Vanguard Natural Resources, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.	vnr2015q310-qexhibit32x2.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.	vnr2015q310-qexhibit31x1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.	vnr2015q310-qexhibit31x2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.	vnr2015q310-qexhibit32x1.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q




	(Mark One)
	x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2015
	OR
	o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-33756

Vanguard Natural Resources, LLC

(Exact Name of Registrant as Specified in Its Charter)



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



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

(832) 327-2255

(Registrant’s Telephone Number, Including Area Code)

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. x Yes o No

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). x Yes o No

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.



x	Large accelerated filer	o	Accelerated filer
o	Non-accelerated filer	o	Smaller reporting company
	(Do not check if a smaller reporting company)

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

o Yes x No

Common units outstanding on November 5, 2015: 130,464,658.

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

TABLE OF CONTENTS



		Page

PART I – FINANCIAL INFORMATION
Item 1.	Unaudited Consolidated Financial Statements
	Consolidated Statements of Operations	3
	Consolidated Balance Sheets	4
	Consolidated Statements of Members’ Equity	5
	Consolidated Statements of Cash Flows	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	51

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	54

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 NGLs and oil 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” or “our operating subsidiary”), VNR Holdings, LLC (“VNRH”), Vanguard Permian, LLC (“Vanguard Permian”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Energy Partners Operating LLC (“OLLC”) and Encore Clear Fork Pipeline LLC.

Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” Statements included in this Quarterly Report on Form 10-Q that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

These statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in the Risk Factors section of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the “2014 Annual Report”), and this Quarterly Report on Form 10-Q, and those set forth from time to time in our filings with the Securities and Exchange Commission (the “SEC”), which are available on our website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and Retrieval System at www.sec.gov.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

PART I – FINANCIAL INFORMATION

Item 1. Unaudited Consolidated Financial Statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Revenues:
Oil sales	$	33,624		$	69,034		$	113,425		$	211,197
Natural gas sales	50,851			67,827			146,502			201,175
NGLs sales	6,352			16,766			25,635			55,514
Net gains (losses) on commodity derivative contracts	64,328			83,311			102,561			(11,125		)
Total revenues	155,155			236,938			388,123			456,761

Costs and expenses:
Production:
Lease operating expenses	34,169			31,011			101,247			95,726
Production and other taxes	9,082			15,130			31,262			46,693
Depreciation, depletion, amortization, and accretion	52,428			55,680			182,443			150,798
Impairment of oil and natural gas properties	491,487			—			1,357,462			—
Selling, general and administrative expenses	8,046			7,140			26,239			23,042
Total costs and expenses	595,212			108,961			1,698,653			316,259

Income (loss) from operations	(440,057		)	127,977			(1,310,530		)	140,502

Other income (expense):
Interest expense	(21,130		)	(16,721		)	(61,693		)	(49,529		)
Net gains (losses) on interest rate derivative contracts	(807		)	511			(2,291		)	(1,068		)
Net gains (losses) on acquisitions of oil and natural gas properties	(284		)	2,409			(284		)	34,523
Other	1			(77		)	46			54
Total other income (expense), net	(22,220		)	(13,878		)	(64,222		)	(16,020		)
Net income (loss)	$	(462,277	)	$	114,099		$	(1,374,752	)	$	124,482
Distributions to Preferred unitholders	(6,690		)	(4,949		)	(20,070		)	(11,507		)
Net income (loss) attributable to Common and Class B unitholders	$	(468,967	)	$	109,150		$	(1,394,822	)	$	112,975

Net income (loss) per Common and Class B units
Basic	$	(5.39	)	$	1.31		$	(16.25	)	$	1.39
Diluted	$	(5.39	)	$	1.30		$	(16.25	)	$	1.38
Weighted average Common units outstanding
Common units – basic	86,592			83,105			85,414			80,957
Common units – diluted	86,592			83,333			85,414			81,231
Class B units – basic & diluted	420			420			420			420

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(Unaudited)



	September 30, 2015			December 31, 2014
Assets
Current assets
Cash and cash equivalents	$	19,490		$	—
Trade accounts receivable, net	66,200			140,017
Derivative assets	139,901			142,114
Other current assets	11,119			4,102
Total current assets	236,710			286,233

Oil and natural gas properties, at cost	4,257,859			4,140,527
Accumulated depletion, amortization and impairment	(2,695,554		)	(1,164,721		)
Oil and natural gas properties evaluated, net – full cost method	1,562,305			2,975,806

Other assets
Goodwill	420,955			420,955
Derivative assets	62,890			83,583
Other assets	30,529			27,015
Total assets	$	2,313,389		$	3,793,592

Liabilities and members’ equity
Current liabilities
Accounts payable:
Trade	$	17,682		$	15,118
Affiliates	1,512			823
Accrued liabilities:
Lease operating	13,152			19,822
Development capital	9,274			24,706
Interest	21,987			11,517
Production and other taxes	47,155			29,981
Derivative liabilities	636			3,583
Oil and natural gas revenue payable	22,192			40,117
Distributions payable	11,241			18,640
Other	20,770			14,297
Total current liabilities	165,601			178,604
Long-term debt	1,889,674			1,932,816
Derivative liabilities	473			1,380
Asset retirement obligations, net of current portion	173,898			146,676
Other long-term liabilities	730			—
Total liabilities	2,230,376			2,259,476
Commitments and contingencies (Note 7)
Members’ equity (Note 8)
Cumulative Preferred units, 13,881,873 units issued and outstanding at September 30, 2015 and December 31, 2014	335,444			335,444
Common units, 86,597,301 units issued and outstanding at September 30, 2015 and 83,451,746 at December 31, 2014	(260,046		)	1,191,057
Class B units, 420,000 issued and outstanding at September 30, 2015 and December 31, 2014	7,615			7,615
Total members’ equity	83,013			1,534,116
Total liabilities and members’ equity	$	2,313,389		$	3,793,592

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015 AND THE YEAR ENDED DECEMBER 31, 2014

(in thousands)

(Unaudited)



	Cumulative Preferred Units		Common Units			Class B		Total Members’ Equity
Balance at January 1, 2014	$	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, net of offering costs of $589	—		35,549			—		35,549
Distributions to Preferred unitholders (see Note 8)	—		(20,070		)	—		(20,070		)
Distributions to Common and Class B unitholders (see Note 8)	—		(99,163		)	—		(99,163		)
Repurchase of units under the common unit buyback program	—		(2,399		)	—		(2,399		)
Unit-based compensation	—		9,732			—		9,732
Net loss	—		(1,374,752		)	—		(1,374,752		)
Balance at September 30, 2015	$	335,444	$	(260,046	)	$	7,615	$	83,013

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)



	Nine Months Ended
	September 30,
Operating activities	2015			2014
Net income (loss)	$	(1,374,752	)	$	124,482
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	182,443			150,798
Impairment of oil and natural gas properties	1,357,462			—
Amortization of deferred financing costs	3,058			2,586
Amortization of debt discount	216			199
Compensation related items	9,732			5,437
Net (gains) losses on commodity and interest rate derivative contracts	(100,270		)	12,193
Cash settlements received (paid) on matured commodity derivative contracts	125,988			(13,347		)
Cash settlements paid on matured interest rate derivative contracts	(2,968		)	(3,026		)
Net (gains) losses on acquisitions of oil and natural gas properties	284			(34,523		)
Changes in operating assets and liabilities:
Trade accounts receivable	73,817			(32,248		)
Other current assets	(7,012		)	(1,991		)
Premiums paid on commodity derivative contracts	(794		)	—
Accounts payable and oil and natural gas revenue payable	(15,360		)	8,449
Payable to affiliates	689			331
Accrued expenses and other current liabilities	4,716			26,733
Other assets	8,070			(384		)
Net cash provided by operating activities	265,319			245,689
Investing activities
Additions to property and equipment	(329		)	(1,148		)
Additions to oil and natural gas properties	(80,213		)	(79,514		)
Acquisitions of oil and natural gas properties	(13,004		)	(1,303,035		)
Deposits and prepayments of oil and natural gas properties	(13,419		)	(4,957		)
Proceeds from the sale of leasehold interests	—			1,950
Net cash used in investing activities	(106,965		)	(1,386,704		)
Financing activities
Proceeds from long-term debt	117,500			1,321,000
Repayment of long-term debt	(160,721		)	(406,000		)
Proceeds from Preferred unit offerings, net	—			274,521
Proceeds from Common unit offerings, net	35,549			147,841
Repurchase of units under the Common unit buyback program	(2,399		)	—
Distributions to Preferred unitholders	(20,070		)	(10,600		)
Distributions to Common and Class B unitholders	(106,562		)	(153,410		)
Financing fees	(2,161		)	(199		)
Net cash provided by (used in) financing activities	(138,864		)	1,173,153
Net increase cash and cash equivalents	19,490			32,138
Cash and cash equivalents, beginning of period	—			11,818
Cash and cash equivalents, end of period	$	19,490		$	43,956



Supplemental cash flow information:
Cash paid for interest	$	47,718	$	36,143
Non-cash investing activity:
Asset retirement obligations, net	$	24,300	$	51,081
Fair value of derivatives acquired	$	31,421	$	—
Fair value of terminated derivative contracts	$	28,517	$	—

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Description of the Business:

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 September 30, 2015, we own properties and oil and natural gas reserves primarily located in nine operating areas:


•	the Green River Basin in Wyoming;


•	the Piceance Basin in Colorado;


•	the Permian Basin in West Texas and New Mexico;


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


•	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.

1. Summary of Significant Accounting Policies

The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2014, from the audited financial statements contained in our 2014 Annual Report. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2014 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year.

As of September 30, 2015, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2014 Annual Report.


(a)	Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014 include our accounts and those of our subsidiaries. We present our financial statements in accordance with GAAP. All intercompany transactions and balances have been eliminated upon consolidation. 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 (loss) or members’ equity.


(b)	Oil and Natural Gas Properties:

The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values.

Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, the “12-month average price” discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge.

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the nine months ended September 30, 2015 of $1.4 billion as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015, June 30, 2015 and September 30, 2015. The impairment for the first quarter of 2015 was $132.6 million and was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The impairment for the second quarter of 2015 was $733.4 million and was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. The impairment for the third quarter of 2015 was $491.5 million and was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil. No ceiling test impairment was required during the nine months ended September 30, 2014.

