Vanguard Natural Resources Reports Fourth Quarter and Full

HOUSTON, March 04, 2016 (GLOBE NEWSWIRE) -- Vanguard Natural Resources, LLC (NASDAQ:VNR) ("Vanguard" or "the Company") today reported financial and operational results for the full year and fourth quarter ended December 31, 2015.

Mr. Scott W. Smith, President and CEO, commented, “2015 was a challenging yet exciting year for the Company. We negotiated and closed two impactful mergers, the results of which include a 30% increase in our production, additional hedges on oil, natural gas and natural gas liquids and a quality group of employees that will allow us to successfully manage our expanded asset base and position us for future growth. Notwithstanding these positive events, the challenges we face as a result of the continued collapse in commodity prices necessitate we take further actions to strengthen our balance sheet by retaining our cash flow. Our recently completed debt exchange, the decision to monetize our SCOOP/STACK assets in Oklahoma, the significant reduction in our 2016 capital budget, the cash flow to be generated from our commodity price hedges, and the suspension of distributions on both the common and preferred units will allow us to make meaningful progress in reducing our debt in 2016. We believe these proactive steps are prudent in this environment and will ultimately create long-term value for all of our stakeholders.”

Selected Financial Information

A summary of selected financial information follows:

	Three Months Ended December 31,						Year Ended December 31,
	2015			2014			2015			2014
	($ in thousands, except per unit data)
Production (Mcfe/d)	511,119			402,164			415,343			327,109
Oil, natural gas and natural gas liquids sales	$	111,665		$	156,727		$	397,227		$	624,613
Net gains on commodity derivative contracts	$	66,855		$	174,576		$	169,416		$	163,452
Operating expenses	$	54,721		$	51,970		$	187,230		$	194,389
Selling, general and administrative expenses	$	28,837		$	7,797		$	55,076		$	30,839
Depreciation, depletion, amortization, and accretion	$	64,676		$	76,139		$	247,119		$	226,937
Impairment of oil and natural gas properties	$	484,855		$	234,434		$	1,842,317		$	234,434
Goodwill impairment loss	$	71,425		$	—		$	71,425		$	—
Net income (loss) attributable to Common and Class B Unitholders	$	(515,111	)	$	(66,828	)	$	(1,909,933	)	$	46,148
Adjusted Net Income Available to Common and Class B Unitholders⁽¹⁾	$	62,982		$	16,109		$	75,977		$	90,593
Adjusted Net Income Available to Common and Class B Unitholders, per unit⁽¹⁾	$	0.49		$	0.19		$	0.78		$	1.10
Adjusted EBITDA⁽¹⁾	$	132,707		$	125,647		$	396,829		$	421,445
Interest expense, including settlements paid on interest rate derivatives	$	28,139		$	21,245		$	92,800		$	73,800
Estimated maintenance capital expenditures	$	32,426		$	23,811		$	112,639		$	116,528
Distributions to Preferred Unitholders	$	6,689		$	6,690		$	26,759		$	18,197
Distributable Cash Flow Available to Common and Class B Unitholders ⁽¹⁾	$	65,453		$	73,901		$	164,631		$	214,870
Distributable Cash Flow per Common and Class B unit ⁽¹⁾	$	0.50		$	0.88		$	1.78		$	2.61
Common and Class B units distribution coverage ⁽¹⁾	2.82x			1.40x			1.44x			1.04x
Weighted average Common and Class B units outstanding at record date attributable to distribution period	130,896			83,962			92,461			82,238

(1) Non-GAAP financial measures. Please see Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders table at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure. Supplemental information on Vanguard's financial and operations results, including Adjusted Net Income Available to Common and Class B Unitholders, can be found under "Presentations" on the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com.

