Vanguard Natural Resources, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.	vnr2016q210-qexhibit32x2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.	vnr2016q210-qexhibit32x1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.	vnr2016q210-qexhibit31x2.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.	vnr2016q210-qexhibit31x1.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 June 30, 2016
	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 July 27, 2016: 131,038,826.

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’ Deficit	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	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	52

PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 3.	Defaults Upon Senior Securities	57
Item 4.	Mine Safety Disclosures	57
Item 5.	Other Information	57
Item 6.	Exhibits	57

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”), VNR Holdings, LLC (“VNRH”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Clear Fork Pipeline LLC, Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Energy Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Energy Acquisition Partnership II, L.P. (“ERAP II”).

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. Forward-looking statements include, but are not limited to, statements we make concerning future actions, conditions or events, future operating results, income or cash flow.

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, 2015 (the “2015 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. These factors and risks include, but are not limited to:


•	risks relating to any of our unforeseen liabilities;


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


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


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


•	the timing of exploitation and development expenditures;


•	inaccuracies of reserve estimates or assumptions underlying them;


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


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


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


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


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


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


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


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


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


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


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


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


•	ability to replace oil and natural gas reserves;


•	any loss of senior management or technical personnel;


•	competition in the oil and gas industry;


•	risks arising out of hedging transactions;


•	the costs and effects of litigation;


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


•	change to tax treatment;


•	lack of sufficient cash flow to pay down our borrowing base deficiency;


•	inability to access debt and equity capital markets and the unreasonable costs of, or our inability to access, alternative sources of capital; and


•	material restructurings of a significant number of companies in the oil and gas industry, which could result in competitors having significantly less leverage than us and, thus, greater ability to acquire additional oil and gas properties and finance their development.

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						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Revenues:
Oil sales	$	49,941		$	44,011		$	85,595		$	79,801
Natural gas sales	32,431			39,897			69,302			95,651
NGLs sales	11,104			11,933			20,019			19,283
Net gains (losses) on commodity derivative contracts	(68,610		)	(20,800		)	(36,851		)	38,233
Total revenues	24,866			75,041			138,065			232,968

Costs and expenses:
Production:
Lease operating expenses	38,515			31,600			80,842			67,078
Production and other taxes	9,476			10,754			18,144			22,180
Depreciation, depletion, amortization, and accretion	38,786			63,175			86,839			130,015
Impairment of oil and natural gas properties	157,894			733,365			365,658			865,975
Selling, general and administrative expenses	13,408			9,142			24,430			18,193
Total costs and expenses	258,079			848,036			575,913			1,103,441

Loss from operations	(233,213		)	(772,995		)	(437,848		)	(870,473		)

Other income (expense):
Interest expense	(23,932		)	(20,374		)	(49,636		)	(40,563		)
Net losses on interest rate derivative contracts	(2,135		)	(281		)	(6,825		)	(1,484		)
Net loss on acquisition of oil and natural gas properties	(1,665		)	—			(1,665		)	—
Gain on extinguishment of debt	—			—			89,714			—
Other	196			5			252			45
Total other income (expense), net	(27,536		)	(20,650		)	31,840			(42,002		)
Net loss	$	(260,749	)	$	(793,645	)	$	(406,008	)	$	(912,475	)
Less: Net income attributable to non-controlling interests	(40		)	—			(64		)	—
Net loss attributable to Vanguard unitholders	(260,789		)	(793,645		)	(406,072		)	(912,475		)
Distributions to Preferred unitholders	(6,689		)	(6,690		)	(13,379		)	(13,380		)
Net loss attributable to Common and Class B unitholders	$	(267,478	)	$	(800,335	)	$	(419,451	)	$	(925,855	)

Net loss per Common and Class B unit – basic and diluted	$	(2.04	)	$	(9.27	)	$	(3.20	)	$	(10.86	)

Weighted average Common units outstanding
Common units – basic & diluted	131,015			85,875			130,772			84,816
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)



	June 30, 2016			December 31, 2015
Assets
Current assets
Cash and cash equivalents	$	31,175		$	—
Trade accounts receivable, net	87,879			115,200
Derivative assets	116,862			236,886
Other current assets	5,669			6,436
Total current assets	241,585			358,522
Oil and natural gas properties, at cost	4,692,747			4,961,218
Accumulated depletion, amortization and impairment	(3,681,745		)	(3,239,242		)
Oil and natural gas properties evaluated, net – full cost method	1,011,002			1,721,976
Other assets
Goodwill	506,046			506,046
Derivative assets	17,176			80,161
Other assets	51,898			28,887
Total assets	$	1,827,707		$	2,695,592

Liabilities and members’ equity
Current liabilities
Accounts payable:
Trade	$	2,737		$	22,895
Affiliates	1,480			1,757
Accrued liabilities:
Lease operating	11,705			19,910
Development capital	10,315			26,726
Interest	10,520			11,958
Production and other taxes	34,647			40,472
Other	3,850			10,378
Derivative liabilities	99			356
Oil and natural gas revenue payable	24,786			44,823
Distributions payable	—			5,018
Current portion of long-term debt	86,040			—
Other current liabilities	16,023			17,715
Total current liabilities	202,202			202,008
Long-term debt, net of current portion (Note 3)	1,819,844			2,277,931
Derivative liabilities	632			—
Asset retirement obligations, net of current portion	258,929			262,432
Other long-term liabilities	39,739			40,656
Total liabilities	2,321,346			2,783,027
Commitments and contingencies (Note 7)
Members’ deficit (Note 8)
Cumulative Preferred units, 13,881,873 units issued and outstanding at June 30, 2016 and December 31, 2015	335,444			335,444
Common units, 131,041,849 units issued and outstanding at June 30, 2016 and 130,476,978 at December 31, 2015	(843,985		)	(430,494		)
Class B units, 420,000 issued and outstanding at June 30, 2016 and December 31, 2015	7,615			7,615
Total VNR members’ deficit	(500,926		)	(87,435		)
Non-controlling interest in subsidiary	7,287			—
Total members’ deficit	(493,639		)	(87,435		)
Total liabilities and members’ deficit	$	1,827,707		$	2,695,592

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBERS’ DEFICIT

FOR THE SIX MONTHS ENDED JUNE 30, 2016 AND THE YEAR ENDED DECEMBER 31, 2015

(in thousands)

(Unaudited)



	Cumulative Preferred Units		Common Units			Class B		Non-controlling Interest			Total Members’ Equity (deficit)
Balance at January 1, 2015	$	335,444	$	1,191,057		$	7,615	$	—		$	1,534,116
Issuance of Common units as consideration for the Eagle Rock Merger, net of merger costs of $5,560	—		253,068			—		—			253,068
Issuance of Common units as consideration for the LRE Merger, net of merger costs of $3,961	—		119,315			—		—			119,315
Issuance of Common units, net of offering costs of $593	—		35,544			—		—			35,544
Repurchase of units under the common unit buyback program			(2,399		)	—		—			(2,399		)
Distributions to Preferred unitholders (see Note 8)	—		(26,760		)	—		—			(26,760		)
Distributions to Common and Class B unitholders (see Note 8)	—		(134,019		)	—		—			(134,019		)
Unit-based compensation	—		16,874			—		—			16,874
Net loss	—		(1,883,174		)	—		—			(1,883,174		)
Balance at December 31, 2015	$	335,444	$	(430,494	)	$	7,615	$	—		$	(87,435	)
Issuance costs related to prior period equity transactions	—		67			—		—			67
Distributions to Preferred unitholders (see Note 8)	—		(5,575		)	—		—			(5,575		)
Distributions to Common and Class B unitholders (see Note 8)	—		(8,014		)	—		—			(8,014		)
Unit-based compensation	—		6,103			—		—			6,103
Net income (loss)	—		(406,072		)	—		64			(406,008		)
Non-controlling interest in subsidiary	—		—			—		7,453			7,453
Potato Hills cash distribution to non-controlling interest	—		—			—		(230		)	(230		)
Balance at June 30, 2016	$	335,444	$	(843,985	)	$	7,615	$	7,287		$	(493,639	)

See accompanying notes to consolidated financial statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)



	Six Months Ended
	June 30,
Operating activities	2016			2015
Net loss	$	(406,008	)	$	(912,475	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	86,839			130,015
Impairment of oil and natural gas properties	365,658			865,975
Amortization of deferred financing costs	2,348			1,937
Amortization of debt discount	1,783			142
Compensation related items	6,103			7,420
Net (gains) losses on commodity and interest rate derivative contracts	43,676			(36,749		)
Cash settlements received on matured commodity derivative contracts	142,476			80,620
Cash settlements paid on matured interest rate derivative contracts	(4,727		)	(1,980		)
Net loss on acquisition of oil and natural gas properties	1,665			—
Gain on extinguishment of debt	(89,714		)	—
Changes in operating assets and liabilities:
Trade accounts receivable	25,427			54,263
Other current assets	(96		)	(1,852		)
Net premiums received (paid) on commodity derivative contracts	905			(794		)
Accounts payable and oil and natural gas revenue payable	(40,220		)	(13,491		)
Payable to affiliates	(277		)	443
Accrued expenses and other current liabilities	(41,323		)	(11,823		)
Other assets	4,495			3,064
Net cash provided by operating activities	99,010			164,715
Investing activities
Additions to property and equipment	(36		)	(196		)
Potato Hills Gas Gathering System acquisition	(7,470		)	—
Additions to oil and natural gas properties	(35,469		)	(52,100		)
Acquisitions of oil and natural gas properties	—			(1,372		)
Deposits and prepayments of oil and natural gas properties	(5,342		)	(3,818		)
Proceeds from the sale of oil and natural gas properties	285,590			—
Net cash provided by (used in) investing activities	237,273			(57,486		)
Financing activities
Proceeds from long-term debt	93,500			117,500
Repayment of long-term debt	(377,228		)	(159,636		)
Proceeds from Common unit offerings, net	—			32,737
Repurchase of units under the Common unit buyback program	—			(2,399		)
Distributions to Preferred unitholders	(6,690		)	(13,380		)
Distributions to Common and Class B unitholders	(11,917		)	(75,794		)
Potato Hills distribution to non-controlling interest	(230		)	—
Financing fees	(2,543		)	(2,125		)
Net cash used in financing activities	(305,108		)	(103,097		)
Net increase cash and cash equivalents	31,175			4,132
Cash and cash equivalents, beginning of period	—			—
Cash and cash equivalents, end of period	$	31,175		$	4,132



Supplemental cash flow information:
Cash paid for interest	$	47,008	$	38,525
Non-cash financing and investing activity:
Asset retirement obligations, net	$	10,045	$	789
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 June 30, 2016, we own properties and oil and natural gas reserves primarily located in ten operating areas:


•	the Green River Basin in Wyoming;


•	the Permian Basin in West Texas and New Mexico;


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


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Piceance Basin in Colorado;


•	the Big Horn Basin in Wyoming and Montana;


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Cumulative Preferred Units”), 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Cumulative Preferred Units”) and 7.75% Series C Cumulative Redeemable Perpetual Preferred Units (“Series C Cumulative Preferred Units,” and, collectively with the Series A Units and Series B Units, the “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, 2015, from the audited financial statements contained in our 2015 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 2015 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 June 30, 2016, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2015 Annual Report.


(a)	Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of June 30, 2016 and December 31, 2015 and for the three and six months ended June 30, 2016 and 2015 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.

We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements.


(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 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 six months ended June 30, 2016 of $365.7 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2016 and June 30, 2016. The impairment for the first quarter of 2016 was $207.8 million and was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. The impairment for the second quarter of 2016 was $157.9 million and was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil.