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.


(c)	New Pronouncement Issued But Not Yet Adopted:

In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. The standard provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures).

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 should 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.

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.

The amendments under ASU No. 2015-16 also require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of 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 with earlier application permitted for financial statements that have not been issued. The only disclosures required at transition should be the nature of and reason for the change in accounting principle. An entity should disclose that information in the first annual period of adoption and in the interim periods within the first annual period if there is a measurement-period adjustment during the first annual period in which the changes are effective. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements.


(d)	Use of Estimates:

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and 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.

2. Acquisitions

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 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.

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

On October 5, 2015, Vanguard completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015, pursuant to which a subsidiary of Vanguard merged into LRR Energy, L.P. and, at the same time, Vanguard acquired LRE GP, LLC, the general partner of LRR Energy, L.P. See Note 11. Subsequent Events for further discussion.

On October 8, 2015, Vanguard completed the merger with Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and pursuant the terms of the merger agreement, Eagle Rock has become a wholly-owned indirect subsidiary of Vanguard. See Note 11. Subsequent Events for further discussion.

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.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility (as defined below). 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.



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 $496.4 million in cash with an effective date of July 1, 2014. We refer to this acquisition as the “Piceance Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility. 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	$	523,537
Asset retirement obligations	(19,452		)
Production and ad valorem taxes payable	(7,552		)
Suspense liabilities	(445		)
Other	(124		)
Total fair value of assets and liabilities acquired	495,964
Fair value of consideration transferred	496,391
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 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. The effective date of the acquisition is 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 $265.1 million. We refer to this acquisition as the “Gulf Coast Acquisition.” The purchase price was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is 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 which was funded with borrowings under our existing Reserve-Based Credit Facility.

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and nine months ended September 30, 2014 to show the effect on our consolidated results of operations as if our acquisitions completed in 2014 had occurred on January 1, 2013.

The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2014, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The net gains on acquisitions of oil and natural gas properties was excluded from the pro forma results for the three and nine months ended September 30, 2014. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:



	Pro forma
	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
	(in thousands, except per unit data)
Total revenues	$	275,547	$	613,584
Net income attributable to Common and Class B unitholders	$	118,458	$	134,928
Net income per Common and Class B unit:
Basic	$	1.42	$	1.66
Diluted	$	1.41	$	1.65

Post-Acquisition Operating Results

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for our 2014 acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(in thousands)
Pinedale Acquisition
Revenues	$	22,098	$	36,947	$	66,445	$	106,163
Excess of revenues over direct operating expenses	$	14,694	$	29,423	$	44,598	$	82,709
Piceance Acquisition
Revenues	$	9,081	$	283	$	28,811	$	283
Excess of revenues over direct operating expenses	$	4,310	$	227	$	15,237	$	227
Other acquisitions
Revenues	$	9,987	$	8,671	$	28,720	$	11,831
Excess of revenues over direct operating expenses	$	5,522	$	5,868	$	15,836	$	7,970

3. Long-Term Debt

Our financing arrangements consisted of the following as of the date indicated:



			Amount Outstanding
Description	Interest Rate	Maturity Date	September 30, 2015			December 31, 2014
			(in thousands)
Senior Secured Reserve-Based Credit Facility	Variable(1)	April 16, 2018	$	1,320,000		$	1,360,000
Senior Notes	7.875% (2)	April 1, 2020	550,000			550,000
Lease Financing Obligation	4.16%	August 10, 2020 (3)	$	25,764		28,986
			$	1,895,764		$	1,938,986
Less:
Unamortized discount on Senior Notes			(1,636		)	(1,852		)
Current portion of Lease Financing Obligation			(4,454		)	(4,318		)
Total long-term debt			$	1,889,674		$	1,932,816


(1)	Variable interest rate was 2.45% and 2.17% at September 30, 2015 and December 31, 2014, respectively.


(2)	Effective interest rate was 8.0%.


(3)	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

The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and an initial borrowing base of $1.6 billion (the “Reserve-Based Credit Facility”). As of September 30, 2015, there were approximately $1.32 billion of outstanding borrowings and $275.5 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of 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 which became effective upon closing of the LRE Merger 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 starting in 2017 and beyond.

Interest rates under the Reserve-Based Credit Facility are based on Eurodollar (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 September 30, 2015, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Grid



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

Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios. 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 total 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 starting 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 September 30, 2015, we were in compliance with all of our debt covenants.

Letters of Credit

At September 30, 2015, we have 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.

Senior Notes

We have $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due 2020 (the “Senior Notes”). The issuers of the Senior Notes are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes (the “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, subject to certain customary release provisions, including: (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 Indenture; (iv) upon legal defeasance or covenant defeasance or the discharge of the 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 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 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Indenture exists, many of the foregoing covenants will terminate. At September 30, 2015, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, approximately $234.5 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.

Interest on the Senior Notes is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a “make-whole” premium. 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 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively.

Lease Financing Obligations

On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement, whereby we acquired compressors and 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 current fair market value. The Lease Financing Obligations also contain an early buyout option whereby 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%.

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 is 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 September 30, 2015, the Company had open commodity derivative contracts covering our anticipated future production as follows:

Fixed-Price Swaps



	Gas			Oil			NGLs
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average WTI Price		Bbls	Weighted Average Fixed Price
October 1, 2015 – December 31, 2015	22,436,000	$	4.26	602,600	$	71.94	62,100	$	46.34
January 1, 2016 – December 31, 2016	55,083,000	$	4.47	329,400	$	76.10	567,300	29.96
January 1, 2017 – December 31, 2017	24,027,000	$	4.35	—	$	—	—	$	—

Call Options Sold



	Gas			Oil
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average Fixed Price
October 1, 2015 – December 31, 2015	—	—		18,400	$	105.00
January 1, 2016 – December 31, 2016	9,150,000	$	4.25	622,200	$	125.00
January 1, 2017 – December 31, 2017	9,125,000	$	4.50	365,000	$	95.00

Swaptions



	Gas
Contract Period	MMBtu	Weighted Average Fixed Price
October 1, 2015 – December 31, 2015	610,000	$	3.50
January 1, 2016 – December 31, 2016	910,000	$	3.50

Basis Swaps



	Gas
Contract Period	MMBtu	Weighted Avg. Basis Differential ($/MMBtu)			Pricing Index
October 1, 2015 – December 31, 2015	7,360,000	$	(0.28	)	Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2016 – December 31, 2016	21,960,000	$	(0.23	)	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



	Oil
Contract Period	Bbls	Weighted Avg. Basis Differential ($/Bbl)			Pricing Index
October 1, 2015 – December 31, 2015	128,800	$	(1.68	)	WTI Midland and WTI Cushing Basis Differential
January 1, 2016 – December 31, 2016	512,400	$	(0.94	)	WTI Midland and WTI Cushing Basis Differential
October 1, 2015 – December 31, 2015	36,800	$	(2.33	)	West Texas Sour and WTI Cushing Basis Differential
January 1, 2016 – December 31, 2016	219,600	$	(0.43	)	West Texas Sour and WTI Cushing Basis Differential
October 1, 2015 – December 31, 2015	184,000	$	(14.50	)	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
October 1, 2015 – December 31, 2015	69,000	$	90.00	$	99.13	$	76.67
January 1, 2016 – December 31, 2016	1,061,400	$	90.00	$	96.18	$	73.62

Put Options Sold



	Gas			Oil
Contract Period	MMBtu	Put Sold ($/MMBtu)		Bbls	Put Sold ($/Bbl)
October 1, 2015 – December 31, 2015	6,670,000	$	3.16	128,800	$	71.43
January 1, 2016 – December 31, 2016	1,830,000	$	3.00	146,400	$	75.00
January 1, 2017 – December 31, 2017	1,825,000	$	3.50	73,000	$	75.00

Range Bonus Accumulators



	Gas
Contract Period	MMBtu	Bonus		Range Ceiling		Range Floor
October 1, 2015 – December 31, 2015	368,000	$	0.16	$	4.00	$	2.50



	Oil
Contract Period	Bbls	Bonus		Range Ceiling		Range Floor
October 1, 2015 – December 31, 2015	46,000	$	4.00	$	100.00	$	75.00
January 1, 2016 – December 31, 2016	183,000	$	4.00	$	100.00	$	75.00

Collars



	Oil
Contract Period	Bbls	Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
October 1, 2015 – December 31, 2015	46,000	$	50.00	$	58.45

Call Spreads



	Oil
Contract Period	Bbls	Call Price ($/Bbl)		Short Call Price ($/Bbl)
October 1, 2015 – December 31, 2015	473,800	$	70.00	$	85.00

Puts



	Oil
Contract Period	Bbls	Put Price ($/Bbl)
January 1, 2016 – December 31, 2016	366,000	$	60.00

Interest Rate Swaps

At September 30, 2015, we had open interest rate derivative contracts as follows (in thousands):



Period	Notional Amount		Fixed LIBOR Rates
October 1, 2015 to December 10, 2016	$	20,000	2.17	%
October 1, 2015 to October 31, 2016	$	40,000	1.65	%
October 1, 2015 to August 5, 2018	$	30,000	2.25	%
October 1, 2015 to August 6, 2016	$	25,000	1.80	%
October 1, 2015 to October 31, 2016	$	20,000	1.78	%
October 1, 2015 to September 23, 2016	$	75,000	1.15	%
October 1, 2015 to March 7, 2016	$	75,000	1.08	%
October 1, 2015 to September 7, 2016	$	25,000	1.25	%
October 1, 2015 to December 10, 2015 ⁽¹⁾	$	50,000	0.21	%
Total	$	360,000

(1) The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.

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 as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):



	September 30, 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	$	230,500		$	(24,175	)	$	206,325
Interest rate derivative contracts	—			(3,534		)	(3,534		)
Total derivative instruments	$	230,500		$	(27,709	)	$	202,791

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	$	(24,827	)	$	24,175		$	(652	)
Interest rate derivative contracts	(3,991		)	3,534			(457		)
Total derivative instruments	$	(28,818	)	$	27,709		$	(1,109	)



	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. Long-Term Debt for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $230.5 million at September 30, 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 September 30, 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.

