Management Presentation January 2017 Confidential – Prepared in connection with settlement discussions Subject to FRE 408 and similar provisions
36 32 87 89 89 89 83 141 213 168 177 182 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 January 7, 2017. Forward Looking Statements 2
36 32 87 89 89 89 83 141 213 168 177 182 Company Overview Asset and Operations Overview Northern Division Overview Pinedale Overview & Upside Piceance Overview & Upside East Central Division Overview Arkoma Woodford Overview & Upside Southern Division Overview East Haynesville Field Overview & Upside Red Lake Overview & Upside Business Plan Overview 4 10 18 20 24 29 34 37 46 52 56 Agenda 3
36 32 87 89 89 89 83 141 213 168 177 182 Company Overview 4
36 32 87 89 89 89 83 141 213 168 177 182 Name Title Prior Affiliations Years of Experience Scott W. Smith President and CEO • Ensource Energy • The Wiser Oil Company • San Juan Partners >34 Richard A. Robert EVP and CFO • Enbridge USA • Midcoast Energy Resources • Various energy-related entrepreneurial ventures >27 Britt Pence EVP, Operations • Anadarko Petroleum • Greenhill Petroleum • Mobil >30 Mark Carnes Vice President – Acquisitions & Divestitures • Synergy Oil & Gas • Petromark • Torch Energy Advisors >37 Ryan Midgett Vice President – Finance and Treasurer • Linn Energy >10 Chris Raper Land Manager • Synergy Oil & Gas • Amoco Production >35 Rod Banks Marketing Manager • Apache Corporation • Mariner Energy • Producers Energy Marketing >34 Management Team 5
36 32 87 89 89 89 83 141 213 168 177 182 Company Highlights Low-Cost Operator Diversified, Low-Decline Reserve Base Experienced Management Team Significant Gas Option Value 4.3 Tcfe of proved(1) reserves: 78% Gas, 33% PD, 28 year R/P Reserves and production diversified across 10 basins spanning Rockies, Mid-Continent, West Texas and Gulf Coast $1.43 billion PDP PV-10 at Strip price deck(2) ~10% projected base annual production decline across portfolio Best-in-class corporate 3Q 2016 G&A of $0.29/Mcfe (peer group(3) average of $0.59/Mcfe) Best-in-class 3Q 2016 LOE of $1.01/Mcfe (peer group(3) average of $1.90/Mcfe) Excluding LRE and EROC mergers, the Company has reduced operated LOE by ~33% in 3Q 2016 vs. 4Q 2014 2.8 Tcfe of low-risk proved(1) drilling opportunities, primarily in Pinedale, Piceance and Arkoma Woodford PUDs contribute approximately $605 million(1) of PV-10 value at Strip price deck(2) Pinedale and Piceance drilling opportunities both average 28% RORs, at Strip price deck Arkoma Pittsburg & Cole County Woodford locations generate 24% ROR and 45% ROR, respectively, at Strip At a $0.50 premium to gas strip, PUDs contribute $880 million of PV-10 Senior executive team averages 30 years of experience in the oil and gas industry Team has successfully navigated challenging low-price environments in past cycles Long track record of successful acquisitions and extracting value from mature assets 6 (1) Proved reserves include 1.7 Tcfe of technical PUDs, which are wells that would qualify for proved status but are drilled outside the five year window . (“Technical PUDs” represent $197 million of PV-10 value at Strip) (2) Strip as of 12/9/16 (Oil – 2017: $54.19, 2018: $54.94, 2019: $54.88, 2020: $55.22, 2021: $55.76, 2022+: $56.44; Natural Gas – 2017: $3.52, 2018: $3.08, 2019: $2.89, 2020: $2.90, 2021: $2.94, 2022+: $2.99) (3) Peer group: ARP, BBEP, EVEP, LGCY, LINE, MCEP, MEMP 9
