Credit Agricole 5th Annual High Yield Conference

Transcription

1 April 2012 Credit Agricole 5th Annual High Yield Conference NYSE: VNR

2 Forward-Looking Statements Statements made by representatives of Vanguard Natural Resources, LLC during the course of this presentation that are not historical facts are forward looking statements, including (but not limited to) statements about the acquisition (including its benefits, results and effects), the related financing plans, whether and when the acquisition will be consummated, the operating results of Encore Energy Partners LP following the acquisition and statements with respect to future distributions. These statements are based on certain assumptions and expectations made by the Company which reflect management s experience, estimates 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 anticipated in the forward looking statements. These include risks relating to the satisfaction of the conditions to closing of the acquisition, uncertainties as to timing, financial performance and results, our indebtedness under our revolving credit facility, availability of sufficient cash to pay our distributions and execute our business plan, prices and demand for oil, natural gas and natural gas liquids, our ability to replace reserves and efficiently develop our reserves, our ability to make acquisitions on economically acceptable terms and other important factors that could cause actual results to differ materially from those anticipated or implied in the forward looking statements. See Risk Factors in our most recent annual report on Form 10-K and Item 1A. of Part II Risk Factors in our subsequent quarterly reports on Form 10-Q and any other public filings and press releases. Vanguard Natural Resources, LLC undertakes no obligation to publicly update any forward looking statements, whether as a result of new information or future events. This presentation has been prepared as of April 9,

3 Overview of Vanguard Natural Resources Upstream oil & gas LLC, headquartered in Houston, Texas Initial Public Offering VNR October 2007 (Total Enterprise Value of ~$240mm) Twelve strategic acquisitions totaling ~$1.6bn expanded geographic profile and commodity diversity (including merger with Encore Energy Partners LP) Quarterly distribution of $ per unit ($2.35 annualized) yields approximately 8.3% at current price; Increased distributions ~38% since IPO Diverse portfolio of mature, long life gas and oil properties, combined with a multi-year hedging program provide stable cash flow and support distribution growth No General Partner or incentive distribution rights (IDRs) Reduces cost of capital ~73.2 MMBoe total proved reserves Q Production: ~14 MBoe/d ~88% proved developed and 17 year Proved R/P (3) & PD R/P of 15 years ~71% liquids / 29% gas on a consolidated basis ($ in millions) Company Profile VNR UNITS OUTSTANDING (1) 51.9 EQUITY MARKET CAP (2) $1,466 TOTAL DEBT $656 LESS CASH $7 ENTERPRISE VALUE $2,115 3 * Proved reserves as of 12/31/11 based on reserve report prepared by our independent reserve engineers, DeGolyer & MacNaughton (D&M), and 12-month average spot prices. Pro forma for exchange of Appalachian assets (1) Pro forma for retirement of 1.9mm common units in connection with the Appalachian exchange (2) Market data as of April 9, 2012 includes 420 thousand Class B units. Balance sheet data as adjusted for January 2012 equity offering (3) Based on 12/31/11 proved reserves and Q production, pro forma for exchange of Appalachian assets

4 Key Investment Highlights High quality, long-lived reserve base with low production decline rates and low capital reinvestment requirements Geographically diverse asset base comprised predominantly of oil properties Active hedging program which has locked in attractive margins through 2014 Significant inventory of low-risk development opportunities Well-capitalized balance sheet with sufficient liquidity and financial flexibility Experienced management team with a track record of successful operations, acquisitions, and integrations 4

