piceance compressor assets. 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 3, 2016, we had 381 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 collective bargaining agreements. 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 Center-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 under “Investor Center-Corporate Governance.” 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

Oil, natural gas and NGLs prices are volatile due to factors beyond our control and have decreased dramatically during 2015 and the beginning of 2016. Sustained lower prices or any further decline in prices of oil, natural gas and NGLs, could have a material adverse impact on us.

Our financial condition, profitability and future growth and the carrying value of our oil and natural gas properties depend substantially on prevailing oil, natural gas and NGLs prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. During 2014, 2015 and the beginning of 2016, for example, oil, natural gas and NGLs prices decreased dramatically. The crude oil spot price per barrel during the years ended December 31, 2014 and 2015 ranged from a high of $107.95 to a low of $34.55 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $6.15 to a low of $1.76. NGLs prices also suffered a similar decline. As of February 29, 2016, the crude oil price per barrel was $32.74 and the NYMEX natural gas spot price per MMBtu was $1.62. This price decline impacted our operating results for the year ended December 31, 2015 and contributed to a reduction in our anticipated future capital expenditures. In addition, this decline resulted in a reduction in our estimated proved reserves and, as a result of this reduction, we recorded substantial impairments to our oil, natural gas and NGLs properties in the year ended December 31, 2015.

The prices for oil, natural gas and NGLs are volatile due to a variety of factors, including, but not limited to:

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


•	the ability of members of the Organization of Petroleum Exporting Countries (“OPEC”) and other producing countries to agree upon production levels which has an impact on oil prices;


•	social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States, such as the Middle East, and armed conflict or terrorist attacks, whether or not in oil or natural gas producing regions;

•the level and growth of consumer product demand;

•labor unrest in oil and natural gas producing regions;


•	weather conditions, including hurricanes and other natural occurrences that affect the supply and/or demand of oil and natural gas;

•the price and availability of alternative fuels and renewable energy sources;


•	the impact of the U.S. dollar exchange rates on commodity prices;

•the price of foreign imports;


•	technological advances affecting energy consumption;

•worldwide economic conditions; and

•the availability of liquid natural gas imports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil, natural gas and NGLs.

Sustained lower prices or any further decline in prices of 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, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil and gas properties, all of which could have a material adverse effect on our financial condition, results of operations and reserves. If the oil and gas industry continues to experience low prices or experiences significant further 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 resume cash distributions to our unitholders, all of which can affect the value of our units.

Continued low 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.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development drilling plans, production data, economics and other factors, we may be required to write down the carrying value of our properties.

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.

In accordance with the guidance contained within ASC Topic 805, “Business Combinations,” (“ASC Topic 805”), upon the

acquisition of oil and natural gas properties, the Company records an asset based on the measurement of the fair value of the properties acquired determined using forward oil and natural gas price curves at the acquisitions dates, which can have several price increases over the entire reserve life. As discussed above, capitalized oil and natural gas property costs are limited to a ceiling based on the present value of future net revenues, computed using a flat price for the entire reserve life equal to the historical 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. As a result, there is a risk that we will be required to record an impairment of our oil and natural gas properties if certain attributes exist, such as declining oil and natural gas prices.

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2015 of $1.8 billion as a result of a decline in realized oil and natural gas prices at the respective measurement dates of March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. Such impairment was recognized during each quarter of 2015 and was calculated based on 12-month average prices for oil and natural gas as follows:



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2015	$	132,610	$3.91	$82.62
Second quarter 2015	$	733,365	$3.44	$71.51
Third quarter 2015	$	491,487	$3.11	$59.23
Fourth quarter 2015	$	484,855	$2.62	$50.20
Total	1,842,317

The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2015 were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisition dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.

We expect to record an additional impairment of our oil and natural gas properties during 2016 as a result of declining oil and natural gas prices. Based on the 11-month average oil, natural gas and NGLs prices through February 1, 2016 and if such prices do not change during March 2016, we estimate that, on a pro forma basis, we will record a ceiling test write down on our existing assets of approximately $221.3 million at March 31, 2016 and an additional write down of $458.9 million for the remainder of the year ending December 31, 2016. If oil, natural gas and NGLs prices were to decline an additional 10% from their 11-month average through February 1, 2016, we estimate that, on a pro forma basis, we would record additional ceiling test write downs on our existing assets of approximately $504.0 million at March 31, 2016 and an additional write down of $388.2 million for the remainder of the year ending December 31, 2016. However, whether the amount of any such impairments will be similar in amount to such estimates, is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2016, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and natural gas property acquisitions, which could increase, decrease or eliminate the need for such impairments.

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 Encore Energy Partners LP acquisition completed in December 2010 and the LRE Merger. Significant oil, natural gas and NGLs price declines could cause us to record an impairment of goodwill, which would be reflected as a non-cash charge against current earnings. We recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

We may not have sufficient cash from operations to resume the payment of monthly cash distributions on our common and Class B units, and we may not have sufficient funds to resume the payment of monthly cash distributions on our preferred units.

We have suspended cash distributions to the holders of our common and Class B units and preferred units in order to conserve cash, repay our debt under our Reserve-Based Credit Facility and improve our liquidity.

We may not have sufficient available cash each month to resume distributions to our common and Class B unitholders. Under the terms of our limited liability company agreement, in the event that we elect to resume such monthly cash distributions to our common and Class B unitholders, 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, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our common and Class B unitholders.

The amount of cash we can distribute on our common and Class B units principally depends upon the amount of cash we generate from our operations, which will fluctuate from month to month based on, among other things:


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


•	the prices at which we are able to sell our oil, natural gas and NGLs production (which decreased significantly in 2015 and have continued to decrease in 2016);


•	the level of our operating costs;


•	the level of our price risk management activities; and


•	voluntary 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, but not limited to:


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


•	required payments on our debt agreements;


•	the success of our price risk management activities;


•	fluctuations in our working capital needs;


•	timing and collectability of receivables;


•	prevailing economic conditions; and


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

As a result of these factors, we may not have sufficient available cash to resume our monthly cash distributions to our common and Class B unitholders. Even if we were able to resume a monthly cash distribution to these unitholders, the amount of available cash that we could distribute in any month to our unitholders may fluctuate significantly from month to month.

In addition, we may not have sufficient funds each month to resume distributions to our preferred unitholders. Furthermore, while the monthly preferred unit distributions on our preferred units are in arrears, we are restricted from making cash distributions on our common units, which in turn may cause the price of our common units to decline. If at any time the preferred unit distributions on any class of our preferred units become 18 months in arrears, whether consecutive or not, the holders of our preferred units will become entitled to elect two members of our board of directors, and the size of our board of directors will be increased to accommodate such change, if needed. The holders of our preferred units will be entitled to continue electing two members of our board of directors until we pay in full, or declare and set aside funds for the payment of, all unpaid distributions on the preferred units.

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 and borrowings from the credit facility (the “Reserve-Based Credit Facility”) under our Third Amended and Restated Credit Agreement (the “Credit Agreement”); 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 upon maturity. In addition, we have limited borrowing capacity under our Reserve-Based Credit Facility; as of December 31, 2015, there was approximately $1.69 billion of outstanding borrowings and $107.5 million of borrowing capacity under the Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit .

A significant increase in our indebtedness, or an increase in our indebtedness that is proportionately greater than our issuances of equity, as well as disruptions in credit market and debt and equity capital market conditions 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.

The terms of our indebtedness include restrictions and financial covenants that could limit growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The indentures governing our Senior Notes due 2020 and Senior Secured Second Lien Notes and our Reserve-Based Credit Facility impose significant operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:


•	resume distributions in respect of our common units and preferred units or make other restricted payments;


•	incur additional secured and unsecured indebtedness;


•	create liens;


•	engage in mergers or consolidations or sell or otherwise dispose of all or substantially all of our assets;


•	make certain dispositions and transfers of assets;


•	engage in transactions with affiliates;


•	make investments; and


•	refinance certain indebtedness.

In addition, our Reserve-Based Credit Facility contains a number of significant covenants that, among other things, restrict our ability to:


•	dispose of assets;


•	incur or guarantee additional indebtedness and issue certain types of preferred equity;


•	resume distributions in respect of our common units;


•	create liens on our assets;


•	enter into sale or leaseback transactions;


•	enter into specified investments or acquisitions;


•	repurchase, redeem or retire our capital stock or subordinated debt;


•	merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;


•	engage in specified transactions with subsidiaries and affiliates; or


•	pursue other corporate activities.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the indentures governing our Senior Notes due 2020 and Senior Secured Second Lien Notes and our Reserve-Based Credit Facility. Our Reserve-Based Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Additionally, the indentures governing our Senior Notes due 2020 and Senior Secured Second Lien Notes contain covenants limiting our ability to incur additional indebtedness unless we meet one of two alternative tests. The first test applies to all indebtedness and requires that, after giving effect to the incurrence of additional debt, our fixed charge coverage ratio (which is the ratio of our adjusted consolidated EBITDA (as defined in our indentures) to our adjusted consolidated interest expense over the trailing four fiscal quarters) will be at least 2.25 to 1.0. If our fixed coverage ratio falls below 2.25 to 1.0, the second test applies to borrowings under credit agreements and limits these borrowings to: (i) under our Senior Notes due 2020, the greater of (a) a fixed sum of $1.0 billion and (b) $475.0 million plus 35% of our adjusted consolidated net tangible assets, which is determined primarily by the value of discounted future net revenues from proved oil and natural gas reserves, and (ii) under our Senior Secured Second Lien Notes, the greater of (a) a fixed sum of $1.8 billion and (b) $950.0 million plus 35% of our modified adjusted consolidated net tangible assets. Lower oil and natural gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil, and natural gas and NGLs prices, or a prolonged period of oil, natural gas and NGLs prices at existing levels, could eventually result in our failing to meet one or more of the financial covenants under our Reserve-Based Credit Facility, which could require us to finance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the indentures referenced above or our Reserve-Based Credit Facility. A default under these agreements, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it, and, even if new financing were then available, it may not be on terms that are acceptable to us. Further, to the extent that we enter into additional transactions which result in the discharge of debt at a discount, the holders of our common units may be subject to income tax to the extent the cancellation of indebtedness income exceeds cumulative passive losses generated by Vanguard in prior years, if applicable. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

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

As of March 3, 2016, we had an aggregate amount of approximately $2.3 billion outstanding under our Reserve-Based Credit Facility, Senior Notes due 2020, Senior Secured Second Lien Notes and Lease Financing Obligations with additional borrowing capacity of approximately $96.6 million under our Reserve-Based Credit Facility. As a result of our indebtedness, we will use a portion of our cash flow to pay interest and principal when due, which will reduce the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate.

Our ability to make payments on our indebtedness and to fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control.

We cannot assure you that our business will generate sufficient cash flow from operations to service our outstanding indebtedness, or that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:


•	refinancing or restructuring our debt;


•	selling assets;


•	reducing or delaying acquisitions or our drilling program; or


•	seeking to raise additional capital.

However, we cannot assure you that we would be able to refinance or restructure our debt or implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such alternative financing plans would allow us to meet our debt obligations. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financings, could materially and adversely affect our business, financial condition, results of operations and prospects.

The borrowing base under our Reserve-Based Credit Facility 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. In June 2015, our lenders reduced the borrowing base under our Reserve-Based Credit Facility from $2.0 billion to $1.6 billion, although the borrowing base was automatically increased to $1.8 billion upon the closing of the LRE Merger. Our next borrowing base redetermination is scheduled for April 2016. Based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next scheduled redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant.

Continued declines in commodity prices could result in future redeterminations that further reduce our borrowing base 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 Reserve-Based Credit Facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid within 30 days, or in six monthly installments beginning within 30 days, 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.

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, or we may be outbid by competitors. If we are unable to acquire properties containing additional proved reserves, our total level of additional proved reserves will decline as a result of our production, and we will be limited in our ability to pay cash distributions to our unitholders. Even if future acquisitions are completed, they may pose substantial risks to our businesses, financial conditions and results of operations.

A widening of commodity differentials and our inability to enter into hedge contracts for a sufficient amount of our production at favorable pricing could materially adversely impact our financial condition, results of operations and cash flows from operations.

Our crude oil, natural gas and NGLs are priced in the local markets where the production occurs based on local or regional supply and demand factors. The prices that we receive for our crude oil, natural gas and NGLs production are generally lower than the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We may not be able to accurately predict crude oil, natural gas and NGLs differentials.

Price differentials may widen in the future. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, changes in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. We may be adversely impacted by a widening differential on the products we sell. Our oil and natural gas hedges are based on WTI or natural gas index prices and the NGLs hedges are based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices, so we may be subject to basis risk if the differential on the products we sell widens from those benchmarks and we do not have a contract tied to those benchmarks. We have entered into fixed-price swaps derivative contracts to cover a portion of our NGLs production to reduce exposure to fluctuations in NGLs prices. Currently, we are unable to hedge widening oil differentials in certain operating areas. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive and our inability to enter into hedge contracts at favorable pricing and for a sufficient amount of our production could adversely affect our financial condition, results of operations and cash flows from operations in the future.

Our limited ability to hedge our NGLs production could adversely impact our net cash provided by operating activities and results of operations.

A liquid, readily available and commercially viable market for hedging NGLs has not developed in the same way that exists for crude oil and natural gas. The current direct NGLs hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits our ability to hedge our NGLs production effectively or at all. As a result, our net cash provided by operating activities and results of operations could be adversely impacted by fluctuations in the market prices for NGLs products.

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 resume or sustain 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 depleted through production, investors in our units should consider the cash distributions that are paid on the units not merely as a “distribution 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.

Adverse developments in our operating areas would reduce our ability to resume distributions to our unitholders.

Our properties are located in Wyoming, Colorado, Texas, New Mexico, Louisiana, Mississippi, Montana, Arkansas, Oklahoma, North Dakota and Alabama. An adverse development in the oil and natural gas business of any of these geographic areas, such as in our ability to attract and retain field personnel or in our ability to comply with local regulations, could have a negative impact on our results of operations and cash available for distribution to our unitholders.

Our acquisition activities will subject us to certain risks.

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. We have therefore historically expanded our operations through acquisitions.

Any acquisition involves potential risks, including, but not limited to, the following, which could reduce the amount of cash available from the affected properties:


•	the validity of our assumptions about reserves, future production, revenues and costs, including synergies;


•	unforeseen difficulties encountered in operating in new geographic areas;


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


•	we may assume liabilities, including environmental liabilities, that were not disclosed or that exceed their estimates, losses or costs for which we are not indemnified or for which our indemnity is inadequate;


•	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 decrease our liquidity by using a significant portion of our available cash or borrowings to finance acquisitions;


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


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


•	we may incur a significant increase in our interest expense or financial leverage if we incur additional debt related to future acquisitions;


•	an increase in our costs or a decrease in our revenues associated with any potential royalty owner or landowner claims or disputes;


•	customer or key employee losses at the acquired businesses; and


•	acquisitions could cause other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charge.

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.

For example, the realized success of the LRE Merger and Eagle Rock Merger will depend, in part, on our ability to realize the anticipated benefits and synergies from combining our business with the business of LRE and Eagle Rock. To realize these anticipated benefits, the businesses must be successfully combined. If the combined entity is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the LRE Merger and Eagle Rock Merger may not be realized fully or at all. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the mergers.

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

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

ended December 31, 2015 would have increased by approximately $0.4 million. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risks” included under Part II of this annual report for further information regarding interest rate sensitivity.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. As of December 31, 2015, we operated approximately 56% of our production and non-operated wells represented approximately 44% of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. In the past, we have changed our development plans for certain proved undeveloped reserves and expect future development plans may also change as the operators of our outside operated properties adjust their capital plans based on prevailing market conditions. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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 resume the payment of distributions even when we record net income, and we may be able to resume the payment of 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 reservoir 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. We prepare our own estimates of proved reserves and engage D&M, an independent petroleum engineering firm, to audit a substantial portion of our 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, to illustrate the impact of a sustained low commodity price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2015 would decrease from 2,288.9 Bcfe to 2,061.3 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices were $2.57 per MMBtu (or a $0.05 price decrease from the 12-month average price of $2.62) and oil prices were $44.28 per barrel (or a $5.92 price decline from the 12-month average price of $50.20), while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2015 would increase from 2,288.9 Bcfe to 2,324.1 Bcfe. The preceding assumed prices in example (2) were derived from the 5-year New York Mercantile Exchange (NYMEX) forward strip price at February 29, 2016. 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 PV-10 of our proved reserves at December 31, 2015 may not be the same as the current market value of our estimated oil, natural gas and NGLs reserves.

You should not assume that the present value of future net reserves (“PV-10”) value of our proved reserves as of December 31, 2015 is the current market value of our estimated oil, natural gas and NGLs reserves. We base the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:


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


•	our actual development and production 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 and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating PV-10 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. Actual future prices and costs may differ materially from those used in the present value estimates included in this annual report, which could have a material effect on the value of our reserves. The oil and natural gas prices used in computing our PV-10 as of December 31, 2015 under SEC guidelines were $50.20 per barrel of crude oil and $2.62 per MMBtu for natural gas, respectively, before price differentials.

Using more recent prices in estimating proved reserves would result in a reduction in proved reserve volumes because they are lower than the prices used in estimated proved reserves and due to economic limits, which would further reduce the PV-10 value of our proved reserves.

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 resume 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 our access to capital are subject to a number of variables, including, but not limited to:


•	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. In turn, we may not be able to resume or sustain any distributions without making accretive acquisitions or capital expenditures that 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 oil and 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 oil and 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.

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, 2015, sales of oil, natural gas and NGLs to Mieco Inc., Marathon Oil Company, ConocoPhillips, Plains Marketing, L.P. and Targa Resources, Inc. accounted for approximately 20%, 7%, 7%, 7%, and 6%, respectively, of our oil, natural gas and NGLs revenues. Our top five purchasers during the year ended December 31, 2015 therefore accounted for 47% 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.

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

The FTC, FERC and 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 resume 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.

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 regulatory requirement 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.

The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to resume distributions to our unitholders.

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 investigatory, corrective action or remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose joint and several strict 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 in the performance of our operations as a result of our handling petroleum hydrocarbons, hazardous substances and wastes, because of air emissions and wastewater discharges relating to our operations, and due to historical industry operations and waste disposal practices by us or prior operators or other third parties over whom we had no control. 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. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters.”

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

The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts 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. While from time to time Congress has considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.

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 in the United States on an annual basis, which include certain of our operations. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters-Climate Change.” These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities, should those facilities exceed threshold permitting levels of GHG emissions.

A number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

The enactment of derivatives legislation 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.

On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, 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. The position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, the CFTC introduced new rules in 2013 that would place position limits on future and option contracts and for swaps that are their economic equivalent for certain physical commodities that would be subject to exemptions for bona fide hedges. These rules have not been finalized, and their impact on our hedging activities is uncertain. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap,” “security-based swap,” “swap dealer” and “major swap participant”. The Act and CFTC Rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). On December 16, 2015, the CFTC adopted final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants or financial end users (though non-financial end users are excluded from margin requirements). While we do not anticipate being subject to margin requirements as a swap dealer, major swap participant or financial end user, application of these requirements to other market participants could affect the cost and availability of swaps we use for hedging. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act also may 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 Act 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 Act 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 resume distributions. Finally, the Act 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 Act 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.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, operating restrictions or delays, and adversely affect our production.

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 targeted subsurface formations to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations.

While hydraulic fracturing is typically regulated by state oil and natural gas commissions, and other similar state agencies, increased federal interest has arisen in recent years. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters-Hydraulic Fracturing.” Some states in which we operate, including Montana, North Dakota, 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. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. 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.

Laws and regulations pertaining to threatened and endangered species could delay or restrict our operations and cause us to incur substantial costs.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, and the Clean Water Act. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS is required to make a determination on listing of numerous species as endangered or threatened under the ESA through the agency’s 2018 fiscal year.

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. Please read “Item 1. Business-Operations-Environmental and Occupational Health Safety Matters-Endangered Species Act Considerations.”

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. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves, and may inhibit our ability to further exploit and develop our reserves.

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 resume distributions.

Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGLs prices, the generation of additional seismic or geological information, the availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing leasehold acreage. As of December 31, 2015, we have identified 1,591 proved undeveloped drilling locations and over 5,013 additional drilling locations. These identified drilling locations represent a significant part of our strategy. The SEC’s reserve reporting rules include a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. To the extent that we do not drill these locations within five years of initial booking, they may not continue to qualify for classification as proved reserves, and we may be required to reclassify such reserves as unproved reserves. The reclassification of such reserves could also have a negative effect on the borrowing base under our Reserve-Based Credit Facility.

Our ability to drill and develop these locations depends on a number of factors, including, among others, the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, drilling and operating costs and drilling results. In addition, we have not assigned any proved reserves to the over 5,013 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, financial position, results of operations and our ability to resume distributions.

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 resume 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, but not limited to:


•	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 and conditions;


•	adverse weather conditions;


•	human errors;


•	facility or equipment malfunctions;


•	title deficiencies that can render a lease worthless;


•	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 natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;


•	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 resume paying 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 monthly 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 continue to 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 increased 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 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 resume distributions to our unitholders.

We enter into derivative contracts to reduce the impact of oil, natural gas and NGLs price volatility on our cash flow from operations. Currently, we primarily use fixed-price swaps, basis swap contracts and other hedge option contracts to hedge 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 additional information about our price risk management activities.

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.

Our price risk management arrangements in place will not fully mitigate the effect of oil, natural gas and NGLs price volatility, and our revenue and results of operations will be adversely affected if prices remain at current levels or decline further. In the current commodity price environment, we are less likely to hedge future revenues to the same extent as our historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced.

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, joint interest owners and by counterparties to our price risk management arrangements. Some of our vendors, customers, joint interest owners and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers, joint interest owners 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’, joint interest owners’ 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, joint interest owners and/or counterparties could reduce our ability to resume 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 Executive Vice President of Operations. We do not maintain key person insurance for any of 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.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be unable to compete effectively with larger companies in the oil and natural gas industry, 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. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with our larger competitors that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

Risks Related to Our Structure

Our limited liability company agreement limits our duties to our unitholders and restricts the remedies available to our unitholders for actions taken by us that might otherwise constitute breaches of duty.

Our limited liability agreement contains provisions that reduce the standards to which we might otherwise be held by state fiduciary duty law. For example, our limited liability company agreement:


•	provides that our board of directors and our directors and officers will not have any liability to us or our unitholders for decisions made so long as our board of directors or any director or officer acted in good faith, meaning that our board of directors or such director or officer believed the determination or other action was in our best interests;

•

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by our conflicts committee and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by us in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” we may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

•

provides that we and our officers and directors will not be liable to us or our unitholders for losses sustained or liabilities incurred as a result of any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining in respect of such matter or question that we or such other persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.

Our unitholders are bound by the provisions in our liability company agreement, including those discussed above.

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

Our unitholders’ voting rights are restricted by the provision in our limited liability company agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our founding unitholder and his

affiliates or transferees and 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.

We may issue an unlimited number of additional units without common unitholder approval, which would dilute the ownership interest of existing unitholders.

Under our limited liability company agreement, we may, without the approval of our unitholders, issue an unlimited number of additional limited liability company interests of any type, including common units, without the approval of our unitholders.

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


•	our existing unitholders’ proportionate ownership interest in us may decrease;


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


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


•	the market price of our common units may decline.

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 a tax liability upon a sale of their units.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our limited liability company agreement requires us to make quarterly distributions to our unitholders of all available cash, reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. We pay distributions on monthly basis. The value of our units, including common units, may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.

Our management may have conflicts of interest with our unitholders. Our limited liability company agreement limits the remedies available to our unitholders in the event our unitholders have a claim relating to conflicts of interest.

Conflicts of interest may arise between our management, on the one hand, and the Company and our unitholders, on the other hand, related to the divergent interests of our management. Situations in which the interests of our management may differ from interests of our non-affiliated unitholders include, among others, the following situations:


•	our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our management will use its reasonable discretion to establish and maintain cash reserves sufficient to fund our drilling program;


•	our management team, subject to oversight from our board of directors , determines the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, borrowings, issuances of additional units and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders; and


•	affiliates of our directors are not prohibited under our limited liability company agreement from investing or engaging in other businesses or activities that compete with us.

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

During 2015, the quoted market prices of our common and preferred units fluctuated as follows:



	Low		High
Common unit (VNR)	$	2.41	$	19.50
Series A Preferred unit (VNRAP)	$	5.91	$	25.23
Series B Preferred unit (VNRBP)	$	4.67	$	23.76
Series C Preferred unit (VNRCP)	$	5.39	$	24.24

The market prices of our common and preferred units are subject to fluctuations in response to a number of factors, most of which we cannot control, including, but not limited to:


•	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, including fluctuations in commodity prices;


•	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 monthly cash distributions; and


•	future issuances and sales of our units.

In recent years, and in particular during 2015, 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 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. Under Delaware law, a unitholder who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the distribution amount. Any such unitholder will have no liability for the account of any such distribution after three years from the date of the distribution unless an action to recover the distribution from that unitholder is conditioned within such three-year period and such unitholder is adjudicated liable in the action. A purchaser of common units who becomes a member 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, and may negatively affect our ability to issue additional equity or incur debt.