Changes in fair value of our commodity and interest rate derivatives for the nine months ended September 30, 2015 and the year ended December 31, 2014 are as follows:



	Nine Months Ended September 30, 2015			Year Ended December 31, 2014
	(in thousands)
Derivative asset at beginning of period, net	$	220,734		$	66,711
Purchases
Fair value of derivatives acquired	35,643			(1,344		)
Net gains on commodity and interest rate derivative contracts	100,270			161,519
Settlements
Cash settlements received on matured commodity derivative contracts	(125,988		)	(10,187		)
Cash settlements paid on matured interest rate derivative contracts	2,968			4,035
Termination of derivative contracts	(31,945		)	—
Derivative asset at end of period, net	$	201,682		$	220,734

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, recognition of asset retirement obligations and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance 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. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction.

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. We consider this fair value estimate as a Level 2 input. As of September 30, 2015, the fair value of our Senior Notes was estimated to be $319.8 million. We consider the inputs to the valuation of our Senior Notes to be Level 1 as fair value was estimated based on prices quoted from a third-party financial institution.

Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swaps, call options sold, swaptions, put options sold, call spreads, call options, put options, three-way collars 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-swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimate for these derivative instruments as a Level 2 input. We estimate the value 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 valuation 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 estimate 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):



	September 30, 2015
	Fair Value Measurements Using								Assets/Liabilities
	Level 1		Level 2			Level 3			at Fair value
Assets:
Commodity price derivative contracts	$	—	$	212,394		$	(6,069	)	$	206,325
Interest rate derivative contracts	—		(3,534		)	—			(3,534		)
Total derivative instruments	$	—	$	208,860		$	(6,069	)	$	202,791
Liabilities:
Commodity price derivative contracts	$	—	$	(652	)	$	—		$	(652	)
Interest rate derivative contracts	—		(457		)	—			(457		)
Total derivative instruments	$	—	$	(1,109	)	$	—		$	(1,109	)



	December 31, 2014
	Fair Value Measurements Using								Assets/Liabilities
	Level 1		Level 2			Level 3			at Fair value
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 (unobservable inputs) in the fair value hierarchy:



	Nine Months Ended
	September 30,
	2015			2014
	(in thousands)
Unobservable inputs, beginning of period	$	(6,470	)	$	566
Total gains	3,525			798
Settlements	(3,124		)	(184		)
Unobservable inputs, end of period	$	(6,069	)	$	1,180

Change in fair value included in earnings related to derivatives still held as of September 30,	$	(2,254	)	$	1,132

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. While no goodwill impairment was recognized at September 30,

2015, any further significant decline in prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the reporting unit and could result in an impairment charge.

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 nine months ended September 30, 2015 and the year ended December 31, 2014, in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $2.0 million and $52.8 million, respectively, at fair value. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging between 4.6% and 5.2%; and (4) the average inflation factor (2.3%). 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 September 30, 2015 and December 31, 2014 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows:



	September 30, 2015			December 31, 2014
	(in thousands)
Asset retirement obligations, beginning of period	$	149,062		$	87,967
Liabilities added during the current period	1,971			52,829
Accretion expense	5,537			5,889
Retirements	(692		)	(450		)
Disposition of properties	—			(1,291		)
Change in estimate	22,329			4,118
Asset retirement obligation, end of period	178,207			149,062
Less: current obligations	(4,309		)	(2,386		)
Long-term asset retirement obligation, end of period	$	173,898		$	146,676

Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During 2015 and 2014, the Company reviewed actual abandonment costs with previous estimates and, as a result, increased its estimates of future asset retirement obligations by $22.3 million and $4.1 million, respectively, to reflect increased costs incurred for plugging and abandonment costs.

7. Commitments and Contingencies

Transportation Demand Charges

As of September 30, 2015, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from nine months 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 September 30, 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.



	September 30, 2015
	(in thousands)
October 1, 2015 - December 31, 2015	$	4,194
2016	15,442
2017	12,512
2018	11,696
2019	9,661
Thereafter	410
Total	$	53,915

Legal Proceedings

We are also a party to separate legal proceedings relating to each of the LRE Merger and the Eagle Rock Merger (these proceedings are together referred to as the “Merger Litigation”). Please see Part II-Item 1-Legal Proceedings in this Quarterly Report for a detailed discussion of the Merger Litigation.

8. Members’ Equity and Net Income per Common and Class B Unit

Cumulative Preferred Units

The following table summarizes the Company’s Cumulative Preferred units outstanding at September 30, 2015 and December 31, 2014:



				September 30, 2015			December 31, 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 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, commencing on the redemptions dates as stated above. 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.

Upon the occurrence of a change of control, each holder of Cumulative Preferred Units will have the right to convert some or all of their Cumulative Preferred Units into our common units unless prior to the change of control, we provide notice of our election to redeem the Cumulative Preferred Units or we exercise any of our redemption rights relating to the units prior to the change of control conversion date as set by our board of directors. Also upon the occurrence of a change of control we may, at our option and subject to certain restrictions, redeem the Cumulative Preferred Units by paying $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared.

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.

The following is a summary of the changes in our common units issued during the nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands):



	September 30, 2015		December 31, 2014
Beginning of period	83,452		78,337
Issuance of Common units for cash	2,430		4,864
Repurchase of units under the Common unit buyback program	(157	)	(135	)
Reissuance of Common units for restricted unit grants	288		—
Unit-based compensation	584		386
End of period	86,597		83,452

There was no change in issued and outstanding Class B units during the nine months ended September 30, 2015 or the year ended December 31, 2014.

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 basic 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 (loss) per common and Class B unit were as follows (in thousands, except per unit data):



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(in thousands, except per unit amounts)
Net income (loss) attributable to Common and Class B unitholders	$	(468,967	)	$	109,150	$	(1,394,822	)	$	112,975
Weighted average number of Common and Class B units outstanding - basic	87,012			83,525		85,834			81,377
Effect of dilutive securities:
Phantom units ^(a)	—			228		—			274
Weighted average number of Common and Class B units outstanding - diluted	87,012			83,753		85,834			81,651
Net income (loss) per Common and Class B unit
Basic	$	(5.39	)	$	1.31	$	(16.25	)	$	1.39
Diluted	$	(5.39	)	$	1.30	$	(16.25	)	$	1.38


(a)	For the three and nine months ended September 30, 2015, 47,626 and 166,331 phantom units were excluded from the calculation of diluted earnings per unit, respectively, 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 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, when, as and if declared by our board of directors. We will pay cumulative distributions in cash on the 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.

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

On October 19, 2015, our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of September 2015. See Note 11. Subsequent Events for further discussion.



	Cash Distributions
Distribution	Per Unit		Declared Date	Record Date	Payment Date
2015
Third Quarter
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 20, 2014	March 3, 2014	March 17, 2014
2013
Fourth Quarter
December	$	0.2075	January 16, 2014	February 3, 2014	February 14, 2014

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 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.

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

In June and July 2013, we and VNRH entered into amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve-month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date.

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 September 30, 2015, an accrued liability was recognized and compensation expense of $1.1 million was recorded for the nine months ended September 30, 2015 related to these 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. Any 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 nine months ended September 30, 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. VNR employees were also granted a total of 169,772 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 years from the date of grant.

A summary of the status of the non-vested restricted units as of September 30, 2015 is presented below:



	Number of Non-vested Restricted Units		Weighted Average Grant Date Fair Value
Non-vested restricted units at December 31, 2014	440,047		$	28.87
Granted	556,868		$	15.23
Forfeited	(17,670	)	$	20.54
Vested	(119,904	)	$	29.22
Non-vested restricted units at September 30, 2015	859,341		$	20.15

At September 30, 2015, there was approximately $11.7 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.7 years. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $3.4 million and $1.3 million in the selling, general and administrative expenses line item for the three months ended September 30, 2015 and 2014, respectively, and $10.4 million and $5.2 million for the nine months ended September 30, 2015 and 2014, respectively.

Phantom Unit Grants

A summary of the status of the non-vested phantom units under the VNR LTIP as of September 30, 2015 is presented below:



	Number of Non-vested Phantom Units		Weighted Average Grant Date Fair Value
Non-vested phantom units at December 31, 2014	330,440		$	21.27
Forfeited	(2,979	)	$	28.28
Vested	(124,127	)	$	21.56
Non-vested phantom units at September 30, 2015	203,334		$	20.99

At September 30, 2015, there was approximately $2.8 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.4 years. Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $0.4 million and $0.2 million in the selling, general and administrative expense line item for the three months ended September 30, 2015 and 2014, respectively, and $1.3 million for each of the nine months ended September 30, 2015 and 2014.

10. 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 under our currently effective shelf registration statement filed with the SEC, as amended (the “Shelf Registration Statement”). 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 are 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 Cumulative 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.

We have 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 representing limited liability company interests 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 nine months ended September 30, 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 the registration statement discussed above. VNR has no independent assets or operations. Debt securities that we may offer may be guaranteed by our subsidiaries. We contemplate that if we offer debt securities, the guarantees will be full and unconditional and joint and several (subject to certain customary release provisions), and any subsidiaries of VNR that do not guarantee the securities will be minor.

11. Subsequent Events

Distributions

On October 19, 2015, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of September 2015 of $0.1175 per common and Class B unit ($1.41 on an annualized basis) expected to be paid on November 13, 2015 to Vanguard unitholders of record on November 2, 2015, which includes unitholders who received the newly issued Vanguard Common Units as part of the LRE Merger and Eagle Rock Merger discussed below.

Also on October 19, 2015, our board of directors declared a cash distribution for our preferred unitholders 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 November 13, 2015 to Vanguard preferred unitholders of record on November 2, 2015.

Mergers

LRE Merger

On October 5, 2015, Vanguard completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015 (the “LRE Merger Agreement”), pursuant to which a subsidiary of Vanguard merged into LRR Energy, L.P. (“LRE”) and, at the same time, Vanguard acquired LRE GP, LLC (the “LRE GP”), the general partner of LRR Energy, L.P. (the “LRE Merger”).

