Credit Agricole High Yield Conference Richard Robert EVP & CFO March 21, 2013
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. 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 March 13, 2013.
Overview of Vanguard Natural Resources Upstream oil & gas LLC, headquartered in Houston, Texas Initial Public Offering VNR October 2007 (Total Enterprise Value of ~$240mm) Seventeen strategic acquisitions totaling ~$2.5bn expanded geographic profile and commodity diversity (including merger with Encore Energy Partners LP, Arkoma Basin acquisition and Barrett acquisition) Monthly distribution of $0.2025 per unit ($2.43 annualized) yields approximately 8.6% at current price; Increased distributions ~43% since IPO Instituted a monthly distribution beginning with the July 2012 distribution Diverse portfolio of mature, long life oil and gas properties, combined with a multi-year hedging program provide stable cash flow and support distribution growth No General Partner or incentive distribution rights (IDRs) Asset Profile* ~152 MMBoe total proved reserves ~74% proved developed ~40% liquids / 60% gas 2012 Production: 18.3 MBoe/d 2013E Production: 32.3 MBoe/d Market Valuation Company Profile VNR UNITS OUTSTANDING (1) 68.3 EQUITY MARKET CAP (1) $1,929 TOTAL DEBT (2) $997 ENTERPRISE VALUE $2,926 3 * Proved reserves as of 12/31/2012 based on SEC reserve report. (1) Market data as of 3/13/13 and includes 420,000 Class B units. (2) Debt as of 2/25/12.
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 ~152 MMBoe total proved reserves, 74% proved developed Balanced commodity portfolio transitioned portfolio from 100% gas at IPO to approximately 40% liquids Low capital requirements to maintain cash flow going forward $55 million capital expenditure program for 2013 which is approximately 18% of 2013E Adjusted EBITDA Disciplined Acquisition Strategy 17 strategic acquisitions since the IPO, including the ENP acquisition, the Woodford/Fayettville acquisition and the Barrett acquisition in the Piceance Basin in Colorado and the Powder River and Wind River Basins in Wyoming Average acquisition price of ~$9.35/Boe and captured margins of ~$44.70/Boe Acquisitions have supported 43% distribution growth since 2008 while improving overall coverage and credit position We review between 125-150 and evaluate approximately 50 acquisition candidates each year Active Hedging Program Approximately 90% of expected oil production hedged through 2014 at FLOOR PRICE of $92.47 per barrel Approximately 85% of expected gas production hedged through 1H 2017 at $4.62 per MMBtu Acquisition strategy incorporates active hedging component to lock in anticipated margins Strong Credit Profile Well capitalized balance sheet with sufficient liquidity and spending coverage VNR is not outspending cash flow like many resource play focused peers Management commitment to maintaining long-term leverage of less than 3.0x Debt / EBITDA No General Partner or incentive distribution rights (IDRs) 4 Management Team with Extensive Experience Extensive experience in acquisition integration, development and operation of oil and gas assets demonstrated at Vanguard and previous companies Continuing to build team and infrastructure to support VNR s growing company and platform
Experienced Management Team Name Title Prior Affiliations Years of Experience Scott W. Smith President and CEO Ensource Energy The Wiser Oil Company San Juan Partners >32 Richard A. Robert EVP and CFO Enbridge USA Midcoast Energy Resources Various energy-related entrepreneurial ventures >25 Britt Pence Senior Vice President of Operations Anadarko Petroleum Greenhill Petroleum Mobil >28 Mark Carnes Director of Acquisitions Synergy Oil & Gas Petromark Torch Energy Advisors >35 Chris Raper Land Manager Synergy Oil & Gas Amoco Production >33 Rod Banks Marketing Manager Apache Corporation Mariner Energy Producers Energy Marketing Coastal Gas Marketing ORYX Energy Company >32 5