5 Geographically Diversified Reserve Base Core Areas Overview Big Horn Basin Proved Reserves: 26.5 MMBoe 82% oil and 97% Proved Developed 3.9 MBoe/d net production 93% operated Williston Basin Proved Reserves: 5.4 MMBoe 92% oil and 91% Proved Developed 0.9 MBoe/d net production 70% operated 73.2 MMBoe Proved Reserves 71% oil and 88% Proved Developed 14 MBoe/d net production PD R/P of 15 Years Operate 79% of cash flow BIG HORN BASIN WILLISTON BASIN Proved Reserves by Area 73.2 MMBoe Permian Basin Proved Reserves: 29.9 MMBoe 49% oil and 86% Proved Developed 5.1 MBoe/d net production 85% operated PERMIAN BASIN ARKOMA BASIN MISSISSIPPI VNR Major Producing Fields Big Horn Basin 36% Williston Basin 7% Arkoma 2% Permian 41% South Texas Proved Reserves: 7.8 MMBoe 59% gas and 65% Proved Developed 1.1 MBoe/d net production 0% operated SOUTH TEXAS Arkoma Basin Proved Reserves: 1.1 MMBoe 73% gas and 100% Proved Developed 0.4 MBoe/d net production 0% operated Mississippi Parker Creek Proved Reserves: 2.5 MMBoe 100% oil and 76% Proved Developed 0.6 MBoe/d net production 90% operated Mississippi 3% South Texas 11% 5 Note: Proved reserves as of 12/31/11 based on reserve report prepared by D&M. Production represents 2011 average daily net production. Pro forma for exchange of Appalachian assets. Percent operated statistics are based on a cash flow basis

6 Liquids Focused Reserve Base Total Proved 2011 Net % of Proved Developed % Proved Production % Liquids PV-10 Proved Operating Area (MMBoe) (MMBoe) Developed (MBoe/d) (Production) ($mm) PV-10 Permian Basin % % $544 38% Big Horn Basin South Texas Williston Basin Mississippi Arkoma Basin Total % % $1, % Proved Reserves by Commodity Proved Reserves by Category 2011 Revenue by Commodity Gas 29% NGLs 10% PUD 12% PDNP 4% PDP 84% Gas 12% NGLs 10% Oil 78% Oil 61% 6 Note: Proved reserves as of 12/31/11 based on reserve report prepared by D&M. Production represents 2011 average daily net production. Pro forma for exchange of Appalachian assets

7 Permian Basin Acquired producing assets from Apache in December 2007 Established Permian Basin as an operating area, with approximately 50 operated wells in 7 fields Encore acquisition added 16.9 MMBoe of proved reserves (37% oil, 78% PDP) 2011 acquisitions added 9.3 MMBoe of proved reserves (75% oil, 95% PDP) Added 3 field offices Future growth opportunities through bolt-on acquisitions 2012E capex of $16.0mm (43% of total) PERMIAN BASIN ASSET Proved Reserves: 29.9 MMBoe (1) 59% liquids and 86% Proved Developed 85% operated 121,952 gross (91,564 net) acres 926 Vanguard operated producing wells ~5.1 MBoe/d 2011 net production (57% liquids) R/P ratio of 16 years (1) D&M estimates as of 12/31/11, $96.24/bbl and $4.12/MMBtu price deck 7

8 Big Horn Basin Majority of Big Horn Basin properties located in Elk Basin and Gooseberry Field Elk Basin Major producing horizons include Embar- Tensleep, Madison, Frontier Formations Gooseberry Field Active waterflood project located 60 miles south of Elk Basin, which consists of 26 active producing wells Operatorship over local systems: (i) Elk Basin natural gas processing plant (XOM owns 34% interest) (ii) Wildhorse pipeline system (12-mile natural gas gathering system) 2012E capex of $2.6 MM (7% of total) Asset Map BIG HORN BASIN ASSET Proved Reserves: 26.5 MMBoe (1) 88% liquids and 97% Proved Developed 93% operated 36,312 gross (31,651 net) acres 335 Vanguard operated producing wells ~3.9 MBoe/d 2011 net production (80% liquids) R/P ratio of 18 years (1) D&M estimates as of 12/31/11, $96.24/bbl and $4.12/MMBtu price deck Field Offices 8

9 How We Spend Capital Disciplined approach to capital spending focus on maintaining cash flow from mature, long lived fields By contrast, resource players invest in growth to support equity valuation The nature of our capital program is inherently less risky due to the lengthy production histories in the fields we operate We grow production primarily through accretive acquisitions of low-risk producing properties, rather than through the drillbit Our capital spending as a percent of EBITDA is best-in-class 2012E capital budget of $37.5 million approximately 15% of 2012E Adjusted EBITDA VNR E&P MLPs (1) Resource Players 15% 49% 172% Capital Spending vs. Cash Flow Resource Players E&P MLPs $1,400 1,200 1,000 $1, Adjusted EBITDA 2011 Capex (2) $1,148 ($mm) EBITDA / Capex $709 $654 $545 $620 $639 $550 $541 $396 $375 $235 $225 $225 $202 $212 $34 $76 $72 $84 (3) BRY SFY SD LPI OAS VNR BBEP LGCY EVEP LINE 1.0x 0.7x 0.5x 0.5x 0.4x 6.6x 3.0x 2.8x 2.5x 1.8x 9 Source: Company filings Note: VNR adjusted EBITDA includes the non-controlling interest of ENP (1) Excludes VNR (2) Represents development and exploration expenses, excluding acquisitions (3) Based on Wall Street consensus estimates as of March 7, 2012