Under the terms of the LRE Merger Agreement, (i) each outstanding LRE common unit was converted into the right to receive 0.550 newly issued Vanguard common units and (ii) Vanguard purchased all of the outstanding limited liability company interests in LRE GP in exchange for 12,320 newly issued Vanguard common units. Further, in connection with the LRE Merger Agreement, each award of restricted LRE common units issued under LRE’s long-term incentive plan that was subject to time-based vesting and that was outstanding and unvested immediately prior to the effective time of the LRE Merger became fully vested and was deemed to be a LRE common unit with the right to receive Vanguard common units.

As consideration for the LRE Merger, Vanguard issued approximately 15.4 million common units valued at $121.3 million based on the closing price per Vanguard common unit of $7.86 at October 5, 2015 and assumed $290.0 million in debt.

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.

Eagle Rock Merger

On October 8, 2015, Vanguard completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated as of May 21, 2015 (the “Eagle Rock Merger Agreement”) pursuant to which Eagle Rock Energy Partners, L.P. became a wholly-owned indirect subsidiary of Vanguard (the “Eagle Rock Merger”).

outstanding Eagle Rock common units held by employees and officers of Eagle Rock and members of the board of directors of Eagle Rock who did not receive employment offers from Vanguard accelerated upon the effective time of the Eagle Rock Merger and was converted into the right to receive newly issued Vanguard common units, with the vesting of performance-based restricted units determined based upon Eagle Rock’s actual performance through the effective time of the Eagle Rock Merger (subject to Vanguard’s good faith review).

As consideration for the Eagle Rock Merger, Vanguard issued approximately 28.3 million Vanguard common units valued at $259.2 million based on the closing price per Vanguard common unit of $9.17 at October 8, 2015 and assumed $151.8 million in debt.

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.

Borrowing Base Redetermination

On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Fourth Amended and Restated Credit Agreement (“Restated Credit Agreement”), which reaffirms the Company’s $1.8 billion borrowing base. The terms of the Restated 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 cents for every dollar of junior debt issued.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The historical consolidated financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”) reflect all of the assets, liabilities and results of operations of Vanguard Natural Resources, LLC and its Consolidated Subsidiaries. The following discussion analyzes the financial condition and results of operations of Vanguard for the nine months ended September 30, 2015 and 2014. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Vanguard in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the “2014 Annual Report”) and the historical unaudited consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

Overview


•	the Green River Basin in Wyoming;


•	the Piceance Basin in Colorado;


•	the Permian Basin in West Texas and New Mexico;


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


•	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.

As of September 30, 2015, based on internal reserve estimates, our total estimated proved reserves were 1,876 Bcfe, of which approximately 73% were natural gas reserves, 14% were oil reserves and 13% were NGLs reserves. Of these total estimated proved reserves, approximately 71%, or 1,325 Bcfe, were classified as proved developed. Also, at September 30, 2015, we owned working interests in 10,465 gross (3,946 net) productive wells. Our operated wells accounted for approximately 52% of our total estimated proved reserves at September 30, 2015. Our average net daily production for the nine months ended September 30, 2015 and the year ended December 31, 2014 was 383 MMcfe/day and 327 MMcfe/day, respectively. We have interests in approximately 870,140 gross undeveloped leasehold acres surrounding our existing wells. As of September 30, 2015, based on internal reserve estimates, approximately 29%, or 551 Bcfe, of our estimated proved reserves was attributable to our interests in undeveloped acreage.

Recent Developments

Mergers

LRE Merger

company interests in LRE GP in exchange for 12,320 newly issued Vanguard common units. Further, in connection with the LRE Merger Agreement, each award of restricted LRE common units issued under LRE’s long-term incentive plan that was subject to time-based vesting and that was outstanding and unvested immediately prior to the effective time of the LRE Merger became fully vested and was deemed to be a LRE common unit with the right to receive Vanguard common units.

The LRE Merger increased Vanguard’s proved reserves by approximately 145 Bcfe as of the merger date and is expected to bring additional production of 42 MMcfe per day increasing Vanguard’s production by approximately 11% based on Vanguard’s third quarter 2015 average daily production.

Eagle Rock Merger

Under the terms of the Eagle Rock Merger Agreement, (i) each Eagle Rock common unit was converted into the right to receive 0.185 newly issued Vanguard common units. Further, in connection with the Eagle Rock Merger Agreement, Vanguard adopted Eagle Rock’s long-term incentive plan and each outstanding award of Eagle Rock common units issued under such plan was converted into a new award of restricted units based on Vanguard common units. However, any outstanding Eagle Rock common units held by employees and officers of Eagle Rock and members of the board of directors of Eagle Rock who did not receive employment offers from Vanguard accelerated upon the effective time of the Eagle Rock Merger and was converted into the right to receive newly issued Vanguard common units, with the vesting of performance-based restricted units determined based upon Eagle Rock’s actual performance through the effective time of the Eagle Rock Merger (subject to Vanguard’s good faith review).

The Eagle Rock Merger increased Vanguard’s proved reserves by approximately 387 Bcfe as of the merger date and is expected to bring additional production of 84 MMcfe per day increasing Vanguard’s production by approximately 22% based on Vanguard’s third quarter 2015 average daily production. The assets acquired from this transaction add scale in Vanguard’s existing Gulf Coast and Permian Basins and establish a new operating platform in the SCOOP/STACK play in the Anadarko basin.

Business Environment and Outlook

Historically, the markets for oil and natural gas have been very volatile and multiple factors during the latter half of 2014 and beginning of 2015 have caused the price of oil and natural gas to decrease dramatically. Among the factors causing such volatility are the domestic oversupply of natural gas and the supply of oil, the ability of the members of OPEC and other producing countries to agree upon and maintain prices and production levels, social unrest and instability, particularly in major oil and natural gas producing regions outside the United States, and the level of consumer product demand.

Natural gas and oil prices are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, over the last 22 months from January 1, 2014 through October 30, 2015 the crude oil spot

price per barrel ranged from a high of $107.95 to a low of $38.22 and the NYMEX natural gas spot price per MMBtu has ranged from a high of $6.15 to a low of $2.03.

The dramatic decline in commodity prices has had an impact on our unit price. During the first nine months of 2015, our common unit price fluctuated between a closing high of $18.72 on February 9, 2015 to a closing low of $6.41 on August 21, 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 of oil and natural gas 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 of oil, natural gas and NGLs could reduce the amount of oil, natural gas and NGLs that we can produce economically. 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 September 30, 2015 would decrease from 1,876 Bcfe to 1,393 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices were $2.90 per MMBtu (or a $0.21 price decline from the 12-month average price of $3.11) and oil prices were $55.09 per barrel (or a $4.14 price decline from the 12-month average price of $59.23), 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 September 30, 2015 would decrease from 1,876 Bcfe to 1,862 Bcfe. The preceding assumed prices in example (2) were derived from the 5-year New York Mercantile Exchange (NYMEX) forward strip price at October 30, 2015. 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. We intend to improve our financial outlook through opportunistic hedging, profitable drilling and acquisitions of new oil and natural gas properties. We foresee significant long-term benefits in acquiring assets in this low commodity price environment.

In January 2015, we restructured our hedge portfolio to limit further downside and volatility due to the current commodity price environment. Specifically, we converted a significant portion of our three-way collars in 2015 to fixed-price swaps or lowered the pricing on existing short puts. We have implemented a hedging program for approximately 79% and 50% of our anticipated crude oil production in 2015 and 2016, respectively, with 84% in the form of fixed-price swaps for the balance of 2015. Approximately 88% and 68% of our natural gas production in 2015 and 2016, respectively, is hedged with 100% in the form of fixed-price swaps for the balance of 2015. NGLs production is hedged using fixed-price swaps for approximately 9% and 21% of anticipated production for the balance of 2015 and 2016, respectively. The impact of the LRE Merger and Eagle Rock Merger discussed above is not included in the amounts or percentages shown above.

During 2015, we intend to continue to concentrate our drilling on low risk, development opportunities with the majority of drilling capital focused on high-Btu natural gas wells in the Green River Basin and Gulf Coast Basin which we believe will continue to offer attractive drilling returns even in this low commodity price environment. During the nine months ended September 30, 2015, we drilled three operated wells with a 100% working interest in each well and completed one operated well during the third quarter of 2015. In addition, we participated in the drilling of 125 gross (15.6 net) non-operated wells and in the completion of 81 gross (10.2 net) non-operated wells.

We reduced our cash distribution per common unit to $0.1175 starting in the month of January 2015, or $1.41 per unit on an annualized basis which represents a reduction from the payment for the month of December 2014, which was $0.21 per common unit or $2.52 per unit on an annualized basis. We have maintained this distribution rate during 2015 as it takes into consideration current commodity and financial market conditions and helps to preserve our liquidity for potential future acquisition opportunities.

At November 9, 2015, we had indebtedness under our Reserve-Based Credit facility totaling $1.69 billion with a borrowing base of $1.8 billion which provided for $105.5 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 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 scheduled redetermination is in April 2016. Absent new acquisitions, our borrowing base may be reduced as a result of continued declines in oil and natural gas prices and as existing hedges roll off. The precise amount of any reduction is not known at this time but we do expect that we will have sufficient liquidity to manage our operations. However, if necessary, we believe we have access to capital markets and other financing sources. 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. The Eighth

Amendment however provided for an automatic increase in the borrowing base by $200.0 million which became effective upon closing of the LRE Merger on October 5, 2015. In addition, the Eighth Amendment includes, among other provisions, the 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 starting in 2017 and beyond.

On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Fourth Amended and Restated Credit Agreement (“Restated Credit Agreement”), which reaffirms the the Company’s $1.8 billion borrowing base. The terms of the Restated 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 cents for every dollar of junior debt issued.

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the quarter ended March 31, 2015 of $132.6 million as a result of a decline in oil and natural gas prices at the measurement date, March 31, 2015. The first quarter 2015 impairment was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. We also recorded a non-cash ceiling test impairment of oil and natural gas properties for the quarter ended June 30, 2015 of $733.4 million as a result of a decline in oil and natural gas prices at the measurement date, June 30, 2015. The second quarter 2015 impairment was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. We also recorded a non-cash ceiling test impairment of oil and natural gas properties for the quarter ended September 30, 2015 of $491.5 million as a result of a decline in oil and natural gas prices at the measurement date, September 30, 2015. The third quarter 2015 impairment was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil.