EBITDA ($mm) Proved Reserves (MMBoe) Company History 2006-2007 2008 2009 2010 2011 2012 6 Formed in October 2006 Scott Smith appointed CEO Richard Robert appointed CFO Entered into RCF with a borrowing base of $116mm $350 $300 $250 $200 $150 $100 $50 $0 $30 In January, purchased Permian assets from Apache for $73mm In July, purchased S. TX assets from Lewis Energy for $53mm $49 $56 In July, purchased additional S.TX assets from Lewis Energy for $52mm In December, purchased Permian assets for $55mm $80 11.2 18.1 23.8 28.2 In May, purchased assets in MS, TX and NM for $115mm In November, closed $175mm Term Loan as part of ENP acquisition In December, purchased 100% interest in ENP s GP and a 46.7% LP interest in ENP from Denbury for $380mm $165 79.3 $231 152.2 $303 175.0 2007 2008 2009 2010 2011 (1) 2012 2013E In November, closed amended $1.5bn Revolver and announced $100mm Term Loan In December, completed merger with ENP (remaining 53.2%); $814mm merger Completed $200mm in other acquisitions Note: 2013E reserves include the pending Range Permian acquisition. Adjusted EBITDA excludes the pending Range Permian acquisition. (1) Amounts illustrated reflect ENP and VNR proved reserves on a consolidated basis. 280 240 200 160 120 80 40 0 In January, completed $135mm equity offering In March, completed exchange of Appalachian assets for 1.9mm VNR units In April, completed $350mm senior unsecured notes offering In June, purchased assets in the Arkoma Basin for $434mm In September, completed ~$182mm equity offering In October, completed $200mm add-on of senior unsecured notes In November, announced purchase of assets from Bill Barrett Corp for $335mm 2013 In February, completed $246mm equity offering In February, announced a $275mm Permian acquisition from Range Resources
Geographically Diversified Reserve Base Big Horn Basin Proved Reserves: 22.7 MMBoe 83% oil and 96% Proved Developed 4.0 MBoe/d net production 96% operated Piceance Proved Reserves: 15.7 MMBoe 93% natural gas and 81% Proved Developed 25 MMcfe/d net production 0% operated 7 Permian Basin Proved Reserves: 26.2 MMBoe 51% oil and 85% Proved Developed 5.1 MBoe/d net production 74% operated Core Areas South Texas Proved Reserves: 6.9 MMBoe 58% gas and 59% Proved Developed 0.8 MBoe/d net production 0% operated Williston Basin Proved Reserves: 6.2 MMBoe 89% oil and 92% Proved Developed 1.3 MBoe/d net production 73% operated Powder River Proved Reserves: 4.0 MMBoe 100% natural gas and 94% Proved Developed 25 MMcfe/d net production 89% operated Arkoma Basin Proved Reserves: 61.9 MMBoe 80% gas and 55% Proved Developed 10.6 MBoe/d net production 41% operated Wind River Proved Reserves: 6.0 MMBoe 92% natural gas and 100% Proved Developed 10 MMcfe/d net production 86% operated Mississippi Parker Creek Proved Reserves: 2.6 MMBoe 98% oil and 77% Proved Developed 0.7 MBoe/d net production 87% operated Note: Proved reserves as of 12/31/2012 based on SEC reserve report. Production represents Q4 2012 average daily net production. Percent operated statistics are computed based on cash flow. Arkoma 41% Overview ~152 MMBoe proved reserves 60% gas and 40% liquids 74% proved developed ~58% operated cash flow Proved Reserves by Area ~152 MMBoe 17% Permian & GC 15% Big Horn 10% Piceance 5% S. Texas 4% Williston 2% 2% 4% Wind River Mississippi Powder River
Reserve Growth in 2012 2011 73.2 MMBoe 2012 152.2 MMBoe Natural Gas 34% NGLs 12% Oil 57% NGLs 9% Natural Gas 60% Oil 28% PDNP 3% PDP 82% PDNP 4% PUD 14% PDP 71% PUD 26% Note: Proved reserves based on SEC reserve report. 2011 proved reserves are pro forma for the Appalachia exchange.