10 Our Acquisition Strategy The U.S. has a large inventory of mature oil and natural gas basins which provide significant opportunity for future growth and consolidation Current E&P opportunity set is comprised of an estimated $1.5 trillion of mature properties, which is substantially more than the U.S. midstream sector Approximately $40 billion of E&P assets transacted each year since 2007 Vanguard s Acquisition Strategy is to: Acquire mature oil and gas properties with the following characteristics: Stable, long life production with a shallow decline High percentage of proved developed producing reserves Long reserve life Step-out development opportunities for additional growth Efficiently manage the oil and gas assets with focus on maintaining cash flow levels Reduce commodity price and interest rate risk through hedging Return cash flow through distribution payments to unitholders 10

11 Our Successful Acquisition Track Record Acquisition We acquire developed, proved properties in established oil and gas basins Recently we have focused on oily / liquids properties We review between and evaluate approximately 50 acquisition candidates each year Effective Date Region Adj. Purchase Price ($ mm) Proved Reserves/ PDP (1) Key Features Apache Jan 2008 Permian $ MMBoe / 90% PDP 83% oil Dos Hermanos Jul 2008 South Texas $ Bcfe / 65% PDP 98% natural gas SUN TSH Jul 2009 South Texas $ Bcfe / 74% PDP 55% natural gas Ward County Oct 2009 Permian $ MMBoe / 65% PDP 83% oil Parker Creek May 2010 Mississippi, TX & NM $ MMBoe / 61% PDP 96% oil Encore Acquisition *Encore Merger Dec 2010 *Dec 2011 Permian, Williston, Arkoma & Big Horn Basins $380.0 *$814.0 additional 43.4 MMBoe / 91% PDP 67% oil & NGLs Miscellaneous Q Permian $ MMBoe / 100% PDP 100% oil Permian May 2011 Permian $ MMBoe /100% PDP 70% oil & NGLs Permian May 2011 Permian $ MMBoe / 51% PDP 87% oil & NGLs Wyoming June 2011 Big Horn $ Bcfe / 90% PDP 65% natural gas TX, LA Aug 2011 Gulf Coast $ MMBoe / 100% PDP 83% oil & NGLs Montana, N. Dakota Sept 2011 Williston $ MMBoe / 100% PDP 97% oil Mississippi Dec 2011 Mississippi $ MMBoe / 85% PDP 100% oil Weighted Average (2) 6.0 MMBoe / 86% PDP 66% oil and NGLs 11 * Purchase price adjusted downward for distributions received on ENP units and includes debt as of 11/30/11 (1) Proved reserves and proved developed producing (PDP) numbers are calculated as of the acquisition closing date based on internal estimates (2) Assumes oil to gas conversion ratio of 6:1

12 Largest acquisition to date at $1.2 billion Increased exposure to crude oil for VNR unitholders What Encore Did For Us Significantly increased size and scale, overall operating reach and cash flow stability Improved ability to compete for acquisitions going forward Geographic diversification through exposure to the Big Horn Basin, Williston Basin and Arkoma / Mid-Continent Enhanced existing footprint in the Permian Basin Added complementary, high-quality asset base characterized by: Predictable production profiles Low decline rates Long reserve life Modest capital requirements Immediate accretion to VNR s distributable cash flow Expanded human resource capital Added critical in house functions necessary for operating assets Our experience integrating Encore will be beneficial in future acquisitions 12