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 or local entities. If the Internal Revenue Service (“IRS”) were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, those events would substantially reduce the amount of cash available for payment of distributions on our common units.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as Vanguard will be treated as a corporation for U.S. federal income tax purposes unless we satisfy the “qualifying income” requirement. Based on our current operations, we believe that we satisfy the qualifying income requirement and will therefore be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. 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.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, or deduction would flow through to unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would likely be substantially reduced. Therefore, treatment of Vanguard as a corporation would likely 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 units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such tax on us by any such state will reduce the cash available for distribution to our unitholders.

Our unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income upon cancellation of a portion of our debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different from the unitholder’s interest in our distributable cash flow.

Because our unitholders will be allocated taxable income that could be different in amount from the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income. As of February 25, 2016, we have suspended all cash distributions to unitholders and monthly cash distributions to holders of our preferred units. We may engage in transactions to de-lever the Company and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets, our unitholders may be allocated taxable income and gain resulting from the sale. Further, we have in the past engaged in, and may in the future engage in, debt exchanges, debt repurchases, modifications of our existing debt, or similar transactions that resulted in, or could result in, “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated gain and income from asset sales and COD income and may owe income tax as a result of such allocations notwithstanding the fact that we have currently suspended cash distributions to our unitholders.

For example, our issuance on February 10, 2016 of approximately $75.6 million aggregate principal amount of new Senior Secured Second Lien Notes to certain eligible holders of Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 has resulted in the COD income that will be allocated to our unitholders as of February 29, 2016. Some or all of our unitholders may be allocated substantial amounts of such taxable COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder will depend on the unitholder's individual tax position with respect to the units; however, taxable income allocations from us, including allocations of COD income, increase a unitholder’s tax basis in his units.

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our distributable cash flow. This may occur, for example, in the case of a unitholder who owns units in the month in which the cancellation of debt occurs or a unitholder who acquires units directly from us in exchange for a contribution of property whose fair market value exceeds its tax basis at the time of the contribution. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential transactions that may result in income and gain to unitholders.

The tax treatment of publicly traded partnerships or of an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or of an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama Administration’s budget proposal for fiscal year 2017 recommends that publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of Congress also propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of the qualifying income exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for U.S. federal income tax purposes.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. 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. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

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

If a unitholder sells his common units, he will recognize gain or loss equal to the difference between the amount realized and his tax basis in those common units. Prior distributions per common unit to a unitholder in excess of the total net taxable income allocated per common unit to such unitholder will decrease such unitholder’s tax basis in that common unit. The amount of this decreased tax basis will, in effect, become taxable income to him to the extent the common unit is sold at a price greater than his tax basis in that common unit, even if the sales price is less than his original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells his common units, he may incur a tax liability in excess of the amount of cash he receives from the sale.

Treatment of distributions on our preferred units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our preferred units than the holders of our common units.

The Company will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Although a holder of preferred units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, the company anticipates accruing and making the guaranteed payment distributions monthly. Otherwise, the holders of preferred units are generally not anticipated to share in the Company’s items of income, gain, loss or deduction. Nor will the Company allocate any share of its nonrecourse liabilities to the holders of preferred units.

A holder of preferred units will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit will generally be equal to the sum of the cash and the fair market value of other property paid by the unitholder to acquire such preferred unit. Gain or loss recognized by a unitholder on the sale or exchange of a preferred unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will not be allocated a share of the Company’s items of

depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

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

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

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

Due to a number of factors, including our inability to match transferors and transferees of our common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of our common units and could have a negative impact on the value of our common units or result in audit 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. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. The proposed regulations do not, however, specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this proration 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 the subject of a securities loan (e.g. a loan to a “short seller” to cover a short sale of units) may be considered to have 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 there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder 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, 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 securities loan 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 U.S. federal income tax purposes.

We will be considered to have constructively terminated our partnership for U.S. 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 are 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 Schedule K-1s) for one calendar 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 calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. 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 elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, 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 2017 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.

Our unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to return filing requirements and 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. Further, our unitholders may be subject to penalties for failure to comply with those return filings requirements. We currently conduct business and own assets in many states. Several of these states currently impose a personal income tax on individuals and all of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may conduct business or own assets in additional states that impose a personal income tax. It is the responsibility of each of our unitholders 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 office leases in Houston and Odessa, Texas; Gillette, Wyoming; and Mustang and Tulsa, Oklahoma. As of December 31, 2015, the leases for the Houston offices cover approximately 37,156 square feet and 90,293 square feet of office space with terms ending on February 29, 2020 and February 28, 2018, respectively. Our lease for the Odessa office covers approximately 6,500 square feet of office space, and runs through June 30, 2019. In Wyoming, the lease for our Gillette office covers approximately 5,000 square feet with a lease term expiring on April 30, 2018. We are also leasing a fenced yard in Gillette, Wyoming with lease term ending on March 31, 2018. Our leases for the Mustang and Tulsa, Oklahoma offices cover approximately 1,750 square feet and 3,000 square feet, respectively, with terms ending on July 31, 2016 and November 30, 2017, respectively. We also have leases in Eunice, New Mexico and Lindsay and Stroud, Oklahoma which are month-to-month. The total annual cost of our office leases for 2015 was approximately $2.3 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

We are defendants in certain 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 these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. 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.

We are also a party to separate legal proceedings relating to each of the LRE Merger, the Eagle Rock Merger and our debt exchange, as further discussed below.

Litigation Relating to the LRE Merger

A putative class action was filed on June 3, 2015 in connection with the LRE Merger by a purported LRE unitholder (the “LRE Delaware State Plaintiff”) against LRE, LRE GP, the members of the LRE GP board of directors, Vanguard, Lighthouse Merger Sub, LLC, an indirect wholly owned subsidiary of Vanguard (“Lighthouse Merger Sub”), and the other parties to the LRE Merger Agreement (collectively, the “LRE Litigation Defendants”). The lawsuit was styled Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, in the Court of Chancery of the State of Delaware (the “LRE Delaware State Lawsuit”). On July 23, 2015, the LRE Delaware State Plaintiff voluntarily dismissed the LRE Delaware State Lawsuit without prejudice.

On July 10, 2015 and July 13, 2015, two additional purported LRE unitholders (the “LRE Texas State Plaintiffs”) filed putative class action lawsuits against the LRE Litigation Defendants. These lawsuits were styled (a) Christopher Tiberio v. Eric Mullins et al., Cause No. 2015-39864, in the District Court of Harris County, Texas, 334th Judicial District; and (b) Eddie Hammond v. Eric Mullins et al., Cause No. 2015-40154, in the District Court of Harris County, Texas, 295th Judicial District (the “LRE Texas State Lawsuits”). On July 28, 2015, the LRE Texas State Lawsuits were nonsuited without prejudice.

On July 14, 2015, an additional purported LRE unitholder (the “LRE Texas Federal Plaintiff”) filed a putative class action lawsuit against the LRE Litigation Defendants. This lawsuit was styled Ronald Krieger v. LRR Energy, L.P. et al., Civil Action No. 4:15-cv-2017, in the United States District Court for the Southern District of Texas, Houston Division (the “LRE Texas Federal Lawsuit”). On July 17, 2015, the LRE Texas Federal Plaintiff voluntarily dismissed the LRE Texas Federal Lawsuit without prejudice.

On August 18, 2015, another purported LRE unitholder (the “LRE Plaintiff”) filed a putative class action lawsuit against the members of the LRE GP board of directors, Vanguard, and Lighthouse Merger Sub (the “LRE Lawsuit Defendants”). This lawsuit is styled Robert Hurwitz v. Eric Mullens et al., Civil Action No. 1:15-cv-00711-UNA, in the United States District Court for the District of Delaware (the “LRE Lawsuit”).

The LRE Lawsuit alleges that the LRE Lawsuit Defendants violated Sections 14(a) and/or 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder. In general, the LRE Plaintiff alleges that the proxy statement/prospectus filed in connection with the LRE Merger failed, among other things, to disclose allegedly material details concerning (i) the background of the LRE Merger, (ii) the financial analyses conducted by LRE’s and the LRE conflicts committee’s financial advisors in connection with the LRE Merger, (iii) LRE’s and Vanguard’s financial and operational projections, and (iv) alleged conflicts of interest held by one of LRE’s financial advisors.

The LRE Plaintiff seeks, among other relief, to rescind the LRE Merger, and an award of attorneys’ fees and costs.

The LRE Plaintiff has not yet served the LRE Lawsuit Defendants, and the LRE Lawsuit Defendants’ date to answer, move to dismiss, or otherwise respond to the LRE Lawsuit has not yet been set.

Vanguard cannot predict the outcome of the LRE Lawsuit or any others that might be filed subsequent to the date of the filing of this report; nor can Vanguard predict the amount of time and expense that will be required to resolve the LRE Lawsuit. The LRE Lawsuit Defendants believe the LRE Lawsuit is without merit and intend to vigorously defend against it.

Litigation Relating to the Eagle Rock Merger

On May 28, 2015 and June 10, 2015, alleged Eagle Rock unitholders (the “State Plaintiffs”) filed two derivative and class action lawsuits against Eagle Rock, Eagle Rock GP, Eagle Rock Energy G&P, LLC (“Eagle Rock G&P”), Vanguard, Talon Merger Sub, LLC, a wholly owned indirect subsidiary of Vanguard (“Merger Sub”), and the members of Eagle Rock G&P’s board of directors (collectively, the “Defendants”). These lawsuits have been consolidated as Irving and Judith Braun v. Eagle Rock

Energy GP, L.P. et al., Cause No. 2015-30441, in the District Court of Harris County, Texas, 125th Judicial District (the “State Lawsuits”). On November 11, 2015, the State Lawsuits were voluntarily dismissed without prejudice.

On June 1, 2015, another alleged Eagle Rock unitholder filed a class action lawsuit against the Defendants. This lawsuit was styled Pieter Heydenrych v. Eagle Rock Energy Partners, L.P. et al., Cause No. 4:15-cv-01470, in the United States District Court for the Southern District of Texas, Houston Division (the “Federal Lawsuit”). On February 12, 2016, certain additional alleged Eagle Rock unitholders (the “Federal Plaintiffs”) amended the complaint in the Federal Lawsuit (the “Amended Complaint”), which is now styled Irving Braun, et al. v. Eagle Rock Energy Partners, L.P. et al., Cause No. 4:15-cv-01470.

In the Amended Complaint, the Federal Plaintiffs allege multiple causes of action related to the registration statement and proxy statement filed with the SEC in connection with the Eagle Rock Merger, including that (i) Vanguard and certain of its officers and directors have allegedly violated Section 11 of the Securities Act for including inaccurate, misleading and untrue material statements in the registration statement and proxy statement related to the Eagle Rock Merger , (ii) the members of Vanguard’s board of directors are allegedly culpable participants in the violations of Section 11 of the Securities Act for signing the registration statements and of Section 15 of the Securities Act for participating in the issuance of common units in connection with the Eagle Rock Merger, (iii) the Defendants have allegedly violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder for filing proxy statements with misleading and untrue material statements and (iv) the Defendants have allegedly violated Section 20 of the Exchange Act by failing to use their control and influence to stop the violation of Section 14(a) of the Exchange Act. The Federal Plaintiffs allege that the registration statement and proxy statement filed in connection with the Eagle Rock Merger failed, among other things, to disclose allegedly material details concerning (x) Eagle Rock’s and Vanguard’s financial and operational projections, (y) Vanguard’s debt obligations and (z) an imminent reduction in Vanguard’s distributions to unitholders.

Based on these allegations, the Federal Plaintiffs seek damages and attorneys’ fees.

The Defendants’ date to answer, move to dismiss, or otherwise respond to the Federal Lawsuit is currently set for March 28, 2016. Vanguard cannot predict the outcome of the Federal Lawsuit or any others that might be filed subsequent to the date of the filing of this report; nor can Vanguard predict the amount of time and expense that will be required to resolve the Federal Lawsuit. The Defendants believe the Federal Lawsuit is without merit and intend to vigorously defend against it.

Litigation Relating to the Debt Exchange

On March 1, 2016, a purported holder of the 7.875% Senior Notes due 2020, Gregory Maniatis, individually and purportedly on behalf of other non-qualified institutional buyers (“non-QIBs”) who beneficially held the Senior Notes due 2020 (the “Debt Exchange Plaintiff”), filed a class action lawsuit, against Vanguard and VNRF (collectively, the “Debt Exchange Defendants”). The lawsuit is styled Gregory Maniatis v. Vanguard Natural Resources, LLC and VNR Finance Corp., Case No. 16-cv-1578, in the United States District Court for the Southern District of New York (the “Debt Exchange Lawsuit”).

The Debt Exchange Plaintiff alleges a variety of causes of action challenging the Company’s debt exchange, whereby the Debt Exchange Defendants issued new 7.0% Senior Secured Second Lien Notes due 2023 in exchange for certain Senior Notes due 2020, including that (a) the Debt Exchange Defendants have allegedly violated Section 316(b) of the Trust Indenture Act of 1939 by benefiting themselves and a minority of the holders of Senior Notes due 2020 at the expense of the non-QIB holders of Senior Notes due 2020, (b) the Debt Exchange Defendants have allegedly breached the terms of the indenture governing the Senior Notes due 2020 (the “Senior Notes Indenture”) and the Debt Exchange Plaintiff’s and class members’ contractual rights under the indenture, (c) the Debt Exchange Defendants have allegedly violated the implied covenant of good faith and fair dealing in connection with the debt exchange, and (d) the Debt Exchange Defendants have allegedly unjustly enriched themselves at the expense of the Debt Exchange Plaintiff and class members by reducing indebtedness and reducing the value of the Senior Notes due 2020.

Based on these allegations, the Debt Exchange Plaintiff seeks declaratory relief that the debt exchange and the liens created for the benefit of the Senior Secured Second Lien Notes are null and void and that the debt exchange effectively resulted in a default under the Senior Notes Indenture. The Debt Exchange Plaintiff also seeks monetary damages and attorneys’ fees.

The Debt Exchange Lawsuit is in early stages of litigation. The Debt Exchange Defendants have yet to answer, move to dismiss or otherwise respond to the Debt Exchange Lawsuit. Vanguard cannot predict the outcome of the Debt Exchange Lawsuit or any others that might be filed subsequent to the date of the filing of this report; nor can Vanguard predict the amount of time and expense that will be required to resolve the Debt Exchange Lawsuit. The Debt Exchange Defendants believe the Debt Exchange Lawsuit is without merit and intend to vigorously defend against it.

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 NASDAQ under the symbol “VNR.” On March 3, 2016, there were 130,481,279 common units outstanding and approximately 515 unitholders, which does not include beneficial owners whose units are held by a clearing agency, such as a broker or a bank. On March 3, 2016, the market price for our common units was $2.11 per unit, resulting in an aggregate market value of units held by non-affiliates of approximately $270.6 million. The following table presents the high and low sales price for our common units during the periods indicated.



	Common Units
	High		Low
2015
Fourth Quarter	$	9.53	$	2.41
Third Quarter	$	15.50	$	5.50
Second Quarter	$	17.59	$	13.81
First Quarter	$	19.50	$	11.90
2014
Fourth Quarter	$	27.72	$	12.57
Third Quarter	$	33.04	$	26.11
Second Quarter	$	32.21	$	29.26
First Quarter	$	31.50	$	29.11

Stock Performance Graph. The performance graph below compares total unitholder return on our common 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 six oil and natural gas production publicly traded partnerships. The partnerships included in our peer group are Linn Energy, LLC, BreitBurn Energy Partners, LP, Legacy Reserves LP, EV Energy Partners, L.P., Mid-Con Energy Partners, LP and Memorial Production Partners LP. We have selected the members in our peer group based on annual revenue, market capitalization, total assets, and areas of operation. 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 ($29.65) on December 31, 2010, 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 or the Exchange Act, each as amended, except to the extent that we specifically incorporate it by reference into such filing.



	12/31/10		12/31/11	12/31/12	12/31/13	12/31/14	12/31/15
Vanguard Natural Resources, LLC	$	100.00	100.52	104.58	129.59	72.57	16.46
Peer Group Index	100.00		115.28	114.68	125.48	59.41	10.56
S&P 500 Index	100.00		102.11	118.44	156.78	178.22	180.67

Distributions Declared. The following table shows the amount per unit, record date and payment date of the cash distributions we paid on each of our common units attributable to 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. On February 18, 2016, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2016 of $0.03 per common and Class B unit, or $0.36 on an annualized basis, which will be paid on March 15, 2016 to Vanguard unitholders of record on March 1, 2016. On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and preferred units effective with the February 2016 distribution.

For additional information about our ability to resume distributions to our unitholders, please read “Item 1A. Risk Factors-Risks Related to Our Business-We may not have sufficient cash from operations to resume monthly distributions on our common units following establishment of cash reserves and payment of operating costs.”



	Cash Distributions
	Per Unit		Record Date	Payment Date
2015
Fourth Quarter
December	$	0.0300	February 1, 2016	February 12, 2016
November	$	0.0300	January 4, 2016	January 14, 2016
October	$	0.1175	December 1, 2015	December 15, 2015
Third Quarter
September	$	0.1175	November 2, 2015	November 13, 2015
August	$	0.1175	October 1, 2015	October 15, 2015
July	$	0.1175	September 1, 2015	September 14, 2015
Second Quarter
June	$	0.1175	August 3, 2015	August 14, 2015
May	$	0.1175	July 1, 2015	July 15, 2015
April	$	0.1175	June 1, 2015	June 12, 2015
First Quarter
March	$	0.1175	May 1, 2015	May 15, 2015
February	$	0.1175	April 1, 2015	April 14, 2015
January	$	0.1175	March 2, 2015	March 17, 2015
2014
Fourth Quarter
December	$	0.2100	February 2, 2015	February 13, 2015
November	$	0.2100	January 2, 2015	January 14, 2015
October	$	0.2100	December 1, 2014	December 15, 2014
Third Quarter
September	$	0.2100	November 3, 2014	November 14, 2014
August	$	0.2100	October 1, 2014	October 15, 2014
July	$	0.2100	September 2, 2014	September 12, 2014
Second Quarter
June	$	0.2100	August 1, 2014	August 14, 2014
May	$	0.2100	July 1, 2014	July 15, 2014
April	$	0.2100	June 2, 2014	June 13, 2014
First Quarter
March	$	0.2100	May 1, 2014	May 15, 2014
February	$	0.2100	April 1, 2014	April 14, 2014
January	$	0.2075	March 3, 2014	March 17, 2014

Our limited liability company agreement requires that, within 90 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 month 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 and redemption payments on Series A Cumulative Preferred Units, Series B Cumulative Preferred Units and Series C Cumulative Preferred Units; or


(iv)	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.

Distributions on our preferred units are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, unless the 15th day falls on a weekend or holiday, in which case it will be paid on the next business day, when, as and if declared by our board of directors. If we resume distributions on our preferred units, we will pay cumulative distributions in cash on our preferred units on a monthly basis at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit.

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, 2015.

Unregistered Sale of Equity Securities and Use of Proceeds. During the year ended December 31, 2015, one of our wholly-owned subsidiaries purchased 157,156 of our common units on the open market at the then prevailing market price. The average price paid per common unit was $15.27. The repurchased units were subsequently granted to two of our executive officers, Messrs. Smith and Robert and our three independent directors, Loren B. Singletary, W. Richard Anderson and Bruce W. McCullough, who elected to receive quarterly unit grants in lieu of their 2015 cash compensation.

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⁾
	2015			2014			2013			2012⁽⁶⁾			2011⁽⁷⁾
	(in thousands, except per unit data)
Statement of Operations Data:
Revenues:
Oil sales	$	164,111		$	268,685		$	268,922		$	233,153		$	236,003
Natural gas sales	193,496			285,439			124,513			47,270			47,977
NGLs sales	39,620			70,489			49,813			29,933			28,862
Net gains on commodity derivative contracts ⁽¹⁾	169,416			163,452			11,256			36,846			6,735
Total revenues	566,643			788,065			454,504			347,202			319,577
Costs and Expenses:
Production:
Lease operating expenses	146,654			132,515			105,502			74,366			63,944
Production and other taxes	40,576			61,874			40,430			29,369			28,621
Depreciation, depletion, amortization and accretion	247,119			226,937			167,535			104,542			84,857
Impairment of oil and natural gas properties	1,842,317			234,434			—			247,722			—
Goodwill impairment loss	71,425			—			—			—			—
Selling, general and administrative expenses ⁽²⁾	55,076			30,839			25,942			22,466			19,779
Total costs and expenses	2,403,167			686,599			339,409			478,465			197,201
Income (Loss) from Operations:	(1,836,524		)	101,466			115,095			(131,263		)	122,376
Other Income (Expense):
Interest expense	(87,573		)	(69,765		)	(61,148		)	(41,891		)	(28,994		)
Net gains (losses) on interest rate derivative contracts	153			(1,933		)	(96		)	(6,992		)	(4,962		)
Net gain (loss) on acquisitions of oil and natural gas properties	40,533			34,523			5,591			11,111			(367		)
Other	237			54			69			220			77
Total other expense, net	(46,650		)	(37,121		)	(55,584		)	(37,552		)	(34,246		)
Net Income (Loss)	(1,883,174		)	64,345			59,511			(168,815		)	88,130
Less: Net income attributable to non-controlling interest	—			—			—			—			(26,067		)
Net Income (Loss) Attributable to Vanguard Unitholders	$	(1,883,174	)	$	64,345		$	59,511		$	(168,815	)	$	62,063
Less: Distributions to Preferred unitholders	(26,759		)	(18,197		)	(2,634		)	—			—
Net Income (Loss) Attributable to Common and Class B unitholders	$	(1,909,933	)	$	46,148		$	56,877		$	(168,815	)	$	62,063
Net Income (Loss) Per Common and Class B Unit:
Basic	$	(19.80	)	$	0.56		$	0.78		$	(3.11	)	$	1.95
Diluted	$	(19.80	)	$	0.55		$	0.77		$	(3.11	)	$	1.95
Distributions Declared Per Common and Class B Unit ⁽³⁾	$	1.42		$	2.52		$	2.46		$	2.79		$	2.28
Weighted Average Common Units Outstanding:
Basic	96,048			81,611			72,644			53,777			31,370
Diluted	96,048			82,039			72,992			53,777			31,370
Weighted Average Class B Units Outstanding	420			420			420			420			420
Cash Flow Data:
Net cash provided by operating activities	$	370,084		$	339,752		$	260,965		$	204,490		$	176,332
Net cash used in investing activities	$	(128,144	)	$	(1,446,202	)	$	(397,977	)	$	(839,244	)	$	(236,350	)
Net cash provided by (used in) financing activities	$	(241,940	)	$	1,094,632		$	137,267		$	643,466		$	61,041
Other Financial Information:
Adjusted EBITDA attributable to Vanguard unitholders interest⁽⁴⁾	$	396,829		$	421,445		$	309,745		$	230,512		$	164,603


(1)	Oil and natural gas derivative contracts were used to reduce our exposure to changes in oil and natural gas prices. 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 was 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 commodity derivative contracts are recorded in earnings and classified as gain (loss) on commodity derivative contracts.


(2)	Includes $18.5 million, $11.7 million, $5.9 million, $5.4 million and $3.0 million of non-cash unit-based compensation expense in 2015, 2014, 2013, 2012 and 2011, respectively.

(3)

Includes distributions declared during the respective periods. Due to the change in the payment of our distributions from quarterly to monthly starting with our July 2012 distribution, the distributions declared during 2012 include 14 months of distributions compared to 12 months of distributions for each of the other years presented. See “Item 8. Financial Statements and Supplementary Data—Note 8” for further detail on distributions declared.


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


(5)	From 2011 through 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these assets. The operating results of these properties were included with ours from the closing date of the acquisitions forward.


(6)	On March 30, 2012, we divested oil and natural gas properties in the Appalachian Basin. As such, there are no operating results from these properties included in our operating results from the closing date of the divestiture forward.

(7)

On December 31, 2010, we acquired all of the member interests in Encore Energy Partners GP, LLC, the general partner of Encore Energy Partners LP ("ENP") and certain limited partnership interests in ENP (the “ENP Purchase”) together representing a 46.7% aggregate equity interest in ENP at the date of the ENP Purchase. On December 1, 2011, we acquired the remaining 53.4% of the limited partnership interests in ENP not held by us through a merger (the “ENP Merger”) with one of our wholly-owned subsidiaries. We refer to the ENP Purchase and ENP Merger collectively as the “ENP Acquisition.” 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,
	2015			2014		2013		2012		2011
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	—		$	—	$	11,818	$	11,563	$	2,851
Short-term derivative assets	236,886			142,114		21,314		46,690		2,333
Other current assets	121,636			144,119		73,025		55,738		51,508
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment	1,721,976			2,975,806		1,810,517		1,576,236		1,217,985
Long-term derivative assets	80,161			83,583		60,474		53,240		1,105
Goodwill⁽¹⁾	506,046			420,955		420,955		420,955		420,955
Other assets	42,592			27,015		91,538		35,712		19,626
Total Assets	$	2,709,297		$	3,793,592	$	2,489,641	$	2,200,134	$	1,716,363
Short-term derivative liabilities	$	356		$	3,583	$	10,992	$	5,366	$	12,774
Other current liabilities	201,652			175,021		114,411		74,136		33,064
Long-term debt	2,291,636			1,932,816		1,007,879		1,247,631		771,000
Long-term derivative liabilities	—			1,380		4,085		11,996		20,553
Other long-term liabilities	303,088			146,676		83,939		63,541		35,051
Members’ equity (deficit)	(87,435		)	1,534,116		1,268,335		797,464		843,921
Total Liabilities and Members’ Equity	$	2,709,297		$	3,793,592	$	2,489,641	$	2,200,134	$	1,716,363


(1)	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 and the LRE Merger completed on October 5, 2015.