Our Business Strategies Acquire and produce mature, long lived oil and gas properties which are nearly fully developed and have established, predictable production profiles We have a diversified asset base, geographically, by commodity and within our core operating areas, which reduces single asset risk Remove risk from our portfolio through active commodity and interest rate hedging Grow our stable distributions to unitholders, prudently and over time What We Do: Acquire mature properties Maintain cash flow by investing minimal capital expenditures Grow our production through acquisitions Reduce risk by hedging a significant percentage of production What We Don t Do: Lease large tracts of acreage for development Outspend cash flow to grow production Acquire properties which need significant development capital Take commodity price exposure 9
($mm) 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 drill bit Our capital spending as a percent of 2012A EBITDA is best-in-class 2013E capital budget is $55 million approximately 18% of 2013E Adjusted EBITDA Resource Players Capital Spending vs. Cash Flow E&P MLPs VNR 22% E&P MLPs (1) 66% Resource Players 181% $2,000 $1,825 $1,600 2012 Adjusted EBITDA 2012 Capex (2) $1,403 $1,200 $1,070 $1,078 $1,062 $932 $800 $731 $670 $400 $511 $453 $512 $346 $231 $50 $296 $153 $198 $68 $268 $137 $0 BRY SFY SD LPI OAS VNR BBEP LGCY EVEP LINE EBITDA / Capex 0.7x 0.5x 0.6x 0.5x 0.5x 4.6x 1.9x 2.9x 1.9x 1.3x 10 Source: Company filings. (1) Excludes VNR. (2) Represents development and exploration expenses, excluding acquisitions.
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 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 11
U.S. Natural Gas Reserves / Resource Life Shale development has significantly increased the natural gas reserves / resource in the United States Natural gas can now be viewed as a long-term energy solution 2,000 Tcf 100 Yr Life 250 Tcf 12 Yr Life Pre-Shale (EIA 2000) Post-Shale 12 Source: Jefferies January 2013 IPAA luncheon presentation.
Billions of Barrels U.S. Oil & Liquids Reserves / Resources Increase in U.S. liquids production is reducing imports 300 270 250 200 150 100 100 50 20 - U.S Existing U.S. Unconventional Potential Saudi Arabia 13 Source: Jefferies January 2013 IPAA luncheon presentation.
Future Shale Development Requires Massive Capital Average of $70 billion per year in capital requirements for the next 30 years Creates opportunities for E&P MLPs to acquire higher PDP assets as Shale players try to close the funding gap in their capital budget Play Est. Total Area (Million Acres) Wells to be Drilled Implied Recov. Res. (Tcfe) Future Drilling Capital ($B) Marcellus 12.0 150,000 750 675 Utica 5.0 52,500 344 281 Haynesville 3.0 37,500 247 300 Eagle Ford 3.0 37,500 206 206 Fayetteville - Core 2.5 31,250 84 102 Bossier 1.0 12,500 69 94 Woodford 1.0 12,500 39 69 Barnett - Core 1.2 21,818 55 57 Bakken 3.0 9,375 34 31 Total Drilling 31.7 364,943 1,828 $1,815 Estimated Midstream - - - 251 Grand Total $2,066 14 Source: Jefferies January 2013 IPAA luncheon presentation.
Capital Sources for North American E&P Companies Since 2007 ($B) More than $500 billion raised since 2007 $297 $112 $74 $53 M&A (Asset Only) Debt Equity Joint Ventures 15 Source: Jefferies January 2013 IPAA luncheon presentation.
Our Successful Acquisition Track Record $1,200 $1,021 $1,000 $800 $783 $600 $494 liquids gas $400 $275 $200 $127 $106 $0 2008 2009 2010 2011 2012 2013 # of Deals 2 2 2 8 3 1* 16 * 2013 includes the recently announced pending Range Permian acquisition expected to close on or around April 1, 2013.