13 Our Successful Execution of the E&P MLP Strategy High Quality, Low Risk Asset Portfolio Geographically diverse portfolio of long life assets, well positioned in most of the mature US basins (1) 73.2 MMBoe total proved reserves, 88% proved developed and 17 year Proved R/P Balanced commodity portfolio transitioned portfolio from 100% gas at IPO to approximately 71% liquids (61% oil) today Low capital requirements to maintain cash flow going forward $37.5 million capital expenditure program for 2012 which is approximately 15% of 2012E Adjusted EBITDA Disciplined Acquisition Strategy 12 strategic acquisitions since the IPO, including the recent acquisition of ENP Average acquisition price of $17.00/Boe and captured margins of $53.70/Boe Acquisitions have supported 38% distribution growth since 2008 while improving overall coverage and credit position We review between and evaluate approximately 50 acquisition candidates each year Active Hedging Program Approximately 80% of expected oil production hedged through 2014 at FLOOR PRICE of $90.80 per barrel Approximately 75% of expected natural gas production hedged through 2014 at $5.36 per MMBtu Acquisition strategy incorporates active hedging component to lock in anticipated margins Strong Credit Profile Proven Management Team with Extensive Experience Well capitalized balance sheet with sufficient liquidity and spending coverage VNR is not outspending cash flow like many resource play focused peers Management commitment to maintaining long-term leverage of less than 2.5x Debt / EBITDA Vanguard s long-term strategy is to fund its acquisition program with approximately 60% equity and 40% debt, de-levering the company over time No General Partner or incentive distribution rights (IDRs) Extensive experience in acquisition integration, development and operation of oil and gas assets demonstrated at Vanguard and previous companies Continuing to build team and infrastructure to support VNR s growing company and platform (1) Based on 12/31/11 proved reserves and Q production, pro forma for exchange of Appalachian assets 13

14 14 Financial Overview

15 Senior Notes Transaction Overview Sources & Uses of Funds ($ in millions) Sources of Funds Amount Uses of Funds Amount Senior Notes Issuance $347 Reduce Revolver Borrowings $283 Repay Term Loan 57 Fees and Expenses 8 Total Sources $347 Total Uses $347 ($ in millions, except per unit data) Pro Forma Capitalization As of As Adjusted for As Adjusted % of Leverage (1)(2) (2) 12/31/2011 Equity / Exchange for Bond Offering Capitalization Multiple Cash and Cash Equivalents $2.9 $2.9 $2.9 Debt Revolver $671.0 $579.1 $ % 1.3x Term Loan New Senior Notes % 1.6x Total Debt $771.0 $636.1 $ % 2.9x Members' Equity $843.9 $924.7 $ % (3) Total Capitalization $1,614.9 $1,560.8 $1, % Borrowing Base $765 $740 $671 Availability Total Debt / (3) 2011 Adjusted EBITDA ($224.6mm) 3.4x 2.8x 2.9x Capitalization 47.7% 40.8% 41.2% Proved Reserves ($ / Boe) $9.72 $8.69 $8.84 PD Reserves ($ / Boe) Current Production ($ / Boe/d) $56,335 $53,455 $54,356 PV-10 / Debt 1.9x 2.3x 2.2x (1) Pro forma for January 2012 equity offering. Proceeds used to repay debt outstanding under the Term Loan and Revolver (2) Pro forma for exchange of Appalachian assets, including reduction in borrowing base to $740mm from $765mm (3) 15 Leverage multiple based on 2011 Adjusted EBITDA of $224.6mm, before non-controlling interest

16 Summary Operating Performance Proved Reserves (MMBoe) (1) Production (Boe/d) (2) 15,000 12,500 10,000 7,500 5,000 2, ,723 4,721 2,701 3,335 1,931 1,935 13, (2) Adjusted EBITDA ($mm) Distribution Growth ($ / unit) $250.0 $200.0 $150.0 $100.0 $50.0 $0.0 $224.6 $225 $80.4 $48.8 $49 $56.2 $ (3) $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $2.31 $2.35 $1.89 $2.03 $2.19 $1.70 (4) (5) (1) Proved reserves as of 12/31/11 based on reserve report prepared by our independent reserve engineers, DeGolyer & MacNaughton (D&M) and 12-month average spot prices. Amounts illustrated reflect ENP s and VNR s proved reserves on a consolidated basis. (2) Amounts illustrated reflect ENP and VNR proved reserves and production on a consolidated basis. Pro forma for exchange of Appalachian assets. 16 (3) Adjusted EBITDA includes the non-controlling interest of ENP (4) Annualized quarterly distribution (5) Annualized based on current quarterly distribution price of $0.5875