We expect to record an additional impairment of our oil and natural gas properties during the fourth quarter of 2015 as a result of declining oil and natural gas prices and as a result of closing the LRE and Eagle Rock Mergers. Based on the 12-month average oil, natural gas and NGLs prices through November 1, 2015 and if such prices do not change during December 2015, we estimate that, on a pro forma basis, we will record a ceiling test write down on our existing assets of approximately $352.0 million at December 31, 2015. 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 2015, 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. In a price environment, where the historical 12-month average price is less than the expected prices in future years, it is highly likely that an impairment would be recorded in the quarter in which we complete an acquisition. In accordance with the guidance contained within ASC Topic 805, “Business Combinations,” 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. There is a risk that we will be required to record an impairment of our oil and natural gas properties if certain conditions, such as declining oil and natural gas prices, arise.

While no goodwill impairment was recognized at September 30, 2015, our unit price and accordingly, the fair value of our reporting unit have been volatile. Any further significant decline in prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the reporting unit and could result in an impairment charge in the future.

Results of Operations

The following table sets forth selected financial and operating data for the periods indicated (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015 ^(a)			2014 ^(a)			2015 ^(a)			2014^(a)
Revenues:
Oil sales	$	33,624		$	69,034		$	113,425		$	211,197
Natural gas sales	50,851			67,827			146,502			201,175
NGLs sales	6,352			16,766			25,635			55,514
Oil, natural gas and NGLs sales	90,827			153,627			285,562			467,886
Net gains (losses) on commodity derivative contracts	64,328			83,311			102,561			(11,125		)
Total revenues	$	155,155		$	236,938		$	388,123		$	456,761
Costs and expenses:
Production:
Lease operating expenses	$	34,169		$	31,011		$	101,247		$	95,726
Production and other taxes	9,082			15,130			31,262			46,693
Depreciation, depletion, amortization, and accretion	52,428			55,680			182,443			150,798
Impairment of oil and natural gas properties	491,487			—			1,357,462			—
Non-cash compensation	3,827			1,438			11,654			6,440
Other selling, general and administrative expenses	4,219			5,702			14,585			16,602
Total costs and expenses	$	595,212		$	108,961		$	1,698,653		$	316,259
Other income (expense):
Interest expense	$	(21,130	)	$	(16,721	)	$	(61,693	)	$	(49,529	)
Net gains (losses) on interest rate derivative contracts	$	(807	)	$	511		$	(2,291	)	$	(1,068	)
Net gains (loss) on acquisitions of oil and natural gas properties	$	(284	)	$	2,409		$	(284	)	$	34,523
Other	$	1		$	(77	)	$	46		$	54


(a)	During 2015 and 2014, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

Revenues

Oil, natural gas and NGLs sales decreased $62.8 million to $90.8 million during the three months ended September 30, 2015 as compared to the same period in 2014. The key oil, natural gas and NGLs revenue measurements were as follows:



	Three Months Ended				Percentage Increase / (Decrease)
	September 30,
	2015 ^(a)		2014 ^(a)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	40.10	$	84.96	(53	)%
Natural Gas (Price/Mcf)	$	1.94	$	3.24	(40	)%
NGLs (Price/Bbl)	$	8.86	$	26.66	(67	)%
Average realized prices, including hedges^(b):
Oil (Price/Bbl)	$	53.66	$	84.36	(36	)%
Natural Gas (Price/Mcf)	$	3.17	$	3.55	(11	)%
NGLs (Price/Bbl)	$	11.23	$	26.70	(58	)%
Average NYMEX prices:
Oil (Price/Bbl)	$	46.39	$	97.13	(52	)%
Natural Gas (Price/Mcf)	$	2.77	$	4.07	(32	)%
Total production volumes:
Oil (MBbls)	839		813		3	%
Natural Gas (MMcf)	26,242		20,962		25	%
NGLs (MBbls)	717		629		14	%
Combined (MMcfe)	35,574		29,610		20	%
Average daily production volumes:
Oil (Bbls/day)	9,115		8,832		3	%
Natural Gas (Mcf/day)	285,236		227,850		25	%
NGLs (Bbls/day)	7,792		6,835		14	%
Combined (Mcfe/day)	386,679		321,847		20	%


(a)	During 2015 and 2014, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.


(b)	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 three months ended September 30, 2015 compared to the same period in 2014 was due primarily to the decrease in average realized oil, natural gas and NGLs prices. Oil revenues decreased by 51% from $69.0 million in the third quarter of 2014 to $33.6 million in the third quarter of 2015, as a result of a $44.86 per Bbl, or 53%, decrease in average realized oil price, excluding hedges. The decrease in average realized oil price is primarily due to a lower average NYMEX price, which decreased from $97.13 per Bbl in the third quarter of 2014 to $46.39 per Bbl in the third quarter of 2015. Natural gas revenues decreased by 25% from $67.8 million in the third quarter of 2014 to $50.9 million in the third quarter of 2015 as a result of a $1.30 per Mcf, or 40%, decrease in average realized natural gas price, excluding hedges. The decrease in price was partially offset by a 5,280 MMcf increase in our natural gas production 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 three months of production in the third quarter of 2015. NGLs revenues also decreased 62% during the third quarter of 2015 compared to the same period in 2014 due to a $17.80 per Bbl decrease in our average realized NGLs price, excluding hedges, offset by a 88 MBbls increase in NGLs production volumes. Overall, our total production for the three months ended September 30, 2015 increased by 20% on an Mcfe basis compared to the same period in 2014. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 14%, 74% and 12%, respectively, of our production during the three months ended September 30, 2015 compared to 16%, 71% and 13%, respectively, of our production during the same period in 2014.

Hedging and Price Risk Management Activities

During the three months ended September 30, 2015, we recognized a $64.3 million net gain on commodity derivative contracts. Cash receipts on matured commodity derivative contracts of $45.4 million were recognized 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.

Costs and Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and other customary charges. Lease operating expenses increased by $3.2 million to $34.2 million for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014, mainly due to a $4.7 million increase in lease operating expenses for oil and natural gas properties acquired during the third quarter of 2014. This increase was offset by a $1.5 million decrease in maintenance and repair expenses on existing wells and lower lease 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 or county and are based on the value of our reserves. Production and other taxes decreased by $6.0 million for the three months ended September 30, 2015 as compared to the same period in 2014 primarily due to lower wellhead revenues as a result of the decrease in our average realized oil and natural gas prices. As a percentage of wellhead revenues, production, severance and ad valorem taxes slightly increased from 9.8% for the three months ended September 30, 2014 to 10.0% for the three months ended September 30, 2015. The percentage was higher during the three months ended September 30, 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 decreased by approximately $3.3 million to $52.4 million for the three months ended September 30, 2015 from approximately $55.7 million for the three months ended September 30, 2014, primarily due to a lower depletion base as a result of the non-cash ceiling impairment charge of $866.0 million recorded during the first six months of 2015.

An impairment of oil and natural gas properties of $491.5 million was recognized during the quarter ended September 30, 2015 as a result of a decline in oil and natural gas prices at the measurement date, September 30, 2015. The third quarter 2015 impairment was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil.

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 decreased $1.5 million to $4.2 million for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014 primarily resulting from a change in the accrual of executive and employee bonuses for the 2015 performance year discussed below of about $1.0 million and a $0.5 million decrease in the Texas margin deferred tax asset during the third quarter of 2015 due to the decrease in the Company’s oil and gas properties book basis that resulted from the non-cash ceiling impairment charge. Non-cash compensation expense for the three months ended September 30, 2015 increased $2.4 million to $3.8 million as compared to the three months ended September 30, 2014, primarily related to the accrual of executive and employee bonuses that will be paid in Vanguard common units rather than in cash. 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 Board of Directors elected this option and under the plan receive quarterly grants of Vanguard common units instead their 2015 cash compensation.

Other Income and Expense

Interest expense increased to $21.1 million for the three months ended September 30, 2015 from $16.7 million for the three months ended September 30, 2014 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility during the three months ended September 30, 2015 compared to the same period in 2014.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014

Revenues

Oil, natural gas and NGLs sales decreased $182.3 million to $285.6 million during the nine months ended September 30, 2015 as compared to the same period in 2014. The key oil, natural gas and NGLs revenue measurements were as follows:



	Nine Months Ended				Percentage Increase / (Decrease)
	September 30,
	2015 ^(a)		2014^(a)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	44.41	$	88.23	(50	)%
Natural Gas (Price/Mcf)	$	1.91	$	3.55	(46	)%
NGLs (Price/Bbl)	$	12.20	$	29.26	(58	)%
Average realized prices, including hedges ^(b):
Oil (Price/Bbl)	$	55.49	$	84.36	(34	)%
Natural Gas (Price/Mcf)	$	3.13	$	3.49	(10	)%
NGLs (Price/Bbl)	$	14.38	$	28.98	(50	)%
Average NYMEX prices:
Oil (Price/Bbl)	$	51.04	$	99.62	(49	)%
Natural Gas (Price/Mcf)	$	2.80	$	4.57	(39	)%
Total production volumes:
Oil (MBbls)	2,554		2,394		7	%
Natural Gas (MMcf)	76,645		56,651		35	%
NGLs (MBbls)	2,102		1,897		11	%
Combined (MMcfe)	104,577		82,396		27	%
Average daily production volumes:
Oil (Bbls/day)	9,355		8,769		7	%
Natural Gas (Mcf/day)	280,751		207,512		35	%
NGLs (Bbls/day)	7,698		6,949		11	%
Combined (Mcfe/day)	383,067		301,816		27	%


(a)	During 2015 and 2014, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.


(b)	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 nine months ended September 30, 2015 compared to the same period in 2014 was due primarily to the decrease in average realized oil, natural gas and NGLs prices. Oil revenues decreased 46% from $211.2 million in the first nine months of 2014 to $113.4 million in the first nine months of 2015 as a result of a $43.82 per Bbl, or 50%, decrease in our average realized oil price, excluding hedges. The decrease in average realized oil price is primarily due to a lower average NYMEX price, which decreased from $99.62 per Bbl during nine months ended September 30, 2014 to $51.04 per Bbl during the nine months ended September 30, 2015. Natural gas revenues decreased 27% from $201.2 million in the first nine months of 2014 to $146.5 million in the first nine months of 2015 as a result of a $1.64 per Mcf, or 46%, decrease in our average realized natural gas price, excluding hedges, offset by a 19,994 MMcf, or 35%, increase in our natural gas production due to acquisitions completed during 2014. NGLs revenues also

decreased 54% during the first nine months of 2015 compared to the same period in 2014 due to a $17.06 per Bbl, or 58%, decrease in our average realized NGLs price, excluding hedges.