Fourth Quarter 2015 Highlights:

Successfully closed the LRR Energy, L.P. and the Eagle Rock Energy Partners, L.P. mergers during the fourth quarter of 2015.
Reported average production of 511,119 Mcfe per day in the fourth quarter of 2015 was up 27% compared to 402,164 Mcfe per day produced in the fourth quarter of 2014 and a 32% increase compared to the third quarter of 2015. On a Mcfe basis, crude oil, natural gas and NGLs accounted for 18%, 64%, and 18% of our production, respectively.
Adjusted EBITDA (a non-GAAP financial measure defined below) increased 6% to $132.7 million from $125.6 million in the fourth quarter of 2014 and increased 50% compared to the $88.2 million recorded in the third quarter of 2015.
Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 11% to $65.5 million compared to the $73.9 million generated in the fourth quarter of 2014 and increased 109% from the $31.3 million generated in the third quarter of 2015.
We reported a net loss attributable to Common and Class B Unitholders for the quarter of $515.1 million or $(4.02) per basic unit after deducting distributions to Preferred Unitholders compared to a net loss of $66.8 million or $(0.80) per basic unit in the fourth quarter of 2014.
Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $63.0 million in the fourth quarter of 2015, or $0.49 per basic unit, as compared to $16.1 million, or $0.19 per basic unit, in the fourth quarter of 2014. The recent quarter includes net non-cash expenses of $566.4 million that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders. The 2015 adjustments include a $484.9 million impairment charge on our oil and natural gas properties, a $71.4 million goodwill impairment loss and a $43.6 million loss from the change in fair value of commodity derivative contracts, offset by a $40.8 million net gain from our acquisitions and mergers. The fourth quarter of 2014 results include net non-cash expenses of $82.5 million.

	Three Months Ended December 31,^(a)				Percentage Increase / (Decrease)		Three Months Ended September 30,^(a)		Percentage Increase / (Decrease)
	2015		2014		Percentage Increase / (Decrease)		2015		Percentage Increase / (Decrease)
Average realized prices, excluding hedges:
Oil (Price/Bbl)	$	34.85	$	63.39	(45	)%	$	40.10	(13	)%
Natural Gas (Price/Mcf)	$	1.57	$	3.19	(51	)%	$	1.94	(19	)%
NGLs (Price/Bbl)	$	10.08	$	17.37	(42	)%	$	8.86	14	%

Average realized prices, including hedges ^(b):
Oil (Price/Bbl)	$	59.35	$	78.97	(25	)%	$	53.66	11	%
Natural Gas (Price/Mcf)	$	3.12	$	3.52	(11	)%	$	3.17	(2	)%
NGLs (Price/Bbl)	$	12.62	$	18.22	(31	)%	$	11.23	12	%

Average NYMEX prices:
Oil (Price/Bbl)	$	42.08	$	72.68	(42	)%	$	46.39	(9	)%
Natural Gas (Price/Mcf)	$	2.23	$	3.99	(44	)%	$	2.77	(19	)%

Total production volumes:
Oil (MBbls)	1,454		907		60	%	839		73	%
Natural Gas (MMcf)	29,970		26,386		14	%	26,242		14	%
NGLs (MBbls)	1,387		862		61	%	717		93	%
Combined (MMcfe)	47,023		36,999		27	%	35,574		32	%

Average daily production volumes:
Oil (Bbls/day)	15,810		9,857		60	%	9,115		73	%
Natural Gas (Mcf/day)	325,754		286,805		14	%	285,236		14	%
NGLs (Bbls/day)	15,084		9,369		61	%	7,792		93	%
Combined (Mcfe/day)	511,119		402,164		27	%	386,679		32	%

(a) During 2015 and 2014, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.
(b) Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

Full Year 2015 Highlights:

Implemented a successful cost reduction initiative in which we reduced the lease operating expenses on our operated properties by approximately $20.6 million, or 20%, during 2015.
Reported average production of 415,343 Mcfe per day in 2015 was up 27% compared to 327,109 Mcfe per day produced in 2014. On a Mcfe basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 16%, 70% and 14% of our production, respectively.
Adjusted EBITDA (a non-GAAP financial measure defined below) decreased 6% to $396.8 million from the $421.4 million generated in 2014.
Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 23% to $164.6 million from the $214.9 million generated in 2014.
We reported a net loss attributable to Common and Class B unitholders for the year ended December 31, 2015 of $1.9 billion or $(19.80) per basic unit compared to a net income of $46.1 million or $0.56 per basic unit in the year ended December 31, 2014.
Adjusted Net Income Available to Common and Class B Unitholders (a non-GAAP financial measure defined in the supplemental presentation posted at www.vnrllc.com) was $76.0 million in 2015, or $0.78 per unit, compared to $90.6 million, or $1.10 per unit, in 2014. The 2015 results include net non-cash losses of $2.0 billion that are adjustments to arrive at Adjusted Net Income Available to Common and Class B Unitholders. The 2015 adjustments include a $1.8 billion impairment charge on our oil and natural gas properties, a $71.4 million goodwill impairment loss and a $61.6 million loss from the change in fair value of commodity derivative contracts, offset by a $40.5 million net gain on acquisitions and mergers. The 2014 results include non-cash losses of $43.7 million.