17 Disciplined Financial Strategy Maintain conservative capital structure and sufficient liquidity Availability under Revolver at closing of Senior Notes offering of $364 million Target Debt / EBITDA of less than 2.5x provides sufficient liquidity Active management of debt levels by periodic access to the equity markets as needed Utilize excess cash flow to reduce revolving debt levels Prudent management of commodity price risk through multi-year hedging program Approximately 80% of expected oil production hedged through 2014 at FLOOR PRICE of $90.80 per barrel Approximately 75% of expected natural gas production hedged through 2014 at $5.36 per MMBtu Acquisition strategy incorporates active hedging component to lock-in anticipated margins Prudently seek acquisitions utilizing our low cost of capital Accretive acquisitions of long life oil and gas assets Maintain a prudent coverage ratio to provide distribution stability and comfortable growth Maintain strong relationships with a diversified bank syndicate Currently have 20 banks in the Revolver 17

18 Acquisition Financing Strategy Vanguard s long-term strategy is to fund its acquisition program with approximately 60% equity and 40% debt, de-levering the company over time via equity issuances and utilizing excess cash flow to pay down debt To date, Vanguard has issued more than 42mm units for a total of approximately $1.0bn in net proceeds, including ~$487mm for the second step of the Encore merger ~63% of the total acquisition value for transactions has been financed with equity $1,000 Total of ~$1.6bn $882 $1,000 Total of ~$1.0bn $800 $800 $600 $494 $600 $488 $400 $400 $274 $200 $137 $127 $200 $106 $96 $0 $21 $0 $ (1) Cumulative $127 $233 $727 $1,609 $1,609 Cumulative $21 $117 $391 $879 $1,016 (1) Encore merger purchase price adjusted downward for distributions received on ENP units and includes debt as of 11/30/11 18

19 Hedging Philosophy Hedge commodity prices on estimated production from acquisitions for three to five years upon signing the Purchase and Sale Agreement to protect rate of return from price fluctuations Opportunistic hedging program to extend hedge positions as existing hedges roll off Reduce cash flow volatility and protect distribution levels Primary use of swaps and costless collars, with the addition of threeway collars to provide more upside Interest rate risk also mitigated through hedging 19

20 Locking in Margins Provides Stability Through the use of hedging, Vanguard is able to lock in significant acquisition margins for the foreseeable future, helping to insure distribution stability $ $92.82 $92.27 $93.42 $90.00 $80.00 $80.28 $78.85 $84.87 $81.72 $70.00 $60.00 $60.42 $60.48 $56.12 $68.50 $67.41 $51.62 $62.21 $50.00 $40.00 $43.74 $44.46 $44.83 $63.10 $48.66 $63.99 $70.50 $59.05 $77.93 $30.00 $44.99 $31.21 $20.00 $10.00 $0.00 $16.68 $16.02 Apache (12/21/07) Dos Hermanos (7/21/08) $11.29 SUN TSH (7/21/09) $17.19 Ward County (11/30/09) $24.32 Parker Creek (5/3/10) $18.75 Encore (11/17/10) $14.85 $14.37 Permian (6/22/11) Permian (8/15/11) $6.63 Wyoming (9/1/11) $22.67 Gulf coast (8/31/11) $14.34 Montana / N. Dakota (12/1/11) Mississippi (12/22/11) NYMEX 5 Year WAVG Forward Strip Price on a Boe Basis Acquisiton Cost per Boe 20

21 Hedges Mitigate Commodity Price Risk Approximately 80% of expected crude oil production (total proved) thru 2014 Approximately 75% of expected natural gas production (total proved) thru 2014 MBbls 3,500 3,000 2,500 2,000 1,500 1, % 17% 39% $88.57 $ % 14% Weighted average floor price of $90.80 per barrel ( ) 35% 3% $ % 50% 45% 44% 87% $ % 5% Swaps Collars Three Way Collars Put Spreads Unhedged MMcfe 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Weighted average price of $5.36 per MMBtu 22% $5.23 $5.57 4% 60% 100% $ % 40% Swaps Puts Unhedged 21 Note: Hedge prices reflect a weighted average of swap prices, floor prices on collars and puts and long put prices on three way collars. Excludes production associated with Appalachia properties for the recently announced divestiture for 1.9 million VNR units that is expected to close in March Excludes NGL production.