Overall, our total production for the nine months ended September 30, 2015 increased by 27% on an Mcfe basis compared to the same period in 2014, which was primarily attributable to the impact from all of our acquisitions completed in 2014 wherein we realized the benefit of a full nine months of production in 2015. On an Mcfe basis, crude oil, natural gas, and NGLs accounted for 15%, 73% and 12%, respectively, of our production during the nine months ended September 30, 2015 compared to 17%, 69% and 14%, respectively, of our production during the same period in 2014.

Hedging and Price Risk Management Activities

During the nine months ended September 30, 2015, we recognized $102.6 million in net gains on commodity derivative contracts. Cash payments on matured commodity derivative contracts of $126.0 million were recognized 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 arranging for the counterparty to pay us when commodity prices are below the hedged price and for us to 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.

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 $5.5 million to $101.2 million for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014, of which $18.3 million related to increased lease operating expenses for oil and natural gas properties acquired during 2014. The increase was offset by a $12.8 million decrease in maintenance and repair expenses on existing wells and lower lease 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 or county and are based on the value of our reserves. Production and other taxes decreased by $15.4 million for the nine months ended September 30, 2015 as compared to the same period in 2014 primarily due to lower wellhead revenues as a result of the decrease in our average realized oil and natural gas prices. As a percentage of wellhead revenues, production, severance and ad valorem taxes were 10.9% and 10.0% for the nine months ended September 30, 2015 and 2014, respectively. The percentage was higher during the nine months ended September 30, 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 by approximately $31.6 million to $182.4 million for the nine months ended September 30, 2015 from approximately $150.8 million for the nine months ended September 30, 2014 primarily due to a higher depletion base and increased production associated with properties acquired during 2014 partially offset by a decrease in the depletion base as a result of the non-cash ceiling impairment charge of $866.0 million recorded during the first six months of 2015.

An impairment of oil and natural gas properties of $1.4 billion was recognized during the nine months ended September 30, 2015 as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015, June 30, 2015 and September 30, 2015. The first quarter impairment of $132.6 million was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The second quarter impairment of $733.4 million was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. The third quarter impairment of $491.5 million was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil.

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 decreased $2.0 million to $14.6 million for the nine months ended September 30, 2015 as compared to the same period in 2014, primarily resulting from a change in the accrual of executive and employee bonuses for the 2015 performance year discussed below of about $2.7 million, offset by an increase of about $0.7 million resulting from the hiring of additional employees and higher office expenses related to our acquisitions. Non-cash compensation expense for the nine months ended September 30, 2015 increased $5.2 million to $11.7 million as compared to the same period in 2014, primarily related to the accrual of executive and employee bonuses that will be paid in Company common units rather than in cash. 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 Board of Directors elected this option and under the plan receive quarterly grants of Vanguard common units instead of their 2015 cash compensation.

Other Income and Expense

Interest expense increased to $61.7 million for the nine months ended September 30, 2015 from $49.5 million for the nine months ended September 30, 2014 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility during the nine months ended September 30, 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 goodwill of $0.3 million, which was immediately impaired and recorded as a loss for the nine months ended September 30, 2015. The comparable measurement for the acquisitions completed during 2014 resulted in a gain of $34.5 million for the nine months ended September 30, 2014. The net gain resulted from the increase 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 preparation of financial statements in accordance with GAAP requires management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of September 30, 2015, our critical accounting policies were consistent with those discussed in our 2014 Annual Report.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in recording the acquisition of oil and natural gas properties and in impairment tests of oil and natural gas properties and goodwill, the fair value of derivative contracts and 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.

Liquidity and Capital Resources

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. As we execute our business strategy, we will continually monitor the capital resources available to us to meet future financial obligations, planned capital expenditures, acquisition capital and distributions to our unitholders. Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for and acquiring additional reserves. We expect to fund our drilling capital expenditures and distributions to unitholders with cash flow from operations, while funding any acquisition capital expenditures that we might incur with borrowings under our Reserve-Based Credit Facility and publicly offered equity and debt or other more non-traditional sources, depending on market conditions. Currently and for the foreseeable future, raising funds through the public equity and debt markets is expected to be very challenging and as such we will likely have to consider sources of capital outside the public markets for any significant acquisition capital needs. As of November 9, 2015, we had $105.5 million available to be borrowed under our Reserve-Based Credit Facility and our current borrowing base is $1.8 billion.

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 next scheduled redetermination is in April 2016. Absent new acquisitions of oil and natural gas properties, if commodity prices further decline and banks lower their internal projections of oil, natural gas and NGLs prices, we will be subject to decreases in our borrowing base availability in the future.

As a result, absent accretive acquisitions, to the extent available after unitholder distributions, debt service and capital expenditures, it is our current intention to utilize our excess cash flow during 2015 to reduce our borrowings under our Reserve-Based Credit Facility. Based upon current expectations, we believe existing liquidity and capital resources will be sufficient for the conduct of our business and operations for the foreseeable future.

Cash Flow from Operations

Net cash provided by operating activities was $265.3 million during the nine months ended September 30, 2015, compared to $245.7 million during the nine months ended September 30, 2014. Changes in working capital increased total cash flows by $64.1 million and $0.9 million for the nine months ended September 30, 2015 and 2014, respectively. Contributing to the increase in working capital during 2015 was an $73.8 million decrease in accounts receivable related to the timing of

receipts from production. The increase in working capital was offset by a $10.6 million decrease in accounts payable, oil and natural gas revenue payable and accrued expenses and other current liabilities that resulted primarily from the timing effects of payments. 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 nine months ended September 30, 2015 or 2014.

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 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, respectively, as well as the prices received for production. We enter into derivative contracts to reduce the impact of commodity price volatility on operations. Currently, we use a combination of fixed-price swaps, basis swaps, call options sold, put options sold, call spreads, call options, put options, three-way collars and range bonus accumulators to reduce our exposure to the volatility in oil and natural gas prices. See Note 4. Price and Interest Rate Risk Management Activities in the Notes to Consolidated Financial Statements and Part I—Item 3—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk, for details about derivative contracts in place through 2017.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $107.0 million for the nine months ended September 30, 2015, compared to $1.4 billion during the same period in 2014. Cash used in investing activities during the first nine months of 2015 primarily included $80.2 million for the drilling and development of oil and natural gas properties, $13.4 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties and $13.0 million for the acquisition of oil and natural gas properties. Net cash used in investing activities during the first nine months of 2014 was primarily attributable to $1.3 billion for the acquisition of oil and natural gas properties, $79.5 million for the drilling and development of oil and natural gas properties and $5.0 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties, offset by $2.0 million in proceeds from the sale of certain leasehold interests in the Williston Basin.

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $138.9 million for the nine months ended September 30, 2015, compared to net cash provided by financing activities of $1.2 billion during the same period in 2014. Cash used in financing activities during the nine months ended September 30, 2015 included $43.2 million in net repayments of our long-term debt and $126.6 million cash paid to preferred, common and Class B unitholders in the form of distributions. Additionally, cash provided by financing activities during the nine months ended September 30, 2015 included net proceeds from our public common unit offerings of $35.5 million. Net cash provided by financing activities during the nine months ended September 30, 2014 included net proceeds from borrowings under our long-term debt of $915.0 million and net proceeds from our public common unit and preferred unit offerings of $422.4 million, offset by $164.0 million cash used in distributions to preferred, common and Class B unitholders.

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 $1.6 billion (the “Reserve-Based Credit Facility”). As of September 30, 2015, there were approximately $1.32 billion of outstanding borrowings and $275.5 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $4.5 million reduction in availability for letters of credit (discussed below).

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 cents for every dollar of junior debt issued.

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 scheduled redetermination is in April 2016. Absent new acquisitions of oil and natural gas properties, if commodity prices further decline and banks lower their internal projections of oil, natural gas and NGLs prices, we will be subject to decreases in our borrowing base availability in the future.

As of November 9, 2015, we have $105.5 million available to be borrowed under our Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit (as discussed below).

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 September 30, 2015, we had 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, “Derivatives and Hedging,” 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 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting 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 an event of default.

We believe that we were in compliance with the terms of our Reserve-Based Credit Facility at September 30, 2015. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the Reserve-Based Credit Facility 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 Securities Exchange Act of 1934 (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

Senior Notes

September 30, 2015, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, approximately $234.5 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.

Interest on the Senior Notes is payable on April 1 and October 1 of each year, beginning on October 1, 2012. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.9375% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter. We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a “make-whole” premium. 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 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively.

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 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 current fair market value. The Lease Financing Obligations also contain an early buyout option whereby 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

At September 30, 2015, we did not have any off-balance sheet arrangements that have, or are reasonably likely to have, an effect on our financial position or results of operations.

Contingencies

We regularly analyze current information and accrue 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.

Commitments and Contractual Obligations

A summary of our contractual obligations as of September 30, 2015 is provided in the following table (in thousands):



	Payments Due by Year
	2015		2016		2017		2018		2019		After 2019		Total
Management base salaries ⁽¹⁾	$	351	$	—	$	—	$	—	$	—	$	—	$	351
Asset retirement obligations ⁽²⁾	1,077		5,171		6,856		7,929		4,010		153,164		178,207
Derivative liabilities ⁽³⁾	10,123		14,177		4,268		250		—		—		28,818
Reserve-Based Credit Facility ⁽⁴⁾	—		—		—		1,320,000		—		—		1,320,000
Senior Notes and related interest	32,484		43,313		43,313		43,312		43,312		564,438		770,172
Operating leases	304		1,078		1,089		1,336		1,342		217		5,366
Development commitments ⁽⁵⁾	14,615		27,861		—		—		—		—		42,476
Firm transportation agreements ⁽⁶⁾	4,194		15,442		12,512		11,696		9,661		410		53,915
Lease Financing Obligations ⁽⁷⁾	1,360		5,033		5,216		5,408		5,607		5,988		28,612
Total	$	64,508	$	112,075	$	73,254	$	1,389,931	$	63,932	$	724,217	$	2,427,917


(1)	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 elected this option and under the plan will receive quarterly grants of Vanguard common units instead of their remaining 2015 full cash compensation totaling $0.3 million.