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

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

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

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

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

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

Proved Reserves

Total estimated proved reserves at December 31, 2015 were 2,288.9 billion cubic feet equivalent, consisting of 122.5 million barrels of crude oil, condensate, and natural gas liquids and 1,554.2 billion cubic feet of natural gas. Proved reserves were calculated utilizing the 12-month unweighted average first-day-of-the-month prices ("12-month average prices") during 2015, or $50.20 per Bbl of oil and $2.62 per Mcf of natural gas as compared to $94.87 per Bbl of oil and $4.36 per Mcf of natural gas for 2014. Our proved reserves for the year ended December 31, 2015, included 171.4 Bcfe of net negative revisions. We had 587.3 Bcfe of negative revisions primarily due to lower oil and natural gas prices as compared to the prior year, offset by 415.9 Bcfe of positive revisions due to asset performance.

Using the 12-month average prices, the estimated discounted net present value of Vanguard's proved oil and natural gas reserves, using a 10 percent per annum discount rate (“PV-10 Value”) was approximately $1.7 billion at December 31, 2015, as compared to a PV-10 Value of approximately $3.0 billion at December 31, 2014.

At December 31, 2015, natural gas reserves accounted for 68% of total proved reserves, and 72% of total proved reserves are developed. The following table summarizes the changes in proved reserves:

	Bcfe
Reserves at December 31, 2014	2,031.3
Performance revisions	415.9
Revisions of previous estimates due to price	(587.3	)
Extensions, discoveries and other	54.5
Purchases of reserves in place	527.5
Sales of reserves-in-place	(1.4	)
Production	(151.6	)
Reserves at December 31, 2015	2,288.9

Vanguard's proved reserve estimates for all of its properties were prepared by its internal reservoir engineers and were audited by DeGolyer and MacNaughton (D&M), an independent third party engineering firm. D&M's audit covered properties representing 80.1% of Vanguard's total estimated proved reserves at year-end 2015.

Capital Expenditures

Capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $32.4 million in the fourth quarter of 2015 compared to $32.5 million for the comparable quarter of 2014 and $28.1 million for the third quarter of 2015. All capital spending in the fourth quarter of 2015 has been characterized as maintenance capital expenditures. For the fourth quarter of 2014, capital spending included maintenance capital expenditures of $23.8 million and the balance of $8.7 million was attributable to growth capital expenditures primarily associated with the Pinedale Acquisition in the Green River Basin. Total capital expenditures were approximately $112.6 million for the year ended December 31, 2015 compared to $142.0 million in the comparable period of 2014.

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

Hedging Activities

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

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

The weighted average price for oil and natural gas will fluctuate based on the value of existing three-way collars and short puts as the respective prices settle. The above weighted average prices are calculated based on forward strip commodity prices as of February 29, 2016. For a summary of our current commodity derivative contracts, please refer to our Supplemental Presentation on the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com.

Liquidity Update

At December 31, 2015, Vanguard had indebtedness under its reserve-based credit facility totaling $1.69 billion with a borrowing base of $1.8 billion which provided for $107.5 million in undrawn capacity, after consideration of a $4.5 million reduction in availability for letters of credit.

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”) in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders. The Senior Secured Second Lien Notes were issued to certain eligible holders of Senior Notes due 2020 who validly tendered and did not validly withdraw their Senior Notes due 2020 pursuant to the terms of the exchange offer, which expired on February 5, 2016. Interest is payable on the Senior Secured Second Lien Notes 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 have repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with proceeds of certain Indebtedness (as defined in the Offering Memorandum dated January 8, 2016), such Indebtedness has a final maturity date no earlier than the date that is 91 days after February 15, 2023. This reduction in outstanding Senior Notes due 2020 reduced our interest expense by $7.9 million on an annual basis. Under our credit agreement, the issuance of new second lien debt requires, among other things, that our borrowing base decrease by 25% of the amount of new second lien debt. Because of this, the $1.8 billion borrowing base decreased by $18.9 million to $1.78 billion.