22 Case #1 - E&P MLPs after Hedges Roll Off E&P MLP peer hedge books are supporting their EBITDA due to higher than market gas hedges and will require prices to increase to a much higher level in the outer years to maintain current cash flows but what if prices remain at their current levels? For VNR, it is a very different story after the hedges roll off due to being primarily liquids focused $1,350 ASSUMED PRICE DECK: OIL - $ & GAS - $2.50 (EBITDA - $ in millions) $1,200 $1,050 $900 $250 $200 6% Increase 25% Decrease 23% Decrease 12% Decrease $ VNR EVEP BBEP LINE Note: Assumes 2012 company guidance for VNR and peers, and 2012 production held flat through NYMEX price deck of $ / $2.50 held flat through

23 Case #2 - E&P MLPs after Hedges Roll Off E&P MLP peer hedge books are supporting their EBITDA due to higher than market gas hedges and will require prices to increase to a much higher level in the outer years to maintain current cash flows but what if the current oil and gas curves are correct? For VNR, it is a very different story after the hedges roll off due to being primarily liquids focused ASSUMED PRICE DECK: CURRENT STRIP (EBITDA - $ in millions) $1,350 $1,200 $1,050 $900 $250 13% Decrease 7% Decrease $200 7% Decrease 2% Decrease $ VNR EVEP BBEP LINE Note: Assumes 2012 company guidance for VNR and peers, and 2012 production held flat through Market data as of 3/7/12. NYMEX Strip as of 4/9/ : $104.74/bbl and $2.50/MMBtu; 2013: $104.52/bbl and $3.45/MMBtu; 2014: $100.56/bbl and $3.94/MMBtu; 2015: $97.26/bbl and $4.23/MMBtu; 2016: $95.02/bbl and $4.56/MMBtu 23

24 PV-10 Value and Commodity Hedges NYMEX Strip Case (1)(2) VNR PV-10 Asset Value ($mm) PD Value $1,374 PUD Value 143 Total Proved Value $1,517 Hedge Value 29 Proved + Hedge Value $1,545 Total PV-10 Value ($mm) $1,600 1,400 1,200 1,000 (3) Robust Asset Coverage Total Debt Pro Forma for Senior Notes (3) $1,374 $1,374 $1,517 $1,545 $143 $29 $143 $1,374 $1,374 PD Value Proved Value Proved Value + Hedges PD PUD Hedges Asset Value / Debt 2.1x 2.3x 2.4x PV-10 Value and Commodity Hedges $70.00 / Bbl and $2.00 / MMBtu Case (1) VNR PV-10 Asset Value ($mm) PD Value $807 PUD Value 49 Total Proved Value $856 Hedge Value 142 Proved + Hedge Value $999 Total PV-10 Value ($mm) $1,200 1, (3) Total Debt Pro Forma for Senior Notes (3) $999 $856 $142 $807 $49 $ $807 $807 $ PD Value Proved Value Proved Value + Hedges PD PUD Hedges Asset Value / Debt 1.3x 1.3x 1.6x (1) Represents value of current hedge portfolio as of December 31, 2011, discounted back to 12/31/11 at 10% (2) NYMEX Strip as of 4/9/ : $104.74/bbl and $2.50/MMBtu; 2013: $104.52/bbl and $3.45/MMBtu; 2014: $100.56/bbl and $3.94/MMBtu; 2015: $97.26/bbl and $4.23/MMBtu; 2016: $95.02/bbl and $4.56/MMBtu; 2017: $94.05/bbl and $4.81/MMBtu; and 2018: $93.46/bbl and $5.05/MMBtu thereafter. NGL prices 24 assumed to be 50% of WTI (3) Represents VNR debt value of $646.8mm, pro forma for Senior Notes offering