For the six months ended June 30, 2015, we recorded a non-cash ceiling test impairment of oil and natural gas properties of $866.0 million as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015 and

June 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.

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 August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities must apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018.

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

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities—Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective.


(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.


(e)	Prior Year Financial Statement Presentation

Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this Quarterly Report on Form 10-Q. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion regarding this reclassification.

2. Acquisitions and Divestitures

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. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below.

2016 Acquisitions and Divestitures

In January 2016, we completed the acquisition of a 51% joint venture interest in Potato Hills Gas Gathering System, a gathering system located in Latimer County, Oklahoma, including the acquisition of the compression assets relating to the gathering system, for a total consideration of $7.7 million. As part of the acquisition, Vanguard also acquired the seller’s rights as manager under the related joint venture agreement. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

During the six months ended June 30, 2016, we completed the sale of certain of our properties in Eddy County, New Mexico, Martin County, Texas and Pontotoc County, Oklahoma for an aggregate consideration of approximately $21.2 million. All cash proceeds received from the sale of these properties were used to reduce borrowings under our Reserve-Based Credit Facility.

In May 2016, we completed the sale of our natural gas, oil and natural gas liquids assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $272.5 million, subject to final post-closing adjustments (the “SCOOP/STACK Divestiture”). At closing, we received net cash proceeds of $263.1 million, while $9.4 million of the total consideration is currently held in escrow. The Company used $261.0 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale.

2015 Acquisitions and Mergers

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 based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

LRE Merger

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

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

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

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

The following presents the values assigned to the net assets acquired in the LRE Merger as of the merger date (in thousands):




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

Eagle Rock Merger

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

Under the terms of the Eagle Rock Merger Agreement, each common unit representing limited partner interests in Eagle Rock (“Eagle Rock Common Unit”) was converted into the right to receive 0.185 newly issued Vanguard common units or, in the case of fractional Vanguard common units, cash (without interest and rounded up to the nearest whole cent).

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

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

The following presents the values assigned to the net assets acquired in the Eagle Rock Merger as of the merger date (in thousands):



Consideration
Market value of Vanguard’s common units issued to Eagle Rock unitholders	$	258,282
Long-term debt assumed	156,550
Replacement unit-based payment awards attributable to pre-combination services	346
	415,178
Add: fair value of liabilities assumed
Accounts payable and accrued liabilities	53,255
Other current liabilities	2,206
Derivative liabilities	2,201
Asset retirement obligations	48,633
Deferred tax liability	39,327
Other long-term liabilities	1,244
Amount attributable to liabilities assumed	146,866
Less: fair value of assets acquired
Cash	6,971
Trade accounts receivable	15,878
Other current assets	15,664
Oil and natural gas properties	462,715
Derivative assets	90,234
Other assets	9,734
Amount attributable to assets acquired	601,196
Bargain Purchase Gain	$	(39,152	)

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

Vanguard determined that the bargain purchase gain was primarily attributable to unfavorable market trends between the date the parties agreed to the consideration for the Eagle Rock Merger and the date the transaction was completed, resulting in the decline of Vanguard’s unit price. Although the depressed oil and natural gas market also affected the fair value of Eagle Rock’s oil and natural gas properties, it had a more significant impact on Vanguard’s unit price compared to the resulting decrease in the fair value of those properties. As a result, the fair value of the net assets acquired in the Eagle Rock Merger, including the oil and natural gas properties, exceeded the total consideration paid. During the three and six months ended June 30, 2016, Vanguard made an adjustment to the amounts assigned to the net assets acquired based on new information obtained about facts that existed as of the merger date. As a result, the bargain purchase gain was reduced by $1.6 million. This adjustment is included in the net loss on acquisition of oil and natural gas properties for this period.

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and six months ended June 30, 2015 to show the effect on our consolidated results of operations as if our acquisitions and mergers completed in 2015 had occurred on January 1, 2014. The pro forma results also reflect the impact of the SCOOP/STACK Divestiture as if it had occurred on January 1, 2015

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 2015 and eliminating the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture, 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, (iii) interest expense on additional debt assumed in the LRE Merger and the Eagle Rock Merger, and (iv) the impact of the common units issued in the LRE Merger and the Eagle Rock Merger.

The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:



	Pro forma
	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in thousands, except per unit data)
Total revenues	$	17,480		$	89,272		$	120,523		$	322,641
Net loss	$	(269,028	)	$	(844,023	)	$	(425,383	)	$	(1,044,315	)
Net loss per unit
Common and Class B units - basic and diluted	$	(2.05	)	$	(6.54	)	$	(3.25	)	$	(8.09	)

The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows (in thousands):



	Pro forma
	Three Months Ended June 30, 2016		Six Months Ended June 30, 2016
	(in thousands)
Revenues	$	7,386	$	17,542
Excess of revenues over direct operating expenses	$	6,222	$	15,278

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 2015 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		Six Months Ended
	June 30, 2016		June 30, 2016
	(in thousands)
Eagle Rock Merger
Revenues	$	14,208	$	33,180
Excess of revenues over direct operating expenses	$	7,182	$	17,723
LRE Merger
Revenues	$	11,800	$	16,340
Excess of revenues over direct operating expenses	$	5,362	$	6,854

3. Long-Term Debt

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



			Amount Outstanding
Description	Interest Rate	Maturity Date	June 30, 2016			December 31, 2015
			(in thousands)
Senior Secured Reserve-Based Credit Facility	Variable(1)	April 16, 2018	$	1,406,500		$	1,688,000
Senior Notes due 2019	8.375% (2)	June 1, 2019	51,120			51,120
Senior Notes due 2020	7.875% (3)	April 1, 2020	381,830			550,000
Senior Notes due 2023	7.00%	February 15, 2023	75,634			—
Lease Financing Obligation	4.16%	August 10, 2020 (4)	22,441			24,668
			$	1,937,525		$	2,313,788
Less:
Current portion of debt under the Reserve-Based Credit Facility (5)			(86,040		)	—
Unamortized discount on Senior Notes			(15,131		)	(17,651		)
Unamortized deferred financing costs (6)			(11,915		)	(13,705		)
Current portion of Lease Financing Obligation			(4,595		)	(4,501		)
Total long-term debt			$	1,819,844		$	2,277,931


(1)	Variable interest rate was 2.96% and 2.90% at June 30, 2016 and December 31, 2015, respectively.


(2)	Effective interest rate was 21.45% at June 30, 2016 and December 31, 2015.


(3)	Effective interest rate was 8.00% at June 30, 2016 and December 31, 2015.


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


(5)	Represents the remaining borrowing base deficiency obligation as of June 30, 2016 payable in five equal monthly installments through November 2016.


(6)	In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or members’ equity.

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. On May 26, 2016, the Company entered into the Tenth Amendment (the “Tenth Amendment”) to its Credit Agreement which reduced the Company’s borrowing base from $1.78 billion to $1.325 billion (the “Reserve-Based Credit Facility”). As of May 26, 2016, Vanguard had $1.424 billion in outstanding borrowings and approximately $4.5 million in outstanding letters of credit (discussed below), resulting in a deficiency of approximately $103.5 million. Under Vanguard’s Credit Agreement, the Company will make principal payments in an aggregate amount equal to such borrowing base deficiency in six equal monthly installments of approximately $17.3 million with the first payment due and payable within 30 days of the effective date of the Tenth Amendment. Vanguard made the first and second required deficiency payments for a total of $35.0 million on June 27, 2016 and July 26, 2016, respectively, thus reducing the remaining future monthly installments to $17.1 million.

The Tenth Amendment also includes, among other provisions, a one-time current ratio waiver for the second quarter of 2016, an increase in the mortgage requirement from 80% to 95% and an additional Event of Default clause. An Event of Default would occur should the Company make any payment of principal, accrued interest or fees to any Senior Notes or Second Lien Debt on or after September 15, 2016 if the Company’s pro forma liquidity after giving pro forma effect to such payment is less than $50 million. Liquidity, as defined under the Credit Agreement, means the sum of (a) the Company’s unrestricted cash and cash equivalents, plus (b) the amount available to be borrowed under our Reserve-Based Credit Facility. Since the Company currently has a borrowing base deficiency, liquidity is equal to the balance of the Company’s unrestricted cash and cash equivalents less the borrowing base deficiency obligation.

The mortgage requirement provides that the mortgaged properties under the Credit Agreement must represent at least 95% of the value of the Company’s oil and natural gas properties evaluated based on the Company’s most recently completed engineering report with respect to our oil, natural gas and NGLs reserves. In the event that the mortgage requirement is not met, the Company would be required to provide additional lien interest on its oil and natural gas properties to be in compliance with terms of our Credit Agreement.

As of June 30, 2016, there were approximately $1.41 billion of outstanding borrowings and approximately $4.5 million in outstanding letters of credit resulting in a borrowing deficiency of $86.0 million under the Reserve-Based Credit Facility.

The Company’s failure to repay any of the installments due related to the borrowing base deficiency shall constitute an event of default under the Credit Agreement and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Notes Due 2020 and Senior Secured Second Lien Notes. In such case, we may not have sufficient assets to repay our creditors, including the holders of our Senior Notes. As a result, there may not be any value remaining attributable to the holders of our Common units and Cumulative Preferred Units.

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 June 30, 2016, 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 5.25 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. As discussed above, under the Tenth Amendment, the lenders waived the requirement to maintain a current ratio of not less than 1.0 to 1.0 solely for the fiscal quarter ended June 30, 2016. We were in compliance with all of our debt covenants as of June 30, 2016.

Letters of Credit

At June 30, 2016, 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 marketing counterparties.

8.375% Senior Notes Due 2019

At June 30, 2016, we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger. Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 are fully and unconditionally (except for customary release provisions) and jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of our existing subsidiaries, all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”). Prior to the Eagle Rock Merger, the parties to the indenture executed a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default with respect to the Senior Notes due 2019.

We have the option to redeem some or all of the Senior Notes due 2019 at any time at redemption prices equal to the aggregate principal amount multiplied by (i) 102.094% if such Senior Notes due 2019 are redeemed in 2016 and (ii) 100.000% if such Senior Notes due 2019 are redeemed in 2017 and thereafter.

7.875% Senior Notes Due 2020

At June 30, 2016, we had $381.8 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations.

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

The Senior Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes due 2020 achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Notes Indenture exists, many of the foregoing covenants will terminate. As of June 30, 2016, based on the most restrictive covenants of the Senior Notes Indenture and as a result of our borrowing base deficiency, we are restricted from making distributions to our unitholders. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under Senior Notes due 2020.

Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes due 2020 at any one or more occasions on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016, plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed, declining to 100% on April 1, 2018 and thereafter. We had the option to redeem some or all of the Senior Notes due 2020 at any one or more occasions prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes due 2020 thereof, plus a “make-whole” premium, and accrued and unpaid interest to the redemption date. We did not redeem any of the Senior Notes due 2020 prior to April 1, 2016. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes due 2020, respectively.

7.0% Senior Secured Second Lien Notes Due 2023

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

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

The Senior Secured Second Lien Notes Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Secured Second Lien Notes achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Senior Secured Second Lien Notes Indenture exists, many of the foregoing covenants will terminate. As of June 30, 2016, based on the most restrictive covenants of the Senior Secured Second Lien Notes Indenture and as a result of our borrowing base deficiency, we are restricted from making distributions to our unitholders. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Secured Second Lien Notes.

The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for the six months ended June 30, 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 extinguished in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million.

Lease Financing Obligations

On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, 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%.