Arkoma Basin Acquisition Woodford Shale Fayetteville Shale 17 Assets located in the Woodford Shale and Fayetteville Shale plays Total proved reserves of ~362 Bcfe (54% PDP) Current net production of ~61 MMcfe/d (includes ~800 Bbl/d of NGLs) Reserve to production ratio of 16 years ~71,300 net acres (89% held by production) ~180 drilling locations with an average 22.5% working interest (modeled with ~$22 million in capex per year) Restructured acquired hedges to cover ~100% of expected proved production for the next five years at $5.04/MMBtu beginning in August 2012 Immediately accretive to cash flow
Barrett Acquisition Piceance Basin, CO, Powder River & Wind River, WY 18 Assets located in the Piceance Basin in Colorado and the Powder River and Wind River Basins in Wyoming Total proved reserves of ~151 Bcfe (84% PDP) Current net production of ~60 MMcfe/d Escalating working interest in the Piceance Basin designed to maintain cash flow from the entire acquisition ~184,000 net acres in the Wind River Basin (12% held by production), ~67,000 net acres in the Powder River Basin (93% held by production), and ~4,000 net acres in the Piceance Basin (95% held by production) Vanguard significantly hedged the expected natural gas and oil production through 2016 and expected natural gas liquids production in April 2013-December 2013 Immediately accretive to cash flow
Pending Range Permian Acquisition Three operated field areas in the Permian Basin Eunice Area Lea County, New Mexico Loving East Eddy County, New Mexico Powell Ranch Glasscock County, Texas Total proved reserves of 137 Bcfe (78% PDP) Current net production of ~17 MMcfe/d (41% natural gas, 28% oil and 31% NGLs) Reserve to production ratio of approximately 22 years Operate over 90% of wells 19 Significant upside through behind-pipe and drilling opportunities Pref. Right on small portion of the assets
20 Financial Overview
Disciplined Financial Strategy Maintain conservative capital structure and sufficient liquidity Availability under Revolver as of 2/25/2013 of ~$750 million Target Debt / EBITDA of less than 3.0x 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 90% of expected oil production hedged through 2014 at a FLOOR PRICE of $92.47 per Bbl Approximately 85% of expected natural gas production hedged through the 1H 2017 at $4.62 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 24 banks in the Revolver 21
Risk Mitigation Vanguard seeks to mitigate risk across all facets of its business Drilling and Operational Risk Rate of return disciplined approach to project selection Drill only onshore, proved undeveloped locations Commodity Risk Management seeks to hedge approximately 85% of proved production for a period of 4-5 years Geographic and commodity diversity across the United States Interest Rate Risk Utilize LIBOR swaps to lock-in interest rates for a period of 3-4 years for senior secured debt Issue senior notes which have longer tenures and have fixed rates Acquisition Risk Other Measured and conservative approach to evaluating acquisitions Focus on largely PDP assets with proved upside potential Insurance for property, well control, pollution and general liability 22
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 three-way collars to provide more upside Interest rate risk also mitigated through hedging 23
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 $100.00 $92.82 $92.27 $93.42 $98.49 $90.00 $80.00 $80.28 $78.85 $84.87 $81.72 $70.00 $67.41 $60.00 $50.00 $40.00 $60.42 $60.48 $43.74 $44.46 $56.12 $44.83 $63.10 $68.50 $48.66 $63.99 $70.50 $51.62 $59.05 $77.93 $62.21 $82.57 $35.14 $39.98 $30.00 $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) $44.99 $6.63 Wyoming (9/1/11) $22.67 Gulf coast (8/31/11) $14.34 $31.21 Montana / N. Mississippi Dakota (12/22/11) (12/1/11) $15.92 Wyoming (3/31/12) $30.05 $33.29 $5.09 $6.69 Arkoma (6/29/12) * Barrett (11/1/12) NYMEX 5 Year WAVG Forward Strip Price on a Boe Basis Acquisiton Cost per Boe 24 * Arkoma Basin acquisition adjusted for value of the hedges acquired.