25 Historical Credit Metrics Debt / Adjusted EBITDA Adjusted EBITDA / Interest Expense 4.0x x 2.8x 2.3x 2.2x 2.8x 12.0x x 8.7x 9.1x 10.6x 7.0x 0.0 (1) (2) (FDC + Debt) / Proved Reserves ($ / Boe) Debt / PD Reserves ($ / Boe) $ $10.25 $9.45 $11.81 $10.65 $ $10.01 $8.04 $9.43 $9.90 $ $ $ Note: Proved reserves as of 12/31/11 based on reserve report prepared by D&M. Production represents 2011 average daily net production. Pro forma for exchange of Appalachian assets (1) Excludes acquired debt of Encore as transaction closed on 12/31/2010 with no associated EBITDA impact (2) Pro forma for January 2012 equity offering and exchange of Appalachian assets 25

26 Relative Bond Yields % % % 9.348% 8.000% 7.220% 7.469% 7.637% 7.785% 7.961% 6.000% 6.054% 6.240% 4.000% 2.000% 0.000% SFY OAS LINE BBEP CRZO EVEP VNR AMH VQ Issue Ratings B3 / B+ Caa1 / B B2 / B B3 / B B3 / B B3 / B- Caa1 / B- B3 / B Caa1 / B- 26 Source: Citibank. Note: YTW data as of April 9, 2012.

27 Peer Benchmarking Operational / Asset Metrics Proved Reserves (MMBoe) Value of Proved Reserves ($bn) (2) LINE EVEP SFY BBEP CRZO VQ OAS VNR AMH % Liquids Gas Reserves Liquids Reserves PD R/P Ratio (years) (1) $8.0 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 $7.8 $1.7 $1.5 $1.4 $1.4 $1.4 $1.3 $1.1 $1.0 LINE BBEP SFY EVEP VNR VQ OAS AMH CRZO % Proved Developed % % 87% 72% 68% 64% 51% 46% 45% 35% 0 EVEP BBEP VNR LINE CRZO VQ OAS AMH SFY 0 VNR BBEP AMH EVEP L IN E VQ OAS CRZO SFY 27 Source: Company filings. Pro forma for M&A activity through 3/23/2012 Note: Proved reserves as of 12/31/11 based on reserve report prepared by D&M. Production represents 2011 average daily net production. Pro forma for exchange of Appalachian assets (1) Based on current production (2) Reflects standardized measure as of 12/31/2011 which is based on 2011 average prices of $96.24 for oil and $4.12 for natural gas.

28 Peer Benchmarking Credit / Leverage Metrics Debt / 2011 Adjusted EBITDA Asset Coverage (PV-10 / Debt) (2) 5.0x 4.5x 2.5x 2.2x 2.2x 2.1x 2.0x 2.0x 2.0x x 3.6x 3.4x 3.2x 3.1x 2.9x 2.5x 1.8x x 1.5x 1.5x LINE CRZO BBEP OAS EVEP VQ VNR AMH SFY (1) 0.0 AMH VNR SFY EVEP BBEP VQ OAS CRZO LINE (FDC + Debt) / Proved Reserves ($ / Boe) Debt / PD Reserves ($ / Boe) $ $20.12 $18.68 $18.18 $16.19 $14.17 $13.07 $11.66 $10.79 $7.67 $ $22.32 $14.64 $14.09 $12.94$11.73 $11.70 $10.08 $6.24 $ OAS EVEPCRZO SFY VQ AMH LINE VNR BBEP 0.00 OAS CRZO VQ SFY AMH LINE VNR BBEP EVEP Source: Company filings. Pro forma for capital markets and M&A activity through 4/10/2012 (1) Pro forma for January 2012 equity offering (2) Based on standardized measure 28

29 Key Investment Highlights High quality, long-lived reserve base with low production decline rates and low capital reinvestment requirements Geographically diverse asset base comprised predominantly of oil properties Active hedging program which has locked in attractive margins through 2014 Significant inventory of low-risk development opportunities Well-capitalized balance sheet with sufficient liquidity and financial flexibility Experienced management team with a track record of successful operations, acquisitions, and integrations 29

30 30 Q&A

31 31 Appendix

32 Experienced Management Team Name Title Prior Affiliations Years of Experience Scott W. Smith President and CEO Ensource Energy The Wiser Oil Company San Juan Partners >32 Richard A. Robert EVP and CFO Enbridge USA Midcoast Energy Resources Various energy-related entrepreneurial ventures >20 Britt Pence Senior Vice President of Operations Anadarko Petroleum Greenhill Petroleum Mobil >28 Mark Carnes Director of Acquisitions Synergy Oil & Gas Petromark Torch Energy Advisors >35 Chris Raper Land Manager Synergy Oil & Gas Amoco Production >33 Rod Banks Marketing Manager Apache Corporation Mariner Energy Producers Energy Marketing Coastal Gas Marketing ORYX Energy Company >32 32