36 32 87 89 89 89 83 141 213 168 177 182 Asset Profile(1) 7 Upstream oil & gas LLC, headquartered in Houston, TX Initial public offering – “VNR” – in October 2007 had a total Enterprise Value of approximately $240 million In February 2016, VNR issued ~$75.6 million of new 7.0% Senior Secured Lien Notes due 2023 to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for ~$168.2 million of the Senior Notes due 2020 In 2013, VNR was the first master limited partnership to issue publicly traded preferred units with its initial 7.875% Series A Cumulative Redeemable Perpetual Preferred Units In total, VNR has raised net proceeds of more than $328 million from three preferred equity offerings Company Overview Company Profile 25 Strategic Acquisitions Totaling ~$5.0 BN ~4.3 Tcfe (~719 MMBoe) Proved Reserves(1)(2) 33% Proved Developed(1) 78% Natural Gas and 22% Liquids(1) 2014 Production: 327 MMcfed 2015 Production: 415 MMcfed Q3 2016 Production: 424 MMcfed(3) Market Valuation (1) Based on proved reserves as of 1/1/2017 from management reserve report; Pro forma for SCOOP/STACK divestiture (2) Includes 1.7 Tcfe of Technical PUDs which represent $197 million of PV-10 at Strip (3) Q2 2016 production pro forma for SCOOP/STACK divestiture (4) Market data as of 1/6/17 and includes 420,000 Class B units; Based on VNR closing price of $0.76 Company Profile(4) ($ in millions) Common Units 131.4 MM Preferred Units 13.9 MM Current Equity Market Capitalization (w/ Preferred at Market Value) $137 Total Debt $1,779 Enterprise Value (w/ Preferred at Face Value) $2,189
36 32 87 89 89 89 83 141 213 168 177 182 Current Capital Structure Current Capital Structure 1 8 Note: Strip as of 12/9/16 (1) As of 1/6/17 (2) Applicable margin range from L+150-250, based on utilization; commitment fee range from 0.375%-0.500%, based on utilization (3) Preferred units shown at face value. Does not reflect accruals since distributions have been suspended (4) Market value of equity is calculated by multiplying the share price of $0.76 on 1/6/17 by current shares outstanding of 131.4 million (5) PV-10 calculations include $63.5 million of COPAS value; Effective date as of 1/1/17; Pro forma for SCOOP / STACK divestiture 9/30/16 Cash Multiple of LTV of Face Coupon Interest Maturity 2017E EBITDA 1P PV-10 at Strip Cash and Cash Equivalents (1) $25 First Lien Debt RBL Facility (1)(2) $1,250 L + 250 $44 Apr-18 Lease Financing Obligations(1) 20 4.160% 1 Aug-20 Total First Lien Debt $1,270 $45 4.2x 60% Net First Lien Debt $1,245 4.1x 59% Other Secured Debt 7.000% 2L Notes due 2023 $76 7.000% $5 Feb-23 Total Secured Debt $1,346 $50 4.5x 63% Net Secured Debt $1,321 4.4x 62% Other Debt: 8.375% Senior Notes due 2019 $51 8.375% $4 Jun-19 7.875% Senior Notes due 2020 382 7.875% 30 Apr-20 Unsecured Notes $433 $34 Total Debt $1,779 $84 5.9x 84% Total Net Debt $1,753 5.8x 83% Preferred Units & Equity: 7.875% Preferred Units (Series A) (3) $62 7.875% $ - 7.625% Preferred Units (Series B) (3) 169 7.625% - 7.750% Preferred Units (Series C) (3) 104 7.750% - Preferred Equity $335 $ - 7.0x 100% Market Value of Equity (4) 100 - Total Enterprise Value $2,189 $84 7.3x 103% Memo: 2017E Adj. EBITDA $301 1P PV-10 at Strip (5) 2,124 Liquidity RBL Facility Borrowing Base $1,100 Less: Amount Outstanding (1,250) Less: Letters of Credit - Revolver Deficiency ($150) Revolver Availability $ - Plus: Cash and Equivalents 25 Total Liquidity $25