Summary Reserve and Operating Data

The following tables show estimated net proved reserves based on a reserve report prepared by us and audited by 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 “Item 1. Business—Oil, Natural Gas and NGLs Data—Production and Price History” included in this Annual Report in evaluating the material presented below.



	As of December 31, 2015
Reserve Data:
Estimated net proved reserves:
Crude oil (MMBbls)	64.1
Natural gas (Bcf)	1,554.2
NGLs (MMBbls)	58.4
Total (Bcfe)	2,288.9
Proved developed (Bcfe)	1,652.4
Proved undeveloped (Bcfe)	636.5
Proved developed reserves as % of total proved reserves	72		%
Standardized Measure (in millions) ⁽¹⁾⁽²⁾	$	1,722.5
Representative Oil and Natural Gas Prices ⁽³⁾:
Oil—WTI per Bbl	$	50.20
Natural gas—Henry Hub per MMBtu	$	2.62
NGLs—Volume-weighted average price per Bbl	$	16.14

(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 as defined below) 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 unweighted average of first-day-of-the-month commodity prices (the “12-month average price”) for January through December 2015, with these representative prices adjusted by field for quality, transportation fees and regional price differentials to arrive at the appropriate net price. NGLs prices were calculated using the differentials to the WTI price per Bbl of $50.20.



	Net Production⁽¹⁾			Average Realized Sales Prices ⁽²⁾						Production Cost ⁽³⁾
	Crude Oil Bbls/day	Natural Gas Mcf/day	NGLs Bbls/day	Crude Oil Per Bbl		Natural Gas Per Mcf		NGLs Per Bbl		Per Mcfe
Year Ended December 31, 2015
Pinedale (Green River Basin)	804	98,266	1,932	$	58.87	$	2.37	$	0.26	$	0.54
Mamm Creek (Piceance Basin)	649	58,764	3,701	$	49.30	$	1.96	$	12.18	$	0.43
All other fields	9,529	135,065	3,927	$	57.24	$	2.07	$	21.71	$	1.41
Total	10,982	292,095	9,560	$	56.89	$	3.13	$	13.68	$	0.96

Year Ended December 31, 2014
Pinedale (Green River Basin)	659	72,090	3,028	$	77.76	$	3.96	$	13.76	$	0.43
Mamm Creek (Piceance Basin)	288	32,455	1,424	$	72.85	$	3.33	$	25.71	$	0.71
All other fields	8,096	122,953	3,107	$	83.66	$	3.27	$	37.14	$	1.54
Total	9,043	227,498	7,559	$	82.88	$	3.50	$	25.62	$	1.11

Year Ended December 31, 2013
All fields	8,462	137,632	4,047	$	82.26	$	3.39	$	33.76	$	1.36


(1)	Average daily production for 2015, 2014 and 2013 calculated based on 365 days and includes production for all of our acquisitions from the closing dates of these acquisitions.

(2)

Average realized sales prices include the impact of hedges but exclude the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. The average realized prices also reflect deductions for gathering, transportation and processing fees. For details on average sales prices without giving effect to the impact of hedges please see “Item 7. Management’s Discussion and Analysis of Financial Condition-Year Ended December 31, 2015 compared to Year Ended December 31, 2014” and “Item 7. Management’s Discussion and Analysis of Financial Condition -Year Ended December 31, 2014 compared to Year Ended December 31, 2013.”


(3)	Production costs include such items as lease operating expenses and exclude production taxes (severance and ad valorem taxes).

Non-GAAP Financial Measure

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) attributable to Vanguard unitholders plus, for 2011, net income (loss) attributable to the non-controlling interest. The result is net income (loss) which includes the non-controlling interest for 2011. From this we add or subtract the following:


•	Net interest expense, including write-off of deferred financing fees;


•	Depreciation, depletion, amortization and accretion;


•	Impairment of oil and natural gas properties;


•	Goodwill impairment loss;


•	Net gains or losses on commodity derivative contracts;


•	Cash settlements on matured commodity derivative contracts;


•	Net gains or losses on interest rate derivative contracts;


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


•	Texas margin taxes;


•	Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers;


•	Transaction costs incurred on acquisitions and mergers;


•	Interest income;


•	For 2011, 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


•	For 2011, 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 monthly 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. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our Reserve-Based Credit Facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our Consolidated Statements of Cash Flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our Consolidated Statements of Cash Flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows which may increase or decrease the amount we have available to fund distributions.

As noted above, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way the initial acquisition or development costs of our oil and natural gas properties are presented in our Consolidated Statements of Cash Flows; the initial cash outflows are presented as cash used in investing activities, while the cash flows generated from these assets are included in operating cash flows. The consideration of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities for purposes of determining our Adjusted EBITDA differs from the presentation in our consolidated financial statements prepared in accordance with GAAP which (i) presents premiums paid for derivatives entered into as operating activities and (ii) the fair value of derivative contracts acquired as part of a business combination as investing activities.

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



	Year Ended December 31,
	2015			2014			2013			2012			2011^(d)
	(in thousands)
Net income (loss) attributable to Vanguard unitholders	$	(1,883,174	)	$	64,345		$	59,511		$	(168,815	)	$	62,063
Net income attributable to non-controlling interest	—			—			—			—			26,067
Net income (loss)	(1,883,174		)	64,345			59,511			(168,815		)	88,130
Plus:
Interest expense	87,573			69,765			61,148			41,891			28,994
Depreciation, depletion, amortization and accretion	247,119			226,937			167,535			104,542			84,857
Impairment of oil and natural gas properties	1,842,317			234,434			—			247,722			—
Goodwill impairment loss	71,425			—			—			—			—
Net gains on commodity derivative contracts	(169,416		)	(163,452		)	(11,256		)	(36,846		)	(6,735		)
Net cash settlements received on matured commodity derivative contracts ^(a)(b)	211,723			10,187			30,905			39,102			18,720
Net (gains) losses on interest rate derivative contracts ^(c)	(153		)	1,933			96			6,992			4,962
Net (gain) loss on acquisitions of oil and natural gas properties	(40,533		)	(34,523		)	(5,591		)	(11,111		)	367
Texas margin taxes	(266		)	(630		)	601			239			261
Compensation related items	18,522			11,710			5,931			6,796			3,026
Transaction costs incurred on acquisitions and mergers	11,692			739			865			—			2,019
Adjusted EBITDA before non-controlling interest	$	396,829		$	421,445		$	309,745		$	230,512		$	224,601
Non-controlling interest attributable to adjustments above	—			—			—			—			(62,838		)
Administrative services fees eliminated in consolidation	—			—			—			—			2,840
Adjusted EBITDA available to Vanguard unitholders	$	396,829		$	421,445		$	309,745		$	230,512		$	164,603

(a) Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties.	$	5,434		$	—		$	220		$	11,641		$	11,346
(b) Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties.	$	44,761		$	21,306		$	30,200		$	26,505		$	169
(c) Includes settlements paid on interest rate derivatives	$	5,227		$	4,035		$	3,888		$	2,515		$	2,874
(d) Results of operations from 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.

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 monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. After the LRE and Eagle Rock Mergers in October 2015, through our operating subsidiaries, as of December 31, 2015, we own properties and oil and natural gas reserves primarily located in ten operating basins:


•	the Green River Basin in Wyoming;


•	the Permian Basin in West Texas and New Mexico;


•	the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Piceance Basin in Colorado;


•	the Big Horn Basin in Wyoming and Montana;


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

At December 31, 2015, we owned working interests in 14,459 gross (5,285 net) productive wells. In addition to these productive wells, we own leasehold acreage allowing us to drill new wells. We own working interests in approximately 881,508 gross undeveloped acres surrounding our existing wells. Approximately 636.5 Bcfe, or 28%, of our estimated proved reserves were attributable to our working interests in undeveloped leasehold acreage.

Recent Developments and Outlook

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitcal and economic conditions. During 2014, 2015 and the beginning of 2016, for example, oil, natural gas and NGLs prices decreased dramatically. The crude oil spot price per barrel during the years ended December 31, 2014 and 2015 ranged from a high of $107.95 to a low of $34.55 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $6.15 to a low of $1.76. NGLs prices also suffered a similar decline. As of February 29, 2016, the crude oil spot price per barrel was $32.74 and the NYMEX natural gas spot price per MMBtu was $1.62. Among the factors causing such volatility are the domestic and foreign supply of oil and natural gas, the inability of the members of OPEC and other producing countries to agree upon and maintain prices and production levels, social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States and the level and growth of consumer product demand.

The dramatic decline in commodity prices has had a negative impact on the price of our common and preferred units. During 2015, our common unit price declined from a high of $18.72 on February 9, 2015 to a low of $2.46 on December 14, 2015. This low commodity price environment has had and will continue to have a direct impact on our revenue, cash flow from operations and Adjusted EBITDA until commodity prices improve. Sustained low prices or any further declines in prices of oil, natural gas and NGLs could have a material adverse impact on our financial condition, profitability, future growth, borrowing base and the carrying value of our oil and natural gas properties. Additionally, sustained low prices or any further decline in prices of oil, natural gas and NGLs could reduce the amount of oil, natural gas and NGLs that we can produce economically, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil and natural gas properties. To illustrate the impact of a sustained low commodity price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2015 would decrease from 2,288.9 Bcfe to 2,061.3 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices were $2.57 per MMBtu (or a $0.05 price decrease from the 12-month average price of $2.62) and oil prices were $44.28 per barrel (or a $5.92 price decline from the 12-month average price of $50.20), while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of December 31, 2015 would increase from 2,288.9 Bcfe to 2,324.1 Bcfe. The preceding assumed prices in example (2) were derived from the 5-year New York Mercantile Exchange (NYMEX) forward strip price at February 29, 2016. Our management believes that the use of this 5-year NYMEX forward strip price may help provide investors with an understanding of the impact of a sustained low commodity price environment to our proved reserves through a reasonable downsize case assumption. However, the use of this 5-year NYMEX forward strip price is not necessarily indicative of management’s overall outlook on future commodity prices.



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2015	$	132,610	$3.91	$82.62
Second quarter 2015	$	733,365	$3.44	$71.51
Third quarter 2015	$	491,487	$3.11	$59.23
Fourth quarter 2015	$	484,855	$2.62	$50.20
Total	1,842,317

We recognized a goodwill impairment loss of $71.4 million as of December 31, 2015 as a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions. Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could require us to record additional impairment charges during future periods. Although these goodwill impairment charges are of a non-cash nature, they do adversely affect our results of operations in the periods which such charges are recorded.

In an effort to mitigate the impact of the challenging commodity price environment, we have taken the steps described below to provide significant incremental cash flow, allow us to meaningfully reduce our leverage over the course of 2016 and provide sufficient liquidity to manage the expected reductions to the borrowing base in our Reserve-Based Credit Facility.

We have implemented a hedging program for approximately 67% and 21% of our anticipated crude oil production in 2016 and 2017, respectively, with 57% in the form of fixed-price swaps in 2016. Approximately 78% and 49% of our natural gas production in 2016 and 2017, respectively, is hedged with 85% in the form of fixed-price swaps in 2016. NGLs production is under fixed-price swaps for approximately 22% of anticipated production in 2016. These hedges will provide some cash flow certainty regardless of the volatility in commodity prices. In the current commodity price environment, however, we are less likely to hedge future revenues to the same extent as our historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced. In addition, the volumes hedged and hedge prices are lower than those related to the hedges that settled in 2015. Therefore, the benefit to our future operating results is expected to be lower.

We have significantly reduced our capital expenditures budget for 2016. We currently anticipate a capital expenditures budget for 2016 of approximately $63.0 million, which is 44% less than the $112.6 million we spent in 2015. We expect to spend approximately 40% of the 2016 capital expenditures budget in the Green River Basin where we will participate as a non-operating partner in the drilling and completion of directional natural gas wells in the Pinedale Field. Additionally, we expect to spend approximately 21% of the 2016 capital expenditures budget in the Anadarko Basin on the newly acquired SCOOP and STACK assets, participating as a non-operated partner drilling standard length and extended length liquid rich horizontal gas and oil wells targeting the Woodford Shale and various stacked pay Mississippian reservoirs. The balance of the 2016 capital expenditures budget is related to recompletion and maintenance activities in our other operating areas. Due to our plans to reduce capital spending in 2016, we anticipate our annual production will be 10% to 15% lower than our fourth quarter 2015 average daily production of 511,119 Mcfe per day.

In December 2015, we reduced our cash distribution per common unit to $0.03 for the month of November 2015, or $0.36 per unit on an annualized basis. This amount represents an approximate 75% reduction from the payment for the month of October 2015, which was $0.1175 per common unit or $1.41per unit on an annualized basis. This takes into consideration current commodity and financial market conditions and the excess cash flow generated by this action will be used to pay down debt under the Reserve-Based Credit Facility. On February 25, 2016, our board of directors elected to suspend our monthly cash distribution on our common, Class B and preferred units effective with the February 2016 distribution.

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued pursuant to an exchange offer. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we have repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023. This reduction in outstanding Senior Notes due 2020 reduced our interest expense by $7.9 million on an annual basis. Under our credit agreement, the issuance of new second lien debt requires, among other things, that our borrowing base decrease by 25% of the amount of new second lien debt. Because of this, the $1.8 billion borrowing base decreased by $18.9 million to $1.78 billion.

At March 3, 2016, we had indebtedness under our Reserve-Based Credit Facility totaling $1.68 billion with a borrowing base of $1.78 billion which provided for $96.6 million in undrawn capacity, after consideration of a $4.5 million reduction in availability for letters of credit. This does not take into consideration available cash of $10.0 million. 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 our lender’s petroleum engineers utilizing the lender’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 2016. Based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next scheduled redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant. As such, we

initiated a process to sell the SCOOP/STACK assets acquired in the Eagle Rock Merger. We anticipate that this divestiture would be consummated at the same time as the April 2016 redetermination and will allow us to reduce borrowings under the Reserve-Based Credit Facility in an amount sufficient to mitigate the reduction in the borrowing base for the April 2016 redetermination. Based on our internal forecasts, we will continue to experience low liquidity but expect to be at a liquidity level sufficient to run our business for the foreseeable future. However, there can be no assurances that our banks will not redetermine our borrowing base at a level below our outstanding borrowings in our April 2016 redetermination or any subsequent redetermination. Should a borrowing base deficiency occur, our Reserve-Based Credit Facility requires us to repay the deficiency in equal monthly installments over a six month period. Our internal forecasts show that we will generate a substantial amount of excess cash flow over the course of 2016 which will be used to reduce borrowings under our Reserve-Based Credit Facility and we expect would be sufficient to repay a deficiency should one exist in April 2016.

Results of Operations

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



	Year Ended December 31, ⁽¹⁾
	2015			2014			2013
	(in thousands)
Revenues:
Oil sales	$	164,111		$	268,685		$	268,922
Natural gas sales	193,496			285,439			124,513
NGLs sales	39,620			70,489			49,813
Oil, natural gas and NGLs sales	397,227			624,613			443,248
Net gains on commodity derivative contracts	169,416			163,452			11,256
Total revenues	$	566,643		$	788,065		$	454,504
Costs and expenses:
Lease operating expenses	146,654			132,515			105,502
Production and other taxes	40,576			61,874			40,430
Depreciation, depletion, amortization and accretion	247,119			226,937			167,535
Impairment of oil and natural gas properties	1,842,317			234,434			—
Goodwill impairment loss	71,425			—			—
Selling, general and administrative expenses (excluding non-cash compensation)	36,554			19,129			20,011
Non-cash compensation	18,522			11,710			5,931
Total costs and expenses	$	2,403,167		$	686,599		$	339,409
Other income and expenses:
Interest expense	$	(87,573	)	$	(69,765	)	$	(61,148	)
Net gains (losses) on interest rate derivative contracts	$	153		$	(1,933	)	$	(96	)
Net gain on acquisitions of oil and natural gas properties	$	40,533		$	34,523		$	5,591
Other	$	237		$	54		$	69


(1)	From 2013 through 2015, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Revenues

Oil, natural gas and NGLs sales decreased by $227.4 million, or 36%, to $397.2 million during the year ended December 31, 2015 as compared to the same period in 2014. The key revenue measurements were as follows:



	Year Ended December 31,⁽¹⁾				Percentage Increase (Decrease)
	2015		2014		Percentage Increase (Decrease)
Average realized prices, excluding hedging:
Oil (Price/Bbl)	$	40.94	$	81.40	(50	)%
Natural Gas (Price/Mcf)	$	1.81	$	3.44	(47	)%
NGLs (Price/Bbl)	$	11.35	$	25.55	(56	)%

Average realized prices, including hedging ⁽²⁾:
Oil (Price/Bbl)	$	56.89	$	82.88	(31	)%
Natural Gas (Price/Mcf)	$	3.13	$	3.50	(11	)%
NGLs (Price/Bbl)	$	13.68	$	25.62	(47	)%

Average NYMEX prices:
Oil (Price/Bbl)	$	47.79	$	92.21	(48	)%
Natural Gas (Price/Mcf)	$	2.64	$	4.39	(40	)%

Total production volumes:
Oil (MBbls)	4,008		3,301		21	%
Natural Gas (MMcf)	106,615		83,037		28	%
NGLs (MBbls)	3,489		2,759		26	%
Combined (MMcfe)	151,600		119,395		27	%

Average daily production volumes:
Oil (Bbls/day)	10,982		9,043		21	%
Natural Gas (Mcf/day)	292,095		227,498		28	%
NGLs (Bbls/day)	9,560		7,559		26	%
Combined (Mcfe/day)	415,343		327,109		27	%


(1)	During 2015 and 2014, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward.


(2)	Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

The decrease in oil, natural gas and NGLs sales during the year ended December 31, 2015 compared to the same period in 2014 was primarily due to the decrease in the average realized oil, natural gas and NGLs prices.

Oil revenues decreased by 39% from $268.7 million during the year ended December 31, 2014 to $164.1 million during the same period in 2015 as a result of a $40.46 per Bbl, or 50%, decrease in our average realized oil sales price received, excluding hedges. The decrease in average realized oil price is primarily due to a lower average NYMEX price, which decreased from $92.21 per Bbl during the year ended December 31, 2014 to $47.79 per Bbl during the same period in 2015. The impact of the decrease in average realized price was partially offset by a 707 MBbls increase in oil production volumes in 2015 compared to the prior year principally due to the positive impact of our acquisitions and the LRE and Eagle Rock Mergers.

Natural gas revenues decreased by 32% from $285.4 million during the year ended December 31, 2014 to $193.5 million during the same period in 2015 primarily as a result of a $1.63 per Mcf, or 47%, decrease in our average realized natural gas sales price received, excluding hedges. The decrease in average realized natural gas price is primarily due to a lower average NYMEX price, which decreased from $4.39 per Mcf during the year ended December 31, 2014 to $2.64 per Mcf during the same period in 2015. The impact of the decrease in average realized price was partially offset by a 23,578 MMcf increase in our natural gas production volumes attributable to the impact from our acquisitions in the Piceance and Gulf Coast Basins completed during the third quarter of 2014 wherein we realized the benefit of a full year of production in 2015 and the LRE and Eagle Rock Mergers during the fourth quarter of 2015.

NGLs revenues also decreased by 44% in 2015 compared to the same period in 2014 primarily due to a $14.20 per Bbl, or 56%, decrease in our average realized NGLs sale price received, excluding hedges, offset by a 730 MBbls increase in NGLs production volumes due to the positive impact of our acquisitions and the LRE and Eagle Rock Mergers.

Overall, our total production increased by 27% on a Mcfe basis for the year ended December 31, 2015 over the comparable period in 2014. This increase was primarily attributable to the impact from our acquisitions completed at the end of the third quarter in 2014 wherein we realized the benefit of a full year of production in 2015 as well as from our LRE and Eagle Rock Mergers whereby we experienced the benefit of their operations in the fourth quarter of 2015. On a Mcfe basis, crude oil, natural gas and NGLs accounted for 16%, 70% and 14%, respectively, of our production during the years ended December 31, 2015 and 2014.

Hedging and Price Risk Management Activities

During the year ended December 31, 2015, we recognized a $169.4 million net gain on commodity derivative contracts. Net cash settlements on matured commodity derivative contracts of $211.7 million were received during the period. Our hedging program is intended to help 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 our hedges are currently 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 in our consolidated statement of operations in the net gains or losses on commodity derivative contracts line item. However, these fair value changes that are reflected in the consolidated statement of operations 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. For additional information on our price risk management activities, please read “Item 1A. Risk Factors-Our price risk management activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to resume distributions to our unitholders.”

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by $14.1 million to $146.7 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014, of which $30.9 million was related to increased lease operating expenses for oil and natural gas properties acquired in 2015 and 2014. The increase was offset by a $16.8 million decrease in maintenance and repair expenses on existing wells and lower operating expenses as a result of cost reduction initiatives, including price negotiations with field vendors.

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 and county and are based on the value of our reserves. Production and other taxes decreased by $21.3 million to $40.6 million for the year ended December 31, 2015 primarily due to lower wellhead revenues as a result of the decrease in our average realized sales prices received for oil, natural gas and NGLs. As a percentage of wellhead revenues, production, severance, and ad valorem taxes increased from 9.9% during the year ended December 31, 2014 to 10.2% for the year ended December 31, 2015 primarily due to higher tax rates on properties acquired during 2014 in the states of Wyoming, Colorado, Louisiana and Texas.

Depreciation, depletion, amortization and accretion increased to approximately $247.1 million for the year ended December 31, 2015 from approximately $226.9 million for the year ended December 31, 2014 primarily due to a higher depletion base associated with properties acquired during 2014 and 2015.

An impairment of oil and natural gas properties of $1.8 billion was recognized during the year ended December 31, 2015 as a result of a decline in realized oil and natural gas prices at the respective measurement dates of March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. Such impairment was recognized during each quarter of 2015 and calculated using the prices indicated above in “Recent Developments and Outlook.” The most significant factors causing us to record an impairment of oil and natural gas properties in the year ended December 31, 2015 were declining oil and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired (determined using forward oil and natural gas price curves on the acquisitions dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices on the impairment test measurement dates. However, the impairment calculations did not consider the positive impact of our commodity derivative positions because generally accepted accounting principles only allow the inclusion of derivatives designated as cash flow hedges.

We recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties include: (i) observable forward prices for commodities at December 31, 2015 and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

Selling, general and administrative expenses include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses for the year ended December 31, 2015 increased by $17.4 million as compared to the year ended December 31, 2014 primarily resulting from the recognition of severance costs paid to former Eagle Rock executives and employees who were terminated subsequent to the Eagle Rock Merger amounting to $11.3 million, an increase of about $3.6 million resulting from the hiring of additional employees and higher office expenses related to our acquisitions and the change in the accrual of employee bonuses for the 2015 performance year discussed below of about $2.5 million. Non-cash compensation expense for the year ended December 31, 2015 increased $6.8 million to $18.5 million as compared to the year ended December 31, 2014, primarily related to the costs related to the accelerated vesting of LTIP grants issued to former Eagle Rock executives and employees that are attributable to post merger services amounting to $7.3 million. In addition, our board of directors approved the option for Vanguard’s management team to receive Vanguard common units in lieu of their 2015 cash compensation. Messrs. Smith and Robert and our three independent directors, Loren B. Singletary, W. Richard Anderson and Bruce W. McCullough elected this option and under the plan received quarterly grants of Vanguard common units instead of their 2015 cash compensation. This increase in non-cash compensation was offset by the fact that a large portion of the 2015 employee bonuses that will be paid in cash rather than in Vanguard common units amounted to approximately $2.5 million compared to 2014.

Other Income and Expense

Interest expense increased to $87.6 million for the year ended December 31, 2015 as compared to $69.8 million for the year ended December 31, 2014 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility in 2015 compared to the same period in 2014.

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 acquisitions completed during 2015 compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $40.8 million and goodwill of $156.8 million, of which $0.3 million was immediately impaired and recorded as a loss, resulting in a net gain of $40.5 million for the year ended December 31, 2015. The comparable measurement for the acquisitions completed during 2014 resulted in a gain of $34.9 million and goodwill of $0.4 million, which was immediately impaired and recorded as a loss, resulting in a net gain of $34.5 million for the year ended December 31, 2014. The net gains and losses resulted from the increases and decreases in oil and natural gas prices used to value the reserves between the commitment and close dates and have been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Revenues

Oil, natural gas and NGLs sales increased by $181.4 million, or 41%, to $624.6 million during the year ended December 31, 2014 as compared to the same period in 2013. The key revenue measurements were as follows:



	Year Ended December 31,⁽¹⁾				Percentage Increase (Decrease)
	2014		2013⁽²⁾		Percentage Increase (Decrease)
Average realized prices, excluding hedging:
Oil (Price/Bbl)	$	81.40	$	87.06	(7	)%
Natural Gas (Price/Mcf)	$	3.44	$	2.48	39	%
NGLs (Price/Bbl)	$	25.55	$	33.72	(24	)%

Average realized prices, including hedging ⁽³⁾:
Oil (Price/Bbl)	$	82.88	$	82.26	1	%
Natural Gas (Price/Mcf)	$	3.50	$	3.39	3	%
NGLs (Price/Bbl)	$	25.62	$	33.76	(24	)%

Average NYMEX prices:
Oil (Price/Bbl)	$	92.21	$	98.04	(6	)%
Natural Gas (Price/Mcf)	$	4.39	$	3.66	20	%

Total production volumes:
Oil (MBbls)	3,301		3,089		7	%
Natural Gas (MMcf)	83,037		50,236		65	%
NGLs (MBbls)	2,759		1,477		87	%
Combined (MMcfe)	119,395		77,630		54	%

Average daily production volumes:
Oil (Bbls/day)	9,043		8,462		7	%
Natural Gas (Mcf/day)	227,498		137,632		65	%
NGLs (Bbls/day)	7,559		4,047		87	%
Combined (Mcfe/day)	327,109		212,686		54	%


(1)	During 2014 and 2013, we acquired certain oil and natural gas properties and related assets, as well as additional interests in these properties. The operating results of these properties are included with ours from the date of acquisition forward.