33 South Texas Acquired properties from Lewis Energy in July 2008 and July 2009 Webb County, TX Most of the South Texas properties are located in two fields Gold River North Field (Webb County, TX) Sun TSH Field (La Salle County, TX) Reserves comprised of rich gas and NGL production Additional upside potential if gas prices rebound No associated 2012E capital expenditures SOUTH TEXAS ASSETS Proved Reserves: 46.8 Bcfe (1) 41% liquids and 65% Proved Developed 0% operated 21,020 gross (14,266 net) acres 191 Lewis operated producing wells ~6.5 MMcfe/d current net production (39% liquids) R/P ratio of 19 years La Salle County, TX (1) D&M estimates as of 12/31/11, $96.24/bbl and $4.12/MMBtu price deck 33

34 Williston Basin Located in North Dakota and Montana Williston Basin properties include: Horse Creek, Charlson Madison Unit, Cedar Creek MT, Lookout Butte East, Pine, Beaver Creek and others Bakken activity began in Participated as non-operator with Continental, SM Energy, Oasis and Brigham. Negotiating JV for additional development in E capex of $16.6 MM (45% of total) Asset Map WILLISTON BASIN ASSET Proved Reserves: 5.4 MMBoe (1) 92% oil and 91% Proved Developed 70% operated 63,996 gross (45,022 net) acres 75 Vanguard operated producing wells ~0.9 MBoe/d current net production (90% liquids) R/P ratio of 16 years (1) D&M estimates as of 12/31/11, $96.24/bbl and $4.12/MMBtu price deck 34

35 Mississippi Acquired producing assets in Mississippi, Texas and New Mexico in May 2010 Inventory of PDNP opportunities and recompletions designed to maintain production in 2012 Majority of production comes from Parker Creek Field in Jones County, MS 65% WI Mainly oil production that produces from the Hosston Formation from a depth ranging from 13,000 ft. to 15,000 ft. 2012E capex of $2.1 MM (6% of total) Parker Creek MISSISSIPPI ASSETS Proved Reserves: 2.5 MMBoe (1) 100% oil; 76% Proved Developed 90% operated 2,560 gross (1,296 net) acres 9 Vanguard operated producing wells ~0.6 MBoe/d current net production (99% liquids) R/P ratio of 11 years (1) D&M estimates as of 12/31/11, $96.24/bbl and $4.12/MMBtu price deck Jones County, MS 35

36 Arkoma Basin Arkoma properties include royalty interest and non-operated working interest properties Royalty interest properties include interests in over 1,700 wells in Arkansas, Texas and Oklahoma 10,300 unleased mineral acres Non-operated working interest properties include interests in over 100 producing wells in Chimsville field No associated 2012E capex ARKOMA BASIN ASSETS Proved Reserves: 6.6 Bcfe (1) 73% gas and 100% Proved Developed 0% operated 3,549 gross (495 net) acres ~2.2 MMcfe/d current net production (15% liquids) R/P ratio of 8 years (1) D&M estimates as of 12/31/11, $96.24/bbl and $4.12/MMBtu price deck 36

37 Reconciliation to EBITDA ($ in thousands) 2011 Net income (loss) attributable to Vanguard unitholders $62,063 Net income attributable to non-controlling interest 26,067 Net income (loss) $88,130 Plus: Interest expense, including realized losses on interest rate derivative contracts $31,868 Depreciation, depletion, amortization and accretion 84,857 Amortization of premiums paid on derivative contracts 11,346 Amortization of value on derivative contracts acquired 169 Unrealized (gains) losses on other commodity and interest rate derivative contracts 2,558 Net (gain) loss on acquisitions of oil and natural gas properties 367 Deferred taxes 261 Unit-based compensation expense 2,557 Unrealized fair value of phantom units granted to officers 469 Material transaction costs incurred on acquisitions and mergers 2,019 Adjusted EBITDA before non-controlling interest $224,601 37