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 June 30, 2016, the Company had open commodity derivative contracts covering our anticipated future production as follows:

Fixed-Price Swaps (NYMEX)



	Gas			Oil			NGLs
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average WTI Price		Bbls	Weighted Average Fixed Price
July 1, 2016 – December 31, 2016	36,528,944	$	4.36	938,283	$	84.00	455,000	$	30.31
January 1, 2017 – December 31, 2017	53,725,260	$	3.75	749,698	$	85.70	—	$	—

Fixed-Price Swaps (Light Louisiana Sweet)



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

Call Options Sold



	Gas			Oil
Contract Period	MMBtu	Weighted Average Fixed Price		Bbls	Weighted Average Fixed Price
July 1, 2016 – December 31, 2016	4,600,000	$	4.25	312,800	$	50.00
January 1, 2017 – December 31, 2017	11,862,500	$	3.01	365,000	$	95.00

Swaptions



	Gas
Contract Period	MMBtu	Weighted Average Fixed Price
January 1, 2017 – December 31, 2017	2,062,500	$	2.74
January 1, 2018 – December 31, 2018	675,000	$	2.74

Basis Swaps



	Gas
Contract Period	MMBtu	Weighted Avg. Basis Differential ($/MMBtu)			Pricing Index
July 1, 2016 – December 31, 2016	19,320,000	$	(0.20	)	Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2017 – December 31, 2017	21,900,000	$	(0.20	)	Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
July 1, 2016 – December 31, 2016	477,354	$	(0.08	)	Houston Ship Channel and NYMEX Henry Hub Basis Differential
July 1, 2016 – December 31, 2016	140,433	$	(0.10	)	TexOk and NYMEX Henry Hub Basis Differential
July 1, 2016 – December 31, 2016	788,896	$	(0.13	)	WAHA and NYMEX Henry Hub Basis Differential



	Oil
Contract Period	Bbls	Weighted Avg. Basis Differential ($/Bbl)			Pricing Index
July 1, 2016 – December 31, 2016	486,000	$	(1.01	)	WTI Midland and WTI Cushing Basis Differential
July 1, 2016 – December 31, 2016	110,400	$	(0.43	)	West Texas Sour and WTI Cushing Basis Differential
July 1, 2016 – December 31, 2016	368,000	$	(14.25	)	WTI and West Canadian Select Basis Differential

Three-Way Collars



	Gas
Contract Period	MMBtu	Floor		Ceiling		Put Sold
July 1, 2016 – December 31, 2016	6,440,000	$	3.95	$	4.25	$	3.00
January 1, 2017 – December 31, 2017	14,600,000	$	3.88	$	4.15	$	3.31



	Oil
Contract Period	Bbls	Floor		Ceiling		Put Sold
July 1, 2016 – December 31, 2016	533,600	$	90.00	$	96.18	$	73.62

Put Options Sold



	Gas			Oil
Contract Period	MMBtu	Put Sold ($/MMBtu)		Bbls	Put Sold ($/Bbl)
July 1, 2016 – December 31, 2016	920,000	$	3.00	73,600	$	75.00
January 1, 2017 – December 31, 2017	1,825,000	$	3.50	73,000	$	75.00

Range Bonus Accumulators



	Oil
Contract Period	Bbls	Bonus		Range Ceiling		Range Floor
July 1, 2016 – December 31, 2016	92,000	$	4.00	$	100.00	$	75.00

Collars



	Oil
Contract Period	Bbls	Floor Price ($/Bbl)		Ceiling Price ($/Bbl)
July 1, 2016 – December 31, 2016	322,000	$	41.00	$	50.57

Puts



	Oil
Contract Period	Bbls	Put Price ($/Bbl)
July 1, 2016 – December 31, 2016	184,000	$	60.00

Interest Rate Swaps

At June 30, 2016, we had open interest rate derivative contracts as follows (in thousands):



Period	Notional Amount		Fixed LIBOR Rates
July 1, 2016 to December 10, 2016	$	20,000	2.17	%
July 1, 2016 to October 31, 2016	$	40,000	1.65	%
July 1, 2016 to August 5, 2018	$	30,000	2.25	%
July 1, 2016 to August 6, 2016	$	25,000	1.80	%
July 1, 2016 to October 31, 2016	$	20,000	1.78	%
July 1, 2016 to September 23, 2016	$	75,000	1.15	%
July 1, 2016 to September 7, 2016	$	25,000	1.25	%
July 1, 2016 to December 31, 2019	$	175,000	2.32	%
July 1, 2016 to February 16, 2017	$	75,000	1.73	%
July 1, 2016 to June 16, 2017	$	70,000	1.43	%
July 1, 2016 to February 16, 2017	$	75,000	1.73	%
Total	$	630,000

Balance Sheet Presentation

Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets 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):



	June 30, 2016
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	$	171,889		$	(25,165	)	$	146,724
Interest rate derivative contracts	—			(12,686		)	(12,686		)
Total derivative instruments	$	171,889		$	(37,851	)	$	134,038

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	$	(25,828	)	$	25,165		$	(663	)
Interest rate derivative contracts	(12,754		)	12,686			(68		)
Total derivative instruments	$	(38,582	)	$	37,851		$	(731	)



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

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

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. The majority of our counterparties are participants in our Reserve-Based Credit Facility (see Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements 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 $171.9 million at June 30, 2016. 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 June 30, 2016. 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 six months ended June 30, 2016 and the year ended December 31, 2015 are as follows:



	Six Months Ended June 30, 2016			Year Ended December 31, 2015
	(in thousands)
Derivative asset at beginning of period, net	$	316,691		$	220,734
Purchases
Fair value of derivatives acquired	—			195,273
Net premiums and fees (received) paid or deferred for derivative contracts	(1,959		)	7,126
Net gains (losses) on commodity and interest rate derivative contracts	(43,676		)	169,569
Settlements
Cash settlements received on matured commodity derivative contracts	(142,476		)	(211,723		)
Cash settlements paid on matured interest rate derivative contracts	4,727			5,227
Termination of derivative contracts	—			(69,515		)
Derivative asset at end of period, net	$	133,307		$	316,691

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 represent their 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 June 30, 2016, the fair value of our Senior Notes due 2020 was estimated to be $132.7 million and our Senior Notes due 2019 was estimated to be $16.2 million. Our Senior Secured Second Lien Notes are a private debt and we estimated its fair value to be $26.3 million valued based on the prices used to estimate the fair value of our Senior Notes due 2020. 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):



	June 30, 2016
	Fair Value Measurements Using								Assets/Liabilities
	Level 1		Level 2			Level 3			at Fair Value
Assets:
Commodity price derivative contracts	$	—	$	148,960		$	(2,236	)	$	146,724
Interest rate derivative contracts	—		(12,686		)	—			(12,686		)
Total derivative instruments	$	—	$	136,274		$	(2,236	)	$	134,038
Liabilities:
Commodity price derivative contracts	$	—	$	(663	)	$	—		$	(663	)
Interest rate derivative contracts	—		(68		)	—			(68		)
Total derivative instruments	$	—	$	(731	)	$	—		$	(731	)



	December 31, 2015
	Fair Value Measurements Using								Assets/Liabilities
	Level 1		Level 2			Level 3			at Fair Value
Assets:
Commodity price derivative contracts	$	—	$	333,380		$	(5,933	)	$	327,447
Interest rate derivative contracts	—		(10,400		)	—			(10,400		)
Total derivative instruments	$	—	$	322,980		$	(5,933	)	$	317,047
Liabilities:
Commodity price derivative contracts	$	—	$	(99	)	$	—		$	(99	)
Interest rate derivative contracts	—		(257		)	—			(257		)
Total derivative instruments	$	—	$	(356	)	$	—		$	(356	)

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:



	Six Months Ended
	June 30,
	2016			2015
	(in thousands)
Unobservable inputs, beginning of period	$	(5,933	)	$	(6,470	)
Total gains	6,922			4,417
Settlements	(3,225		)	(1,869		)
Unobservable inputs, end of period	$	(2,236	)	$	(3,922	)

Change in fair value included in earnings related to derivatives still held as of June 30,	$	589		$	734

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 June 30, 2016, 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 six months ended June 30, 2016, in connection with new wells drilled, we incurred and recorded asset retirement obligations totaling $0.3 million, at fair value and also recorded a $4.4 million reduction due to a change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the six months ended June 30, 2016. During the year ended December 31, 2015, in connection with the oil and natural gas properties acquired in all of our acquisitions, the LRE Merger and the Eagle Rock Merger, as well as new wells drilled, we incurred and recorded asset retirement obligations totaling $90.9 million, at fair value. In addition, we recorded a $22.3 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the year ended December 31, 2015. 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 5.5%; and (4) the average inflation factor (2.0%). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

6. Asset Retirement Obligations

The asset retirement obligations as of June 30, 2016 and December 31, 2015 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2016 and the year ended December 31, 2015 were as follows:



	June 30, 2016			December 31, 2015
	(in thousands)
Asset retirement obligations, beginning of period	$	271,456		$	149,062
Liabilities added during the current period	287			2,699
Liabilities added from the LRE Merger and the Eagle Rock Merger	—			88,228
Accretion expense	6,150			10,238
Retirements	(249		)	(838		)
Liabilities related to assets divested	(5,964		)	(262		)
Change in estimate	(4,368		)	22,329
Asset retirement obligation, end of period	267,312			271,456
Less: current obligations	(8,383		)	(9,024		)
Long-term asset retirement obligation, end of period	$	258,929		$	262,432

Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During the six months ended June 30, 2016 and year ended December 31, 2015, the Company reviewed actual abandonment costs with previous estimates and as a result, decreased its estimates of future asset retirement obligations by $4.4 million and increased its estimates of future asset retirement obligations by $22.3 million, respectively, to reflect revised estimates to be incurred for plugging and abandonment costs.

7. Commitments and Contingencies

Transportation Demand Charges

As of June 30, 2016, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one month to four 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 June 30, 2016. 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.



	June 30, 2016
	(in thousands)
July 1, 2016 - December 31, 2016	$	6,972
2017	12,512
2018	11,696
2019	9,661
2020	410
Total	$	41,251

Legal Proceedings

We are defendants in certain legal proceedings arising in the normal course of our business. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

We are also a party to separate legal proceedings relating to (i) the LRE Merger, (ii) the Eagle Rock Merger and (iii) our exchange (the “Debt Exchange”) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for further discussion). Please read Part II, Item 1, Legal Proceedings for further discussion.

8. Members’ Deficit and Net Loss per Common and Class B Unit

Cumulative Preferred Units

The following table summarizes the Company’s Cumulative Preferred Units outstanding at June 30, 2016 and December 31, 2015:



				June 30, 2016			December 31, 2015
	Earliest Redemption Date	Liquidation Preference Per Unit	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, in connection with a change of control. The Cumulative Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Cumulative Preferred Units in the event of a change of control. Holders of the Cumulative Preferred Units will have no voting rights except for

limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above.

On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. All preferred distributions will continue to accumulate and must be paid in full before distributions to common and Class B unitholders can resume. As of June 30, 2016, dividends in arrears related to our Cumulative Preferred Units were $1.7 million, $4.4 million and $2.8 million, respectively.

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 six months ended June 30, 2016 and the year ended December 31, 2015 (in thousands):



	June 30, 2016	December 31, 2015
Beginning of period	130,477	83,452
Issuance of Common units as consideration for the Eagle Rock Merger	—	27,886
Issuance of Common units as consideration for the LRE Merger	—	15,448
Issuance of Common units for cash	—	2,430
Repurchase of units under the Common unit buyback program	—	(157	)
Unit-based compensation	565	1,418
End of period	131,042	130,477

There was no change in issued and outstanding Class B units during the six months ended June 30, 2016 or the year ended December 31, 2015.