36 32 87 89 89 89 83 141 213 168 177 182 Significant Operating Cost Reductions Achieved Over Last 6 Quarters 9 (1) Excludes LRE and EROC Reduction in Vanguard Operated LOE(1) LOE decreased by $18.4 MM (18%) in 2015 $23.0 $19.5 $18.5 $19.6 $18.6 $16.3 $15.7 $16.5 $1.4 $0.5 $1.1 $1.5 $1.1 $1.2 $0.3 $0.6 $1.4 $0.4 $0.8 $1.8 $1.1 $0.7 $0.6 $0.2 $-- $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 4Q 2014 1Q 2015 2Q 2015 3Q 2015 4Q 2015 1Q 2016 2Q 2016 3Q 2016 LOE ( $M M) Lease Operating Expense Workover Facility AFE'D Expenses 33% LOE Reduction 2015 Average: $21.2 MM / quarter
36 32 87 89 89 89 83 141 213 168 177 182 Asset and Operations Overview 10
36 32 87 89 89 89 83 141 213 168 177 182 Geographically Diversified Reserve Base Core Operating Areas (1) Overview Proved Reserves By Area (1) 11 Green River Basin Proved Reserves: 1 Tcfe 87% Natural Gas 35% Proved Developed 129 MMcfed Net Production Piceance Basin Proved Reserves: 854 Bcfe 66% Natural Gas 39% Proved Developed 78 MMcfed Net Production Wind River Basin Proved Reserves: 25 Bcfe 92% Natural Gas 100% Proved Developed 9 MMcfed Net Production Williston Basin Proved Reserves: 5 MMBoe 94% Liquids 98% Proved Developed 1 MBoed Net Production Powder River Basin Proved Reserves: 16 Bcfe 100% Natural Gas 100% Proved Developed 16 MMcfed Net Production Big Horn Basin Proved Reserves: 15 MMBoe 93% Liquids 98% Proved Developed 3 MBoed Net Production Anadarko Basin Proved Reserves: 28 Bcfe 74% Natural Gas 81% Proved Developed 9 MMcfed Net Production Arkoma Basin Proved Reserves: 1.6 Tcfe 94% Natural Gas 9% Proved Developed 46MMcfed Net Production Permian Basin Proved Reserves: 42 MMBoe 63% Liquids 63% Proved Developed 9 MBoed Net Production Gulf Coast Basin Proved Reserves: 185 Bcfe 42% Natural Gas 46% Proved Developed 40 MMcfed Net Production – Primarily Natural Gas – VNR Major Operated Field – Primarily Oil – VNR Major Non-Operated Field Proved Reserves: ~4.3 Tcfe (~719 MMBoe) (1) 78% Natural Gas and 22% Liquids(1) 33% Proved Developed(1) R/P of 28 years(1) Note: Proved reserves based on management reserve report. Production based on Q3 2016 average daily net production. Pro forma for SCOOP/STACK divestiture (1) Includes 1.7 Tcfe of Technical PUDs Large difference between original and updated gulf coast numbers 17 39% 25% 21% 6% 5% 2%1% Arkoma Green River Piceance Permian Gulf Coast Big Horn Williston Anadarko Wind River Powder River
36 32 87 89 89 89 83 141 213 168 177 182 Low-Risk Proved Reserve Base with Significant PDP Component Note: PV-10 calculations include $63.5 million of COPAS value; Assumes Strip pricing as of 12/9/16, effective date as of 1/1/17; Pro forma for SCOOP / STACK divestiture 12 18 1/1/17 Management Reserve Database Reserves By Commodity Reserves By Category PV-10 By Category Net Cases Oil (MMBbl) Gas (Bcf) NGL (MMBbl) Total Volumes (Bcfe) % Gas PV-9 ($MM) PV-10 ($MM) PV-12 ($MM) PV-15 ($MM) PDP 8,273 45 944 38 1,441 66% 1,498 1,428 1,307 1,163 PDNP 320 4 43 2 78 55% 98 92 81 67 PUD 1,696 11 941 22 1,142 82% 458 408 324 228 Technical PUDs 1,215 4 1,436 32 1,654 87% 238 197 136 79 Total 1P 11,504 64 3,364 94 4,316 78% $2,292 $2,124 $1,847 $1,537 PROB 170 4 25 2 64 39% 21 18 12 7 POSS 38 1 2 0 8 26% 5 4 3 2 Total 3P 11,712 69 3,391 97 4,388 77% $2,319 $2,146 $1,862 $1,545 Oil 10% Natural Gas 77% NGL 13% PDP 33% PDNP 2% PUD 26% Technical PUDs 38% PROB 1% POSS 0% PDP 67% PDNP 4% PUD 19% Technical PUDs 9% PROB 2% POSS 0%