At March 3, 2016, we had indebtedness under our Reserve-Based Credit facility totaling $1.68 billion with a borrowing base of $1.78 billion which provided for $96.6 million in undrawn capacity, after consideration of a $4.5 million reduction in availability for letters of credit. This does not take into consideration available cash of $10.0 million. Our next borrowing base redetermination is scheduled for April 2016 and based on projected market conditions, continued declines in oil and natural gas prices and as existing hedges roll off, we expect a reduction in our borrowing base at the next redetermination. The precise amount of the reduction is not known at this time but we do expect that the amount will be significant. As such, we initiated a process to sell the SCOOP/STACK assets acquired in the Eagle Rock Merger. We anticipate that this divestiture would be consummated at the same time as the April 2016 redetermination and will allow us to reduce borrowings under the Reserve-Based Credit facility in an amount sufficient to mitigate the reduction in the borrowing base for the April 2016 redetermination. Based on our internal forecasts, we will continue to experience low liquidity but expect to be at a liquidity level sufficient to run our business for the foreseeable future. However, there can be no assurances that our banks will not redetermine our borrowing base at a level below our outstanding borrowings in our April 2016 redetermination or any subsequent redetermination. Should a borrowing base deficiency occur, our Reserve-Based Credit facility requires us to repay the deficiency in equal monthly installments over a six month period. Our internal forecasts show that we will generate a substantial amount of excess cash flow over the course of 2016 which will be used to reduce borrowings under our Reserve-Based Credit facility and we expect would be sufficient to repay a deficiency should one exist in April 2016.

Cash Distributions

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

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

On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and preferred units effective with the February 2016 distribution. All preferred distributions will continue to be accrued and must be paid in full before distributions to common and Class B unitholders can resume.

2016 Outlook

Summary of Estimates

The following table sets forth certain estimates being used by Vanguard to model its anticipated results of operations for the fiscal year ending December 31, 2016. These estimates do not include any future acquisitions or divestitures of oil or natural gas properties. In addition, the expectations below assume Vanguard's current capital structure and does not contemplate any future equity or debt offerings.

	FY 2016E											FY 2015
Net Production:
Oil (Bbls/d)	12,800					-	14,200						10,982
Natural gas (Mcf/d)	280,000					-	310,000						292,095
Natural gas liquids (Bbls/d)	10,800					-	12,000						9,560
Total (Mcfe/d)	421,600						467,200						415,343

Costs:
Lease operating expenses	$		162,500			-	$		179,000			$	146,654
Production taxes	$		35,000			-	$		38,000			$	40,576
G&A expenses (excluding non-cash compensation)	$		40,000			-	$		42,000			$	36,554
Depreciation, depletion, amortization and accretion	$		210,000			-	$		245,000			$	247,119

Costs per Mcfe:
Lease operating expenses	$		1.00			-	$		1.10			$	0.97
Production taxes (% of revenue)	11.0			%		-	12.0			%			10.2				%
G&A expenses (excluding non-cash compensation)	$		0.24			-	$		0.26			$	0.24
Depreciation, depletion, amortization and accretion	$		1.30			-	$		1.50			$	1.63

Cash Flow Calculation (in thousands):
Adjusted EBITDA ⁽¹⁾	$	360,000										$	396,829
Interest expense, including settlements paid on interest rate derivatives	$	(105,000									)	$	(92,800				)
Capital expenditures ⁽²⁾	$	(63,000									)	$	(112,638				)
Distributions to Preferred Unitholders ⁽³⁾	$	(2,230									)	$	(26,759				)

Distributable cash flow	$	189,770										$	164,632

Excess of net cash after distributions to unitholders ⁽⁴⁾	$	145,000										$	50,443

Mid-point adjusted net income per unit ⁽¹⁾	$	0.10										$	0.78
Units outstanding (millions)		131.1											92.5

Assumed NYMEX Pricing (February 29, 2016) ⁽⁵⁾:	Q1 2016						Q2 2016					Q3 2016			Q4 2016
Oil ($/Bbl)	$	31.20					$	35.48				$	38.48		$	40.08
Natural gas ($/MMBtu)	$	2.09					$	1.80				$	2.02		$	2.26