Net 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, which reflects all accumulated distributions on Cumulative Preferred Units, including distributions in arrears, 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.

For the three months ended June 30, 2016 and 2015, 2,633,333 and 192,156 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. For the six months ended June 30, 2016 and 2015, 2,633,333 and 211,400 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were also in a loss position.

Distributions Declared

The Cumulative Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Cumulative Preferred Units are cumulative from the date of original issue and 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. Distributions on our Cumulative Preferred Units accumulate at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative Preferred Unit.

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

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



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

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

On March 18, 2016, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence in order to set forth in writing the revised terms of each executive’s employment relationship with VNRH. The Amended Agreements were effective January 1, 2016 and the initial term of the Amended Agreements ends on January 1, 2019, with a subsequent twelve-month term extension automatically commencing on January 1, 2019 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 the executive officers an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon four Company performance components: adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses, as well as a fifth component determined solely in the discretion of our board of directors. As of June 30, 2016 and 2015, we recognized an accrued liability of $0.7 million related to the performance-based bonus award. In addition, compensation expense related to these arrangements of $0.7 million and $0.3 million were recorded for the three months ended June 30, 2016 and 2015, respectively, and $1.2 million and $0.7 million for the six months ended June 30, 2016 and 2015, respectively, which were 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.

2016 Unit Grants

In January 2016, the executives were granted a total of 2,255,033 phantom units in accordance with the Amended Agreements. Also, during the six months ended June 30, 2016, our three independent board members were granted a total of 125,838 phantom units which will vest one year from the date of grant. In addition, VNR employees were granted 1,331,579

phantom units under the VNR LTIP which will vest three years from the date of grant and a VNR employee was granted a total of 7,500 restricted units under the VNR LTIP of which one-third will vest on each one-year anniversary of the date of grant so long as the employee remains continuously employed with the Company. The phantom units include a tandem grant of DERs.

Restricted Units

A summary of the status of the non-vested restricted units as of June 30, 2016 is presented below:



	Number of Non-vested Restricted Units		Weighted Average Grant Date Fair Value
Non-vested restricted units at December 31, 2015	976,348		$	18.29
Granted	7,500		$	3.11
Forfeited	(26,868	)	$	13.83
Vested	(255,483	)	$	16.95
Non-vested restricted units at June 30, 2016	701,497		$	18.83

At June 30, 2016, there was approximately $7.6 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.4 years. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $1.4 million and $3.4 million in the selling, general and administrative expenses line item for the three months ended June 30, 2016 and 2015, respectively, and $2.6 million and $7.0 million for the six months ended June 30, 2016 and 2015, respectively.

Phantom Units

A summary of the status of the non-vested phantom units under the VNR LTIP as of June 30, 2016 is presented below:



	Number of Non-vested Phantom Units		Weighted Average Grant Date Fair Value
Non-vested restricted units at December 31, 2015	203,221		$	20.99
Granted	3,712,450		$	2.56
Forfeited	(20,747	)	$	2.04
Vested	(121,273	)	$	22.24
Non-vested phantom units at June 30, 2016	3,773,651		$	2.93

At June 30, 2016, there was approximately $9.4 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 $1.2 million and $0.4 million in the selling, general and administrative expense line item for the three months ended June 30, 2016 and 2015, respectively, and $2.4 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively.

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 three and six months ended June 30, 2016 and 2015. 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, 2015 (the “2015 Annual Report”) and the historical unaudited consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.

Overview

acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, as of June 30, 2016, we own properties and oil and natural gas reserves primarily located in ten operating basins:


•	the Green River Basin in Wyoming;


•	the Permian Basin in West Texas and New Mexico;


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


•	the Anadarko Basin in Oklahoma and North Texas;


•	the Piceance Basin in Colorado;


•	the Big Horn Basin in Wyoming and Montana;


•	the Arkoma Basin in Arkansas and Oklahoma;


•	the Williston Basin in North Dakota and Montana;


•	the Wind River Basin in Wyoming; and


•	the Powder River Basin in Wyoming.

As of June 30, 2016, based on internal reserve estimates, our total estimated proved reserves were 1,843 Bcfe, of which approximately 67% were natural gas reserves, 18% were oil reserves and 15% were NGLs reserves. Of these total estimated proved reserves, approximately 75%, or 1,374 Bcfe, were classified as proved developed. Also, at June 30, 2016, we owned working interests in 12,803 gross (4,509 net) productive wells. Our operated wells accounted for approximately 57% of our total estimated proved reserves at June 30, 2016. Our average net daily production for the six months ended June 30, 2016 and the year ended December 31, 2015 was 459 MMcfe/day and 415 MMcfe/day, respectively. We have interests in approximately 776,676 gross undeveloped leasehold acres surrounding our existing wells. As of June 30, 2016, based on internal reserve estimates, approximately 25%, or 469 Bcfe, of our estimated proved reserves was attributable to our interests in undeveloped acreage.

Recent Developments

Divestiture

On May 19, 2016, we completed the sale of our natural gas, oil and natural gas liquids assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $272.5 million, subject to final post-closing adjustments. This transaction had an effective date of January 1, 2016. At closing, we received net cash proceeds of $263.1 million, while $9.4 million of the total consideration is currently being held in escrow. The Company used $261.0 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale.

Tenth Amendment to the Credit Agreement

On May 26, 2016, we entered into the Tenth Amendment to our Credit Agreement (the “Tenth Amendment”) which reduced the Company’s borrowing base from $1.78 billion to $1.325 billion (the “Reserve-Based Credit Facility”). As of May 26, 2016, Vanguard had $1.424 billion in outstanding borrowings and approximately $4.5 million in outstanding letters of credit (discussed below), resulting in a deficiency of approximately $103.5 million. Under Vanguard’s Credit Agreement, the Company will make principal payments in an aggregate amount equal to such borrowing base deficiency in six equal monthly installments of approximately $17.3 million with the first payment due and payable within 30 days of the effective date of the Tenth Amendment. Vanguard made the first and second required deficiency payments for a total of $35.0 million on June 27, 2016 and July 26, 2016, respectively.

Second Lien Debt on or after September 15, 2016 if the Company’s pro forma liquidity after giving pro forma effect to such payment is less than $50 million.

Business Environment and Outlook

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitcal and economic conditions. During the past two years and the first half of 2016, oil, natural gas and NGLs prices decreased dramatically. The crude oil spot price per barrel during the years ended December 31, 2014 and 2015 ranged from a high of $107.95 to a low of $34.55 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $6.15 to a low of $1.76. NGLs prices also suffered a similar decline. The crude oil spot price per barrel during the first half of 2016 ranged from a high of $51.23 to a low of $26.19 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $2.92 to a low of $1.64. As of July 25, 2016, the crude oil spot price per barrel was $42.40 and the NYMEX natural gas spot price per MMBtu was $2.80. Among the factors causing such volatility are the domestic and foreign supply of oil and natural gas, the inability of the members of OPEC and other producing countries to agree upon and maintain prices and production levels, social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States and the level and growth of consumer product demand.

The dramatic decline in commodity prices has had a negative impact on the price of our common and preferred units. During 2015, our common unit price declined from a high of $18.72 on February 9, 2015 to a low of $2.46 on December 14, 2015. During the first half of 2016, our common unit price fluctuated between a closing high of $3.11 on January 4, 2016 to a closing low of $1.15 on June 27, 2016. This low commodity price environment has had and will continue to have a direct impact on our revenue, cash flow from operations and Adjusted EBITDA until commodity prices improve. Sustained low prices or any further declines in prices of oil, natural gas and NGLs could have a material adverse impact on our financial condition, profitability, future growth, borrowing base and the carrying value of our oil and natural gas properties. Additionally, sustained low prices or any further decline in prices of oil, natural gas and NGLs could reduce the amount of oil, natural gas and NGLs that we can produce economically, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil and natural gas properties. To illustrate the impact of a sustained low commodity price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of June 30, 2016 would decrease from 1,843 Bcfe to 1,140 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices and oil prices were derived from the 5-year NYMEX forward strip price (using monthly NYMEX settlement prices through December 2021) at July 21, 2016, our total proved reserves as of June 30, 2016 would increase from 1,843 Bcfe to 2,190 Bcfe. Below is a tabular presentation of the impact on reserves from the change in prices depicted in illustration (2) above compared to the SEC 12-month average pricing of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil (held constant):



	2016	2017	2018	2019	2020	2021 ⁽¹⁾
Oil ($/Bbl)	$45.82	$49.39	$51.99	$53.61	$54.90	$55.92
Gas ($/MMBtu)	$2.81	$3.09	$3.00	$3.00	$3.05	$3.16

(1) Prices for 2021 and subsequent years were not escalated and were held flat for the remaining lives of the properties. Capital and lease operating expenses were also not inflated and held constant for the remaining lives of the properties.

When comparing these settlement prices to the prices of $2.24 per MMBtu for natural gas and $42.91 per barrel of crude oil used to generate our June 30, 2016 (“2Q16”) reserve report, the average annual prices for oil and natural gas for each annual year presented above is higher than the 2Q16 reserve report price. The impact of the increase in forward prices to gas wells and oil wells, as compared to the 2Q16 reserve report prices, includes (i) an extension of economic lives (ii) an increase in economically recoverable volumes, and (iii) even if such volumes did not increase, an increase in realized prices. Because the Company’s asset mix is 67% natural gas paired with a higher rate increase in natural gas prices when compared to oil (specifically the year 2021 and forward), the hypothetical increase in natural gas reserves was greater than the hypothetical gain of oil and NGLs reserves on an MMcfe basis. The following table compares the 2Q16 reserve report volumes by product with the strip pricing volumes:



	Net Oil (Bbls)	Net Gas (Mcf)	Net NGL (Bbls)	Net MMcfe
Reserve Report at 2Q16	55,220	1,240,340	45,258	1,843,207
July 21, 2016 NYMEX Strip Price	62,830	1,501,209	51,985	2,190,098
% Difference	14%	21%	15%	19%

Management believes that the use of the 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.

If oil, natural gas and NGLs prices were to decline an additional 10% from their 11-month average through July 1, 2016, we estimate that, on a pro forma basis, we would record additional ceiling test write downs on our existing assets of approximately $25.5 million at September 30, 2016, with no additional write down expected for the remainder of the year ending December 31, 2016. However, whether the amount of any such impairments will be similar in amount to such estimates, is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2016, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and natural gas property acquisitions, which could increase, decrease or eliminate the need for such impairments.

We performed an interim test and assessed goodwill for impairment at June 30, 2016. While no goodwill impairment was recognized at June 30, 2016, 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. Although these goodwill impairment charges are of a non-cash nature, they do adversely affect our results of operations in the periods which such charges are recorded.

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

We have implemented a hedging program for approximately 94% and 24% of our anticipated crude oil production in 2016 and 2017, respectively, with 47% in the form of fixed-price swaps in 2016. Approximately 85% and 73% of our anticipated natural gas production in 2016 and 2017, respectively, is hedged with 85% in the form of fixed-price swaps in 2016. NGLs production is under fixed-price swaps for approximately 27% of anticipated production in 2016. These hedges will provide some cash flow certainty regardless of the volatility in commodity prices. In the current commodity price environment, however, we are less likely to hedge future revenues to the same extent as our historical and existing hedging arrangements. As such, our revenues will become more susceptible to commodity price volatility as our commodity price hedges settle and are not replaced. In addition, the volumes hedged and hedge prices are lower than those related to the hedges that settled in 2015. Therefore, the benefit to our future operating results is expected to be lower.