(2)	Represents the discounted future plugging and abandonment costs of oil and natural gas wells and the decommissioning of the Elk Basin and Fairway gas plants. Please read Note 6. Asset Retirement Obligations of the Notes to the Consolidated Financial Statements for additional information regarding our asset retirement obligations.

(3)

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 Part I—Item 3—Quantitative and Qualitative Disclosures About Market Risk and Note 4. Price and Interest Rate Risk Management Activities of the Notes to the Consolidated Financial Statements for additional information regarding our commodity and interest rate derivative contracts.


(4)	This table does not include interest to be paid on the Reserve-Based Credit Facility principal balances shown as the interest rates are variable. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for additional information regarding our Reserve-Based Credit Facility.


(5)	Represents authorized expenditures for drilling, completion and major workover projects.


(6)	Represents gross transportation demand charges. Please read Note 7. Commitments and Contingencies of the Notes to the Consolidated Financial Statements for additional information regarding our firm transportation agreements.


(7)	The Lease Financing Obligations are calculated based on the aggregate present value of minimum future lease payments.

Non-GAAP Financial Measure

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:


•	Net interest expense;


•	Depreciation, depletion, amortization, and accretion;


•	Impairment of oil and natural gas properties;


•	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 (losses) on acquisition 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; and


•	Material transaction costs incurred on acquisitions.

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 (loss), 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.

For the three months ended September 30, 2015, as compared to the three months ended September 30, 2014, Adjusted EBITDA decreased 19%, from $108.2 million to $88.2 million. For the nine months ended September 30, 2015, as compared to the nine months ended September 30, 2014, Adjusted EBITDA decreased 11%, from $295.8 million to $264.1 million. The following table presents a reconciliation of consolidated net income (loss) to Adjusted EBITDA (in thousands):



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Net income (loss)	$	(462,277	)	$	114,099		$	(1,374,752	)	$	124,482
Plus:
Interest expense	21,130			16,721			61,693			49,529
Depreciation, depletion, amortization, and accretion	52,428			55,680			182,443			150,798
Impairment of oil and natural gas properties	491,487			—			1,357,462			—
Net (gains) losses on commodity derivative contracts	(64,328		)	(83,311		)	(102,561		)	11,125
Net cash settlements received (paid) on matured commodity derivative contracts^(a)(b)(c)	45,368			6,033			125,988			(13,347		)
Net (gains) losses on interest rate derivative contracts ^(d)	807			(511		)	2,291			1,068
Net (gains) losses on acquisitions of oil and natural gas properties	284			(2,409		)	284			(34,523		)
Texas margin taxes	(522		)	156			(380		)	(125		)
Compensation related items	3,827			1,438			11,654			6,440
Material transaction costs incurred on acquisitions	—			349			—			349
Adjusted EBITDA	$	88,204		$	108,245		$	264,122		$	295,796

(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.	$	2,057		$	—		$	4,624		$	—
(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. Also excludes the fair value of derivative contracts acquired and settled during the period.	$	12,453		$	5,608		$	32,734		$	16,472
(c) Excludes fair value of restructured derivative contracts.	$	—		$	—		$	(31,945	)	$	—
(d) Includes settlements paid on interest rate derivatives	$	988		$	1,021		$	2,968		$	3,026

Item 3. 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 over-hedged volumes.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, natural gas and NGLs production. Realized pricing is primarily driven by prevailing spot regional market prices at our primary sales points and the applicable index 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 natural 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.


•	Put options - gives the owner the right, but not the obligation, to sell a specified amount of an underlying security at a specified price.

•

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 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.


•	Put or Call spread options - created when we purchase a put/call and sell a put/call simultaneously.


•	Range bonus accumulators - a structure that allows us to receive a cash payment when the daily average 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. 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 NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits our ability to hedge our NGL 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 they believe that they can take advantage of an unusual market condition allowing them to realize a current gain and then have the ability to enter into a new derivative contract in the future at or above the commodity price of the contract that was liquidated.

At September 30, 2015, the fair value of commodity derivative contracts was an asset of approximately $205.7 million, of which $142.3 million settles during the next twelve months.

The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at September 30, 2015. The amounts below exclude the impact of the LRE Merger and Eagle Rock Merger.



	October 1 - December 31, 2015		Year 2016		Year 2017
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu)	22,436,000		55,083,000		24,027,000
Fixed Price ($/MMBtu)	$	4.26	$	4.47	$	4.35
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)	22,436,000		67,893,000		40,452,000
Floor Price ($/MMBtu)	$	4.26	$	4.37	$	4.18



	October 1 - December 31, 2015		Year 2016
Oil Positions:
Fixed-Price Swaps:
Notional Volume (Bbls)	602,600		329,400
Fixed Price ($/Bbl)	$	71.94	$	76.10
Collars:
Notional Volume (Bbls)	46,000		—
Floor Price ($/Bbl)	$	50.00	$	—
Ceiling Price ($/Bbl)	$	58.45	$	—
Puts:
Notional Volume (Bbls)	—		366,000
Put Price ($/Bbl)	$	—	$	60.00
Three-Way Collars:
Notional Volume (Bbls)	69,000		1,061,400
Floor Price ($/Bbl)	$	90.00	$	90.00
Ceiling Price ($/Bbl)	$	99.13	$	96.18
Put Sold ($/Bbl)	$	76.67	$	73.62
Total Oil Positions:
Notional Volume (Bbls)	717,600		1,756,800
Floor Price ($/Bbl)	$	72.27	$	81.14



	October 1 - December 31, 2015		Year 2016
NGLs Positions:
Fixed-Price Swaps:
Mont Belvieu Propane
Notional Volume (Bbls)	41,400		274,500
Fixed Price ($/Bbl)	$	43.21	$	22.40
Mont Belvieu N. Butane
Notional Volume (Bbls)	9,200		128,100
Fixed Price ($/Bbl)	$	52.08	$	27.63
Mont Belvieu Isobutane
Notional Volume (Bbls)	11,500		54,900
Fixed Price ($/Bbl)	$	53.00	$	27.20
Mont Belvieu N. Gasoline
Notional Volume (Bbls)	—		109,800
Fixed Price ($/Bbl)	$	—	$	52.97
Total NGLs Positions:
Notional Volume (Bbls)	62,100		567,300
Fixed Price ($/Bbl)	$	46.34	$	29.96

As of September 30, 2015, the Company sold the following put option contracts:



	October 1 - December 31, 2015		Year 2016		Year 2017
Gas Positions:
Notional Volume (MMBtu)	6,670,000		1,830,000		1,825,000
Put Sold ($/MMBtu)	$	3.16	$	3.00	$	3.50
Oil Positions:
Notional Volume (Bbls)	128,800		146,400		73,000
Put Sold ($/Bbl)	$	71.43	$	75.00	$	75.00

As of September 30, 2015, the Company had the following open range bonus accumulator contracts:



	October 1 - December 31, 2015		Year 2016
Gas Positions:
Notional Volume (MMBtu)	368,000		—
Bonus ($/MMBtu)	$	0.16	$	—
Range Ceiling ($/MMBtu)	$	4.00	$	—
Range Floor ($/MMBtu)	$	2.50	$	—
Oil Positions:
Notional Volume (Bbls)	46,000		183,000
Bonus ($/Bbl)	$	4.00	$	4.00
Range Ceiling ($/Bbl)	$	100.00	$	100.00
Range Floor ($/Bbl)	$	75.00	$	75.00

As of September 30, 2015, the Company had the following open basis swap contracts:



	October 1 - December 31, 2015			Year 2016			Year 2017
Gas Positions:
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu)	7,360,000			21,960,000			10,950,000
Weighted-basis differential ($/MMBtu)	$	(0.28	)	$	(0.23	)	$	(0.22	)



	October 1 - December 31, 2015			Year 2016
Oil Positions:
WTI Midland and WTI Cushing Basis Differential
Notional Volume (Bbls)	128,800			512,400
Weighted-basis differential ($/Bbl)	$	(1.68	)	$	(0.94	)
West Texas Sour and WTI Cushing Basis Differential
Notional Volume (Bbls)	36,800			219,600
Weighted-basis differential ($/Bbl)	$	(2.33	)	$	(0.43	)
WTI and West Canadian Select Basis Differential
Notional Volume (Bbls)	184,000			—
Weighted-basis differential ($/Bbl)	$	(14.50	)	$	—

As of September 30, 2015, the Company sold calls as follows:



	October 1 - December 31, 2015		Year 2016		Year 2017
Gas Positions:
Notional Volume (MMBtu)	—		9,150,000		9,125,000
Weighted Average Fixed Price ($/MMBtu)	$	—	$	4.25	$	4.50
Oil Positions:
Notional Volume (Bbls)	18,400		622,200		365,000
Weighted Average Fixed Price ($/Bbl)	$	105.00	$	125.00	$	95.00

As of September 30, 2015, the Company had the following open swaptions contracts:



	October 1 - December 31, 2015		Year 2016
Gas Positions:
Notional Volume (MMBtu)	610,000		910,000
Weighted Average Fixed Price ($/MMBtu)	$	3.50	$	3.50

As of September 30, 2015, the Company had the following open call spread contracts:



	October 1 - December 31, 2015
Oil Positions:
Notional Volume (Bbls)	473,800
Call Price ($/Bbl)	$	70.00
Short Call Price ($/Bbl)	$	85.00

Interest Rate Risks

At September 30, 2015, we had debt outstanding of $1.9 billion. The amount outstanding under our Reserve-Based Credit Facility at September 30, 2015 was approximately $1.32 billion and 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 $0.2 million increase in annual interest expense after consideration of the interest rate swaps discussed below.

We enter into interest rate swaps, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The Company records changes in the fair value of its interest rate derivatives in current earnings under net gains or losses on interest rate derivative contracts.

The following summarizes information concerning our positions in open interest rate derivative contracts at September 30, 2015 (in thousands):



	October 1 - December 31, 2015 ⁽¹⁾			Year 2016			Year 2017		January 1 - August 5, 2018
Weighted Average Notional Amount	$	348,587		$	199,399		30,000		30,000
Weighted Average Fixed LIBOR Rate	1.33		%	1.60		%	2.25	%	2.25	%


(1)	The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% for a notional amount of $50.0 million from December 10, 2015 to December 10, 2017.