MMcfe Hedges Mitigate Commodity Price Risk Approximately 85% of expected natural gas proved production hedged thru the first half of 2017 at a weighted average FLOOR price of $4.62 per MMBtu Primarily use NYMEX and basis swaps 60,000 50,000 40,000 $4.60 6% $4.58 14% $4.60 7% $4.69 9% 30,000 20,000 94% 86% 93% 91% $4.75 10,000 56% 0 44% 2013 2014 2015 2016 1H 2017 Swaps Puts Unhedged 25 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 the exchanged Appalachia properties. Excludes NGL production.
MBbls Hedges Mitigate Commodity Price Risk Approximately 90% of expected crude oil proved production hedged thru 2014 at a weighted average FLOOR price of $92.47 per barrel Use a combination of swaps, collars and three-way collars 3,500 3,000 2,500 2,000 $92.53 32% 3% $92.40 12% 35% $94.00 $89.66 64% 78% 1,500 1,000 65% 53% 9% 500 0 25% 19% 2013 2014 2015 2016 Swaps Collars Three Way Collars Put Spreads Unhedged 26 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 NGL production. In 2013, Vanguard sold puts on 834,650 Bbls at a weighted average price of $665.13. Weighted average floor price includes impact from the range bonus accumulators in 2013-2014.
Summary Operating Performance 200 175 150 125 100 75 50 25 0 175 35,000 32,334 152 23 30,000 152 25,000 20,000 18,298 69 73 15,000 11,946 10,000 11 18 24 5,000 1,935 2,701 3,335 4,721 0 2007 2008 2009 2010 2011 2012 2013 2007 2008 2009 2010 2011 2012 2013E $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 $1.70 $1.89 $2.03 $2.19 $2.31 $2.40 $2.43 (5) (6) 2007 2008 2009 2010 2011 2012 2013 27 (1) Proved reserves as of 12/31/2012 based on SEC reserve report. Excludes pending Range Permian acquisition. (2) Amounts illustrated reflect ENP and VNR proved reserves and production on a consolidated basis. Pro forma for exchange of Appalachian assets. (3) Pro forma for the recent pending Range Permian acquisition. (4) Based on 2013E guidance announced on 3/1/2013. (5) Annualized quarterly distribution. (6) Annualized at the current monthly distribution of $0.2025 per unit.
2013E Guidance FY 2013E FY 2012 Net Production: Oil (Bbls/d) 7,750-8,250 7,536 Natural gas (Mcf/d) 122,400-130,000 53,695 Natural gas liquids (Bbls/d) 3,200-3,400 1,813 Total (BOE/d) 31,350-33,317 18,298 Costs per BOE: Lease operating expenses $8.25 - $9.25 $11.10 Production taxes (% of revenue) 8.5% - 9.5% 9.5% G&A expenses $1.25 - $1.75 $2.34 Depreciation, depletion and amortization $12.25 - $13.25 $15.61 Cash Flow Calculation: Adjusted EBITDA (1) $302,500 $230,512 Interest expense (64,000) (44,406) Maintenance capital expenditures (2) : Operated (32,000) (16,544) Non-operated (23,000) (33,861) Total maintenance capital expenditures (55,000) (50,405) Distributable cash flow (3) $183,500 $141,223 Mid-point distributable cash flow per unit $2.69 $2.60 Mid-point distribution coverage ratio (4) 1.11x 1.08x Mid-point adjusted net income per unit (1) $1.20 $1.18 Units outstanding (millions) 68.3 54.4 Assumed NYMEX Pricing (February 28, 2013) (5) : Q1 2013 Q2 - Q4 2013 FY 2012 Oil (Bbl) $94.03 $93.47 $94.19 Natural gas (MMBtu) $3.34 $3.63 $2.96 Average NYMEX Differentials: Oil (Bbl) $(13.85) $(8.70) $(9.66) Natural gas (MMBtu) $(0.85) $(0.90) $(0.55) NGL realization of crude oil price (%) 42% 43% 48% Maintenance Capital Expenditures: Q1 2013 Q2 2013 Q3 2013 Q4 2013 Operated $(5,000) $(12,500) $(8,500) $(6,000) Non-operated $(4,500) $(6,500) $(3,000) $(9,000) 28 (1) Adjusted EBITDA and adjusted net income (non-gaap financial measures defined below) exclude the amortization of value on derivative contracts acquired (approximately $30.0 MM for the FY 2013). (2) Additional detail regarding the maintenance capital breakout by quarter is listed below. Actual results for the year ended December 31, 2012 excludes the proceeds from the sale of leasehold interests. (3) Includes $5.5 million in proceeds from the sale of leasehold interests in 2012. (4) Assumes current monthly distribution rate of $0.2025 per unit for 2013 and no additional unit offerings. (5) NYMEX pricing includes actual settlements for 2013.