(2)	Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

The increase in oil, natural gas and NGLs sales during the year ended December 31, 2014 compared to the same period in 2013 was primarily due to the increase in production from our acquisitions that were completed during 2014.

Natural gas revenues increased from $124.5 million during the year ended December 31, 2013 to $285.4 million during the same period in 2014 primarily as a result of a 32,801 MMcf increase in our natural gas production volumes. In addition, we also had a 39% increase in our average realized natural gas sales price received, excluding hedges, due to a higher average NYMEX price, which increased from $3.66 per Mcf during the year ended December 31, 2013 to $4.39 per Mcf during the same period in 2014.

Oil revenues decreased by $0.2 million from $268.9 million during the year ended December 31, 2013 to $268.7 million during the same period in 2014 primarily due to a $5.66 decrease in our average realized oil price, excluding hedges, mainly resulting from the decrease in average NYMEX price from $98.04 per Bbl during the year ended December 31, 2013 to $92.21 during the same period in 2014. The impact of the decrease in average realized price was slightly offset by a 212 MBbls increase in oil production volumes in 2014 compared to the prior year.

NGLs revenues also increased by 42% in 2014 compared to the same period in 2013 primarily due to a 1,282 MBbls increase in NGLs production volumes, offset by an $8.17 per Bbl, or 24%, decrease in our average realized NGLs price, excluding hedges.

Overall, our total production increased by 54% on a Mcfe basis for the year ended December 31, 2014 over the comparable period in 2013, which was primarily attributable to the impact from all of our acquisitions completed in 2013 wherein we realized the benefit of a full year of production in 2014 as well as from our 2014 acquisitions. On a Mcfe basis, crude oil, natural gas and NGLs accounted for 16%, 70% and 14%, respectively, of our production during the year ended December 31, 2014 compared to crude oil, natural gas and NGLs of 24%, 65% and 11%, respectively, during the same period in 2013.

Hedging and Price Risk Management Activities

During the year ended December 31, 2014, we recognized a $163.5 million net gain on commodity derivative contracts. Net cash settlements on matured commodity derivative contracts of $10.2 million were received during the period. Our hedging program is intended to help 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 our hedges are currently 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 in our consolidated statement of operations in the net gains or losses on commodity derivative contracts line item. However, these fair value changes that are reflected in the consolidated statement of operations 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. For additional information on our price risk management activities, please read “Item 1A. Risk Factors-Our price risk management activities could result in financial losses or could reduce our cash flow, which may adversely affect our ability to resume distributions to our unitholders.”

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by $27.0 million to $132.5 million for the year ended December 31, 2014 as compared to the year ended December 31, 2013, of which $31.1 million was related to increased lease operating expenses for oil and natural gas properties acquired in 2014 and 2013. The increase was partially offset by a $4.1 million decrease in maintenance and repair expenses on existing wells.

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 and county and are based on the value of our reserves. Production and other taxes increased by $21.4 million to $61.9 million for the year ended December 31, 2014 primarily due to higher wellhead revenues as a result of the acquisitions completed in 2014. As a percentage of wellhead revenues, production, severance, and ad valorem taxes increased from 9.1% during the year ended December 31, 2013 to 9.9% for the year ended December 31, 2014 primarily due to higher tax rates on properties acquired during 2014 in the state of Wyoming and a lower tax rate in 2013 primarily due to an accrued refund from the state of Texas for overpaid severance taxes on oil and natural gas properties in Texas pertaining to marketing cost reductions and tax reimbursements.

Depreciation, depletion, amortization and accretion increased to approximately $226.9 million for the year ended December 31, 2014 from approximately $167.5 million for the year ended December 31, 2013 primarily due to a higher depletion base associated with properties acquired during 2013 and 2014.

An impairment of oil and natural gas properties of $234.4 million was recognized during the year ended December 31, 2014 as a result of a decline in realized oil and natural gas prices at the measurement date, December 31, 2014. Such impairment was

recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the fair value of the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisitions dates) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations 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. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil.

Other Income and Expense

Interest expense increased to $69.8 million for the year ended December 31, 2014 as compared to $61.1 million for the year ended December 31, 2013 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility in 2014 compared to the same period in 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 acquisitions completed during 2014 compared to the fair value of consideration transferred, adjusted for purchase price adjustments, resulted in a gain of $34.9 million and in goodwill of $0.4 million, which was immediately impaired and recorded as a loss, resulting in a net gain of $34.5 million for the year ended December 31, 2014. The comparable measurement for the acquisitions completed during 2013 resulted in a gain of $7.3 million and in goodwill of $1.7 million, which was immediately impaired and recorded as a loss, resulting in a net gain of $5.6 million for the year ended December 31, 2013. The net gains and losses resulted from the increases and decreases in oil and natural gas prices used to value the reserves between the commitment and close dates and have been recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations.

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, 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, 2015 and 2014, 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 prices based upon the 12-month average prices, 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 (the “ceiling test”). Our hedges are not considered cash flow hedges for accounting purposes, and thus the value of our hedges are not considered in our ceiling test calculations. In addition, we do not include proved undeveloped reserves that were dropped from our drilling program in our ceiling test calculations. 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.



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2015	$	132,610	$3.91	$82.62
Second quarter 2015	$	733,365	$3.44	$71.51
Third quarter 2015	$	491,487	$3.11	$59.23
Fourth quarter 2015	$	484,855	$2.62	$50.20
Total	$	1,842,317

We also recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date of December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the fair value of the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisition date) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations 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. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. No ceiling test impairment was required during 2013.

In accordance with the guidance contained within ASC Topic 805, upon the acquisition of oil and natural gas properties, the company records an asset based on the measurement of the fair value of the properties acquired determined using forward oil and natural gas price curves at the acquisitions dates, which can have several price increases over the entire reserve life. As discussed above, capitalized oil and natural gas property costs are limited to a ceiling based on the present value of future net revenues, computed using a flat price for the entire reserve life equal to the historical 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. As a result, there is a risk that we will be required to record an impairment of our oil and natural gas properties if certain attributes exist, such as declining oil and natural gas prices. We expect to record an additional impairment of our oil and natural gas properties during 2016 as a result of declining oil and natural gas prices. Based on the 11-month average oil, natural gas and NGLs prices through February 1, 2016 and if such prices do not change during March 2016, we estimate that, on a pro forma basis, we will record a ceiling test write down on our existing assets of approximately $221.3 million at March 31, 2016 and an additional write down of $458.9 million for the remainder of the year ending December 31, 2016. If oil, natural gas and NGLs prices were to decline an additional 10% from their 11-month average through February 1, 2016, we estimate that, on a pro forma basis, we would record additional ceiling test write downs on our existing assets of approximately $504.0 million at March 31, 2016 and an additional write down of $388.2 million for the remainder of the year ending December 31, 2016. However, whether the amount of any such impairments will be similar in amount to such estimates, is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2016, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and natural gas property acquisitions, which could increase, decrease or eliminate the need for such impairments.

Business Combinations

We account for business combinations under ASC Topic 805. 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 account for goodwill and other intangible assets under the provisions of the Accounting Standards Codification (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 using a two-step process.

The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. The first step involves a comparison of the estimated fair value of a reporting unit to its net book value, which is its carrying amount, including goodwill. In performing the first step, we determine the fair value of the reporting unit using the market approach based on our quoted common unit price. Quoted prices in active markets are the best evidence of fair value. However, because value results from the ability to take advantage of synergies and other benefits that exist from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market price to determine the total fair value of our reporting unit, derived from marketplace data of actual control premiums in the oil and natural gas extraction industry. The sum of our market capitalization and control premium is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary.

If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. In addition, if the carrying amount of a reporting unit is zero or negative, the second step of the impairment test shall be performed to measure the amount of impairment loss, if any, when it is more likely than not that a goodwill impairment exists. In considering whether it is more likely than not that a goodwill impairment exists, an entity shall evaluate any adverse qualitative factors. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.

Determining fair value requires the exercise of significant judgment, including judgments about market prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets and liabilities, such as a business. As described above, the key inputs used in estimating the fair value of our reporting unit are our common unit price, number of common units outstanding and a control premium. There is no uncertainty associated with our common unit price and number of common units outstanding. The control premium is based on market data of actual control premiums in our industry. Changes in the common unit price, which could result from further significant declines in the prices of oil and natural gas or significant negative reserve adjustments, or changes in market data as it relates to control premiums in the oil and gas extraction industry could change our estimate of the fair value of the reporting unit and could result in a non-cash impairment charge.

We performed our annual impairment tests during 2015, 2014 and 2013 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed interim impairment tests at December 31, 2015 and 2014.

As of December 31, 2015, the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties include: (i) observable forward prices for commodities at December 31, 2015 and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

Based on our estimates, the fair value of our reporting unit exceeded its carrying value by 8% at December 31, 2014 and therefore the second step of the impairment test was not necessary. We believe this difference between the fair value and the net book value is appropriate (in the context of assessing whether a goodwill impairment may exist) when a market-based control premium is taken into account and in light of the recent volatility in the equity markets.

Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could require us to record additional impairment charges during future periods. Although these goodwill impairment charges are of a non-cash nature, they do adversely affect our results of operations in the periods which such charges are recorded.

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, Big Escambia Creek and Fairway gas plants. 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

Our reservoir engineers estimate proved oil and gas reserves accordance with SEC regulations, which directly impact financial accounting estimates, including depreciation, depletion, amortization and accretion. 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 reservoir 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 and depletion rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

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, 2015 or 2014.

Price Risk Management Activities

We 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, we primarily use fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices.

Under ASC Topic 815 “Derivatives and Hedging” (“ASC Topic 815”), the fair value of hedge contracts is recognized in the Consolidated Balance Sheets as an asset or liability, and since we do not apply hedge accounting, 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 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 estimated 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.

Recently Issued Accounting Pronouncements

Please read Note 1 of the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for a detailed list of recently issued accounting pronouncements.

Capital Resources and Liquidity

Overview

Historically, we have obtained financing through proceeds from bank borrowings, cash flow from operations and from the public equity and debt markets to provide us with the capital resources and liquidity necessary to operate our business. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties. 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 and maintenance capital expenditures with cash flow from operations. However, based on current market conditions, we expect it will be difficult to fund any acquisition capital expenditures through traditional public equity and debt markets as we have in the past. Until our access to debt and equity financing through the capital markets improves, our principal focus will be on generating excess cash flow from operations and asset sales which will be used to reduce borrowings under our Reserve-Based Credit Facility.

As of March 3, 2016, we have $96.6 million available to be borrowed under our Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit. 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 $1.78 billion. Our next borrowing base redetermination is scheduled for April 2016 and based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant. As such, we initiated a process to sell the SCOOP/STACK assets acquired in the Eagle Rock Merger. We anticipate that this divestiture would be consummated at the same time as the April 2016 redetermination and will allow us to reduce borrowings under the Reserve-Based Credit Facility in an amount sufficient to mitigate the reduction in the borrowing base for the April 2016 redetermination. Based on our internal forecasts, we will continue to experience low liquidity but expect to be at a liquidity level sufficient to run our business for the foreseeable future. However, there can be no assurances that our banks will not redetermine our borrowing base at a level below our outstanding borrowings in our April 2016 redetermination or any subsequent redetermination. Should a borrowing base deficiency occur, our Reserve-Based Credit Facility requires us to repay the deficiency in equal monthly installments over a six month period. Our internal forecasts show that we will generate a substantial amount of excess cash flow over the course of 2016 which will be used to reduce borrowings under our Reserve-Based Credit Facility and we expect would be sufficient to repay a deficiency should one exist in April 2016.

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.


•	refinancing or restructuring our debt;


•	selling assets;


•	reducing or delaying acquisitions or our drilling program; or


•	seeking to raise additional capital.

outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.

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



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Net cash provided by operating activities	$	370.1		$	339.8		$	261.0
Net cash used in investing activities	$	(128.1	)	$	(1,446.2	)	$	(398.0	)
Net cash provided by (used in) financing activities	$	(241.9	)	$	1,094.6		$	137.3

Cash Flow from Operations

Net cash provided by operating activities was $370.1 million during the year ended December 31, 2015, compared to $339.8 million during the year ended December 31, 2014, and compared to $261.0 million during the year ended December 31, 2013.

During the year ended December 31, 2015, changes in working capital increased total cash flows by $18.9 million. Contributing to the increase in working capital during 2015 was a $53.4 million decrease in accounts receivable related to the timing of receipts from production. was offset by a $43.9 million decrease in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments.

During the year ended December 31, 2014, changes in working capital decreased cash flows by $10.6 million. Contributing to the decrease in working capital during 2014 was a $69.9 million increase in accounts receivable related to the timing of receipts from production from the acquisitions, offset by a $51.5 million increase in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments.

During the year ended December 31, 2013, changes in working capital resulted in a $13.8 million increase in cash flows from operating activities due to a $35.3 million increase in accounts payable and oil and natural gas revenue payable, accrued expenses and other current liabilities that resulted primarily from the timing effects of invoice payments, offset by a $22.1 million increase in accounts receivable related to the timing of receipts from production from the acquisitions.

The change in the fair value of our derivative contracts are non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the years ended December 31, 2015, 2014 and 2013.

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 primarily use fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. However, unlike natural gas, we are unable to hedge oil price differentials in certain operating areas which could significantly impact our cash flow from operations. 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 2017 for oil and natural gas production and through 2016 for NGLs production.

Investing Activities

Cash used in investing activities was approximately $128.1 million for the year ended December 31, 2015, compared to $1.4 billion during 2014, and compared to $398.0 million during 2013.

Cash used in investing activities during the year ended December 31, 2015 included $112.6 million for the drilling and development of oil and natural gas properties, $13.0 million for the acquisition of oil and natural gas properties, $22.2 million for deposits and prepayments related to the drilling and development of oil and natural gas properties and $0.6 million in payments for property and equipment. Also during the year, we received $18.5 million in cash when we closed the LRE and Eagle Rock Mergers and $1.8 million in proceeds from the divestiture of certain oil and natural gas properties and leases.

During the year ended December 31, 2014, we used cash of $1.3 billion for the acquisition of oil and natural gas properties, $142.0 million for the drilling and development of oil and natural gas properties, $5.2 million for deposits and prepayments related to the drilling and development of oil and natural gas properties and $1.4 million for property and equipment additions. Also during the year, we received $5.0 million in proceeds from the divestiture of certain oil and natural gas properties and leases.

During the year ended December 31, 2013, we used cash of $272.1 million for the acquisition of oil and natural gas properties, $56.7 million for the drilling and development of oil and natural gas properties, and $67.3 million for deposits and prepayments related to the drilling and development of oil and natural gas properties and $2.0 million for property and equipment additions.

Excluding any potential acquisitions, we currently anticipate a capital expenditures budget for 2016 of approximately $63.0 million. Our expected capital spending will largely include drilling and completion in the Green River Basin participating as a non-operating partner in the development drilling of directional natural gas wells in the Pinedale Field. We anticipate that our cash flow from operations and expected dispositions of oil and natural gas properties and available borrowing capacity under our Reserve-Based Credit Facility will exceed our planned capital expenditures and other cash requirements for the year ended December 31, 2016. However, future cash flows are subject to a number of variables, including the level of oil and 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 used in financing activities was approximately $241.9 million for year ended December 31, 2015, compared to cash provided of $1.1 billion for the year ended December 31, 2014 and compared to cash provided of $137.3 million for the year ended December 31, 2013.

Cash used in financing activities during the year ended December 31, 2015 included cash of $508.6 million that was used in the repayments of our Reserve-Based Credit Facility, $2.4 million was used for the repurchase of common units under the buyback program and $12.1 million was paid for financing and offering costs. We also paid distributions of $147.6 million to our common and Class B unitholders and $26.8 million to our preferred unitholders. Additionally, we received net proceeds from borrowings of long-term debt of $420.0 million and net proceeds from our common unit offerings of $35.5 million.

Cash provided by financing activities during the year ended December 31, 2014 included net proceeds from borrowings of long-term debt of $1.4 billion, net proceeds from our preferred unit offerings of $274.4 million and net proceeds from our common unit offerings of $147.8 million. Additionally, cash of $488.0 million was used in the repayments of our Reserve-Based Credit Facility, $2.5 million was used for the repurchase of common units under the buyback program and $1.2 million was paid for financing costs. We also paid $206.6 million in distributions to our common and Class B unitholders and $17.3 million in distributions to our preferred unitholders.

Cash provided by financing activities during the year ended December 31, 2013 included $589.5 million net proceeds from borrowings of long-term debt, $61.0 million net proceeds from our preferred unit offerings and $498.4 million net proceeds from our common unit offerings. Additionally, cash of $829.5 million was used in the repayments of our Reserve-Based Credit Facility and $2.1 million was paid for financing costs. We also paid $177.6 million in distributions to our common and Class B unitholders and $2.4 million in distributions to our preferred unitholders.

Shelf Registration Statements and Related Offerings

Under our currently effective shelf registration statement, as amended (File No. 333-202064), filed with the SEC (the “Shelf Registration Statement”), we have registered an indeterminate amount of Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, common units, debt securities and guarantees of debt securities as shall have an aggregate initial offering price not to exceed $500.0 million. In the future, we may issue additional debt and equity securities pursuant to a prospectus supplement to the Shelf Registration Statement.

Net proceeds, terms and pricing of each offering of securities issued under the Shelf Registration Statement will be determined at the time of such offerings. The Shelf Registration Statement does not provide assurance that we will or could sell any such securities. Our ability to utilize the Shelf Registration Statement for the purpose of issuing, from time to time, any combination of debt securities, common units or preferred 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.

terms of the equity distribution agreement, we may sell from time to time through our sales agents, (i) our common units having an aggregate offering price of up to $400.0 million, (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $50.0 million, (iii) our Series B Cumulative Preferred Units having an aggregate offering price of up to $100.0 million or (iv) our Series C Cumulative Preferred Units having an aggregate offering price of up to $75.0 million. The common units and Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the year ended December 31, 2015, total net proceeds received under the equity distribution agreement were approximately $35.5 million, after commissions and fees of $0.6 million, from the sale of 2,430,170 common units.

Subsidiary Guarantors

We and VNRF, our wholly-owned finance subsidiary, may co-issue securities pursuant to our effective shelf registration statement. 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 guaranteed 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.

The guarantees are also subject to certain customary release provisions. Such guarantees may be released in the following customary circumstances:


•	in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of the Company;


•	in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;


•	if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;


•	upon legal defeasance or satisfaction and discharge of the indenture;


•	upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;


•	at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or


•	upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.

Debt and Credit Facilities

Reserve-Based Credit Facility

The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and a borrowing base of $1.8 billion (the “Reserve-Based Credit Facility”) with a maturity date of April 16, 2018. On December 31, 2015, there were $1.69 billion of outstanding borrowings and $107.5 million of borrowing capacity under the Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit (discussed below).

On June 3, 2015, the Company entered into the Eighth Amendment to the Credit Agreement which decreased its borrowing base from $2.0 billion to $1.6 billion. However, the Eighth Amendment provided for an automatic increase in the borrowing base of $200.0 million upon the closing of the LRE Merger, which took place on October 5, 2015. In addition, the Eighth Amendment includes, among other provisions, an amendment of the debt to “Last Twelve Months Adjusted EBITDA” covenant whereby the Company shall not permit such ratio to be greater than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond.

On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Ninth Amendment to the Credit Agreement which reaffirms the Company’s $1.8 billion borrowing base. The terms of the Ninth Amendment to the Credit Agreement also include, among other provisions, the increase in the maximum investments or capital contributions that can be made in certain entities from $5.0 million to $100.0 million. In addition, the Company is permitted to

incur up to $300.0 million of junior lien indebtedness provided the borrowing base will be reduced by $0.25 per dollar of junior debt issued.

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, 2015, 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 2016. Based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant. As such, we initiated a process to sell the SCOOP/STACK assets acquired in the Eagle Rock Merger. We anticipate that this divestiture would be consummated at the same time as the April 2016 redetermination and will allow us to reduce borrowings under the Reserve-Based Credit Facility in an amount sufficient to mitigate the reduction in the borrowing base for the April 2016 redetermination. Based on our internal forecasts, we will continue to experience low liquidity but expect to be at a liquidity level sufficient to run our business for the foreseeable future. However, there can be no assurances that our banks will not redetermine our borrowing base at a level below our outstanding borrowings in our April 2016 redetermination or any subsequent redetermination. Should a borrowing base deficiency occur, our Reserve-Based Credit Facility requires us to repay the deficiency in equal monthly installments over a six month period. Our internal forecasts show that we will generate a substantial amount of excess cash flow over the course of 2016 which will be used to reduce borrowings under our Reserve-Based Credit Facility and we expect would be sufficient to repay a deficiency should one exist in April 2016.

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, 2015, we have elected for interest to be determined by reference to the LIBOR method described above. Interest is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans, but not less frequently than quarterly.

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


•	incur indebtedness;


•	grant certain liens;


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


•	merge or consolidate; or


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

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


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

•

consolidated debt to consolidated net income plus interest expense, income taxes, depreciation, depletion, amortization, accretion, changes in fair value of derivative instruments and other similar charges, minus all non-cash income added to consolidated net income, and giving pro forma effect to any acquisitions or capital expenditures of not more than 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond.

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, 2015. If an event of default exists under the 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.

Letters of Credit

At December 31, 2015, we had unused irrevocable standby letters of credit of approximately $4.5 million. The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks.

7.875% Senior Notes Due 2020

At December 31, 2015, we had $550.0 million outstanding in aggregate principal amount of 7.875% Senior Notes due 2020. Following the exchange of approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 pursuant to the exchange offer described below, at March 3, 2016, we had approximately $381.8 million outstanding aggregate principal amount of Senior Notes due 2020.

Under the indenture governing the Senior Notes due 2020 (the “Senior Notes Indenture”), all of our existing subsidiaries (other than VNRF), all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes due 2020, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Notes Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Notes Indenture, (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us.

The Senior Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes due 2020 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Notes Indenture exists, many of the foregoing covenants will terminate. At December 31, 2015, based on the most restrictive covenants of the Senior Notes Indenture, our cash balance and the borrowings available under the Reserve-Based Credit Facility, $23.0 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.

Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes due 2020 at any one or more occasions on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016, plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes due 2020 at any one or more occasions prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes due 2020 thereof, plus a “make-whole” premium of, and accrued and unpaid interest to, the redemption date. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes due 2020, respectively.

7.0% Senior Secured Second Lien Notes Due 2023

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 to certain eligible holders of their outstanding Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued to certain eligible holders of Senior Notes due 2020 who validly tendered and did not validly withdraw their Senior Notes due 2020 pursuant to the terms of our exchange offer.

Under the indenture governing the Senior Secured Second Lien Notes (the “Senior Secured Second Lien Notes Indenture”), the Subsidiary Guarantors have unconditionally guaranteed, jointly and severally, the Senior Secured Second Lien Notes, subject to release under certain of the following circumstances: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets, (ii) upon the sale or other disposition of our equity interests in the subsidiary, (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Senior Secured Second Lien Indenture, (iv) upon legal defeasance or covenant defeasance or the discharge of the Senior Secured Second Lien Notes Indenture, (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us.

The Senior Secured Second Lien Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Secured Second Lien Notes achieve an investment grade rating from each of

Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Secured Second Lien Notes Indenture exists, many of the foregoing covenants will terminate. At December 31, 2015, based on the most restrictive covenants of the Senior Secured Second Lien Notes Indenture, our cash balance and the borrowings available under the Reserve-Based Credit Facility, $23.0 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.

Interest on the Senior Secured Second Lien Notes is payable on February 15, and August 15 of each year, beginning on August 15, 2016. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023.

We may also redeem some or all of the Senior Secured Second Lien Notes on any one or more occasions prior to February 15, 2019 at a redemption price equal to 100% of the aggregate principal amount of the Senior Secured Second Lien Notes thereof, plus the applicable premium as of, and accrued and unpaid interest, if any, to the redemption date. In addition, on any one or more occasions before February 15, 2019, we may redeem up to 35% of the aggregate principal amount of the Senior Secured Second Lien Notes at a redemption price equal to 107% of the aggregate principal amount of the Senior Secured Second Lien Notes thereof, together with accrued and unpaid interest, if any, to the redemption date, with the proceeds of certain equity offerings, provided that (i) at least 65% of the aggregate principal amount of the Senior Secured Second Lien Notes originally issued under the Senior Secured Second Lien Notes Indenture remain outstanding immediately after any such redemption and (ii) the redemption occurs within 180 days of such equity offering. On or after February 15, 2019, we may redeem some or all of the Senior Secured Second Lien Notes at redemption prices equal to the aggregate principal amount multiplied by the percentage set forth below, plus accrued and unpaid interest, if any:



Year	Percentage
2019	105.250	%
2020	103.500	%
2021	101.750	%
2022 and thereafter	100.000	%

8.375% Senior Notes Due 2019

In connection with the Eagle Rock Merger, VO assumed 8.375% senior notes with a principal amount of $51.1 million due in 2019 (the “Senior Notes due 2019”) with a fair market value of $34.3 million as of the close date of the Eagle Rock Merger. Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 are fully and unconditionally (except for customary release provisions) and jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of its Subsidiary Guarantors.

Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 will mature on June 1, 2019. We have the option to redeem some or all of the Senior Notes due 2019 at any time at redemption prices equal to the aggregate principal amount multiplied by (i) 102.094% if such Senior Notes due 2019 are redeemed in 2016 and (ii) 100.000% if such Senior Notes due 2019 are redeemed in 2017 and thereafter.

Lease Financing Obligations

On October 24, 2014, as part of our Piceance Acquisition, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contain an early buyout option where the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

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, 2015, there were no material loss contingencies.

Commitments and Contractual Obligations

A summary of our contractual obligations as of December 31, 2015 is provided in the following table:



	Payments Due by Year (in thousands)
	2016		2017		2018		2019		2020		Thereafter		Total
Asset retirement obligations ⁽¹⁾	$	9,024	$	9,347	$	9,399	$	6,997	$	9,100	$	227,589	$	271,456
Derivative liabilities ⁽²⁾	23,800		7,242		998		550		—		—		32,590
Reserve-Based Credit Facility ⁽³⁾	—		—		1,688,000		—		—		—		1,688,000
Senior Notes and related interest ⁽⁴⁾	58,779		47,594		47,594		96,216		560,828		—		811,011
Operating leases	3,893		3,898		1,798		1,342		216		—		11,147
Development commitments ⁽⁵⁾	38,013		—		—		—		—		—		38,013
Firm transportation and processing agreements⁽⁶⁾	14,957		12,512		11,696		9,661		410		—		49,236
Lease Financing Obligations ⁽⁷⁾	5,442		5,442		5,442		5,442		4,359		1,278		27,405
Total	$	153,908	$	86,035	$	1,764,927	$	120,208	$	574,913	$	228,867	$	2,928,858


(1)	Represents the discounted future plugging and abandonment costs of oil and natural gas wells and decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Please read Note 6 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 4 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 3 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)	Consists of the Senior Notes due 2019 and the Senior Notes due 2020 and the related interest thereon.


(5)	Represents authorized purchases for work in process.


(6)	Represents transportation demand charges. Please read Note 8 of the Notes to the Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”


(7)	The Lease Financing Obligations are calculated based on the aggregate present value of minimum future lease payments. The amounts presented include interest payable for each year.

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 primary market risk exposure is in the prices we receive for our production. Realized pricing for our natural gas, oil and NGLs production is primarily driven by spot market prices applicable to our natural gas production and the prevailing price for crude oil. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at published natural gas index prices for the producing area due to the proximity to major consuming markets. Our natural gas indexes include the Houston Ship Channel, West Texas (“Waha” Gas index), El Paso Natural Gas Company (Permian Basin), Transwestern (Permian), Colorado Interstate Gas Co. (Rocky Mountains index), Northwest Pipeline Corp. (Rocky Mountains index), Transcontinental Gas Pipe Line Corp (Zone 4), Enable Oklahoma Intrastate Transmission LLC’s West pool and Enable Gas (East index). As for oil production, realized pricing is primarily driven by West Texas WTI, the Light Louisiana Sweet Crude (LLS), Flint Hills Bow River and Net Energy Canadian Daily index for Western Canadian Select prices and calendar NYMEX pricing. The NGLs price exposure is centered on the Oil Price Information Service postings as well as market-negotiated ethane plus (C2+) spot 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 for our Reserve-Based Credit Facility 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.

We routinely 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 as follows:


•	Fixed-price swaps - where we will receive a fixed-price for our production and pay a variable market price to the contract counterparty.


•	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.


•	Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.

•

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 drops below the price of the short put. This allows us to settle for 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.


•	Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years.


•	Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously.


•	Put spread options - created when we purchase a put and sell a put simultaneously.


•	Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously.


•	Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level.

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. Substantially all of our natural gas hedges are at regional sales points in our operating regions, which mitigate the risk of basis differential to the Henry Hub index. Typically, management intends to hedge 75% to 85% of projected oil and natural gas 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. In the current commodity price environment, however, we are less likely to hedge future revenues to the same extent as our

historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced. Currently, we are unable to hedge oil differentials in certain operating areas which exposes our cash flow to increased volatility in these areas. We have also entered into fixed-price swaps derivative contracts to cover a portion of our NGLs production to reduce exposure to fluctuations in NGLs prices. However, a liquid, readily available and commercially viable market for hedging NGLs has not developed in the same way that exists for crude oil and natural gas. The current direct NGLs hedging market is constrained in terms of price, volume, tenor and number of counterparties, which limits our ability to hedge our NGLs production effectively or at all. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Management will consider liquidating a derivative contract, if we believe that we can take advantage of an unusual market condition allowing us 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, 2015, the fair value of commodity derivative contracts was a net asset of approximately $327.3 million, of which $243.5 million settles during the next twelve months. A 10% increase in the oil and natural gas index price above the December 31, 2015 price would result in a net decrease in the fair value of all of our commodity derivative contracts of approximately $36.1 million; conversely, a 10% decrease in the oil and natural gas index price would result in a net increase of approximately $44.4 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, 2015:



	Year 2016		Year 2017
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu)	69,996,888		31,112,760
Fixed Price ($/MMBtu)	$	4.43	$	4.33
Three-Way Collars:
Notional Volume (MMBtu)	12,810,000		16,425,000
Floor Price ($/MMBtu)	$	3.95	$	3.92
Ceiling Price ($/MMBtu)	$	4.25	$	4.23
Put Sold ($/MMBtu)	$	3.00	$	3.37
Total Gas Positions:
Notional Volume (MMBtu)	82,806,888		47,537,760
Floor Price ($/MMBtu)	$	4.36	$	4.19



	Year 2016		Year 2017
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls)	1,875,531		749,698
Fixed Price ($/Bbl)	$	84.01	$	85.70
Fixed-Price Swaps (Light Louisiana Sweet):
Notional Volume (Bbls)	—		168,000
Fixed Price ($/Bbl)	$	—	$	91.25
Three-Way Collars:
Notional Volume (Bbls)	1,061,400		—
Floor Price ($/Bbl)	$	90.00	$	—
Ceiling Price ($/Bbl)	$	96.18	$	—
Put Sold ($/Bbl)	$	73.62	$	—
Puts:
Notional Volume (Bbls)	366,000		—
Floor Price ($/Bbl)	$	60.00	$	—
Total Oil Positions:
Notional Volume (Bbls)	3,302,931		917,698
Floor Price ($/Bbl)	$	83.27	$	86.72



	Year 2016
NGLs Positions:
Fixed-Price Swaps:
Mont Belvieu Propane
Notional Volume (Bbls)	455,700
Fixed Price ($/Bbl)	$	23.62
Mont Belvieu N. Butane
Notional Volume (Bbls)	201,300
Fixed Price ($/Bbl)	$	28.54
Mont Belvieu Isobutane
Notional Volume (Bbls)	95,700
Fixed Price ($/Bbl)	$	28.54
Mont Belvieu N. Gasoline
Notional Volume (Bbls)	154,200
Fixed Price ($/Bbl)	$	53.50
Total NGLs Positions:
Notional Volume (Bbls)	906,900
Fixed Price ($/Bbl)	$	30.31

As of December 31, 2015, the Company had sold the following put option contracts:



	Year 2016		Year 2017
Gas Positions:
Notional Volume (MMbtu)	1,830,000		1,825,000
Put Sold ($/MMbtu)	$	3.00	$	3.50
Oil Positions:
Notional Volume (Bbls)	146,400		73,000
Put Sold ($/Bbl)	$	50.00	$	75.00

As of December 31, 2015, the Company had the following open range bonus accumulators contracts:



	Year 2016
Oil Positions:
Notional Volume (Bbls)	183,000
Bonus ($/Bbl)	$	4.00
Digital call sold ($/Bbl)	$	100.00
Put Sold ($/Bbl)	$	75.00

As of December 31, 2015, the Company had the following open basis swap contracts:



	Year 2016			Year 2017
Gas Positions:
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu)	38,430,000			10,950,000
Weighted-basis differential ($/MMBtu)	$	(0.20	)	$	(0.22	)



	Year 2016
Oil Positions:
WTI Midland and WTI Cushing Basis Differential
Notional Volume (Bbls)	968,700
Weighted-basis differential ($/Bbl)	$	(1.01	)
West Texas Sour and WTI Cushing Basis Differential
Notional Volume (Bbls)	219,600
Weighted-basis differential ($/Bbl)	$	(0.43	)
WTI and West Canadian Select Basis Differential
Notional Volume (Bbls)	716,500
Weighted-basis differential ($/Bbl)	$	(14.26	)

As of December 31, 2015, the Company sold calls as follows:



	Year 2016		Year 2017
Oil Positions:
Notional Volume (Bbls)	622,200		365,000
Weighted Average Fixed Price ($/Bbl)	$	125.00	$	95.00

We have implemented a hedging program for approximately 78% and 49% of our natural gas production in 2016 and 2017, respectively, with 85% in the form of fixed-price swaps in 2016. Approximately 67% and 21% of our anticipated crude oil production in 2016 and 2017, respectively, is hedged with 57% in the form of fixed-price swaps in 2016. NGLs production is under fixed-price swaps for approximately 22% of anticipated production in 2016.



	Year 2016			Year 2017
Gas Production Hedged:
% Anticipated Production Hedged	78		%	49		%
Weighted Average Price ($/MMBtu)	$	4.15		$	3.84
Oil Production Hedged:
% Anticipated Production Hedged	67		%	21		%
Weighted Average Price ($/Bbl)	$	67.52		$	84.13
NGLs Production Hedged:
% Anticipated Production Hedged	22		%	—
Weighted Average Price ($/Bbl)	$	30.31		$	—

The weighted average price for oil and natural gas will fluctuate based on the value of existing three-way collars and short puts as the respective prices settle. The above weighted average prices are calculated based on forward strip commodity prices as of February 29, 2016.

Interest Rate Risks

At December 31, 2015, we had debt outstanding of $2.3 billion. The amount outstanding under our Reserve-Based Credit Facility at December 31, 2015 of $1.69 billion 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 $0.4 million increase in annual interest expense after consideration of the interest rate swaps discussed below. We also had $550.0 million aggregate principal amount of Senior Notes due 2020, $51.1 million aggregate principal amount of Senior Notes due 2019 and $24.7 million aggregate principal amount of Lease Financing Obligations with an implied interest of 4.16%.

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. We record changes in the fair value of its interest rate derivatives in current earnings under net gains (losses) on interest rate derivative contracts.

The following summarizes information concerning our positions in open interest rate swaps at December 31, 2015 (in thousands):



	Year 2016 ⁽¹⁾			Year 2017			Year 2018			Year 2019
Weighted Average Notional Amount	$	594,399		$	256,342		$	192,836		$	175,000
Weighted Average Fixed LIBOR Rate	1.82		%	2.15		%	2.31		%	2.32		%


(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.

Counterparty Risk

At December 31, 2015, based upon all of our open derivative contracts shown above and their respective mark-to-market values, we 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, 2015
ABN AMRO Bank N.V. (A)	$	4,340	$	764	$	—				$	5,104
Bank of America (A)	34,787		22,907		—			—		57,694
Barclays (A-)	19,529		378		—			—		19,907
BMO (A+)	5,867		1,740		—					7,607
CIBC (A+)	3,685		1,318		—			—		5,003
Citibank (A)	6,928		3,418		—			—		10,346
Comerica (A)	12,052		—		—			—		12,052
Commonwealth Bank of Australia (AA-)	1,229		893		—			—		2,122
Credit Agricole (A)	—		—		(257		)	—		(257		)
Fifth Third Bank (A-)	1,122		—		—			—		1,122
Huntington Bank (BBB+)	4,267		—		—			—		4,267
ING Financial Markets (A)	44,008		—		—			—		44,008
JP Morgan (A-)	43,991		14,501		—					58,492
Morgan Stanley (BBB+)	5,670		4,835		—			—		10,505
Natixis (A)	4,438		716		—			—		5,154
NextEra Energy Inc. (A-)	—		—		(99		)	—		(99		)
RBC (AA-)	9,995		4,780		—			—		14,775
Scotia Capital (A+)	17,563		5,581		—			—		23,144
Sun Trust (A-)	1,223		961		—			—		2,184
Wells Fargo (AA-)	16,192		17,369		—			—		33,561
Total	$	236,886	$	80,161	$	(356	)	$	—	$	316,691

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: (i) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (ii) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out. Under the master netting agreement, 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 net fair value of financial instruments, was approximately $317.0 million at December 31, 2015.

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		95
	Consolidated Statements of Operations		96
	Consolidated Balance Sheets		97
	Consolidated Statements of Members’ Equity (Deficit)		98
	Consolidated Statements of Cash Flows		99
	Notes to Consolidated Financial Statements		101
	Supplemental Financial Information
	Supplemental Selected Quarterly Financial Information (Unaudited)		133
	Supplemental Oil and Natural Gas Information		134

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, 2015 and 2014 and the related consolidated statements of operations, members’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vanguard Natural Resources, LLC at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2016 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 7, 2016

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Statements of Operations

For the Years Ended December 31,

(in thousands, except per unit data)



	2015			2014			2013
Revenues:
Oil sales	$	164,111		$	268,685		$	268,922
Natural gas sales	193,496			285,439			124,513
Natural gas liquids sales	39,620			70,489			49,813
Net gains on commodity derivative contracts	169,416			163,452			11,256
Total revenues	566,643			788,065			454,504

Costs and expenses:
Production:
Lease operating expenses	146,654			132,515			105,502
Production and other taxes	40,576			61,874			40,430
Depreciation, depletion, amortization and accretion	247,119			226,937			167,535
Impairment of oil and natural gas properties	1,842,317			234,434			—
Goodwill impairment loss	71,425			—			—
Selling, general and administrative expenses	55,076			30,839			25,942
Total costs and expenses	2,403,167			686,599			339,409

Income (loss) from operations	(1,836,524		)	101,466			115,095

Other income (expense):
Interest expense	(87,573		)	(69,765		)	(61,148		)
Net gains (losses) on interest rate derivative contracts	153			(1,933		)	(96		)
Net gain on acquisitions of oil and natural gas properties	40,533			34,523			5,591
Other	237			54			69
Total other expense, net	(46,650		)	(37,121		)	(55,584		)

Net income (loss)	(1,883,174		)	64,345			59,511
Less: Distributions to Preferred unitholders	(26,759		)	(18,197		)	(2,634		)
Net income (loss) attributable to Common and Class B unitholders	$	(1,909,933	)	$	46,148		$	56,877

Net income (loss) per Common and Class B unit:
Basic	$	(19.80	)	$	0.56		$	0.78
Diluted	$	(19.80	)	$	0.55		$	0.77

Weighted average units outstanding:
Common units – basic	96,048			81,611			72,644
Common units – diluted	96,048			82,039			72,992
Class B units – basic & diluted	420			420			420

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)



	2015			2014
Assets
Current assets
Cash and cash equivalents	$	—		$	—
Trade accounts receivable, net	115,200			140,017
Derivative assets	236,886			142,114
Other currents assets	6,436			4,102
Total current assets	358,522			286,233
Oil and natural gas properties, at cost	4,961,218			4,140,527
Accumulated depletion, amortization and impairment	(3,239,242		)	(1,164,721		)
Oil and natural gas properties evaluated, net – full cost method	1,721,976			2,975,806
Other assets
Goodwill	506,046			420,955
Derivative assets	80,161			83,583
Other assets	42,592			27,015
Total assets	$	2,709,297		$	3,793,592

Liabilities and members’ equity (deficit)
Current liabilities
Accounts payable:
Trade	$	22,895		$	15,118
Affiliates	1,757			823
Accrued liabilities:
Lease operating	19,910			19,822
Developmental capital	26,726			24,706
Interest	11,958			11,517
Production and other taxes	40,472			29,981
Other	10,378			7,594
Derivative liabilities	356			3,583
Oil and natural gas revenue payable	44,823			40,117
Distributions payable	5,018			18,640
Other current liabilities	17,715			6,703
Total current liabilities	202,008			178,604
Long-term debt	2,291,636			1,932,816
Derivative liabilities	—			1,380
Asset retirement obligations	262,432			146,676
Other long-term liabilities	40,656			—
Total liabilities	2,796,732			2,259,476
Commitments and contingencies (Note 7)
Members’ equity (deficit)
Cumulative Preferred units, 13,881,873 units issued and outstanding at December 31, 2015 and 2014	335,444			335,444
Members’ (deficit) capital, 130,476,978 and 83,451,746 common units issued and outstanding at December 31, 2015 and 2014, respectively	(430,494		)	1,191,057
Class B units, 420,000 issued and outstanding at December 31, 2015 and 2014	7,615			7,615
Total members’ equity (deficit)	(87,435		)	1,534,116
Total liabilities and members’ equity (deficit)	$	2,709,297		$	3,793,592

See accompanying notes to consolidated financial statements.

Vanguard Natural Resources, LLC and Subsidiaries

Consolidated Statements of Members’ Equity (Deficit)

For the Years Ended December 31, 2015, 2014 and 2013

(in thousands)



	Cumulative Preferred Units		Common Units			Class B Units		Total Members’ Equity
Balance, January 1, 2013	$	—	$	789,849		$	7,615	$	797,464
Issuance of Common units for the acquisition of oil and natural gas properties	—		29,992			—		29,992
Issuance of Cumulative Preferred units, net of offering costs of $402	61,021		—			—		61,021
Issuance of Common units, net of offering costs of $415	—		498,360			—		498,360
Distributions to Preferred unitholders (see Note 9)	—		(2,634		)	—		(2,634		)
Distributions to Common and Class B unitholders (see Note 8)	—		(181,926		)	—		(181,926		)
Unit-based compensation	—		6,547			—		6,547
Net income	—		59,511			—		59,511
Balance at December 31, 2013	61,021		1,199,699			7,615		1,268,335
Issuance of Cumulative Preferred units, net of offering costs of $371	274,423		—			—		274,423
Issuance of Common units, net of offering costs of $88	—		147,814			—		147,814
Repurchase of units under the common unit buyback program	—		(2,498		)	—		(2,498		)
Distributions to Preferred unitholders (see Note 8)	—		(18,197		)	—		(18,197		)
Distributions to Common and Class B unitholders (see Note 8)	—		(207,883		)	—		(207,883		)
Unit-based compensation	—		7,777			—		7,777
Net income	—		64,345			—		64,345
Balance at December 31, 2014	335,444		1,191,057			7,615		1,534,116
Issuance of Common units as consideration for the Eagle Rock Merger, net of merger costs of $5,560	—		253,068			—		253,068
Issuance of Common units as consideration for the LRE Merger, net of merger costs of $3,961	—		119,315			—		119,315
Issuance of Common units, net of offering costs of $593	—		35,544			—		35,544
Repurchase of units under the common unit buyback program	—		(2,399		)	—		(2,399		)
Distributions to Preferred unitholders (see Note 8)	—		(26,760		)	—		(26,760		)
Distributions to Common and Class B unitholders (see Note 8)	—		(134,019		)	—		(134,019		)
Unit-based compensation	—		16,874			—		16,874
Net loss	—		(1,883,174		)	—		(1,883,174		)
Balance at December 31, 2015	$	335,444	$	(430,494	)	$	7,615	$	(87,435	)

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)



	2015			2014			2013
Operating activities
Net income (loss)	$	(1,883,174	)	$	64,345		$	59,511
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	247,119			226,937			167,535
Impairment of oil and natural gas properties	1,842,317			234,434			—
Goodwill impairment loss	71,425			—			—
Amortization of deferred financing costs	4,206			3,516			3,715
Amortization of debt discount	1,071			269			248
Compensation related items	16,874			10,706			5,931
Post Eagle Rock Merger severance costs	13,955			—			—
Net gains on commodity and interest rate derivative contracts	(169,569		)	(161,519		)	(11,160		)
Net cash settlements received on matured commodity derivative contracts	211,723			10,187			30,905
Net cash settlements paid on matured interest rate derivative contracts	(5,227		)	(4,035		)	(3,888		)
Cash received on termination of derivative contracts	40,998			—			—
Net gain on acquisitions of oil and natural gas properties	(40,533		)	(34,523		)	(5,591		)
Changes in operating assets and liabilities:
Trade accounts receivable	53,423			(69,908		)	(22,065		)
Payables to affiliates	934			574			217
Premiums paid on commodity derivative contracts	(4,235		)	—			(204		)
Other current assets	(1,615		)	(1,669		)	(603		)
Accounts payable and oil and natural gas revenue payable	(555		)	22,166			16,426
Accrued expenses and other current liabilities	(43,320		)	29,377			18,855
Other assets	14,267			8,895			1,133
Net cash provided by operating activities	370,084			339,752			260,965
Investing activities
Additions to property and equipment	(644		)	(1,356		)	(1,975		)
Additions to oil and natural gas properties	(112,639		)	(142,015		)	(56,661		)
Acquisitions of oil and natural gas properties and derivative contracts	(12,970		)	(1,302,568		)	(272,057		)
Cash acquired in the LRE and Eagle Rock Mergers	18,503			—			—
Proceeds from the sale of oil and natural gas properties	1,777			4,973			—
Deposits and prepayments of oil and natural gas properties	(22,171		)	(5,236		)	(67,284		)
Net cash used in investing activities	(128,144		)	(1,446,202		)	(397,977		)
Financing activities
Proceeds from long-term debt	420,000			1,388,000			589,500
Repayment of debt	(508,617		)	(488,000		)	(829,500		)
Proceeds from preferred unit offerings, net	—			274,423			61,021
Proceeds from common unit offerings, net	35,544			147,814			498,360
Repurchase of units under the common unit buyback program	(2,399		)	(2,498		)	—
Distributions to Preferred unitholders	(26,760		)	(17,290		)	(2,426		)
Distributions to Common and Class B members	(147,641		)	(206,649		)	(177,555		)
Financing fees	(12,067		)	(1,168		)	(2,133		)
Net cash provided by (used in) financing activities	(241,940		)	1,094,632			137,267
Net increase (decrease) in cash and cash equivalents	—			(11,818		)	255
Cash and cash equivalents, beginning of year	—			11,818			11,563
Cash and cash equivalents, end of year	$	—		$	—		$	11,818
Supplemental cash flow information:
Cash paid for interest	$	83,557		$	66,434		$	57,067



	2015		2014		2013
Non-cash financing and investing activities:
Asset retirement obligations	$	25,028	$	56,947	$	22,692
Assets acquired under financing obligations	$	—	$	31,502	$	—
LRE and Eagle Rock Mergers
Assets acquired:
Accounts receivable and other current assets	$	44,201	$	—	$	—
Net derivative assets	$	166,758	$	—	$	—
Oil and natural gas properties	$	672,178	$	—	$	—
Other long-term assets	$	10,001	$	—	$	—
Liabilities assumed:
Accounts payable and other current liabilities	$	70,085
Asset retirement obligations	$	88,228	$	—	$	—
Long-term debt	$	446,550	$	—	$	—
Other long-term liabilities	$	40,571	$	—	$	—
Common units issued in the LRE and Eagle Rock Mergers	$	381,904	$	—	$	—
Common units issued for the acquisition of oil and gas properties	$	—	$	—	$	29,992

See accompanying notes to consolidated financial statements.

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Vanguard Natural Resources, LLC and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2015

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. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of December 31, 2015, we own properties and oil and natural gas reserves primarily located in ten operating basins:


•	the Green River Basin in Wyoming;


•	the Permian Basin in West Texas and New Mexico;


•	the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Piceance Basin in Colorado;


•	the Big Horn Basin in Wyoming and Montana;


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

1. Summary of Significant Accounting Policies


(a)	Basis of Presentation and Principles of Consolidation:

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)	New Pronouncement Issued But Not Yet Adopted:

In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities must apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period.

We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018.

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In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date.

For public business entities, the amendments are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments should be applied prospectively to adjustments to provisional amounts that occur after the effective date. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17 Income taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. This ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position.

In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee‘s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements.


(c)	Cash Equivalents:

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.


(d)	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.


(e)	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.


(f)	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 natural gas liquids (“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

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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 estimated future net cash flows from proved reserves, computed using the 12-month unweighted average of first-day-of-the-month commodity prices (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.



	Impairment Amount (in thousands)		Natural Gas ($ per MMBtu)	Oil ($ per Bbl)
First quarter 2015	$	132,610	$3.91	$82.62
Second quarter 2015	$	733,365	$3.44	$71.51
Third quarter 2015	$	491,487	$3.11	$59.23
Fourth quarter 2015	$	484,855	$2.62	$50.20
Total	$	1,842,317

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the year ended December 31, 2014 of $234.4 million as a result of a decline in realized oil and natural gas prices at the measurement date of December 31, 2014. Such impairment was recognized during the fourth quarter of 2014. The most significant factor affecting the 2014 impairment related to the properties that we acquired in the Piceance Acquisition. The fair value of the properties acquired (determined using forward oil and natural gas price curves at the acquisition date) was higher than the discounted estimated future cash flows computed using the 12-month average prices at the impairment test measurement dates. However, the impairment calculations 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. The fourth quarter 2014 impairment was calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil. No ceiling test impairment was required during 2013.