Average NYMEX Differentials:
Oil ($/Bbl)	$	(7.50			)		$	(7.50			)	$	(7.50	)	$	(7.50	)
Natural gas ($/MMBtu)	$	(0.80			)		$	(0.80			)	$	(0.80	)	$	(0.80	)
NGL realization as a percentage of crude oil NYMEX price⁽⁶⁾		24			%			22			%		22	%		22	%

Capital Expenditures Details (in thousands):	Q1 2016						Q2 2016					Q3 2016			Q4 2016
Operated	$	(4,000			)		$	(7,500			)	$	(6,500	)	$	(5,500	)
Non-Operated	$	(15,500			)		$	(12,500			)	$	(6,000	)	$	(5,500	)
Total Capital Expenditures	$	(19,500			)		$	(20,000			)	$	(12,500	)	$	(11,000	)

(1) Adjusted EBITDA and adjusted net income exclude the amortization of value on derivative contracts acquired (approximately $16.7 million for the FY 2016).
(2) Additional detail regarding the capital breakout by quarter is listed below.
(3) Reflects current monthly preferred distributions are suspended effective with the February 2016 distribution, which would have been paid in April 2016.
(4) Excess of net cash after distributions is net of any expected working capital adjustments and cash reserves and does not consider the payment of any accrued preferred distributions.
(5) NYMEX pricing includes actual settlements for January and February 2016.
(6) Assumes a weighted average product breakout of 24% ethane, 35% propane, 14% isobutane, 10% n-butane and 17% pentane.

Annual Report on Form 10-K and Unitholders' Schedule K-1

Vanguard's financial statements and related footnotes will be available on our 2015 Form 10-K, which is expected to be filed on or about Monday, March 7, 2016, and will be available through the Investor Relations/SEC Filings section of the Vanguard's website at http://www.vnrllc.com.

Unitholders' Schedule K-1s for the tax year 2015 will be available for download on our website the week of March 14, 2016. For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-866-536-1972 or via email at VanguardK1Help@deloitte.com.

Conference Call Information

Vanguard will host a conference call on Monday, March 7, 2016, to discuss its fourth quarter and full year 2015 results at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (888) 504-7963 or (719) 325-2469 for international callers and ask for the “Vanguard Natural Resources Earnings Call.” The conference call will also be broadcast live via the Internet and can be accessed through the Investor Relations section of Vanguard's corporate website, http://www.vnrllc.com.

A telephonic replay of the conference call will be available until April 6, 2016 and may be accessed by calling (888) 203-1112 or (719) 457-0820 for international callers and using the pass code 1242022#. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com.

About Vanguard Natural Resources, LLC

Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. Vanguard's assets consist primarily of producing and non-producing oil and natural gas reserves located in 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. More information on Vanguard can be found at www.vnrllc.com.

Forward-Looking Statements

This press release includes "forward-looking statements" within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include but are not limited to statements about the acquisition announced in this press release. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for oil, natural gas and NGLs, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company's reports filed with the Securities and Exchange Commission. Please see "Risk Factors" in the Company's public filings.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to publicly correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

Use of Non-GAAP Measures

Adjusted EBITDA

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

Net interest expense;
Depreciation, depletion, amortization, and accretion;
Impairment of oil and natural gas properties;
Goodwill impairment loss;
Net gains or losses on commodity derivative contracts;
Cash settlements on matured commodity derivative contracts;
Net gains or losses on interest rate derivative contracts;
Net gains and losses on acquisitions of oil and natural gas properties;
Texas margin taxes;
Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and
Transaction costs incurred on acquisitions.

Adjusted EBITDA is a significant performance metric used by 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.

Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows 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.

Distributable Cash Flow Available to Common and Class B Unitholders

We present Distributable Cash Flow Available to Common and Class B Unitholders in addition to our reported net income (loss) in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:

Depreciation, depletion, amortization, and accretion;
Impairment of oil and natural gas properties;
Goodwill impairment loss;
Net gains or losses on commodity derivative contracts;
Cash settlements on matured commodity derivative contracts;
Net gains and losses on acquisitions of oil and natural gas properties;
Texas margin taxes;
Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and
Transaction costs incurred on acquisitions;

Less:

Drilling, capital workover and recompletion expenditures;
Distributions to Preferred Unitholders;

Plus:

Proceeds from the sale of leasehold interests.