We have significantly reduced our capital expenditures budget for 2016 as compared to 2015. We currently anticipate a total capital expenditures budget of between $35.0 million and $38.0 million for the remainder of 2016 or a range between $69.0 million and $73.0 million for the full year of 2016 of which $4.2 million is related to capital spent on assets sold in the SCOOP/STACK Divestiture. This increase of approximately $6.0 million from our original 2016 capital expenditures budget is primarily attributable to increased spending in the Green River Basin where we expect to spend approximately 48% of the remaining 2016 capital expenditures budget participating as a non-operating partner in the drilling and completion of directional natural gas wells in the Pinedale Field. The balance of the remaining 2016 capital expenditures budget is related to recompletion and maintenance activities in our other operating areas. During the six months ended June 30, 2016, we participated in the drilling of 38 gross (9.4 net) non-operated wells and in the completion of 54 gross (6.8 net) non-operated wells.

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

On February 25, 2016, our board of directors elected to suspend our monthly cash distribution on our common, Class B and preferred units effective with the February 2016 distribution.

On May 19, 2016, we completed the sale of our natural gas, oil and natural gas liquids assets in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $272.5 million, subject to final post-closing adjustments. This transaction had an effective date of January 1, 2016. The Company used $261.0 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale.

As discussed above, on May 26, 2016, the Company entered into the Tenth Amendment to its Credit Agreement which reduced the Company’s borrowing base from $1.78 billion to $1.325 billion. As of May 26, 2016, Vanguard had $1.424 billion in outstanding borrowings and approximately $4.5 million in outstanding letters of credit, resulting in a deficiency of approximately $103.5 million. Under Vanguard’s Credit Agreement, the Company will make principal payments in an aggregate amount equal to such borrowing base deficiency in six equal monthly installments of approximately $17.3 million with the first payment due and payable within 30 days of the effective date of the Tenth Amendment. Vanguard made the first and second required deficiency payments for a total of $35.0 million on June 27, 2016 and July 26, 2016, respectively. At July 26, 2016, we had indebtedness under our Reserve-Based Credit facility totaling $1.389 billion with a borrowing base of $1.325 billion resulting in a borrowing base deficiency of $68.5 million, after consideration of a $4.5 million in outstanding letters of credit.

The borrowing base is subject to adjustments from time to time (but not less than on a semi-annual basis) based on the projected discounted present value of estimated future net cash flows (as determined by our lender’s petroleum engineers utilizing the lender’s internal projection of future oil, natural gas and NGLs prices) from our proved oil, natural gas and NGLs reserves. The Company expects that its excess cash flow forecasted for the remainder of the year will allow the Company to satisfy this requirement and be back in compliance under the Credit Agreement. In addition, the Company currently has available cash of approximately $50.0 million. However, the Company’s failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the Credit Agreement and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Notes due 2020 and Senior Secured Second Lien Notes.

Results of Operations

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016 ^(a)			2015 ^(b)			2016 ^(a)			2015 ^(b)
Revenues:
Oil sales	$	49,941		$	44,011		$	85,595		$	79,801
Natural gas sales	32,431			39,897			69,302			95,651
NGLs sales	11,104			11,933			20,019			19,283
Oil, natural gas and NGLs sales	93,476			95,841			174,916			194,735
Net gains (losses) on commodity derivative contracts	(68,610		)	(20,800		)	(36,851		)	38,233
Total revenues	$	24,866		$	75,041		$	138,065		$	232,968
Costs and expenses:
Production:
Lease operating expenses	$	38,515		$	31,600		$	80,842		$	67,078
Production and other taxes	9,476			10,754			18,144			22,180
Depreciation, depletion, amortization, and accretion	38,786			63,175			86,839			130,015
Impairment of oil and natural gas properties	157,894			733,365			365,658			865,975
Non-cash compensation	2,578			3,866			4,975			7,827
Other selling, general and administrative expenses	10,830			5,276			19,455			10,366
Total costs and expenses	$	258,079		$	848,036		$	575,913		$	1,103,441
Other income (expense):
Interest expense	$	(23,932	)	$	(20,374	)	$	(49,636	)	$	(40,563	)
Net losses on interest rate derivative contracts	(2,135		)	(281		)	(6,825		)	(1,484		)
Net loss on acquisitions of oil and natural gas properties	(1,665		)	—			(1,665		)	—
Gain on extinguishment of debt	—			—			89,714			—
Other	196			5			252			45


(a)	On May 19, 2016, we divested oil and natural gas properties in the SCOOP/STACK area in Oklahoma. We also completed the divestiture of other oil and natural gas properties in our other operating areas during the six months ended June 30, 2016. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.


(b)	During 2015, 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 June 30, 2016 Compared to Three Months Ended June 30, 2015

Revenues

Oil, natural gas and NGLs sales decreased $2.4 million to $93.5 million during the three months ended June 30, 2016 as compared to the same period in 2015. The key oil, natural gas and NGLs revenue measurements were as follows:



	Three Months Ended				Percentage Increase / (Decrease)
	June 30,
	2016 ^(a)		2015 ^(b)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	39.44	$	50.85	(22	)%
Natural Gas (Price/Mcf)	$	1.17	$	1.69	(31	)%
NGLs (Price/Bbl)	$	13.05	$	14.98	(13	)%
Average realized prices, including hedges^(c):
Oil (Price/Bbl)	$	55.90	$	58.02	(4	)%
Natural Gas (Price/Mcf)	$	2.89	$	3.16	(9	)%
NGLs (Price/Bbl)	$	14.22	$	16.93	(16	)%
Average NYMEX prices:
Oil (Price/Bbl)	$	45.54	$	57.94	(21	)%
Natural Gas (Price/Mcf)	$	1.95	$	2.63	(26	)%
Total production volumes:
Oil (MBbls)	1,266		866		46	%
Natural Gas (MMcf)	27,820		23,543		18	%
NGLs (MBbls)	851		796		7	%
Combined (MMcfe)	40,524		33,514		21	%
Average daily production volumes:
Oil (Bbls/day)	13,913		9,511		46	%
Natural Gas (Mcf/day)	305,716		258,720		18	%
NGLs (Bbls/day)	9,353		8,751		7	%
Combined (Mcfe/day)	445,314		368,290		21	%


(a)	During 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.


(b)	During 2015, 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.


(c)	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 June 30, 2016 compared to the same period in 2015 was due primarily to the decrease in average realized oil, natural gas and NGLs prices. Natural gas revenues decreased by 19% from $39.9 million in the second quarter of 2015 to $32.4 million in the second quarter of 2016 as a result of a $0.52 per Mcf, or 31%, decrease in average realized natural gas price, excluding hedges. The decrease in price was partially offset by a 4,277 MMcf increase in our natural gas production. NGLs revenues also decreased 7% during the second quarter of 2016 compared to the same period in 2015 due to a $1.93 per Bbl decrease in our average realized NGLs price, excluding hedges, offset by a 55 MBbls increase in NGLs production volumes. Oil revenues increased by 13% from $44.0 million in the second quarter of 2015 to $49.9 million in the second quarter of 2016, as a result of a 400 MBbls, or 46%, increase in our oil production volumes in 2016. The increase in production volumes was partially offset by a $11.41 per Bbl, or 22%, 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 $57.94 per Bbl in the second quarter of 2015 to $45.54 per Bbl in the second quarter of 2016. The increase in oil, natural gas and NGLs production volumes for the second quarter of 2016 compared to the same period in 2015 primarily reflects the additional production from the assets acquired in the LRE Merger and the Eagle Rock Merger completed in the fourth quarter of 2015.

Overall, our total production for the three months ended June 30, 2016 increased by 21% on an Mcfe basis compared to the same period in 2015. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 19%, 69% and 12%, respectively,

of our production during the three months ended June 30, 2016 compared to 16%, 70% and 14%, respectively, of our production during the same period in 2015.

Hedging and Price Risk Management Activities

During the three months ended June 30, 2016, we recognized a $68.6 million net loss on commodity derivative contracts. Cash receipts on matured commodity derivative contracts of $69.9 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 $6.9 million to $38.5 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, mainly due to a $11.8 million increase in lease operating expenses related to oil and natural gas properties acquired in the LRE Merger and the Eagle Rock Merger. This increase was offset by a $4.9 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 $1.3 million for the three months ended June 30, 2016 as compared to the same period in 2015 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 decreased from 11.2% for the three months ended June 30, 2015 to 10.1% for the three months ended June 30, 2016. The percentage was lower during the three months ended June 30, 2016 primarily due to lower tax rates on properties acquired in the LRE Merger and the Eagle Rock Merger in the states of Alabama and Oklahoma.

Depreciation, depletion, amortization, and accretion decreased by approximately $24.4 million to $38.8 million for the three months ended June 30, 2016 from approximately $63.2 million for the three months ended June 30, 2015, primarily due to a lower depletion base as a result of the non-cash ceiling impairment charge of $976.3 million and $207.8 million recorded during the second half of 2015 and the first three months of 2016, respectively.

An impairment of oil and natural gas properties of $157.9 million was recognized during the quarter ended June 30, 2016 as a result of a decline in oil and natural gas prices at the measurement date, June 30, 2016. The second quarter 2016 impairment was calculated based on the 12-month average price of $2.24 per MMBtu for natural gas and $42.91 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 increased $5.6 million to $10.8 million for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015 primarily resulting from about $6.6 million related to the hiring of additional employees, higher office expenses, and professional services related to the LRE Merger and the Eagle Rock Merger completed in the fourth quarter of 2015 and the change in the accrual of employee bonuses for the 2015 performance year discussed below of about $1.3 million. This increase was partially offset by a decrease of about $1.0 million in Texas franchise tax attributed to the increase in the deferred tax asset associated with our oil and natural gas properties. The increase in selling, general and administrative expenses was offset by a decrease of $1.3 million in non-cash

compensation expense for the three months ended June 30, 2016 as compared to the same period in 2015, primarily related to

the change in the accrual of employee bonuses that will be paid in cash during 2016 rather than in Company common units as it

was during 2015.

Other Income and Expense

Interest expense increased to $23.9 million for the three months ended June 30, 2016 from $20.4 million for the three months ended June 30, 2015 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility during the three months ended June 30, 2016 compared to the same period in 2015.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Revenues

Oil, natural gas and NGLs sales decreased $19.8 million to $174.9 million during the six months ended June 30, 2016 as compared to the same period in 2015. The key oil, natural gas and NGLs revenue measurements were as follows:



	Six Months Ended				Percentage Increase / (Decrease)
	June 30,
	2016 ^(a)		2015 ^(b)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	32.82	$	46.52	(29	)%
Natural Gas (Price/Mcf)	$	1.23	$	1.90	(35	)%
NGLs (Price/Bbl)	$	10.24	$	13.93	(26	)%
Average realized prices, including hedges ^(c):
Oil (Price/Bbl)	$	51.05	$	56.38	(9	)%
Natural Gas (Price/Mcf)	$	2.87	$	3.10	(7	)%
NGLs (Price/Bbl)	$	11.85	$	16.01	(26	)%
Average NYMEX prices:
Oil (Price/Bbl)	$	39.20	$	53.31	(26	)%
Natural Gas (Price/Mcf)	$	2.03	$	2.82	(28	)%
Total production volumes:
Oil (MBbls)	2,608		1,715		52	%
Natural Gas (MMcf)	56,211		50,403		12	%
NGLs (MBbls)	1,954		1,385		41	%
Combined (MMcfe)	83,585		69,003		21	%
Average daily production volumes:
Oil (Bbls/day)	14,331		9,477		52	%
Natural Gas (Mcf/day)	308,852		278,472		12	%
NGLs (Bbls/day)	10,737		7,650		41	%
Combined (Mcfe/day)	459,256		381,232		21	%


(a)	During 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.