Historical Credit Metrics Debt / Adjusted EBITDA Adjusted EBITDA / Interest 4.0x 3.0x 2.0x 1.0x 1.2x 2.8x 2.3x 2.2x 2.8x 3.3x 3.3x 12.0x 10.0x 8.0x 6.0x 4.0x 2.0x 3.7x 8.7x 9.1x 10.6x 7.0x 5.2x 4.7x 0.0x (1) (2) (3) 2007 2008 2009 2010 2011 2012 2013E 0.0x 2007 2008 2009 2010 2011 2012 2013E (FDC + Debt) / Proved Reserves ($ / Boe) Debt / PD Reserves ($ / Boe) $15.00 $12.00 $9.00 $6.00 $6.64 $10.25 $11.81 $10.67 $9.45 $9.12 $6.86 $15.00 $12.00 $9.00 $6.00 $4.46 $10.01 $9.43 $8.04 $9.93 $8.90 $8.78 $3.00 $3.00 $0.00 2007 2008 2009 2010 2011 2012 2013E $0.00 2007 2008 2009 2010 2011 2012 2013E 29 Note: Proved reserves as of 12/31/11 based on reserve report prepared by D&M. Production represents 2011 average daily net production. Pro forma for exchange of Appalachian assets. 2013E excludes pending Range Permian acquisition. (1) Excludes acquired debt of Encore as transaction closed on 12/31/2010 with no associated EBITDA impact (2) Pro forma for January 2012 equity offering and exchange of Appalachian assets (3) Excludes debt and adjusted EBITDA associated with the Barrett acquisition
Significant Growth in 2012 Proved Reserves (MMBoe) PV-10 ($ billions) 200 150 152 2.0 1.5 1.4 1.6 100 73 1.0 50 0.5 0 0.0 (1) 2011 2012 2011(1) 2012 Adjusted EBITDA ($ millions) Production (MBoe/d) 250.0 230.5 20.0 18.3 200.0 150.0 100.0 164.6 15.0 10.0 13.4 50.0 5.0 0.0 2011 2012 0.0 2011 2012 30 Note: PV-10 includes SEC pricing as of 12/31/11 and 12/31/12, respectively. Does not take into account the value of the hedge portfolio. (1) Pro forma for the Appalachia exchange.