Distributable Cash Flow Available to Common and Class B Unitholders is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) 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. However, Distributable Cash Flow Available to Common and Class B Unitholders should not be viewed as indicative of the amount that we plan to distribute for a given period. Distributable Cash Flow Available to Common and Class B Unitholders is not intended to be a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a metric commonly used by investors and the analyst community to assess our financial performance from period to period.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses. Our board of directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of our limited liability company agreement. Management considers the timing and size of capital expenditures and long-term views about expected results in determining the amount of distributions. Capital spending and the resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, our board of directors historically has not varied the distribution it declares period to period based on uneven available distributable cash flow. Our board of directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. In instances following acquisitions and development activities, our board of directors reviews any excess in distributable cash flows after distributions to unitholders in those periods, as well as forecasts of expected future net cash flows to determine if increases in distributions could be made. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, our board of directors may determine to reduce, suspend or discontinue paying distributions. Our board of directors may decide to retain the excess in distributable cash flows after distributions to unitholders for our future operations, future capital expenditures, future debt service or other future obligations. Any shortfalls are funded with cash on hand and/or with borrowings under our reserve-based credit facility.

VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted EBITDA (a) and
Distributable Cash Flow Available to Common and Class B Unitholders
(Unaudited)
(in thousands, except per unit amounts)

	Three Months Ended December 31,						Year Ended December 31,
	2015			2014			2015			2014
Net income (loss)	$	(508,422	)	$	(60,138	)	$	(1,883,174	)	$	64,345
Plus:
Interest expense	25,880			20,236			87,573			69,765
Depreciation, depletion, amortization and accretion	64,676			76,139			247,119			226,937
Impairment of oil and natural gas properties	484,855			234,434			1,842,317			234,434
Goodwill impairment loss	71,425			—			71,425			—
Net gains on commodity derivative contracts	(66,855		)	(174,577		)	(169,416		)	(163,452		)
Net cash settlements paid on matured commodity derivative contracts ^(b)(c)	85,735			23,534			211,723			10,187
Net (gains) losses on interest rate derivative contracts ^(d)	(2,444		)	865			(153		)	1,933
Net gains on acquisitions of oil and natural gas properties	(40,817		)	—			(40,533		)	(34,523		)
Texas margin taxes	114			(505		)	(266		)	(630		)
Compensation related items	6,868			5,270			18,522			11,710
Transaction costs incurred on acquisitions	11,692			389			11,692			739
Adjusted EBITDA	$	132,707		$	125,647		$	396,829		$	421,445
Less:
Interest expense, including settlements paid on interest rate derivatives	(28,139		)	(21,245		)	(92,800		)	(73,800		)
Estimated maintenance capital expenditures^(e)	(32,426		)	(23,811		)	(112,639		)	(116,528		)
Distributions to Preferred Unitholders	(6,689		)	(6,690		)	(26,759		)	(18,197		)
Proceeds from sale of leasehold interests	—			—			—			1,950
Distributable Cash Flow Available to Common and Class B Unitholders	$	65,453		$	73,901		$	164,631		$	214,870
Distributions to Common and Class B Unitholders	23,234			52,896			114,189			207,035
Excess of distributable cash flow after distributions to Unitholders	$	42,219		$	21,005		$	50,442		$	7,835

Distributable Cash Flow per Common and Class B unit	$	0.50		$	0.88		$	1.78		$	2.61
Common and Class B unit Distribution Coverage	2.82x			1.40x			1.44x			1.04x

(a) Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows 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.
(b) 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.	$	810		$	—		$	5,434		$	—
(c) 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.	$	12,027		$	4,834		$	44,761		$	21,306
(d) Includes settlements paid on interest rate derivatives	$	2,259		$	1,009		$	5,227		$	4,035

(e) Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in production from the prior year due to the decline in proved developed producing production. These costs, which are incorporated in our annual capital budget as approved by the board of directors, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing production on both operated and non-operated properties. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our production. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all.

Vanguard Natural Resources Reports Fourth Quarter and Full Year 2015 Operating and Financial Results, 2016 Outlook and Suspension of Common and Preferred Distributions

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