(b)	During 2015, 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.


(c)	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 six months ended June 30, 2016 compared to the same period in 2015 was due primarily to the decrease in average realized oil, natural gas and NGLs prices. The decrease in prices

was partially offset by an overall increase in oil, natural gas and NGLs volumes primarily attributable to the oil and natural gas properties acquired in the LRE Merger and the Eagle Rock Merger completed during fourth quarter of 2015.

Natural gas revenues decreased by 28% from $95.7 million in the first six months of 2015 to $69.3 million in the first six months of 2016 as a result of a $0.67 per Mcf, or 35%, decrease in our average realized natural gas price, excluding hedges. The decrease in average realized natural gas price is primarily due to a lower average NYMEX price, which decreased from $2.82 per Mcf during the six months ended June 30, 2015 to $2.03 per Mcf during the six months ended June 30, 2016. The impact of the decrease in average realized price was partially offset by a 5,808 MMcf, or 12%, increase in our natural gas production volumes.

NGLs revenues increased 4% during the first six months of 2016 compared to the same period in 2015 due to a 569 MBbls, or 41%, increase in NGLs production volumes, offset by a $3.69 per Bbl, or 26%, decrease in our average realized NGLs price, excluding hedges.

Oil revenues increased slightly from $79.8 million in the first six months of 2015 to $85.6 million in the first six months of 2016 as a result of a 893 MBbls, or 52%, increase in oil production volumes in 2016 compared to the six months ended 2015. The impact of the increase in oil production volumes was partially offset by a $13.70 per Bbl, or 29%, 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 $53.31 per Bbl during the six months ended June 30, 2015 to $39.20 per Bbl during the six months ended June 30, 2016.

Overall, our total production for the six months ended June 30, 2016 increased by 21% on a Mcfe basis compared to the same period in 2015. On a Mcfe basis, crude oil, natural gas, and NGLs accounted for 19%, 67% and 14%, respectively, of our production during the six months ended June 30, 2016 compared to 15%, 73% and 12%, respectively, of our production during the same period in 2015.

Hedging and Price Risk Management Activities

During the six months ended June 30, 2016, we recognized $36.9 million in net losses on commodity derivative contracts. Cash payments on matured commodity derivative contracts of $142.5 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 $13.8 million to $80.8 million for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, of which $21.5 million is primarily attributable to additional expenses associated with oil and natural gas properties acquired in the LRE Merger and the Eagle Rock Merger. The increase was offset by a $7.8 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.

ended June 30, 2016 and 2015, respectively. The percentage was lower during the six months ended June 30, 2016 primarily due to lower tax rates on properties acquired in the LRE Merger and the Eagle Rock Merger in the states of Alabama and Oklahoma.

Depreciation, depletion, amortization, and accretion decreased by approximately $43.2 million to $86.8 million for the six months ended June 30, 2016 from approximately $130.0 million for the six months ended June 30, 2015 due to a decrease in the depletion base as a result of the non-cash ceiling impairment charges recorded during 2015 and the first quarter of 2016.

June 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.

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 increased $9.1 million to $19.5 million for the six months ended June 30, 2016 as compared to the same period in 2015, primarily resulting from about $12.1 million related to the hiring of additional employees, higher office expenses and professional services related to the LRE Merger and the Eagle Rock Merger completed in the fourth quarter of 2015 and the change in the accrual of employee bonuses for the 2015 performance year discussed below. This increase was partially offset by a decrease of about $3.0 million in Texas franchise tax and federal tax provision attributed to the increase in the deferred tax asset and decrease in the deferred tax liability associated with our oil and natural gas properties. Non-cash compensation decreased by $2.9 million for the six months ended June 30, 2016 as compared to the same period in 2015, primarily related to the change in the accrual of employee bonuses that will be paid in cash during 2016 rather than in Company common units as it was during 2015.

Other Income and Expense

Interest expense increased to $49.6 million for the six months ended June 30, 2016 from $40.6 million for the six months ended June 30, 2015 primarily due to a higher average outstanding debt under our Reserve-Based Credit Facility during the six months ended June 30, 2016 compared to the same period in 2015. For the six months ended June 30, 2016, we recorded a gain on extinguishment of debt amounting to $89.7 million which represents the difference between the aggregate fair market value the Senior Secured Second Lien Notes issued and the net carrying amount of Senior Notes due 2020 that were part of the Debt Exchange entered into in February 2016.

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 June 30, 2016, our critical accounting policies were consistent with those discussed in our 2015 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. Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for and acquiring additional reserves. We expect to fund our drilling and maintenance capital expenditures with cash flow from operations. However, based on current market conditions, we expect it will be difficult to fund any acquisition capital expenditures through traditional public equity and debt markets as we have in the past. Until our access to debt and equity financing through the capital markets improves, our principal focus of our liquidity will be on generating excess cash flow from operations and asset sales which will be used to reduce borrowings under our Reserve-Based Credit Facility.

The borrowing base under our Reserve-Based Credit Facility is subject to adjustments 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. As of July 26, 2016, we had $1.389 billion in outstanding borrowings and approximately $4.5 million in outstanding letters of credit, resulting in a deficiency of approximately $68.5 million based on our current borrowing base of $1.325 billion. Under Vanguard’s Credit Agreement, the Company is required pay the remaining borrowing base deficiency obligation in four equal monthly installments of approximately $17.1 million through November 2016. The Company expects that its forecasted excess cash flow for the remainder of the year will allow the Company to satisfy its repayment obligation and be back in compliance under the term of its Credit Agreement. In addition, the Company currently has a cash balance of approximately $50.0 million.

The Tenth Amendment to the Credit Agreement also includes, among other provisions, a one-time current ratio waiver for the second quarter of 2016, an increase in the mortgage requirement from 80% to 95% and an additional Event of Default clause. An Event of Default would occur should the Company make any payment of principal, accrued interest or fees to any Senior Notes or Second Lien Debt on or after September 15, 2016 if the Company’s pro forma liquidity after giving pro forma effect to such payment is less than $50 million.

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.

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


•	refinancing or restructuring our debt;


•	selling assets;


•	reducing or delaying our drilling program; or


•	seeking to raise additional capital through non-traditional lending or other private sources of capital.

Notwithstanding these measures, we cannot assure you that we would be able to refinance or restructure our debt or implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that implementing any such

alternative financing plans would allow us to meet our debt obligations or cure, waive or extend the deadline to repay the borrowing base deficiency repayment obligation. The Company’s failure to repay any of the installments due to cure the borrowing base deficiency would constitute an event of default under the Credit Agreement and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Notes due 2020 and Senior Secured Second Lien Notes.

Cash Flow from Operations

Net cash provided by operating activities was $99.0 million during the six months ended June 30, 2016, compared to $164.7 million during the six months ended June 30, 2015. Changes in working capital decreased total cash flows by $51.1 million for the six months ended June 30, 2016 and increased total cash flows by $29.8 million in the same period in 2015. Contributing to the decrease in working capital during 2016 was a $81.5 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 decrease was offset by a $25.4 million decrease in accounts receivable related to the timing of receipts from production. 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 six months ended June 30, 2016 or 2015.

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 provided by investing activities was approximately $237.3 million for the six months ended June 30, 2016, compared to net cash used in investing activities of $57.5 million during the same period in 2015. Net cash provided by investing activities during the first six months of 2016 primarily included $285.6 million in proceeds from the sale of oil and natural gas properties. Also during the first six months of 2016 cash used in investing activities included $35.5 million for the drilling and development of oil and natural gas properties, $7.5 million for the acquisition of a 51% joint venture interest in the Potato Hills Gas Gathering System and $5.3 million for deposits and prepayments related to the drilling and development of oil and natural gas properties. Net cash used in investing activities during the first six months of 2015 primarily included $52.1 million for the drilling and development of oil and natural gas properties.

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $305.1 million and $103.1 million for the six months ended June 30, 2016 and 2015, respectively. Cash used in financing activities during the six months ended June 30, 2016 included $283.7 million in net repayments of our long-term debt and $18.6 million cash paid to preferred, common and Class B unitholders in the form of distributions. Net cash used in financing activities during the six months ended June 30, 2015 included $42.1 million in net repayments of our long-term debt and $89.2 million cash paid to preferred, common and Class B unitholders in the form of distributions. Additionally, cash provided by financing activities during the six months ended June 30, 2015 included net proceeds from our public common unit offerings of $32.7 million.

Debt and Credit Facilities

Reserve-Based Credit Facility

in outstanding letters of credit (discussed below), resulting in a deficiency of approximately $103.5 million. Under Vanguard’s Credit Agreement, the Company will make principal payments in an aggregate amount equal to such borrowing base deficiency in six equal monthly installments of approximately $17.3 million with the first payment due and payable within 30 days of the effective date of the Tenth Amendment. Vanguard made the first and second required deficiency payments for a total of $35.0 million on June 27, 2016 and July 26, 2016, respectively, thus reducing the remaining future monthly installments to $17.1 million.

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. 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	%

At July 26, 2016, we had indebtedness under our Reserve-Based Credit Facility totaling $1.389 billion with a borrowing base of $1.325 billion resulting in a borrowing base deficiency of $68.5 million, after consideration of a $4.5 million in outstanding letters of credit.

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 June 30, 2016, 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 5.25 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 June 30, 2016. 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, as amended 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

8.375% Senior Notes Due 2019

Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of each year. The Senior Notes due 2019 are fully and unconditionally (except for customary release provisions) and jointly and severally guaranteed on a senior unsecured basis by Vanguard and all of our existing subsidiaries, all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”). Prior to the Eagle Rock Merger, the parties to the indenture executed a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default with respect to the Senior Notes due 2019.

7.875% Senior Notes Due 2020

7.0 % Senior Secured Second Lien Notes Due 2023

The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for the six months ended June 30, 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 included in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million.

As a result of the Debt Exchange, holders of our common units as of February 10, 2016, will be allocated cancellation of indebtedness income for federal income tax purposes on the IRS Form K-1s of those holders for tax year 2016. There will not be any cash distributions associated with this allocation of taxable income. Accordingly, these holders’ respective shares of our taxable income for 2016 may exceed the cash distributions received by such holders from us in 2016.

Lease Financing Obligations

On October 24, 2014, as part of acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin (the “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 June 30, 2016, 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 June 30, 2016 is provided in the following table (in thousands):



	Payments Due by Year
	2016		2017		2018		2019		2020		After 2020		Total
Management base salaries	$	755	$	1,590	$	1,670	$	—	$	—	$	—	$	4,015
Asset retirement obligations ⁽¹⁾	4,200		8,368		8,657		9,090		9,544		227,453		267,312
Derivative liabilities ⁽²⁾	12,985		20,683		2,848		2,066		—		—		38,582
Reserve-Based Credit Facility ⁽³⁾	86,040		—		1,320,460		—		—		—		1,406,500
Senior Notes and related interest ⁽⁴⁾	30,342		39,645		39,645		163,901		389,347		—		662,880
Operating leases	1,642		3,487		1,652		1,149		1,135		6,877		15,942
Development commitments ⁽⁵⁾	15,742		—		—		—		—		—		15,742
Firm transportation agreements ⁽⁶⁾	6,972		12,512		11,696		9,661		410		—		41,251
Lease Financing Obligations ⁽⁷⁾	2,721		5,442		5,442		5,442		4,359		1,278		24,684
Total	$	161,399	$	91,727	$	1,392,070	$	191,309	$	404,795	$	235,608	$	2,476,908


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

(2)

Represents liabilities for commodity and interest rate derivative contracts, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read 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.