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.


(g)	Goodwill and Other Intangible Assets:

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assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity securities may not be representative of the fair value of the reporting unit as a whole. Accordingly, we add a control premium to the market price to determine the total fair value of our reporting unit, derived from marketplace data of actual control premiums in the oil and natural gas extraction industry. The sum of our market capitalization and control premium is the fair value of our reporting unit. This amount is then compared to the carrying value of our reporting unit. If the estimated fair value of the reporting unit exceeds its net book value, goodwill of the reporting unit is not impaired and the second step of the impairment test is not necessary.

If the net book value of the reporting unit exceeds its fair value, the second step of the goodwill impairment test will be performed to measure the amount of impairment loss, if any. In addition, if the carrying amount of a reporting unit is zero or negative, the second step of the impairment test is performed to measure the amount of impairment loss, if any, when it is more likely than not that a goodwill impairment exists. In considering whether it is more likely than not that a goodwill impairment exists, we evaluate any adverse qualitative factors. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. In other words, the estimated fair value of the reporting unit is allocated to all of the assets and liabilities of that unit (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.

As of December 31, 2015, the carrying value of our reporting unit was negative. Therefore the Company was required to perform the second step of the goodwill impairment test. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015 to write the goodwill down to its estimated fair value of $506.0 million. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

Any further significant decline in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimate of the fair value of the reporting unit and could result in an additional 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, 2015, the net carrying value of this contract was $8.1 million. The carrying value is shown as Other assets 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.

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(h)	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 Big Escambia Creek, Elk Basin and Fairway gas plants. 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.


(i)	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 NGLs, 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 as “Trade accounts receivable, net” in the accompanying Consolidated Balance Sheets.


(j)	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, 2015 and 2014, the cash and cash equivalents were primarily concentrated in one financial institution. We periodically assess the financial condition of this institution 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:



	2015	2014	2013
Mieco, Inc	20%	—%	—%
Anadarko Petroleum Corporation	2%	19%	1%
Marathon Oil Company	7%	12%	14%
Plains Marketing L.P.	7%	7%	10%

Our customers are in the energy industry and they may be similarly affected by changes in economic or other conditions.


(k)	Use of Estimates:

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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.


(l)	Price and Interest Rate Risk Management Activities:

We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility (defined in Note 3) to hedge price risk associated with a portion of our oil, natural gas and NGLs 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. Our natural gas production is primarily sold under market sensitive contracts which are typically priced at a differential to the NYMEX or the published natural gas index prices for the producing area due to the natural gas quality and the proximity to major consuming markets. As for oil production, realized pricing is primarily driven by the West Texas Intermediate (“WTI”), Light Louisiana Sweet Crude, Wyoming Imperial and Flint Hills Bow River prices. NGLs pricing is based on the Oil Price Information Service postings as well as market-negotiated ethane spot prices. During 2015, our derivative transactions included the following:


•	Fixed-price swaps - where we receive a fixed-price for our production and pay a variable market price to the contract counterparty.


•	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.


•	Collars - where we pay the counterparty if the market price is above the ceiling price (short call) and the counterparty pays us if the market price is below the floor (long put) on a notional quantity.

•


•	Swaption agreements - where we provide options to counterparties to extend swap contracts into subsequent years.


•	Call options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position, or a lower liability position. In general, selling a call option is used to enhance an existing position or a position that we intend to enter into simultaneously.


•	Put spread options - created when we purchase a put and sell a put simultaneously.


•	Put options sold - a structure that may be combined with an existing swap to raise the strike price, putting us in either a higher asset position or a lower liability position. In general, selling a put option is used to enhance an existing position or a position that we intend to enter into simultaneously.


•	Range bonus accumulators - a structure that allows us to receive a cash payment when the crude oil or natural gas settlement price remains within a predefined range on each expiry date. Depending on the terms of the contract, if the settlement price is below the floor or above the ceiling on any expiry date, we may have to sell at that level.

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.

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 values are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the change in the fair value of 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. Gains or losses on derivative contracts that do not qualify for hedge accounting treatment are recorded in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the Consolidated Statements of Operations.

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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 in net gains (losses) on commodity derivative contracts or net gains (losses) on interest rate derivative contracts in the accompanying Consolidated Statements of Operations.

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. Premium payments are reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows. When the consideration for an acquisition is cash, the fair value of any derivative contracts acquired in the acquisition is reflected in cash flows from investing activities. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in our Consolidated Statements of Cash Flows.


(m)	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 $1.3 billion and $187.0 million at December 31, 2015 and 2014, respectively.

Legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including otherwise 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 $0.2 million as of December 31, 2015 and 2014 and a deferred tax asset of $0.5 million and $0.3 million as of December 31, 2015 and 2014, respectively. Tax benefits of $0.3 million and $0.6 million and a tax provision of $0.6 million are included in our Consolidated Statements of Operations for the years ended December 31, 2015, 2014, and 2013, respectively, as a component of Selling, general and administrative expenses.

The Company’s provision for income taxes also relates to the federal taxes for ERAC and ERAC II and their wholly owned corporations, ERUD and ERUD II, which are subject to federal income taxes (the “C Corporations”). As part of the Eagle Rock Merger, the Company assumed deferred tax liabilities, the largest single component of which is related to federal income taxes of the C Corporations, where the book/tax differences were created by certain acquisitions completed by ERAC and ERAC II prior to the Eagle Rock Merger. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets. As of December 31, 2015, the Company recorded a deferred tax liability of $39.4 million related to these C Corporations, which is included in the other long-term liabilities line item in the Consolidated Balance Sheet. The Company also recorded a net deferred tax asset of $2.2 million from the Eagle Rock Merger related to the book/tax differences in property, plant and equipment and hedging transactions, which is included in the other assets line item in the Consolidated Balance Sheet.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2015, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of the deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

2. Acquisitions and Divestiture

Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted

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for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below.

On July 31, 2015, we completed the acquisition of additional interests in the same properties located in the Pinedale field of Southwestern Wyoming that were previously acquired in the Pinedale Acquisition in 2014 for an adjusted purchase price of $11.4 million, subject to additional customary post-closing adjustments to be determined based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

2015 Mergers

LRE Merger

As consideration for the LRE Merger, we issued approximately 15.4 million Vanguard common units valued at $123.3 million based on the closing price per Vanguard common unit of $7.98 at October 5, 2015 and assumed $290.0 million in debt. The debt assumed was extinguished using borrowings under the Company’s Reserve-Based Credit Facility following the close of the LRE Merger. As consideration for our purchase of the limited liability company interests in LRE GP, we issued 12,320 Vanguard common units.

The LRE Merger was completed following approval, at a Special Meeting of LRE unitholders on October 5, 2015, of the LRE Merger Agreement and the LRE Merger by holders of a majority of the outstanding LRE Common Units.

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Consideration
Market value of Vanguard’s common units issued to LRE unitholders	$	123,276
Long-term debt assumed	290,000
	413,276
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	5,606
Other current liabilities	9,018
Asset retirement obligations	39,595
Amount attributable to liabilities assumed	54,219
Less: fair value of assets acquired
Cash	11,532
Trade accounts receivable	6,822
Other current assets	4,172
Oil and natural gas properties	209,463
Derivative assets	78,725
Other assets	267
Amount attributable assets acquired	310,981
Goodwill	$	156,514

Eagle Rock Merger

As consideration for the Eagle Rock Merger, Vanguard issued approximately 27.7 million Vanguard common units valued at $258.3 million based on the closing price per Vanguard common unit of $9.31 at October 8, 2015 and assumed $156.6 million in debt. The Company extinguished $122.3 million of the debt assumed using borrowings under its Reserve-Based Credit Facility following the close of Eagle Rock Merger.

The Eagle Rock Merger was completed following (i) approval by holders of a majority of the outstanding Eagle Rock common units, at a Special Meeting of Eagle Rock unitholders on October 5, 2015, of the Eagle Rock Merger Agreement and the Eagle Rock Merger and (ii) approval by Vanguard unitholders, at Vanguard’s 2015 Annual Meeting of Unitholders, of the issuance of Vanguard common units to be issued as Eagle Rock Merger Consideration to the holders of Eagle Rock common units in connection with the Eagle Rock Merger.

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Consideration
Market value of Vanguard’s common units issued to Eagle Rock unitholders	$	258,282
Long-term debt assumed	156,550
Replacement share-based payment awards attributable to pre-combination services	346
	415,178
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	53,255
Other current liabilities	2,206
Derivative liabilities	2,201
Asset retirement obligations	48,633
Deferred tax liability	39,327
Other long-term liabilities	1,244
Amount attributable to liabilities assumed	146,866
Less: fair value of assets acquired
Cash	6,971
Trade accounts receivable	17,543
Other current assets	15,664
Oil and natural gas properties	462,715
Derivative assets	90,234
Other assets	9,734
Amount attributable assets acquired	602,861
Bargain Purchase Gain	$	(40,817	)

As a result of the consideration transferred being less than the fair value of net assets acquired, Vanguard reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. As part of its reassessment, Vanguard also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. Vanguard also determined that there were no non-controlling interests in the Eagle Rock Merger.

Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends between the date the parties agreed to the consideration for the Eagle Rock Merger and the date the transaction was completed, resulting in the decline of Vanguard’s unit price. Although the depressed oil and natural gas market also affected the fair value of Eagle Rock’s oil and natural gas properties, it had a more significant impact on Vanguard’s unit price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock merger, including the oil and natural gas properties, exceeded the total consideration paid.

2014 Acquisitions

Pinedale Acquisition

On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $555.6 million in cash with an effective date of October 1, 2013. We refer to this acquisition as the “Pinedale Acquisition.” In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million, as reflected in the table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.

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Fair value of assets and liabilities acquired	(in thousands)
Oil and natural gas properties	$	600,123
Inventory	244
Asset retirement obligations	(12,404		)
Imbalance liabilities	(171		)
Other	(125		)
Total fair value of assets and liabilities acquired	587,667
Fair value of consideration transferred	555,553
Gain on acquisition	$	32,114

Piceance Acquisition

On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $502.1 million in cash. We refer to this acquisition as the “Piceance Acquisition.” Through this acquisition, we acquired additional interests in the same properties previously acquired in the Rockies acquisition completed in June 2012. The purchase price is subject to additional customary post-closing adjustments to be determined based on an effective date of July 1, 2014. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million, as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.



Fair value of assets and liabilities acquired	(in thousands)
Oil and natural gas properties	$	521,401
Asset retirement obligations	(19,452		)
Imbalance and suspense liabilities	(236		)
Total fair value of assets and liabilities acquired	501,713
Fair value of consideration transferred	502,140
Loss on acquisition	$	(427	)

Other Acquisitions

On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and net cash consideration of $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014.

On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $269.9 million, subject to additional customary post-closing adjustments to be determined based on an effective date of June 1, 2014.

During the year ended December 31, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $17.7 million.

2013 Acquisitions

On April 1, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in southeast New Mexico and West Texas for an adjusted purchase price of $266.2 million. This acquisition had an effective date of January 1, 2013.

On June 28, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in Texas and the San Juan and DJ-Basin in Colorado with an effective date of July 1, 2013 for an adjusted purchase price of $29.9 million. The consideration for this acquisition was paid in common equity by issuing 1,075,000 VNR common units, at an agreed

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price of $27.65 per common unit, valued for financial reporting purposes at the closing price of $27.90 at the closing date of the acquisition.

We also completed other acquisitions during 2013 including the acquisition of additional working interests in previously acquired properties for an aggregate adjusted purchase price of $2.5 million.

The following presents the values assigned to the net assets acquired in our 2013 acquisitions:



Fair value of assets and liabilities acquired:	(in thousands)
Oil and natural gas properties	$	317,573
Inventory	899
Asset retirement obligations	(11,381		)
Oil and natural gas revenue payable and imbalance liabilities	(2,843		)
Total fair value of assets and liabilities acquired	304,248
Fair value of consideration transferred	298,657
Gain on acquisition	$	5,591

Pro Forma Operating Results (Unaudited)

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the years ended December 31, 2015, 2014 and 2013 which reflect the effect on our consolidated results of operations as if (i) all our acquisitions in 2015 had occurred on January 1, 2014, (ii) all our acquisitions in 2014 had occurred on January 1, 2013 and (iii) all our acquisitions in 2013 had occurred on January 1, 2012.

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 adjusted for (i) assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired using the acquisition method of accounting, (iii) interest expense on additional borrowings necessary to finance the acquisitions and additional debt assumed in the LRE and Eagle Rock Mergers, and (iv) the impact of the common units issued in the acquisition of properties completed on June 28, 2013 and the common units issued in the LRE and Eagle Rock Mergers. The net gain (loss) on acquisitions of oil and natural gas properties were excluded from the pro forma results. The pro forma information is based upon these assumptions, and is not necessarily indicative of future results of operations:



	Year Ended December 31,
	2015			2014			2013
	(in thousands, except per unit amounts) (Pro forma)
Total revenues	$	804,564		$	1,430,710		$	841,576
Net income (loss) attributable to Common and Class B unitholders	$	(2,057,879	)	$	(66,405	)	$	161,329
Net income (loss) attributable to Common and Class B unitholders, per unit:
Basic	$	(15.83	)	$	(0.53	)	$	2.19
Diluted	$	(15.83	)	$	(0.53	)	$	2.17

Post-Acquisition Operating Results

The results of operations of the properties acquired, as described above, have been included in our consolidated financial statements from the closing dates of the acquisitions forward. The table below presents the amounts of revenues and excess of revenues over direct operating expenses included in our 2015, 2014 and 2013 Consolidated Statements of Operations for our acquisitions. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.

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	Year Ended December 31,
	2015		2014		2013
	(in thousands)
LRE Acquisition
Revenues	$	13,083	$	—	$	—
Excess of revenues over direct operating expenses	$	6,029	$	—	$	—
Eagle Rock Acquisition
Revenues	$	23,005	$	—	$	—
Excess of revenues over direct operating expenses	$	15,112	$	—	$	—
Pinedale Acquisition
Revenues	$	84,934	$	139,908	$	—
Excess of revenues over direct operating expenses	$	56,672	$	107,934	$	—
Piceance Acquisition
Revenues	$	37,767	$	22,642	$	—
Excess of revenues over direct operating expenses	$	18,427	$	15,234	$	—
All other acquisitions
Revenues	$	58,718	$	76,915	$	34,820
Excess of revenues over direct operating expenses	$	30,373	$	50,317	$	23,160

3. Long-Term Debt

Our financing arrangements consisted of the following:



			Amount Outstanding December 31,
Description	Interest Rate	Maturity Date	2015			2014
			(in thousands)
Senior Secured Reserve-Based Credit Facility	Variable (1)	April 16, 2018	$	1,688,000		$	1,360,000
Senior Notes due 2020	7.875% (2)	April 1, 2020	550,000			550,000
Senior Notes due 2019	8.375% (3)	June 1, 2019	51,120			—
Lease Financing Obligations	4.16% (4)	August 10, 2020 (4)	24,668			28,986
			$	2,313,788		$	1,938,986
Less:
Unamortized discount on Senior Notes			(17,651		)	(1,852		)
Current portion			(4,501		)	(4,318		)
Total long-term debt			$	2,291,636		$	1,932,816


(1)	Variable interest rate was 2.90% and 2.17% at December 31, 2015 and 2014, respectively.


(2)	Effective interest rate is 8.0%.


(3)	Effective interest rate is 21.45%.


(4)	The Lease Financing Obligations expire on August 10, 2020 except for certain obligations which expire on July 10, 2021.

Senior Secured Reserve-Based Credit Facility

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of $200.0 million upon the closing of the LRE Merger, which took place on October 5, 2015. In addition, the Eighth Amendment includes, among other provisions, an amendment of the consolidated leverage ratio whereby the Company shall not permit such ratio to be greater than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond.

On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Ninth Amendment to the Credit Agreement, which reaffirms the Company’s $1.8 billion borrowing base. The terms of the Ninth Amendment to the Credit Agreement also include, among other provisions, the increase in the maximum investments or capital contributions that can be made in certain entities from $5.0 million to $100.0 million. In addition, the Company is permitted to incur up to $300.0 million of junior lien indebtedness provided the borrowing base will be reduced by $0.25 per dollar of junior debt issued.

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. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our current ratio to be less than 1.0 to 1.0 and (b) our consolidated leverage ratio to be more than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond. In addition, we are subject to various other covenants including, but not limited to, those limiting 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, 2015, we were in compliance with all of our debt covenants. Our next borrowing base redetermination is scheduled for April 2016. Based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant.

Letters of Credit

7.875% Senior Notes Due 2020

At December 31, 2015, we had $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes Due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations.

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us.

The Senior Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes due 2020 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Indenture exists, many of the foregoing covenants will terminate. At December 31, 2015, based on the most restrictive covenants of the Senior Notes Indenture, our cash balance and the borrowings available under the Reserve-Based Credit Facility, $23.0 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.

Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes due 2020 at any one or more occasions on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016, plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes due 2020 at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes due 2020 thereof, plus a “make-whole” premium, and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes due 2020, respectively.

Debt Exchange

8.375% Senior Notes Due 2019

Lease Financing Obligations

On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement with Bank of America Leasing & Capital, LLC as the lead bank, whereby we acquired compressors and the related facilities, and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligations also contain an early buyout option where the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

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4. Price and Interest Rate Risk Management Activities

We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs 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. Pricing for these derivative contracts are based on certain market indexes and prices at our primary sales points.

We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.

At December 31, 2015, the Company had open commodity derivative contracts covering our anticipated future production as follows:

Fixed-Price Swaps (West Texas Intermediate)



	Gas			Oil			NGLs
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average WTI Price		Bbls	Weighted Average Fixed Price
January 1, 2016 – December 31, 2016	69,996,888	$	4.43	1,875,531	$	84.01	906,900	$	30.31
January 1, 2017 – December 31, 2017	31,112,760	$	4.33	749,698	$	85.70	—	$	—

Fixed-Price Swaps (Light Louisiana Sweet)



	Oil
Contract Period	Bbls	Weighted Average Fixed Price
January 1, 2017 – December 31, 2017	168,000	$	91.25

Call Options Sold



	Oil
Contract Period	Bbls	Weighted Average Fixed Price
January 1, 2016 – December 31, 2016	622,200	$	125.00
January 1, 2017 – December 31, 2017	365,000	$	95.00

Basis Swaps



	Gas
Contract Period	MMBtu	Weighted Avg. Basis Differential ($/MMBtu)			Pricing Index
January 1, 2016 – December 31, 2016	38,430,000	$	(0.20	)	Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2017 – December 31, 2017	10,950,000	$	(0.22	)	Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential

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	Oil
Contract Period	Bbls	Weighted Avg. Basis Differential ($/Bbl)			Pricing Index
January 1, 2016 – December 31, 2016	968,700	$	(1.01	)	WTI Midland and WTI Cushing Basis Differential
January 1, 2016 – December 31, 2016	219,600	$	(0.43	)	West Texas Sour and WTI Cushing Basis Differential
January 1, 2016 – December 31, 2016	716,500	$	(14.26	)	WTI and West Canadian Select Basis Differential

Three-Way Collars



	Gas
Contract Period	MMbtu	Floor		Ceiling		Put Sold
January 1, 2016 – December 31, 2016	12,810,000	$	3.95	$	4.25	$	3.00
January 1, 2017 – December 31, 2017	16,425,000	$	3.92	$	4.23	$	3.37



	Oil
Contract Period	Bbls	Floor		Ceiling		Put Sold
January 1, 2016 – December 31, 2016	1,061,400	$	90.00	$	96.18	$	73.62

Puts

Put Options Sold



	Gas			Oil
Contract Period	MMbtu	Put Sold ($/MMbtu)		Bbls	Put Sold ($/Bbl)
January 1, 2016 – December 31, 2016	1,830,000	$	3.00	146,400	$	50.00
January 1, 2017 – December 31, 2017	1,825,000	3.50		73,000	$	75.00

Range Bonus Accumulators



	Oil
Contract Period	Bbls	Bonus		Range Ceiling		Range Floor
January 1, 2016 – December 31, 2016	183,000	$	4.00	$	100.00	$	75.00

Interest Rate Swaps

We may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. These interest rate swap agreements require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. If LIBOR is lower than the fixed rate in the contract, we are required to pay the counterparty the difference, and conversely, the counterparty is required to pay us if LIBOR is higher than the fixed rate in the contract. We do not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

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At December 31, 2015, the Company had open interest rate derivative contracts as follows (in thousands):



	Notional Amount		Fixed LIBOR Rates
Period:
January 1, 2016 to December 10, 2016	$	20,000	2.17	%
January 1, 2016 to October 31, 2016	$	40,000	1.65	%
January 1, 2016 to August 5, 2018	$	30,000	2.25	%
January 1, 2016 to August 6, 2016	$	25,000	1.80	%
January 1, 2016 to October 31, 2016	$	20,000	1.78	%
January 1, 2016 to September 23, 2016	$	75,000	1.15	%
January 1, 2016 to March 7, 2016	$	75,000	1.08	%
January 1, 2016 to September 7, 2016	$	25,000	1.25	%
January 1, 2016 to December 31, 2019	$	175,000	2.32	%
January 1, 2016 to February 16, 2017	$	75,000	1.73	%
January 1, 2016 to June 16, 2017	$	70,000	1.43	%
January 1, 2016 to February 16, 2017	$	75,000	1.73	%
Total	$	705,000

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 table summarizes the gross fair values of our derivative instruments and the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):



	December 31, 2015
Offsetting Derivative Assets:	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts	$	349,281		$	(21,834	)	$	327,447
Interest rate derivative contracts	—			(10,400		)	(10,400		)
Total derivative instruments	$	349,281		$	(32,234	)	$	317,047

Offsetting Derivative Liabilities:	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts	$	(21,934	)	$	21,834		$	(100	)
Interest rate derivative contracts	(10,656		)	10,400			(256		)
Total derivative instruments	$	(32,590	)	$	32,234		$	(356	)

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	December 31, 2014
Offsetting Derivative Assets:	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts	289,018			(63,321		)	225,697
Total derivative instruments	$	289,018		$	(63,321	)	$	225,697

Offsetting Derivative Liabilities:	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheets			Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts	$	(63,615	)	$	63,321		$	(294	)
Interest rate derivative contracts	(4,669		)	—			(4,669		)
Total derivative instruments	$	(68,284	)	$	63,321		$	(4,963	)

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 3 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 $349.3 million at December 31, 2015. 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, 2015. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis.

The change in fair value of our commodity and interest rate derivatives for the years ended December 31, 2015, 2014 and 2013 is as follows:



	2015			2014			2013
	(in thousands)
Derivative asset at January 1, net	$	220,734		$	66,711		$	82,568
Purchases
Fair value of derivatives acquired	195,273			(1,344		)	—
Premiums and fees paid or deferred for derivative contracts during the period	7,126			—			—
Net gains on commodity and interest rate derivative contracts	169,569			161,519			11,160
Settlements
Net cash settlements received on matured commodity derivative contracts	(211,723		)	(10,187		)	(30,905		)
Net cash settlements paid on matured interest rate derivative contracts	5,227			4,035			3,888
Termination of derivative contracts	(69,515		)	—			—
Derivative asset at December 31, net	$	316,691		$	220,734		$	66,711

5. 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

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liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value.

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes goodwill, acquisitions of oil and natural gas properties and other intangible assets and the initial measurement of asset retirement obligations. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as 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.

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 the 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 transparency 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.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Financing arrangements. The carrying amounts of our bank borrowings outstanding approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. The fair value of the Lease Financing Obligations is measured using market-based parameters of comparable term secured financing instruments and therefore we estimate that the carrying value approximates its fair value. The fair value measurements for our bank borrowings and the Lease Financing Obligations represent Level 2 inputs. As of December 31, 2015, the fair value of our Senior Notes due 2020 was estimated to be $165.4 million and our Senior Notes due 2019 was estimated to be $14.4 million. We consider the inputs to the valuation of both our Senior Notes due 2020 and our Senior Notes due 2019 to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution.

Derivative instruments. As of December 31, 2015, our commodity derivative instruments consist of fixed-price swaps, basis swap contracts, three-way collars, call options sold, put options sold and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps and basis swap contracts based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option values 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 rates used in the discounted cash flow projections are based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair values 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

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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. We consider the fair value estimates for these derivative instruments as a Level 2 input. We estimate the values of the range bonus accumulators using an option pricing model for both Asian Range Digital options and Asian Put options that takes into account market volatility, market prices and contract parameters. Range bonus accumulators are complex in structure requiring sophisticated valuation methods and greater subjectivity. As such, range bonus accumulators valuations may include inputs and assumptions that are less observable or require greater estimation, thereby resulting in valuations with less certainty. We consider the fair value estimates for range bonus accumulators as a Level 3 input.

Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):



	December 31, 2015
	Fair Value Measurements Using								Assets/Liabilities at Fair Value
	Level 1		Level 2			Level 3			Assets/Liabilities at Fair Value
	(in thousands)
Assets:
Commodity price derivative contracts	$	—	$	333,380		$	(5,933	)	$	327,447
Interest rate derivative contracts	—		(10,400		)	—			(10,400		)
Total derivative instruments	$	—	$	322,980		$	(5,933	)	$	317,047

Liabilities:
Commodity price derivative contracts	$	—	$	(99	)	$	—		$	(99	)
Interest rate derivative contracts	—		(257		)	—			(257		)
Total derivative instruments	$	—	$	(356	)	$	—		$	(356	)



	December 31, 2014
	Fair Value Measurements Using								Assets/Liabilities
	Level 1		Level 2			Level 3			at Fair value
	(in thousands)
Assets:
Commodity price derivative contracts	$	—	$	232,167		$	(6,470	)	$	225,697
Total derivative instruments	$	—	$	232,167		$	(6,470	)	$	225,697

Liabilities:
Commodity price derivative contracts	$	—	$	(294	)	$	—		$	(294	)
Interest rate derivative contracts	—		(4,669		)	—			(4,669		)
Total derivative instruments	$	—	$	(4,963	)	$	—		$	(4,963	)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

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	2015			2014
	(in thousands)
Unobservable inputs at January 1,	$	(6,470	)	$	566
Total gains (losses)	5,151			(8,238		)
Settlements	(4,614		)	1,202
Unobservable inputs at December 31,	$	(5,933	)	$	(6,470	)

Change in fair value included in earnings related to derivatives still held as of December 31,	$	(2,925	)	$	(6,326	)

During periods of market disruption, including periods of volatile oil and natural gas prices, there may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.

We apply the provisions of 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 assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas as well as any continued declines in the quoted market price of the Company’s units could change our estimates of the fair value of our reporting unit and could result in an impairment charge.

As of December 31, 2015, the Company performed the second step of the goodwill impairment test. The fair value amount of the assets and liabilities were calculated using a combination of a market and income approach as follows: equity, debt and certain oil and gas properties were valued using a market approach while the remaining balance sheet assets and liabilities were valued using an income approach. Furthermore, significant assumptions used in calculating the fair value of our oil and gas properties include: (i) observable forward prices for commodities at December 31, 2015 and (ii) a 10% discount rate, which was comparable to discount rates on recent transactions. Based on the results of the the second step of the goodwill impairment test, we recorded a non-cash goodwill impairment loss of $71.4 million for the year ended December 31, 2015. Based on further evaluation of qualitative factors, we determined that the goodwill impairment is primarily a result of the decline in the prices of oil and natural gas as well as deteriorating market conditions and the decline in the market price of our common units.

Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations. These assets and liabilities are recorded at fair value when acquired/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 6, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the years ended December 31, 2015 and 2014, in connection with the oil and natural gas properties acquired in all of our acquisitions, the LRE and Eagle Rock Mergers, as well as new wells drilled during each year, we incurred and recorded asset retirement obligations totaling $90.9 million and $52.8 million, respectively, at fair value. We also recorded a $22.3 million and a $4.1 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the years ended December 31, 2015 and 2014, respectively. The fair value of additions to the asset retirement obligation liability and certain changes in the estimated fair value of the liability are 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 4.6% and 5.5%; and (4) the average inflation factor (2.0%). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

6. 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:



	2015			2014
	(in thousands)
Asset retirement obligation at January 1,	$	149,062		$	87,967
Liabilities added during the current period	2,699			52,829
Liabilities added from the LRE and Eagle Rock Mergers	88,228			—
Accretion expense	10,238			5,889
Change in estimate	22,329			4,118
Disposition of properties	(262		)	(1,291		)
Retirements	(838		)	(450		)
Total asset retirement obligation at December 31,	271,456			149,062
Less: current obligations	(9,024		)	(2,386		)
Long-term asset retirement obligation at December 31,	$	262,432		$	146,676

Accretion expense for the years ended December 31, 2015, 2014 and 2013 was $10.2 million, $5.9 million and $2.8 million, respectively. Each year we review, and to the extent necessary, revise our asset retirement obligation estimates. During 2015 and 2014, we reviewed the actual abandonment costs with previous estimates and, as a result, increased our estimates of future asset retirement obligations by a net $22.3 million and $4.1 million, respectively, to reflect increased costs incurred for plugging and abandonment on certain wells.

7. Commitments and Contingencies

Transportation Demand Charges

As of December 31, 2015, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to five years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.

The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of December 31, 2015. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.



	(in thousands)
2016	$	14,957
2017	12,512
2018	11,696
2019	9,661
2020	410
Thereafter	—
Total	$	49,236

Development Commitments

We have commitments to third-party operators under joint operating agreements relating to the drilling and completion of oil and natural gas wells. Total estimated costs to be spent in 2016 is approximately $38.0 million.

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Legal Proceedings

We are defendants in certain legal proceedings arising in the normal course of our business. We are also a party to separate legal proceedings relating to each of the LRE Merger, the Eagle Rock Merger and our debt exchange. 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. 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.

8. Members’ Equity (Deficit) and Net Income (Loss) per Common and Class B Unit

Cumulative Preferred Units

The following table summarizes the Company’s Cumulative Preferred Units outstanding at December 31, 2015 and 2014:



				2015			2014
	Earliest Redemption Date	Liquidation Preference Per Share	Distribution Rate	Units Outstanding	Carrying Value (in thousands)		Units Outstanding	Carrying Value (in thousands)
Series A	June 15, 2023	$25.00	7.875%	2,581,873	$	62,200	2,581,873	$	62,200
Series B	April 15, 2024	$25.00	7.625%	7,000,000	$	169,265	7,000,000	$	169,265
Series C	October 15, 2024	$25.00	7.75%	4,300,000	$	103,979	4,300,000	$	103,979
Total Cumulative Preferred Units				13,881,873	$	335,444	13,881,873	$	335,444

The Series A, B and C Cumulative Preferred Units (collectively the “Cumulative Preferred Units”) have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above.

Common and Class B Units

The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units.

On October 15, 2014, our board of directors authorized a $10.0 million common unit buyback program. The program was approved for an initial three month period and authorized us to make open market purchases pursuant to the Securities and Exchange Commission guidelines of Rule 10b-18 promulgated under the Securities Exchange Act of 1934, as amended. We intend to hold the common units to fund our VNR LTIP (defined in Note 10) as directed by the Compensation Committee. As of December 31, 2015, since its inception, we have repurchased a total of 291,926 units under the common unit buyback program for an aggregate cost of $4.9 million.

The following is a summary of the changes in our common units issued during the years ended December 31, 2015, 2014 and 2013 (in thousands):

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	2015		2014		2013
Beginning of period	83,452		78,337		58,706
Issuance of Common units as consideration for the Eagle Rock Merger	27,886		—		—
Issuance of Common units as consideration for the LRE Merger	15,448		—		—
Issuance of Common units for the acquisition of oil and natural gas properties	—		—		1,075
Issuance of Common units for cash	2,430		4,864		18,377
Repurchase of units under the common unit buyback program	(157	)	(135	)	—
Unit-based compensation	1,418		386		179
End of period	130,477		83,452		78,337

There was no change in issued and outstanding Class B units during the years ended December 31, 2015, 2014 and 2013.

Net Income (Loss) per Common and Class B Unit

Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B 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. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of net income per unit.

The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income per common and Class B unit were as follows (in thousands, except per unit data):



	2015^(a)			2014		2013

Net income (loss) attributable to Common and Class B unitholders	$	(1,909,933	)	$	46,148	$	56,877
Weighted average number of Common and Class B units outstanding - basic	96,468			82,031		73,064
Effect of dilutive securities:
Phantom units	—			428		348
Weighted average number of Common and Class B units outstanding - diluted	96,468			82,459		73,412
Net income (loss) per Common and Class B unit
Basic	$	(19.80	)	$	0.56	$	0.78
Diluted	$	(19.80	)	$	0.55	$	0.77


(a)	For the year ended December 31, 2015, 164,984 phantom units were excluded from the calculation of diluted earnings per unit due to their antidilutive effect as we were in a loss position.

Distributions Declared

The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Cumulative Preferred Units are cumulative from the date of original issue and payable monthly in arrears on the 15th day of each month of each year, unless the 15th day falls on a weekend or holiday, in which case it will be paid on the next business day, when, as and if declared by our board of directors. Distributions on our Cumulative Preferred Units accumulate at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit.

We reduced our cash distribution per common unit to $0.03 starting with the cash distribution attributable to the month of November 2015, or $0.36 per unit on an annualized basis. This amount represents a reduction from the payment for the month of

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October 2015, which was $0.1175 per common unit or $1.41 per unit on an annualized basis. This new distribution rate takes into consideration current commodity and financial market conditions and helps to preserve our liquidity that will be directed at paying down debt under our Reserve-Based Credit Facility.

On January 20, 2016 and February 18, 2016, our board of directors declared cash distributions on the Cumulative Preferred Units and common and Class B units attributable to the month of December 2015 and January 2016, respectively. Also, on February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. Our ability to resume distributions is at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. See Note 12. Subsequent Events for further discussion.

The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to each period presented.



	Cash Distributions
Distribution	Per Unit		Declared Date	Record Date	Payment Date
2015
Fourth Quarter
November	$	0.0300	December 18, 2015	January 4, 2016	January 14, 2016
October	$	0.1175	November 20, 2015	December 1, 2015	December 15, 2015
Third Quarter
September	$	0.1175	October 19, 2015	November 2, 2015	November 13, 2015
August	$	0.1175	September 21, 2015	October 1, 2015	October 15, 2015
July	$	0.1175	August 20, 2015	September 1, 2015	September 14, 2015
Second Quarter
June	$	0.1175	July 16, 2015	August 3, 2015	August 14, 2015
May	$	0.1175	June 18, 2015	July 1, 2015	July 15, 2015
April	$	0.1175	May 19, 2015	June 1, 2015	June 12, 2015
First Quarter
March	$	0.1175	April 15, 2015	May 1, 2015	May 15, 2015
February	$	0.1175	March 18, 2015	April 1, 2015	April 14, 2015
January	$	0.1175	February 17, 2015	March 2, 2015	March 17, 2015
2014
Fourth Quarter
December	$	0.2100	January 22, 2015	February 2, 2015	February 13, 2015
November	$	0.2100	December 16, 2014	January 2, 2015	January 14, 2015
October	$	0.2100	November 20, 2014	December 1, 2014	December 15, 2014
Third Quarter
September	$	0.2100	October 20, 2014	November 3, 2014	November 14, 2014
August	$	0.2100	September 19, 2014	October 1, 2014	October 15, 2014
July	$	0.2100	August 19, 2014	September 2, 2014	September 12, 2014
Second Quarter
June	$	0.2100	July 16, 2014	August 1, 2014	August 14, 2014
May	$	0.2100	June 24, 2014	July 1, 2014	July 15, 2014
April	$	0.2100	May 20, 2014	June 2, 2014	June 13, 2014
First Quarter
March	$	0.2100	April 17, 2014	May 1, 2014	May 15, 2014
February	$	0.2100	March 17, 2014	April 1, 2014	April 14, 2014
January	$	0.2075	February 2, 2014	March 3, 2014	March 17, 2014
2013
Fourth Quarter
December	$	0.2075	January 16, 2014	February 3, 2014	February 14, 2014
November	$	0.2075	December 17, 2013	January 2, 2014	January 15, 2014

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October	$	0.2075	November 19, 2013	December 2, 2013	December 13, 2013
Third Quarter
September	$	0.2075	October 21, 2013	November 1, 2013	November 14, 2013
August	$	0.2075	September 12, 2013	October 1, 2013	October 15, 2013
July	$	0.2075	August 20, 2013	September 3, 2013	September 13, 2013
Second Quarter
June	$	0.2050	July 18, 2013	August 1, 2013	August 14, 2013
May	$	0.2050	June 20, 2013	July 1, 2013	July 15, 2013
April	$	0.2050	April 30, 2013	June 3, 2013	June 14, 2013
First Quarter
March	$	0.2025	April 19, 2013	May 1, 2013	May 15, 2013
February	$	0.2025	March 21, 2013	April 1, 2013	April 12, 2013
January	$	0.2025	February 18, 2013	March 1, 2013	March 15, 2013
2012
Fourth Quarter
December	$	0.2025	January 25, 2013	February 4, 2013	February 14, 2013

9. Unit-Based Compensation

Long-Term Incentive Plan

The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the board of directors of the Company to compensate employees, consultants, and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights.

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Restricted and Phantom Units

A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding.

The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period.

Executive Employment Agreements and Annual Bonus

In June and July 2013, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ended on January 1, 2016. The three executives have entered into an Amended and Restated Employment Agreement effective January 1, 2016 and ending on January 1, 2019.

The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. As of December 31, 2015, an accrued liability was recognized and compensation expense of $1.1 million was recorded for the year ended December 31, 2015, related to these bonus arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.

Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. The restricted units and phantom units granted to executives under the Amended Agreements are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. Both the restricted and phantom units include a tandem grant of DERs.

Restricted Unit Grants

In January 2015, the executives were granted a total of 360,762 restricted units in accordance with the Amended Agreements. Also, during the year ended December 31, 2015, our three independent board members were granted a total of 26,334 restricted units which will vest one year from the date of grant. The restricted units granted to the executives and our board members are accompanied by DERs. During 2015, VNR employees were also granted a total of 175,297 restricted units under the VNR LTIP of which 1,613 restricted units vested immediately. The remaining grants have vesting periods between three to four years from the date of grant.

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As of December 31, 2015, a summary of the status of the non-vested restricted units under the VNR LTIP is presented below:



	Number of Non-vested Restricted Units		Weighted Average Grant Date Fair Value
Non-vested units at December 31, 2014	440,047		$	28.87
Granted	562,393		$	15.17
Forfeited	(17,670	)	$	20.54
Non-vested Eagle Rock LTIP units replaced with VNR LTIP restricted units	143,647		$	9.01
Vested	(152,069	)	$	26.04
Non-vested units at December 31, 2015	976,348		$	18.29

The weighted average grant-date fair value of restricted units granted was $29.02 and $28.70 during the years ended December 31, 2014 and 2013, respectively.

At December 31, 2015, there was approximately $11.0 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.6 years. Our Consolidated Statements of Operations reflects non-cash compensation related to restricted unit grants of $16.9 million, $10.7 million and $3.4 million in the Selling, general and administrative expenses line item for the years ended December 31, 2015, 2014 and 2013, respectively.

Phantom Unit Grants

As of December 31, 2015, a summary of the status of the non-vested phantom units under the VNR LTIP is presented below:



	Number of Non-vested Phantom Units		Weighted Average Grant Date Fair Value
Non-vested units at December 31, 2014	330,321		$	28.58
Forfeited	(2,979	)	$	28.28
Vested	(124,240	)	$	21.57
Non-vested units at December 31, 2015	203,102		$	20.99

The weighted average grant-date fair value of phantom units granted was $28.29 during the year ended December 31, 2013. We did not grant any phantom units during the years ended December 31, 2015 and 2014.

At December 31, 2015, there was approximately $2.3 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.2 years. Compensation expense related to phantom units granted to executive officers, board members and employees of $1.7 million, $1.0 million and $2.6 million has been recognized in the selling, general and administrative expense line item in the Consolidated Statements of Operations for the years ended December 31, 2015, 2014, and 2013, respectively.

10. Shelf Registration Statements and Related Offerings

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We have also entered into an equity distribution agreement with respect to the issuance and sale of our Series A Cumulative Preferred Units, Series B Cumulative Preferred Units, Series C Cumulative Preferred Units and common units. Pursuant to the terms of the equity distribution agreement, we may sell from time to time through our sales agents, (i) our common units having an aggregate offering price of up to $400.0 million, (ii) our Series A Cumulative Preferred Units having an aggregate offering price of up to $50.0 million, (iii) our Series B Cumulative Preferred Units having an aggregate offering price of up to $100.0 million or (iv) our Series C Cumulative Preferred Units having an aggregate offering price of up to $75.0 million. The common units and Preferred Units to be sold under the equity distribution agreement are registered under our existing Shelf Registration Statement. During the year ended December 31, 2015, total net proceeds received under the equity distribution agreement were approximately $35.5 million, after commissions and fees of $0.6 million, from the sale of 2,430,170 common units.

Subsidiary Guarantors

We and VNRF, our wholly owned finance subsidiary, may co-issue securities pursuant to our effective shelf registration statement. 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 guaranteed 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.

The guarantees are also subject to certain customary release provisions. Such guarantees may be released in the following customary circumstances:


•	in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of the Company;


•	in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;


•	if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;


•	upon legal defeasance or satisfaction and discharge of the indenture;


•	upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;


•	at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or


•	upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.

11. Condensed Consolidating Financial Statements

As previously discussed, in connection with the Eagle Rock Merger, VO assumed the Senior Notes due 2019, which are jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of its subsidiaries. VO and all of the subsidiary guarantors are 100% owned by Vanguard. The guarantees are full and unconditional, subject to certain customary release provisions.

In accordance with Rule 3-10 of Regulation S-X, promulgated by the Securities and Exchange Commission, presented below are condensed consolidating financial statements as supplemental information. The following condensed consolidating balance sheet at December 31, 2015, and condensed consolidating statements of operations and cash flows for the year ended December 31, 2015, present financial information for VO as the issuer and Vanguard as the parent guarantor, each on a stand-alone basis, financial information for all of the subsidiary guarantors on a combined basis, and the consolidation and elimination entries necessary to arrive at the information for Vanguard on a consolidated basis. The financial information may not necessarily be indicative of the financial position or results of operations had VO or the subsidiary guarantors operated as independent entities. Vanguard has prepared the financial information below using the same accounting policies as the consolidated financial statements except for the use by VO and Vanguard of the equity method of accounting to reflect ownership interests in subsidiaries that are eliminated upon consolidation.

There are no restrictions on Vanguard’s ability to obtain cash dividends or other distributions of funds from VO or the subsidiary guarantors.

129

Condensed Consolidating Balance Sheet

As of December 31, 2015



	Parent			Issuer			Guarantors			Consolidating Entries			Total
	($ in thousands)
ASSETS:
Accounts receivable – affiliates	$	1,897,495		$	102,678		$	499,685		$	(2,499,858	)	$	—
Other current assets	—			94,946			263,576			—			358,522
Oil and natural gas properties	—			1,612,791			109,185			—			1,721,976
Total other long-term assets	7,449			530,914			90,436			—			628,799
Total assets	$	1,904,944		$	2,341,329		$	962,882		$	(2,499,858	)	$	2,709,297
LIABILITIES AND MEMBERS’ EQUITY (DEFICIT):
Accounts payable – affiliates	$	—		$	2,499,858		$	1,757		$	(2,499,858	)	$	1,757
Investment in subsidiaries	2,211,408			10,826			—			(2,222,234		)	$	—
Other current liabilities	16,394			165,442			18,415			—			200,251
Other long-term liabilities	—			230,149			72,939			—			303,088
Long-term debt	548,439			55,197			1,688,000			—			2,291,636
Members’ equity (deficit)	(871,297		)	(620,143		)	(818,229		)	2,222,234			(87,435		)
Total liabilities and equity	$	1,904,944		$	2,341,329		$	962,882		$	(2,499,858	)	$	2,709,297

Condensed Consolidating Statement of Operations

For the Year Ended December 31, 2015



	Parent		Issuer		Guarantors		Consolidating Entries	Total
	($ in thousands)
Total revenues	—		388,206		178,437		—	566,643
Operating expenses	—		183,044		4,186		—	187,230
Selling, general and administrative expenses	8,239		17,008		29,829		—	55,076
Depreciation, depletion, amortization and accretion	—		240,891		6,228		—	247,119
Impairment of oil and natural gas properties	—		1,806,319		35,998		—	1,842,317
Goodwill impairment loss	—		71,425		—		—	71,425
Income (loss) from operations	(8,239	)	(1,930,481	)	102,196		—	(1,836,524	)
Interest expense, net	(46,018	)	(375	)	(41,180	)	—	(87,573	)
Other non-operating income	—		41,644		(721	)	—	40,923
Income (loss) before equity in earnings of subsidiaries	(54,257	)	(1,889,212	)	60,295		—	(1,883,174	)
Equity in earnings (loss) of subsidiaries	(1,828,917	)	(37,911	)	—		1,866,828	—
Net Income (loss)	(1,883,174	)	(1,927,123	)	60,295		1,866,828	(1,883,174	)
Less: Preferred units distributions	(26,759	)	—		—		—	(26,759	)
Net income (loss) attributable to Common and Class B unitholders	(1,909,933	)	(1,927,123	)	60,295		1,866,828	(1,909,933	)

130

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2015



	Parent		Issuer		Guarantors		Consolidating Entries	Total
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash flows (used in) provided by operating activities	153,323		149,601		67,160		—	370,084
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment	—		(219	)	(425	)	—	(644	)
Additions to oil and natural gas properties	—		(111,738	)	(901	)	—	(112,639	)
Acquisitions of oil and natural gas properties and derivative contracts	—		(12,933	)	(37	)	—	(12,970	)
Cash transferred in the EROC and LRE Mergers	—		0		18,503		—	18,503
Proceeds from sale of oil and natural gas properties	—		1,777		—		—	1,777
Deposits and prepayments of natural gas and oil properties	—		(22,171	)	0		—	(22,171	)
Net cash flows provided by (used in) investing activities	—		(145,284	)	17,140		—	(128,144	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt			—		420,000		—	420,000
Repayment of debt			(4,317	)	(504,300	)	—	(508,617	)
Proceeds from common unit offerings, net	35,544		—		—		—	35,544
Repurchase of units under the common unit buyback program	(2,399	)	—		—		—	(2,399	)
Distributions to Preferred unitholders	(26,760	)	—		—		—	(26,760	)
Distributions to Common and Class B unitholders	(147,641	)	—		—		—	(147,641	)
Financing fees	(12,067	)	—		—		—	(12,067	)
Net cash flows used in financing activities	(153,323	)	(4,317	)	(84,300	)	—	(241,940	)
Net increase in cash and cash equivalents	—		—		—		—	—
Cash and cash equivalents at beginning of period	—		—		—		—	—
Cash and cash equivalents at end of period	—		—		—		—	—

12. Subsequent Events

Distributions

On January 20, 2016, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of December 2015 of $0.03 per common and Class B unit, or $0.36 on an annualized basis, that was paid on February 12, 2016 to Vanguard unitholders of record on February 1, 2016.

Also on January 20, 2016, our board of directors declared a cash distribution for our preferred unitholders attributable to the month of December 2015 of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit to that was paid on February 12, 2016 to Vanguard preferred unitholders of record on February 1, 2016.

On February 18, 2016, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of January 2016 of $0.03 per common and Class B unit, or $0.36 on an annualized basis, which will be paid on March 15, 2016 to Vanguard unitholders of record on March 1, 2016.

Also on February 18, 2016, our board of directors declared a cash distribution for our preferred unitholders attributable to the month of January 2016 of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.16146 per Series C Cumulative Preferred Unit, which will be paid on March 15, 2016 to Vanguard preferred unitholders of record on March 1, 2016.

131

On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution.

Debt Exchange

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of their outstanding 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”) in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued to certain eligible holders of Senior Notes due 2020 who validly tendered and did not validly withdraw their Senior Notes due 2020 pursuant to the terms of the Issuers’ exchange offer. Interest on the Senior Secured Second Lien Notes is payable on February 15 and August 15 of each year, beginning on August 15, 2016. The Senior Secured Second Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31, 2019, we have not repurchased, redeemed or otherwise repaid in full all of the Senior Notes due 2020 outstanding at that time in excess of $50.0 million in aggregate principal amount and, to the extent we repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain indebtedness, if such indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023.

132

Supplemental Selected Quarterly Financial Information

Financial information by quarter (unaudited) is summarized below.



	Quarters Ended
	March 31			June 30			September 30			December 31			Total
	(in thousands, except per unit amounts)
2015
Oil, natural gas and NGLs sales	$	98,894		$	95,841		$	90,827		$	111,665		$	397,227
Net gains (losses) on commodity derivative contracts	59,033			(20,800		)	64,328			66,855			169,416
Total revenues	$	157,927		$	75,041		$	155,155		$	178,520		$	566,643
Total costs and expenses⁽¹⁾	$	122,795		$	114,671		$	103,725		$	148,234		$	489,425
Impairment of oil and natural gas properties	$	132,610		$	733,365		$	491,487		$	484,855		$	1,842,317
Goodwill impairment loss	$	—		$	—		$	—		$	71,425		$	71,425
Net gains (losses) on acquisitions of oil and natural gas properties	$	—		$	—		$	(284	)	$	40,817		$	40,533
Net loss	$	(118,830	)	$	(793,645	)	$	(462,277	)	$	(508,422	)	$	(1,883,174	)
Distributions to Preferred unitholders	$	(6,690	)	$	(6,690	)	$	(6,690	)	$	(6,689	)	$	(26,759	)
Net loss attributable to Common and Class B unitholders	$	(125,520	)	$	(800,335	)	$	(468,967	)	$	(515,111	)	$	(1,909,933	)

Net loss per Common & Class B unit:
Basic	$	(1.49	)	$	(9.27	)	$	(5.39	)	$	(4.02	)	$	(19.80	)
Diluted	$	(1.49	)	$	(9.27	)	$	(5.39	)	$	(4.02	)	$	(19.80	)

2014
Oil, natural gas and NGLs sales	$	152,740		$	161,519		$	153,627		$	156,727		$	624,613
Net gains (losses) on commodity derivative contracts	(56,037		)	(38,398		)	83,311			174,576			163,452
Total revenues	$	96,703		$	123,121		$	236,938		$	331,303		$	788,065
Total costs and expenses ⁽¹⁾	$	97,103		$	110,194		$	108,961		$	135,907		$	452,165
Impairment of oil and natural gas properties	$	—		$	—		$	—		$	234,434		$	234,434
Net gains on acquisitions of oil and natural gas properties	$	32,114		$	—		$	2,409		$	—		$	34,523
Net income (loss)	$	15,121		$	(4,737	)	$	114,099		$	(60,138	)	$	64,345
Distributions to Preferred unitholders	$	(1,962	)	$	(4,596	)	$	(4,949	)	$	(6,690	)	$	(18,197	)
Net income (loss) attributable to Common and Class B unitholders	$	13,159		$	(9,333	)	$	109,150		$	(66,828	)	$	46,148

Net income (loss) per Common & Class B unit:
Basic	$	0.17		$	(0.12	)	$	1.31		$	(0.80	)	$	0.56
Diluted	$	0.16		$	(0.12	)	$	1.30		$	(0.80	)	$	0.55


(1)	Includes lease operating expenses, production and other taxes, depreciation, depletion, amortization and accretion, and selling, general and administration expenses.