Peer Benchmarking Operational / Asset Metrics Proved Reserves (MMBoe) % Proved Developed 350 1,074 367 100% 90% 300 250 200 253 192 182 80 60 80% 76% 74% 72% 69% 62% 49% 44% 150 152 151 149 143 121 40 38% 34% 32% 100 50 83 58 20 0 LINE SD LPI SFY FST VNR EVEP BBEP OAS CRZO LGCY AMH 0 LGCY BBEP EVEP VNR AMH FST LINE OAS SD CRZO SFY LPI PD R/P Ratio (years) (1) % Liquids (Proved Reserves) 16 12 14 14 13 11 11 100% 80 89% 68% 64% 8 8 8 7 7 7 5 5 60 40 53% 48% 46% 41% 41% 40% 38% 38% 33% 4 20 0 BBEP VNR LGCY EVEP LINE FST AMH SD OAS LPI SFY CRZ 31 Source: Company filings. Note: Pro forma for closed M&A activity. Data as of 3/12/13. (1) Based on current production 0 OAS LGCY LPI BBEP SFY SD LINE CRZO VNR FST AMH EVEP
Peer Benchmarking Leverage Metrics Asset Coverage (PV-10 / Debt) (1) 3.0x 2.0x 2.0x 2.0x 1.9x 1.8x 1.8x 1.8x 1.6x 1.5x 1.5x 1.4x 1.0x 1.0x 0.8x 0.0x SFY AMH OAS LGCY SD BBEP VNR LPI CRZO FST EVEP LINE (FDC + Debt) / Proved Reserves ($ / Boe) Debt / PD Reserves ($ / Boe) $25.00 $19.64 $18.77 $18.38 $20.00 $16.60 $16.20 $15.43 $13.98 $15.00 $13.72 $12.24 $12.08 $10.50 $10.00 $9.12 $25.00 $20.00 $15.00 $10.00 $20.78 $19.82 $17.13 $14.93 $13.95$12.98 $12.29 $11.58$10.34 $9.19 $8.90 $7.48 $5.00 $5.00 $0.00 $0.00 SD EVEP OAS FST CRZO SFY AMH LPI BBEPLGCY LINE VNR CRZO SD OAS LPI SFY AMH FST LINELGCYBBEPVNREVEP 32 Source: Company filings. Note: Pro forma for capital markets and closed M&A activity including VNR February 2013 equity offering. Data as of 3/12/13. (1) Based on standardized measure
Total PV-10 Value ($mm) Total PV-10 Value ($mm) Robust Asset Coverage PV-10 Value and Commodity Hedges NYMEX Strip Case (1)(2) Total Debt as adjusted for Equity Offering (3) VNR PV-10 Asset Value ($mm) PDP Value $1,600 PDNP Value 50 PD Value $1,650 PUD Value 216 Total Proved Value $1,866 Hedge Value 84 Proved + Hedge Value $1,950 $2,500 $2,000 $1,500 $1,000 $500 $0 $1,600 $1,650 $50 $1,866 $1,950 $216 $84 $50 $216 $50 $1,600 $1,600 $1,600 $1,600 PDP Value PD Value Proved Value Proved Value + Hedges PDP Value PDNP Value PUD Value Hedge Value Asset Value / Debt (3) 1.6x 1.7x 1.9x 2.0x PV-10 Value and Commodity Hedges $70.00 / Bbl and $2.00 / MMBtu Case (1) VNR PV-10 Asset Value ($mm) PDP Value $886 PDNP Value 25 PD Value $911 PUD Value 56 Total Proved Value $967 Hedge Value 470 Proved + Hedge Value $1,437 $2,500 $2,000 $1,800 $1,500 $1,350 $1,000 $900 $500 $450 $0 $0 Total Debt as adjusted for Equity Offering (3) $1,866 $1,950 $1,650 $1,600 $50 $216 $84 $1,437 $967 $216 $50 $50 $886 $911 $470 $56 $25 $25 $56 $1,600 $1,600 $1,600 $1,600 $25 $886 $886 $886 $886 PDP Value PD PD Value Proved Value Proved Value + + Hedges PDP Value PDNP Value PUD Value Hedge Value Asset Value / Debt (3) 0.9x 0.9x 1.0x 1.4x 33 (1) Represents value of current hedge portfolio as of 2/25/2013. (2) NYMEX Strip as of 3/8/2013. 2013: $92.93/bbl and $3.68/MMBtu; 2014: $90.17/bbl and $4.14/MMBtu; 2015: $87.22/Bbl and $4.31/MMBtu; 2016: $85.30/Bbl and $4.46/MMBtu; 2017 and thereafter: $84.23/Bbl and $4.64/MMBtu. (3) As adjusted debt reflects $246 million February equity offering.
Key Investor Considerations Diversified and Balanced Portfolio of High Quality, Liquids Focused Assets Long Lived, Predictable Properties with Low Decline Rates Disciplined Acquisition Strategy Active Hedging Program, which Locks in Margins and Mitigates Commodity Risk Strong Asset Coverage with Minimal Reliance on Higher-Risk Development Well Capitalized Balance Sheet with Sufficient Liquidity Active Management Team with Extensive Industry Experience 34