(3)

This table does not include interest to be paid on the Reserve-Based Credit Facility principal balances shown as the interest rates are variable. Pursuant to the semi-annual borrowing base redetermination, the Company’s borrowing base under its Reserve-Based Credit Facility was reduced to $1.325 billion effective May 26, 2016. The decline in the borrowing base resulted in a $103.5 million borrowing base deficiency. Under our Credit Agreement, the Company is required to cure the borrowing base deficiency in six equal monthly installments of approximately $17.3 million. Vanguard has paid the first installment due on June 27, 2016. Please read Note 3. Long-Term Debt of the Notes to the Consolidated Financial Statements for additional information regarding our Reserve-Based Credit Facility.

(4)

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


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


(6)	Represents 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. The amounts presented include interest payable for each year.

Non-GAAP Financial Measure

Adjusted EBITDA

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


•	Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:


•	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;


•	Gain on extinguishment of debt;


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


•	Texas margin taxes;


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


•	Transaction costs incurred on acquisitions, mergers and divestitures; and


•	Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard unitholders.

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 six months ended June 30, 2016, as compared to the six months ended June 30, 2015, Adjusted EBITDA attributable to Vanguard unitholders increased 13%, from $175.9 million to $199.5 million. The following table presents a reconciliation of consolidated net loss to Adjusted EBITDA (in thousands):



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Net loss attributable to Vanguard unitholders	$	(260,789	)	$	(793,645	)	$	(406,072	)	$	(912,475	)
Add: Net income attributable to non-controlling interests	40			—			64			—
Net loss	$	(260,749	)	$	(793,645	)	$	(406,008	)	$	(912,475	)
Plus:
Interest expense	23,932			20,374			49,636			40,563
Depreciation, depletion, amortization, and accretion	38,786			63,175			86,839			130,015
Impairment of oil and natural gas properties	157,894			733,365			365,658			865,975
Net (gains) losses on commodity derivative contracts	68,610			20,800			36,851			(38,233		)
Net cash settlements received on matured commodity derivative contracts^(a)(b)(c)	69,859			42,329			142,476			80,620
Net losses on interest rate derivative contracts ^(d)	2,134			281			6,825			1,484
Gain on extinguishment of debt	—			—			(89,714		)	—
Net loss on acquisition of oil and natural gas properties	1,665			—			1,665			—
Texas margin taxes	(699		)	34			(2,634		)	142
Compensation related items	2,578			3,866			4,975			7,827
Transaction costs incurred on acquisitions, mergers and divestitures	2,779			—			3,123			—
Adjusted EBITDA before non-controlling interest	106,789			90,579			199,692			175,918
Adjusted EBITDA attributable to non-controlling interest	(116		)	—			(232		)	—
Adjusted EBITDA attributable to Vanguard unitholders	$	106,673		$	90,579		$	199,460		$	175,918

(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.	$	823		$	2,047		$	1,699		$	2,567
(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.	$	3,866		$	11,732		$	6,375		$	20,281
(c) Excludes fair value of restructured derivative contracts.	$	—		$	—		$	—		(31,945		)
(d) Includes settlements paid on interest rate derivatives	$	2,123		$	990		$	4,727		$	1,980

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. For a detailed discussion of the risk factors that relate to our potential exposure to market risks, please refer to Part I—Item 1A—Risk Factors in our 2015 Annual Report on Form 10-K.

Commodity Price Risk

Our primary market risk exposure is in the prices we receive for our oil, natural gas and NGLs production. Realized pricing is primarily driven by prevailing spot 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 periods.


•	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 June 30, 2016, the fair value of commodity derivative contracts was an asset of approximately $146.1 million, of which $123.0 million settles during the next twelve months.

The following tables summarize oil, natural gas and NGLs commodity derivative contracts in place at June 30, 2016.



	July 1 -December 31, 2016		Year 2017
Gas Positions:
Fixed-Price Swaps:
Notional Volume (MMBtu)	36,528,944		53,725,260
Fixed Price ($/MMBtu)	$	4.36	$	3.75
Three-Way Collars:
Notional Volume (MMBtu)	6,440,000		14,600,000
Floor Price ($/MMBtu)	$	3.95	$	3.88
Ceiling Price ($/MMBtu)	$	4.25	$	4.15
Put Sold ($/MMBtu)	$	3.00	$	3.31



	July 1 -December 31, 2016		Year 2017
Oil Positions:
Fixed-Price Swaps (West Texas Intermediate):
Notional Volume (Bbls)	938,283		749,698
Fixed Price ($/Bbl)	$	84.00	$	85.70
Fixed-Price Swaps (Light Louisiana Sweet):
Notional Volume (Bbls)	—		168,000
Fixed Price ($/Bbl)	$	—	$	91.25
Collars:
Notional Volume (Bbls)	322,000		—
Floor Price ($/Bbl)	$	41.00	$	—
Ceiling Price ($/Bbl)	$	50.57	$	—
Puts:
Notional Volume (Bbls)	184,000		—
Put Price ($/Bbl)	$	60.00	$	—
Three-Way Collars:
Notional Volume (Bbls)	533,600		—
Floor Price ($/Bbl)	$	90.00	$	—
Ceiling Price ($/Bbl)	$	96.18	$	—
Put Sold ($/Bbl)	$	73.62	$	—



	July 1 -December 31, 2016
NGLs Positions:
Fixed-Price Swaps:
Mont Belvieu Propane
Notional Volume (Bbls)	228,600
Fixed Price ($/Bbl)	$	23.61
Mont Belvieu N. Butane
Notional Volume (Bbls)	101,000
Fixed Price ($/Bbl)	$	28.54
Mont Belvieu Isobutane
Notional Volume (Bbls)	48,000
Fixed Price ($/Bbl)	$	28.53
Mont Belvieu N. Gasoline
Notional Volume (Bbls)	77,400
Fixed Price ($/Bbl)	$	53.50

As of June 30, 2016, the Company sold the following put option contracts:



	July 1 -December 31, 2016		Year 2017
Gas Positions:
Notional Volume (MMBtu)	920,000		1,825,000
Put Sold ($/MMBtu)	$	3.00	$	3.50
Oil Positions:
Notional Volume (Bbls)	73,600		73,000
Put Sold ($/Bbl)	$	75.00	$	75.00

As of June 30, 2016, the Company had the following open range bonus accumulator contracts:



	July 1 -December 31, 2016
Oil Positions:
Notional Volume (Bbls)	92,000
Bonus ($/Bbl)	$	4.00
Range Ceiling ($/Bbl)	$	100.00
Range Floor ($/Bbl)	$	75.00

As of June 30, 2016, the Company had the following open basis swap contracts:



	July 1 -December 31, 2016			Year 2017
Gas Positions:
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu)	19,320,000			21,900,000
Weighted-basis differential ($/MMBtu)	$	(0.20	)	$	(0.20	)
Houston Ship Channel and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu)	477,354			—
Weighted-basis differential ($/MMBtu)	$	(0.08	)	$	—
TexOk and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu)	140,433			—
Weighted-basis differential ($/MMBtu)	$	(0.10	)	$	—
WAHA and NYMEX Henry Hub Basis Differential
Notional Volume (MMBtu)	788,896			—
Weighted-basis differential ($/MMBtu)	$	(0.13	)	$	—



	July 1 -December 31, 2016
Oil Positions:
WTI Midland and WTI Cushing Basis Differential
Notional Volume (Bbls)	486,000
Weighted-basis differential ($/Bbl)	$	(1.01	)
West Texas Sour and WTI Cushing Basis Differential
Notional Volume (Bbls)	110,400
Weighted-basis differential ($/Bbl)	$	(0.43	)
WTI and West Canadian Select Basis Differential
Notional Volume (Bbls)	368,000
Weighted-basis differential ($/Bbl)	$	(14.25	)

As of June 30, 2016, the Company sold calls as follows:



	July 1 - December 31, 2016		Year 2017
Gas Positions:
Notional Volume (MMBtu)	4,600,000		11,862,500
Weighted Average Fixed Price ($/MMBtu)	$	4.25	$	3.01
Oil Positions:
Notional Volume (Bbls)	312,800		365,000
Weighted Average Fixed Price ($/Bbl)	$	50.00	$	95.00

As of June 30, 2016, the Company had the following open swaptions contracts:



	Year 2017		Year 2018
Gas Positions:
Notional Volume (MMBtu)	2,062,500		675,000
Weighted Average Fixed Price ($/MMBtu)	$	2.74	$	2.74

Interest Rate Risks

At June 30, 2016, we had debt outstanding of $1.8 billion. The amount outstanding under our Reserve-Based Credit Facility at June 30, 2016 was approximately $1.41 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 $0.4 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 June 30, 2016 (in thousands):



	July 1 - December 31, 2016			Year 2017			Year 2018			Year 2019
Weighted Average Notional Amount	$	531,875		$	256,342		$	192,836		$	175,000
Weighted Average Fixed LIBOR Rate	1.88		%	2.15		%	2.31		%	2.32		%

Counterparty Risk

At June 30, 2016, 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 June 30, 2016
ABN AMRO (A)	$	1,330	$	265	$	—		$	—		$	1,595
Bank of America (A)	19,800		9,227		—			—			29,027
Barclays (A-)	6,759		—		—			(59		)	6,700
BMO (A+)	2,363		579		—			—			2,942
CIBC (A+)	1,412		511		—			—			1,923
Citibank (A)	4,760		1,036		—			—			5,796
Comerica (A-)	4,878		—		—			—			4,878
Commonwealth Bank of Australia (AA-)	769		275		—			—			1,044
Credit Agricole (A)	—		—		(68		)	—			(68		)
Fifth Third Bank (A-)	567		—		—			—			567
Huntington Bank (BBB+)	1,370		—		—			(344		)	1,026
ING Financial Markets (A)	17,256		—		—			(229		)	17,027
JP Morgan (A-)	28,748		—		—			—			28,748
Morgan Stanley (BBB+)	3,483		1,831		—			—			5,314
Natixis (A)	1,464		286		—			—			1,750
NextEra Energy Inc. (A-)	—		—		(31		)	—			(31		)
RBC (AA-)	5,092		1,811		—			—			6,903
Scotia Capital (A+)	4,768		10		—			—			4,778
SunTrust (A-)	855		354		—			—			1,209
Wells Fargo (AA-)	11,188		991		—			—			12,179
Total	$	116,862	$	17,176	$	(99	)	$	(632	)	$	133,307

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 $133.4 million at June 30, 2016.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) promulgated under 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) promulgated 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 June 30, 2016 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 second quarter of 2016 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 also a party to separate legal proceedings relating to (i) our merger with LRR Energy, L.P. (the “LRE Merger”), (ii) our merger with Eagle Rock Energy Partners, L.P. (the “Eagle Rock Merger”) and (iii) our exchange (the “Debt Exchange”) of 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”) for 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”), as further discussed below.

Litigation Relating to the LRE Merger

In June and July 2015, purported LRE unitholders filed four lawsuits challenging the LRE Merger. These lawsuits were styled (a) Barry Miller v. LRR Energy, L.P. et al., Case No. 11087-VCG, in the Court of Chancery of the State of Delaware; (b) Christopher Tiberio v. Eric Mullins et al., Cause No. 2015-39864, in the District Court of Harris County, Texas, 334th Judicial District; (c) Eddie Hammond v. Eric Mullins et al., Cause No. 2015-40154, in the District Court of Harris County, Texas, 295th Judicial District; and (d) 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. These lawsuits have been voluntarily dismissed or nonsuited.