Counterparty Risk

At September 30, 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 current Standard & Poor’s 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 September 30, 2015
ABN AMRO (A)	$	2,629	$	1,446	$	—		$	—		$	4,075
Bank of America (A)	12,242		6,564		—			—			18,806
Barclays (A-)	10,229		1,807		—			—			12,036
BMO (A+)	6,117		2,788		—			—			8,905
CIBC (A+)	1,478		1,286		—			—			2,764
Citibank (A)	6,410		—		—			(473		)	5,937
Comerica (A)	1,419		326		—			—			1,745
Commonwealth Bank of Australia (AA-)	1,138		949		—			—			2,087
Credit Agricole (A)	—		—		(457		)	—			(457		)
Fifth Third Bank (A-)	2,464		264		—			—			2,728
Huntington Bank (BBB+)	2,220		644		—			—			2,864
ING Financial Markets (A)	1,888		424		—			—			2,312
JP Morgan (A)	39,849		21,785		—			—			61,634
Morgan Stanley (A-)	5,037		5,232		—			—			10,269
Natixis (A)	7,344		1,650		—			—			8,994
PNC (A-)	157		—		—			—			157
RBC (AA-)	8,375		5,985		—			—			14,360
Shell (A+)	—		—		(179		)	—			(179		)
Scotia Capital (A+)	17,954		9,011		—			—			26,965
SunTrust (A-)	1,318		1,040		—			—			2,358
Wells Fargo (AA-)	11,633		1,689		—			—			13,322
Total	$	139,901	$	62,890	$	(636	)	$	(473	)	$	201,682

In order to mitigate the credit risk of financial instruments, we enter into master netting agreements with our counterparties. The master netting agreement is a standardized, bilateral contract between a given counterparty and us. Instead of treating each financial transaction between the counterparty and us separately, the master netting agreement enables the counterparty and us to aggregate all financial trades and treat them as a single agreement. This arrangement is intended to benefit us in two ways: (1) default by a counterparty under one financial trade can trigger rights to terminate all financial trades with such counterparty; and (2) netting of settlement amounts reduces our credit exposure to a given counterparty in the event of close-out. 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 $202.3 million at September 30, 2015.

Item 4. Controls and Procedures

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 Quarterly 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 or submit 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 SEC. Based upon the evaluation, our

principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2015 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

We are defendants in legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of 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. There have been no material developments regarding the various litigation in relation to the Eagle Rock Merger and the LRE Merger as discussed in Part II-Item 1-Legal Proceedings in our Quarterly Report on Form 10-Q for the period ended June 30, 2015, other than as set forth below.

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 June 1, 2015, another alleged Eagle Rock unitholder (the “Federal Plaintiff” and, together with the State Plaintiffs, the “Plaintiffs”) filed a class action lawsuit against Defendants. This lawsuit is 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 (together with the State Lawsuits, the “Lawsuits”).

The Plaintiffs allege a variety of causes of action challenging the Eagle Rock Merger, including that (i) the members of Eagle Rock G&P’s board of directors have allegedly breached duties and the implied covenant of good faith and fair dealing in connection with the Eagle Rock Merger, and (ii) Eagle Rock GP, Eagle Rock G&P, Vanguard, and Merger Sub have allegedly aided and abetted in these alleged breaches. In general, the Plaintiffs allege that the Eagle Rock Merger (a) provided inadequate consideration to Eagle Rock unitholders, (b) was not subject to minority unitholder approval due to a support agreement and the absence of a majority-of-the-minority vote requirement, (c) contained contractual terms (e.g., the no-solicitation, matching rights, and termination fee provisions) that may have dissuaded other potential merger partners from making alternative proposals, and (d) did not include a collar to protect Eagle Rock unitholders against declines in Vanguard’s unit price. The Federal Plaintiff also alleges that Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder. In general, the Federal Plaintiff alleges that the registration statement filed in connection with the Eagle Rock Merger failed, among other things, to disclose allegedly material details concerning (i) Eagle Rock’s and Vanguard’s financial and operational projections, (ii) the analysis underlying the opinion of the financial advisor to Eagle Rock, (iii) the analysis underlying the opinion of the financial advisor to Vanguard, and (iv) the background of the Eagle Rock Merger.

Based on these allegations, the Plaintiffs seek to have the Eagle Rock Merger rescinded. The Federal Plaintiff also seeks damages. The Plaintiffs also seek attorneys’ fees.

The Defendants’ date to answer, move to dismiss, or otherwise respond to the Federal Lawsuit has not yet been set. The Defendants have answered the State Lawsuits, denying the allegations therein. Vanguard cannot predict the outcome of the Lawsuits 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 Lawsuits. The Defendants believe the Lawsuits are without merit and intend to vigorously defend against them.

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.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our securities, please refer to Part I—Item 1A—Risk Factors in our 2014 Annual Report. There have been no material changes to the risk factors set forth in our 2014 Annual Report, other than as set forth below.

Risk Factors Relating to the LRE Merger and Eagle Rock Merger (the “Mergers”)

There may be substantial disruption to Vanguard’s business and distraction of its management and employees as a result of the Mergers.

There may be substantial disruption to the Vanguard’s business and distraction of its management and employees from day-to-day operations because matters related to the Mergers may require substantial commitments of time and resources, which could otherwise have been devoted to other opportunities that could have been beneficial to us.

Vanguard may have difficulty attracting, motivating and retaining executives and other employees in light of the Mergers.

The success of the combined organization after the Mergers will depend in part upon the ability of Vanguard to retain its key employees, including key Eagle Rock and LRE employees. Key employees may depart after the Mergers because of issues relating to the uncertainty and difficulty of integration or a desire not to remain following the Mergers. Accordingly, no assurance can be given that the combined organization will be able to retain key Vanguard, Eagle Rock or LRE employees to the same extent as in the past.

Failure to successfully combine the businesses of Eagle Rock, LRE and Vanguard in the expected time frame may adversely affect the future results of the combined organization.

The success of the Mergers will depend, in part, on the ability of Vanguard to realize the anticipated benefits and synergies from combining the businesses of Vanguard, Eagle Rock and LRE. To realize these anticipated benefits, the businesses must be successfully combined. If the combined organization is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the Mergers 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 and affect the future results of the combined organization.

Lawsuits have been filed challenging the Mergers and additional lawsuits may be filed in the future. Any injunctive relief, rescission, damages, or other adverse judgment could have a material adverse effect on Eagle Rock, LRE, Vanguard, Merger Sub or Lighthouse Merger Sub.

Alleged Eagle Rock unitholders have filed lawsuits challenging the Eagle Rock Merger against Eagle Rock, Eagle Rock GP, Eagle Rock G&P, Vanguard, Merger Sub, and the members of the Eagle Rock G&P board of directors. Alleged LRE unitholders have filed lawsuits challenging the LRE Merger against LRE, LRE GP, the members of the LRE GP board of directors, Vanguard, Lighthouse Merger Sub, and the other parties to the LRE Merger Agreement. Furthermore, additional lawsuits may be filed in the future. For more information on these lawsuits, see “Part II-Item 1-Legal Proceedings.” An adverse judgment for rescission, injunctive relief, monetary damages or other relief could have a material adverse effect on Eagle Rock, LRE, Vanguard or Merger Sub.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

EXHIBIT INDEX

Each exhibit identified below is filed as a part of this Report.



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 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by LRR Energy, L.P. with the SEC on April 22, 2015).	Form 8-K, filed April 22, 2015 (File No. 001-33756)



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. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed by Eagle Rock with the SEC on May 22, 2015).	Form 8-K, filed May 22, 2015 (File No. 001-33756)
3.1	Fifth Amended and Restated Limited Liability Company Agreement of Vanguard Natural Resources, LLC.	Form 8-K, filed September 15, 2014 (File No. 001-33756)
4.1	Registration Rights Agreement, dated as of April 20, 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. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by LRR Energy, L.P. with the SEC on April 22, 2015).	Form 8-K, filed April 22, 2015 (File No. 001-33756)
4.2	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.	Form 8-K, filed May 22, 2015 (File No. 001-33756)
4.3	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. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed by LRR Energy, L.P. with the SEC on May 26, 2015).	Form 8-K, filed May 26, 2015 (File No. 001-33756)
4.4	Specimen Unit Certificate for the Series A Cumulative Redeemable Perpetual Preferred Units (incorporated herein by reference to Exhibit B to Exhibit 3.1).	Form 8-K, filed September 15, 2014 (File No. 001-33756)
4.5	Specimen Unit Certificate for the Series B Cumulative Redeemable Perpetual Preferred Units (incorporated herein by reference to Exhibit C to Exhibit 3.1).	Form 8-K, filed September 15, 2014 (File No. 001-33756)
4.6	Specimen Unit Certificate for the Series C Cumulative Redeemable Perpetual Preferred Units (incorporated herein by reference to Exhibit D to Exhibit 3.1).	Form 8-K, filed September 15, 2014 (File No. 001-33756)
10.1	Voting and Support Agreement, dated as of April 20, 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 purposes of Section 3.2, Lime Rock Management LP, Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by LRR Energy, L.P. with the SEC on April 22, 2015).	Form 8-K, filed April 22, 2015 (File No. 001-33756)
10.2	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 purposes of Section 3.2, Lime Rock Management LP, Lime Rock Resources II-A, L.P. and Lime Rock Resources II-C, L.P. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by LRR Energy, L.P. with the SEC on May 26, 2015).	Form 8-K, filed May 26, 2015 (File No. 001-33756)



10.3	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 hereto	Form 8-K, filed June 3, 2015 (File No. 001-33756)
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities 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(a) and Rule 15d-14(a) of the Securities 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
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

SIGNATURES

Pursuant to the requirements 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.



		VANGUARD NATURAL RESOURCES, LLC
		(Registrant)

	Date: November 9, 2015
		/s/ Richard A. Robert
		Richard A. Robert
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer and Principal Accounting Officer)

Vanguard Natural Resources, Inc. - FORM 10-Q - November 9, 2015

Attached files

Vanguard Natural Resources, Inc. Reports