133

Supplemental Oil and Natural Gas Information

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 Relating to Oil and Natural Gas Producing Activities

Capitalized costs related to oil, natural gas and NGLs producing activities and related accumulated depletion, amortization and accretion were as follows at December 31:



	2015			2014
	(in thousands)
Aggregate capitalized costs relating to oil, natural gas and NGLs producing activities	$	4,961,218		$	4,140,527
Aggregate accumulated depletion, amortization and impairment	(3,239,242		)	(1,164,721		)
Net capitalized costs	$	1,721,976		$	2,975,806

Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

Costs incurred in oil, natural gas and NGLs producing activities, whether capitalized or expensed, were as follows for the years ended December 31:



	2015		2014		2013
	(in thousands)
Property acquisition costs	$	707,853	$	1,474,841	$	332,874
Development costs	112,639		142,015		56,661
Total cost incurred	$	820,492	$	1,616,856	$	389,535

No internal costs or interest expense were capitalized in 2015, 2014 or 2013.

134

Oil and Natural Gas Reserves (Unaudited)

Net quantities of proved developed and undeveloped reserves of oil, natural gas and NGLs and changes in these reserves during the years ended December 31, 2015, 2014 and 2013 are presented below. Estimates of proved reserves at December 31, 2015 were based on studies performed by our internal reservoir engineers in accordance with guidelines established by the SEC. We engaged DeGolyer and MacNaughton (“D&M”), an independent petroleum engineering firm, to audit a substantial portion of our reserves.



	Gas (in MMcf)	Oil (in MBbls)		NGL (in MBbls)
Net proved reserves
January 1, 2013	546,513	42,218		18,940
Revisions of previous estimates	(9,589)	(765)		4,836
Extensions, discoveries and other	13,556	303		343
Purchases of reserves in place	86,245	6,649		6,553
Production	(50,236)	(3,089)		(1,477)
December 31, 2013	586,489	45,316		29,195
Revisions of previous estimates	(66,797)	(2,910)		(10,769)
Extensions, discoveries and other	2,927	465		22
Purchases of reserves in place	1,036,285	12,873		26,840
Sales of reserves in place	—	(2,394)		—
Production	(83,037)	(3,301)		(2,759)
December 31, 2014	1,475,867	50,049		42,529
Revisions of previous estimates	(133,234)	(4,208)		(2,151)
Extensions, discoveries and other	46,664	640		659
Purchases of reserves in place	271,504	21,826		20,836
Sales of reserves in place	—	(225	)	—
Production	(106,615)	(4,008)		(3,489)
December 31, 2015	1,554,186	64,074		58,384

Proved developed reserves
December 31, 2013	455,162	40,099		18,963
December 31, 2014	970,714	39,143		28,678
December 31, 2015	1,069,942	54,945		42,140

Proved undeveloped reserves
December 31, 2013	131,327	5,217		10,233
December 31, 2014	505,153	10,906		13,851
December 31, 2015	484,244	9,129		16,244

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. Our reserves increased by 120.1 Bcfe during the year ended December 31, 2013 due primarily to the acquisitions completed during 2013. Our reserves increased by 997.8 Bcfe during the year ended December 31, 2014 due primarily to the Pinedale Acquisition and Piceance Acquisition completed during 2014, offset by a revision of previous estimates primarily in the Arkoma Basin attributable to a change in our future development plan as a result of changes in commodity pricing and the production cost environment. Our reserves increased by 257.6 Bcfe during the year ended December 31, 2015 due primarily to the properties acquired in the LRE and Eagle Rock Mergers completed during 2015.

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

135

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, natural gas and NGLs 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, 2015.



	Bcfe
PUDs at January 1, 2015	653.7
Acquisitions	123.4
Revisions of prior estimates	(62.2	)
Conversion to developed	(78.4	)
PUDs at December 31, 2015	636.5

136

converting 34.5 Bcfe of volumes attributable to development drilling in Oklahoma on acreage acquired in the Eagle Rock Merger.



	Percent of Natural Gas Proved Undeveloped Reserves Expected to be Converted
2016	11%
2017	30%
2018	26%
2019	21%
2020	12%
Total	100%

Results of operations from producing activities were as follows for the years ended December 31:



	2015			2014			2013
	(in thousands)
Production revenues	$	397,227		$	624,613		$	443,248
Production costs ⁽¹⁾	(187,230		)	(194,389		)	(145,932		)
Depreciation, depletion and amortization	(234,944		)	(219,255		)	(163,122		)
Impairment of oil and natural gas properties	(1,842,317		)	(234,434		)	—
Results of operations from producing activities	$	(1,867,264	)	$	(23,465	)	$	134,194


(1)	Production cost includes lease operating expenses and production related taxes, including ad valorem and severance taxes.

The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at December 31 is as follows:



	2015			2014			2013
	(in thousands)
Future cash inflows	$	7,500,445		$	11,225,973		$	6,670,299
Future production costs	(3,105,260		)	(3,999,460		)	(2,352,721		)
Future development costs	(664,254		)	(845,872		)	(358,119		)
Future net cash flows	3,730,931			6,380,641			3,959,459
10% annual discount for estimated timing of cash flows	(2,008,434		)	(3,404,914		)	(2,125,488		)
Standardized measure of discounted future net cash flows	$	1,722,497		$	2,975,727		$	1,833,971

For the December 31, 2015, 2014, and 2013 calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using the average oil and natural gas price based upon the 12-month average price of $50.20, $94.87 and $96.90 per barrel of crude oil, respectively, $2.62, $4.36 and $3.67 per MMBtu for natural gas, respectively, adjusted for quality, transportation fees and a regional price differential, and the volume-weighted

137

average price of $16.14, $35.35 and $36.28 per barrel of NGLs. The NGLs prices were calculated using the differentials for each property to a West Texas Intermediate reference price of $50.20, $94.87 and $96.90 for the years ended December 31, 2015, 2014, and 2013, respectively. 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⁾
	2015			2014			2013
	(in thousands)
Sales and transfers, net of production costs	$	(209,997	)	$	(430,224	)	$	(297,316	)
Net changes in prices and production costs	(1,724,757		)	11,138			(13,797		)
Extensions discoveries and improved recovery, less related costs	17,039			24,841			24,110
Changes in estimated future development costs	278,883			36,564			43,496
Previously estimated development costs incurred during the period	63,624			68,817			56,661
Revision of previous quantity estimates	(141,045		)	(292,454		)	28,462
Accretion of discount	297,573			183,397			157,655
Purchases of reserves in place	526,245			1,621,571			333,530
Sales of reserves in place	(4,468		)	(48,163		)	—
Change in production rates, timing and other	(356,327		)	(33,731		)	(75,377		)
Net change	$	(1,253,230	)	$	1,141,756		$	257,424


(1)	This disclosure reflects changes in the standardized measure calculation excluding the effects of hedging activities.

138

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, 2015 at the reasonable assurance level.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2015, 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, 2015, 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, 2015. In making this assessment, we used the criteria established in Internal Control — Integrated Framework (2013) 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, 2015. The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report included herein.

139


(c)	Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


(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, 2015, based on criteria established in Internal Control — Integrated Framework (2013) 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. Controls and Procedures — 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, 2015, 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, 2015 and 2014, and the related consolidated statements of operations, members’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2015 and our report dated March 7, 2016 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, Texas

March 7, 2016

140

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, 2015.

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, 2015.

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, 2015.

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, 2015.

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, 2015.

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	95
Consolidated Statements of Operations	96
Consolidated Balance Sheets	97
Consolidated Statements of Members’ Equity (Deficit)	98
Consolidated Statements of Cash Flows	99
Notes to Consolidated Financial Statements	101
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)	133
Supplemental Oil and Natural Gas Information	134

(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
2.1*	Purchase Agreement and Plan of Merger, dated as of April 20, 2015, by and among Vanguard Natural Resources, LLC, Lighthouse Merger Sub, LLC, Lime Rock Management LP, Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P., Lime Rock Resources II-A, L.P., Lime Rock Resources II-C, L.P., LRR Energy, L.P. and LRE GP, LLC	Exhibit 2.1 to Form 8-K, filed April 22, 2015 by LRR Energy, L.P. (File No. 001-33016)
2.2*	Agreement and Plan of Merger, dated as of May 21, 2015, by and among Vanguard Natural Resources, LLC, Talon Merger Sub, LLC, Eagle Rock Energy Partners, L.P. and Eagle Rock Energy GP, L.P.	Exhibit 2.1 to Form 8-K, filed May 22, 2015 by Eagle Rock Energy Partners, L.P. (File No. 001-35344)
3.1	Fifth Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC	Exhibit 3.1 to Form 8-K, filed September 15, 2014 (File No. 001-33756)
4.1	Indenture, dated as of April 4, 2012, among Vanguard Natural Resources, LLC and VNR Finance Corp., as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank National Association, as trustee	Exhibit 4.1 to Form 8-K, filed April 4, 2012 (File No. 001-33756)
4.2	First Supplemental Indenture, dated as of April 4, 2012, among Vanguard Natural Resources, LLC and VNR Finance Corp., as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank National Association, as trustee	Exhibit 4.2 to Form 8-K, filed April 4, 2012 (File No. 001-33756)
4.3	Second Supplemental Indenture, dated as of December 9, 2015, among Vanguard Natural Resources, LLC and VNR Finance Corp., as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank National Association, as trustee	Filed herewith

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4.4	Form of 7.875% Senior Notes due 2020	Exhibit A to Exhibit 4.2 to Form 8-K, filed April 4, 2012 (File No. 001-33756)
4.5	Indenture, dated as of February 10, 2016, among Vanguard Natural Resources, LLC and VNR Finance Corp., as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank National Association, as trustee	Exhibit 4.1 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
4.6	First Supplemental Indenture, dated as of February 10, 2016, among Vanguard Natural Resources, LLC and VNR Finance Corp., as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank National Association, as trustee	Exhibit 4.2 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
4.7	Form of 7.0% Senior Secured Second Lien Notes due 2023	Exhibit A to Exhibit 4.2 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
4.8	Indenture, dated as of May 27, 2011, among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee	Exhibit 4.1 to Form 8-K, filed May 27, 2011 by Eagle Rock Energy Partners, L.P.
4.9	First Supplemental Indenture, dated as of June 28, 2011, among Eagle Rock Gas Services, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee	Exhibit 4.3 to Form 10-Q, filed August 4, 2011 by Eagle Rock Energy Partners, L.P.
4.10	Second Supplemental Indenture dated as of November 19, 2012, among Eagle Rock Crude Pipelines, LLC, a subsidiary of Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee	Exhibit 4.4 to Form S-4, filed November 20, 2012 by Eagle Rock Energy Partners, L.P.
4.11	Third Supplemental Indenture dated as of July 1, 2014, among Eagle Rock Energy Partners, L.P., Eagle Rock Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee	Exhibit 4.1 to Form 8-K, filed July 3, 2014 by Eagle Rock Energy Partners, L.P.
4.12	Fourth Supplemental Indenture effective as of October 8, 2015, among and Vanguard Operating, LLC, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank National Association, as trustee	Filed herewith
4.13	Registration Rights Agreement, dated April 18, 2007, by and among Vanguard Natural Resources, LLC and the private investors named therein	Exhibit 10.23 to Form S-1, filed April 25, 2007 (File No. 333-142363)
4.14	Amended and Restated Registration Rights Agreement, dated as of May 21, 2015, by and among Vanguard Natural Resources, LLC, Lime Rock Management LP, Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P., Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.	Exhibit 4.1 to Form 8-K, filed May 26, 2015 by LRR Energy, L.P. (File No. 001-35344)
4.15	Registration Rights Agreement, dated as of May 21, 2015, by and among Vanguard Natural Resources, LLC, Montierra Minerals & Production, L.P., Montierra Management LLC, Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., NGP Income Management L.L.C., Eagle Rock Holdings NGP 7, LLC, Eagle Rock Holdings NGP 8, LLC, ERH NGP 7 SPV, LLC, ERH NGP 8 SPV, LLC, NGP Income Co-Investment Opportunities Fund II, L.P. and NGP Energy Capital Management, L.L.C.	Exhibit 4.1 to Form 8-K (File No. 001-33756)
4.16	Specimen Unit Certificate for the Series A Cumulative Redeemable Perpetual Preferred Units	Exhibit B to Exhibit 3.1 to Form 8-K, filed September 15, 2014 (File No. 001-33756)
4.17	Specimen Unit Certificate for the Series B Cumulative Redeemable Perpetual Preferred Units	Exhibit C to Exhibit 3.1 to Form 8-K, filed September 15, 2014 (File No. 001-33756)
4.18	Specimen Unit Certificate for the Series C Cumulative Redeemable Perpetual Preferred Units	Exhibit D to Exhibit 3.1 to Form 8-K, filed September 15, 2014 (File No. 001-33756)
10.1+	Vanguard Natural Resources, LLC Long-Term Incentive Plan	Exhibit 10.1 to Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.2+	First Amendment to the Vanguard Natural Resources, LLC Long-Term Incentive Plan	Exhibit 10.1 to Form 10-Q, filed November 2, 2012 (File No. 001-33756)

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10.3+	Form of Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options Grant Agreement	Exhibit 10.5 to Form S-1, filed April 25, 2007 (File No. 333-142363)
10.4+	Vanguard Natural Resources, LLC Class B Unit Plan	Exhibit 10.2 to Form 8-K, filed October 24, 2007 (File No. 001-33756)
10.5+	Form of Vanguard Natural Resources, LLC Class B Unit Plan Restricted Class B Unit Grant	Exhibit 10.7 to Form S-1, filed April 25, 2007 (File No. 333-142363)
10.6+	Director Compensation Agreement	Exhibit 10.31 to Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.7+	Form of Indemnity Agreement, dated August 7, 2008	Exhibit 10.32 to Form 10-Q, filed August 13, 2008 (File No. 001-33756)
10.8+	Phantom Unit Award Agreement, dated August 1, 2012, by and between Vanguard Natural Resources, LLC, and Scott W. Smith	Exhibit 10.1 to Form 8-K, filed August 6, 2012 (File No. 001-33756)
10.9+	Phantom Unit Award Agreement, dated August 1, 2012, by and between Vanguard Natural Resources, LLC, and Richard Robert	Exhibit 10.2 to Form 8-K, filed August 6, 2012 (File No. 001-33756)
10.10+	Phantom Unit Award Agreement, dated August 1, 2012, by and between Vanguard Natural Resources, LLC, and Britt Pence	Exhibit 10.3 to Form 8-K, filed August 6, 2012 (File No. 001-33756)
10.11+	Amended and Restated Employment Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC and Scott W. Smith	Exhibit 10.1 to Form 8-K, filed June 12, 2013 (File No. 001-33756)
10.12+	Amended and Restated Employment Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC and Richard A. Robert	Exhibit 10.2 to Form 8-K, filed June 12, 2013 (File No. 001-33756)
10.13+	Form of Restricted Unit Award Agreement	Exhibit 10.3 to Form 8-K, filed June 12, 2013 (File No. 001-33756)
10.14+	Form of Phantom Unit Award Agreement	Exhibit 10.4 to Form 8-K, filed June 12, 2013 (File No. 001-33756)
10.15+	Amended and Restated Employment Agreement, by and between Vanguard Natural Resources, LLC, VNR Holdings, LLC and Britt Pence	Exhibit 10.1 to Form 8-K, filed July 11, 2013 (File No. 001-33756)
10.16+	Form of Restricted Unit Award Agreement	Exhibit 10.2 to Form 8-K, filed July 11, 2013 (File No. 001-33756)
10.17+	Form of Phantom Unit Award Agreement	Exhibit 10.3 to Form 8-K, filed July 11, 2013 (File No. 001-33756)
10.18+	Amended and Restated Eagle Rock Energy Partners Long-Term Incentive Plan, dated October 8, 2015	Exhibit 10.1 to Form 8-K, filed October 8, 2015 (File No. 001-33756)
10.19	Amended and Restated Indemnity Agreement, dated September 11, 2007, 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	Exhibit 10.18 to Form S-1/A, filed September 18, 2007 (File No. 333-142363)
10.20	Purchase Agreement, dated April 18, 2007, by and among Vanguard Natural Resources, LLC, Majeed S. Nami and the private investors named therein	Exhibit 10.24 to Form S-1, filed April 25, 2007 (File No. 333-142363)
10.21	Purchase and Sale Agreement, dated November 16, 2010, by and 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.	Exhibit 2.1 to Form 8-K, filed November 17, 2010 (File No. 001-33756)
10.22	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.	Exhibit 10.1 to Form 8-K, filed June 23, 2011 (File No. 001-33756)
10.23	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.	Exhibit 10.2 to Form 8-K, filed June 23, 2011 (File No. 001-33756)

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10.24	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	Exhibit 2.1 to Form 8-K, filed July 11, 2011 (File No. 001-33756)
10.25	Unit Exchange Agreement, dated February 21, 2012, by and among Vanguard Natural Gas, LLC, Vanguard Natural Resources, LLC, Majeed S. Nami Personal Endowment Trust and Majeed S. Nami Irrevocable Trust	Exhibit 10.1 to Form 8-K, filed February 29, 2012 (File No. 001-33756)
10.26	Purchase and Sale Agreement, dated June 1, 2012, by and between Vanguard Permian, LLC and Antero Resources Corporation	Exhibit 10.1 to Form 8-K, filed June 4, 2012 (File No. 001-33756)
10.27	Purchase and Sale Agreement, dated October 31, 2012, by and among Bill Barrett Corporation, Bill Barrett CBM Corporation, Encore Energy Partners Operating, LLC and Vanguard Natural Resources, LLC	Exhibit 10.1 to Form 8-K, filed November 5, 2012 (File No. 001-33756)
10.28	Purchase and Sale Agreement, dated November 9, 2012, by and between Encore Energy Partners Operating, LLC and Halliburton Energy Services, Inc.	Exhibit 10.1 to Form 8-K, filed November 15, 2012 (File No. 001-33756)
10.29	Purchase and Sale Agreement, dated February 26, 2013, by and among Vanguard Permian, LLC, Range Texas Production, LLC and Range Operating New Mexico, LLC	Exhibit 10.1 to Form 8-K, filed March 4, 2013 (File No. 001-33756)
10.30	Purchase and Sale Agreement, dated December 23, 2013, by and between Encore Energy Partners Operating, LLC and Anadarko E&P Onshore LLC	Exhibit 10.1 to Form 8-K, filed December 30, 2013 (File No. 001-33756)
10.31	Purchase and Sale Agreement, dated July 30, 2014, by and among Vanguard Permian, LLC, Hunt Oil Company and Hunt Oil Company of Louisiana, Inc.	Exhibit 10.1 to Form 8-K, filed August 7, 2014 (File No.001-33756)
10.32	First Amendment To Purchase and Sale Agreement and Assignment, dated August 29, 2014, by and among Vanguard Permian, LLC, Vanguard Operating, LLC, Hunt Oil Company and Hunt Oil Company of Louisiana, Inc.	Exhibit 10.1 to Form 8-K/A, filed September 4, 2014 (File No. 001-33756)
10.33	Purchase and Sale Agreement, dated September 15, 2014, by and among Vanguard Operating, LLC, Vanguard Natural Resources, LLC and Bill Barrett Corporation	Exhibit 2.1 to Form 8-K, filed September 16, 2014 (File No. 001-33756)
10.34	Amended and Restated Voting and Support Agreement, dated as of May 21, 2015, by and among Vanguard Natural Resources, LLC, Lime Rock Resources A, L.P., Lime Rock Resources B, L.P., Lime Rock Resources C, L.P. LRR Energy, L.P., LRE GP, LLC, and, solely for purpose of certain specified sections, Lime Rock Management LP, Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P.	Exhibit 10.1 to Form 8-K, filed May 26, 2015 by LRR Energy, L.P. (File No. 001-35344)
10.35*	Voting and Support Agreement, dated as of May 21, 2015, by and among Vanguard Natural Resources, LLC, Montierra Minerals & Production, L.P., Montierra Management LLC, Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., NGP Income Management L.L.C., Eagle Rock Holdings NGP 7, LLC, Eagle Rock Holdings NGP 8, LLC, ERH NGP 7 SPV, LLC, ERH NGP 8 SPV, LLC, NGP Income Co-Investment Opportunities Fund II, L.P., NGP Energy Capital Management, L.L.C., and, solely for the purpose of certain specified sections, Eagle Rock Energy Partners, L.P. and Eagle Rock Energy GP, L.P.	Exhibit 2.2 to Form 8-K, filed May 22, 2016 by Eagle Rock Energy Partners, L.P. (File No. 001-33016)
10.36	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	Exhibit 10.1 to Form 8-K, filed October 5, 2011 (File No. 001-33756)
10.37	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.	Exhibit 10.2 to Form 8-K, filed December 2, 2011 (File No. 001-33756)

144



10.38	Second Amendment, dated June 29, 2012, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.1 to Form 8-K, filed July 10, 2012 (File No. 001-33756)
10.39	Third Amendment, dated December 31, 2012, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.53 to Form 10-K, filed March 1, 2013 (File No. 001-33756)
10.40	Fourth Amendment, dated April 16, 2013, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.5 to Form 10-Q, filed August 1, 2013 (File No. 001-33756)
10.41	Fifth Amendment, dated November 5, 2013, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.31 to Form 10-K, filed February 28, 2014 (File No. 001-33756)
10.42	Sixth Amendment, dated April 30, 2014, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.1 to Form 8-K, filed May 2, 2014 (File No. 001-33756)
10.43	Seventh Amendment, dated October 30, 2014, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.1 to Form 10-Q, filed May 4, 2015 (File No. 001-33756)
10.44	Eighth Amendment, dated June 3, 2015, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.1 to Form 8-K, filed June 4, 2015 (File No. 001-33756)
10.45	Ninth Amendment, dated June 3, 2015, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party thereto	Exhibit 10.1 to Form 8-K, filed November 12, 2015 (file No. 001-33756)
10.46	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.	Exhibit 10.3 to Form 8-K, filed December 2, 2011 (File No. 001-33756)
10.47	Second Lien Pledge and Security Agreement, dated as of February 10, 2016, by and among Vanguard Natural Resources, LLC, VNR Finance Corp. and U.S. Bank National Association, as collateral agent	Exhibit 10.1 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
10.48	Second Lien Pledge and Security Agreement, dated as of February 10, 2016, by and among certain subsidiaries and affiliates of Vanguard Natural Resources, LLC and U.S. Bank National Association, as collateral agent	Exhibit 10.2 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
10.49	Intercreditor Agreement, dated as of February 10, 2016, by and among Citibank, N.A., as priority lien agent, and U.S. Bank National Association, as second lien collateral trustee, and acknowledged and agreed to by Vanguard Natural Gas, LLC, VNR Finance Corp. and Vanguard Natural Resources, LLC	Exhibit 10.3 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
10.50	Collateral Trust Agreement, dated as of February 10, 2016, by and among Vanguard Natural Resources, LLC, VNR Finance Corp., the grantors and guarantors named therein and U.S. Bank National Association as trustee and as collateral trustee	Exhibit 10.4 to Form 8-K, filed February 17, 2016 (File No. 001-33756)
12.1	Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Unit Distributions	Filed herewith
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	Filed herewith
24.1	Power of Attorney (included on signature page hereto)	Filed herewith

145



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	Furnished 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	Furnished herewith
99.1	Report of DeGolyer and MacNaughton, Independent Petroleum Engineers and Geologists	Filed herewith
101.INS	XBRL Instance Document	Filed herewith
101.SCH	XBRL Schema Document	Filed herewith
101.CAL	XBRL Calculation Linkbase Document	Filed herewith
101.DEF	XBRL Definition Linkbase Document	Filed herewith
101.LAB	XBRL Label Linkbase Document	Filed herewith
101.PRE	XBRL Presentation Linkbase Document	Filed herewith

* Certain schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission upon request.
+ Management Contract or Compensatory Plan or Arrangement required to be filed as an exhibit hereto pursuant to item 601 of Regulation S-K.

146

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 7th day of March, 2016.



VANGUARD NATURAL RESOURCES, LLC
		/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 7, 2016	/s/ Scott W. Smith
	Scott W. Smith
	President, Chief Executive Officer and Director
	(Principal Executive Officer)

March 7, 2016	/s/ Richard A. Robert
	Richard A. Robert
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer and Principal Accounting Officer)

March 7, 2016	/s/ W. Richard Anderson
	W. Richard Anderson
	Director

March 7, 2016	/s/ Bruce W. McCullough
	Bruce W. McCullough
	Director

March 7, 2016	/s/ Loren B. Singletary
	Loren B. Singletary
	Director

147

Contract Period

Put Price ($/Bbl)

January 1, 2016 – December 31, 2016