On August 18, 2015, another purported LRE unitholder (the “LRE Plaintiff”) filed a putative class action lawsuit in connection with the LRE Merger. 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”). On June 22, 2016, the LRE Plaintiff filed his Amended Class Action Complaint (the “Amended LRE Complaint”) against LRE, the members of the LRE GP board of directors, Vanguard, LRE Merger Sub, and the members of Vanguard’s board of directors (the “LRE Lawsuit Defendants”).

In the Amended LRE Complaint, the LRE Plaintiff alleges multiple causes of action related to the registration statement and proxy statement filed with the SEC in connection with the LRE Merger (the “LRE Proxy”), including that (i) Vanguard and its directors have allegedly violated Section 11 of the Securities Act because the LRE Proxy allegedly contained misleading statements and omitted allegedly material information, (ii) the members of Vanguard’s board of directors have allegedly violated Section 15 of the Exchange Act by signing the LRE Proxy and participating in the issuance of common units in connection with the LRE Merger, (iii) the LRE Lawsuit Defendants have allegedly violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder because the LRE Proxy allegedly contained misleading statements and omitted allegedly material information, and (iv) LRE’s and Vanguard’s directors have allegedly violated Section 20(a) of the Exchange Act by allegedly controlling LRE and Vanguard in disseminating the LRE Proxy. In general, the LRE Plaintiff alleges that the LRE Proxy failed, among other things, to disclose allegedly material details concerning Vanguard’s (x) debt obligations and (y) ability to maintain distributions to unitholders.

Based on these allegations, the LRE Plaintiff seeks, among other relief, to rescind the LRE Merger, and an award of damages, attorneys’ fees, and costs.

The LRE Lawsuit Defendants’ date to answer, move to dismiss, or otherwise respond to the LRE Lawsuit is currently set for August 22, 2016. Vanguard cannot predict the outcome of the LRE Lawsuit or any others that might be filed subsequent to the date of the filing of this report; nor can Vanguard predict the amount of time and expense that will be required to resolve the LRE Lawsuit. The LRE Lawsuit Defendants believe the LRE Lawsuit is without merit and intend to vigorously defend against it.

Litigation Relating to the Eagle Rock Merger

There have been no material developments with respect to the litigation relating to the Eagle Rock Merger previously disclosed in Item 1 of Part II of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2016.

Litigation Relating to the Debt Exchange

On March 1, 2016, a purported holder of the Senior Notes due 2020, Gregory Maniatis, individually and purportedly on behalf of other non-qualified institutional buyers (“non-QIBs”) who beneficially held the Senior Notes due 2020, filed a class action lawsuit, against Vanguard and VNRF. The lawsuit is styled Gregory Maniatis v. Vanguard Natural Resources, LLC and VNR Finance Corp., Case No. 1:16-cv-1578, in the United States District Court for the Southern District of New York. On March 18, 2016, a purported holder of the Senior Notes due 2020, William Rowland, individually and purportedly on behalf of others similarly situated filed a class action lawsuit, against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC. The lawsuit is styled, Rowland v. Vanguard Natural Resources, LLC et al, Case No. 1:16-cv-2021 in the United States District Court for the Southern District of New York. On March 29, 2016, a purported holder of the Senior Notes due 2020, Lawrence Culp, individually and purportedly on behalf of others similarly situated filed a class action lawsuit, against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC. The lawsuit is styled, Culp v. Vanguard Natural Resources, LLC et al, Case No. 1:16-cv-2303 in the United States District Court for the Southern District of New York.

On April 14, 2016, the court in the Maniatis case ordered all related cases consolidated into Case No. 1:16-cv-1578, with the styling In re Vanguard Natural resources Bondholder Litigation (the “Debt Exchange Lawsuit”). Manitatis, Rowland and Culp (the “Debt Exchange Plaintiffs”) filed an Amended Complaint in the Debt Exchange Lawsuit against Vanguard, VNRF, Vanguard Natural Gas, LLC, VNR Holdings, LLC, Vanguard Permian, LLC, Encore Energy Partners Operating LLC, and Encore Clear Fork Pipeline LLC (the “Debt Exchange Defendants”) on April 20, 2016.

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

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

On June 24, 2016, the Debt Exchange Defendants filed a letter with the court requesting leave to file a motion to dismiss the Debt Exchange Lawsuit. The letter indicates that the Debt Exchange Defendants intend to argue in a motion to dismiss that: (1) the lead plaintiffs lack standing; (2) the Amended Complaint fails to plead plausible facts demonstrating that the exchange offer violated the TIA; (3) the Debt Exchange Plaintiffs are barred from bringing their state law claims because the indentures prevent any noteholder from filing these types of claims in court without first presenting the claims to the indenture trustee and waiting sixty days for the trustee to determine if it will bring suit; (4) the Amended Complaint fails to plead plausible facts to demonstrate the exchange offer breached the terms of the indenture; (5) the Amended Complaint fails to plead plausible facts to demonstrate the exchange offer breached the implied covenant of good faith and fair dealing; and (6) unjust enrichment is not an available cause of action in these circumstances. The letter suggests a briefing schedule, including that the Debt Exchange Defendants file their motion to dismiss on August 19, 2016.

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

Item 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 2015 Annual Report on Form 10-K. There have been no material changes to the risk factors set forth in our 2015 Annual Report on Form 10-K, other than as set forth below.

Our lenders periodically redetermine the amount we may borrow under our Reserve-Based Credit Facility, which may materially impact our operations.

The Company uses borrowings under its Reserve-Based Credit Facility (as defined in Part I of this Quarterly Report on Form 10-Q) to fund its exploration, development and acquisition activities and for other corporate purposes. On May 26, 2016, the Company entered into an amendment to its Reserve-Based Credit Facility and completed the semi-annual redetermination of its borrowing base. The redetermination resulted in a revised borrowing base of $1.325 billion, a decrease of 26% from the previous level of $1.78 billion. In addition, the Company and its lenders have agreed to amend certain terms of the Company’s Reserve-Based Credit Facility, all of which may materially impact the Company’s operations.

The borrowing base is subject to adjustments from time to time (but not less than on a semi-annual basis) based on the projected 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.

On May 26, 2016, the Company entered into the Tenth Amendment (the “Tenth Amendment”) to its Credit Agreement which reduced the Company’s borrowing base from $1.78 billion to $1.325 billion (the “Reserve-Based Credit Facility”). As of May 26, 2016, Vanguard had $1.424 billion in outstanding borrowings and approximately $4.5 million in outstanding letters of credit resulting in a deficiency of approximately $103.5 million. Under Vanguard’s Credit Agreement, the Company will make principal payments in an aggregate amount equal to such borrowing base deficiency in six equal monthly installments of approximately $17.3 million with the first payment due and payable within 30 days of the effective date of the Tenth Amendment. Vanguard made the first and second required deficiency payments for a total of $35.0 million on June 27, 2016 and July 26, 2016, respectively. Based on the Company’s 2016 financial outlook, the Company anticipates that its forecasted excess cash flow for the remainder of the year will allow the Company to satisfy this requirement.

Further reduction in the Company’s borrowing base, or an acceleration of the deficiency repayment schedule, would materially and adversely impact our liquidity, which would materially limit our exploration, development, and acquisition activities and adversely affect our operations and financial results.

Additionally, the Company’s failure to repay any of the installments due related to the borrowing base deficiency shall constitute an event of default under the Credit Agreement and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation. In addition, a payment default under the Reserve Based Credit Facility could result in a cross default under our Senior Notes due 2020 and Senior Secured Second Lien Notes. In such case, we may not have sufficient assets to repay our creditors, including the holders of our Senior Notes. As a result, there may not be any value remaining attributable to the holders of our Common units and Cumulative Preferred Units.

We may be unable to hedge additional anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

Although we have hedged a significant portion of our oil and natural gas production through December 31, 2016, our oil and natural gas production are hedged to a lesser extent for 2017, and our NGLs production is completely unhedged for 2017. We have implemented a hedging program for approximately 94% and 24% of our anticipated crude oil production in 2016 and 2017, respectively, with 47% in the form of fixed price swaps in 2016. Approximately 85% and 73% of our anticipated natural gas production in 2016 and 2017, respectively, is hedged with 85% in the form of fixed-price swaps in 2016. NGLs production is under fixed-price swaps for approximately 27% of anticipated production in 2016.

Based on reduced hedging market liquidity and potential reduced counterparty willingness to enter into new hedges with us, we may be unable to hedge additional anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.

We may engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.

We continually monitor the respective capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. As such, we are actively evaluating potential transactions to deleverage our balance sheet and manage our liquidity, which could include reducing existing debt through debt exchanges, debt repurchases and other modifications and extinguishment of existing debt. In the event we execute such a strategic transaction, we expect that we will recognize a significant amount of cancellation of debt income (CODI), which will be allocated to our unitholders at the time of such transaction.

The amount of CODI generally will be equal to the excess of the adjusted issue price of the restructured debt over the value of the consideration received by debtholders in exchange for the debt. In certain cases, CODI can be realized even when existing debt is modified with no reduction in such debt’s stated principal amount. We will not make a corresponding cash distribution with respect to such allocation of CODI. Therefore, any CODI will cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to such unitholder. Such CODI, like other items of our income, gain, loss, and deduction that are allocated to our unitholders, will be taken into account in the taxable income of the holders of our units as appropriate. CODI is not itself an additional tax due but is an amount that must be reported as ordinary income by the unitholder, potentially increasing such unitholder’s tax liabilities.

Our unitholders may not have sufficient tax attributes (including allocated losses from our activities) available to offset such allocated CODI. Moreover, CODI that is allocated to our unitholders will be ordinary income, and, as a result, it may not be possible for our unitholders to offset such CODI by claiming capital losses with respect to their units, even if such units are cancelled for no consideration in connection with such a restructuring. Importantly, certain exclusions that are available with respect to CODI generally do not apply at the partnership level, and any solvent unitholder that is not in a Chapter 11 proceeding will be unable to rely on such exclusions.

CODI with respect to any future transaction undertaken by us will be allocated to our unitholders of record (as applicable) as of the opening of the New York Stock Exchange on the date on which such a strategic transaction closes (the “CODI Allocation Date”). No CODI should be allocated to a unitholder with respect to units which are sold prior to the CODI Allocation Date.

Each unitholder’s tax situation is different. The ultimate effect to each unitholder will depend on the unitholder’s individual tax position with respect to its units. Additionally, certain of our unitholders may have more losses available than other of our unitholders, and such losses may be available to offset some or all of the CODI that could be generated in a strategic transaction involving our debt. Accordingly, unitholders are highly encouraged to consult, and depend on, their own tax advisors in making such evaluation.

Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us or cancellation of our debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

For example, on February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new Senior Secured Second Lien Notes to certain eligible holders of our outstanding Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Debt Exchange will, and other similar transactions in the future may, result in CODI that will be allocated to our unitholders. Some or all of our unitholders may be allocated substantial amounts of such taxable income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder would depend on the unitholder’s individual tax position with respect to the units; however, taxable income allocations from us, including CODI, increase a unitholder’s tax basis in their units. See above for a discussion of CODI allocations to unitholders.

In addition, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what

otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in its units, and the amount, if any, of excess distributions over a unitholder’s tax basis in its units will, in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).

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
10.1	Tenth Amendment, dated May 26, 2016, to Third Amended and Restated Credit Agreement, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent and the lenders party hereto.	Exhibit 10.1 to Form 8-K, filed May 27, 2016 (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: July 29, 2016
		/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 - July 29, 2016

Attached files

Vanguard Natural Resources, Inc. Reports