36 32 87 89 89 89 83 141 213 168 177 182 Updated to December Management Presentation database Reserve category changed to update for current status Removed future LOE savings Adjusted CAPEX Start date adjustments Addition of 133 (97BUD) cases representing 2017 budgeted maintenance capital projects Updated 2017/2018 development plan locations to tie to current budget plan Database Updates 2 13 2017 2018 2019 2020 2021 Thereafter WTI $54.19 $54.94 $54.88 $55.22 $55.76 $56.44 HHUB $3.52 $3.08 $2.89 $2.90 $2.94 $2.99 Strip as of 12/9/2016 (1) Reflects $54.0 million of hedge monetizations (hedge contracts sold consisted of contracts expiring after December 31, 2016) (2) Strip as of 12/9/16 (Oil – 2016: $43.26, 2017: $54.19, 2018: $54.94, 2019: $54.88, 2020: $55.22; Natural Gas – 2016: $2.46, 2017: $3.52, 2018: $3.08, 2019: $2.89, 2020: $2.90) (3) Only includes cash G&A
36 32 87 89 89 89 83 141 213 168 177 182 Meaningful Inventory of Low-Risk Drilling Opportunities Shifted to PUDs 1/1/17 Updated Reserve Database Proved Reserve Bridge 6/30/16 Management Reserve Database 14 19 Pre-Tax PV-10 Reserve Oil Gas NGL Total Strip Pricing Category (MMBbl) (Bcfe) (MMBbl) (Bcfe) ($MM) PDP 50 935 37 1,457 $1,422 PDNP 4 40 2 71 67 PUD 12 1,029 23 1,242 435 Technical PUDs 3 1,454 30 1,650 107 Total 69 3,458 91 4,420 $2,031 4,420 4,316 (73) (49) 18 -- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 6/30/16 Reserve Database PDP Production Price-Related Adjustment Other Adjustments Updated 12/31/16 Reserve Database Res erv es (Bc fe) Pre-Tax PV-10 Reserve Oil Gas NGL Total Strip Pricing Category (MMBbl) (Bcfe) (MMBbl) (Bcfe) ($MM) PDP 45 944 38 , 41 1,428 PDNP 4 43 2 78 92 PUD 11 941 22 1,142 408 Technical PUDs 4 1,436 32 1,654 197 Total 64 3,364 94 4,316 $2,124
36 32 87 89 89 89 83 141 213 168 177 182 -- 5.0 10.0 15.0 20.0 25.0 30.0 35.0 40.0 45.0 Produc tion (Bc fe) Pinedale Piceance Arkoma Permian Gulf Coast East Central Gulf Coast Big Horn Williston Powder River Green River Anadarko Wind River 10.3% Average Annual Decline Through 12/31/20 Low-Decline Base Production Average Annual Decline ~10% Annual Projected Base Decline by Area(2) Projected Quarterly Base PDP Decline(1) (1) Q3 2016 reflects actuals (2) Compound annual decline from 12/31/16 to 12/31/20 15 5.8% 7.4% 7.7% 7.7% 8.0% 8.7% 9.1% 9.1% 9.5% 9.9% 13.6% 26.1% 0% 10% 20% 30% Big Horn Green River Anadarko Williston Arkoma Piceance Gulf Coast Permian Gulf Coast East Central Wind River Pinedale Powder River Base D ecline (%) (Excl. Pinedale)
36 32 87 89 89 89 83 141 213 168 177 182 Significant Inventory of High-Quality, Organic Growth Opportunities Note: Locations and reserves come from management database at 12/9/2016 Strip prices. (1) Q3 2016 Average Daily Net Production (2) Not included in reserve report – Primarily Natural Gas – Primarily Oil 16 Vanguard Natural Resources, LLC 424 Net MMcfed(1) 10,500+ PDP Wells ~4,000 Locations 2.9 Tcfe Net Upside Potential Pinedale (Vertical & Horizontal) 114 Net MMcfed(1) ~2,600 PDP Wells (Non-Operated) ~1,500 Vertical Locations (Average WI: 12.4%) 0.7 Tcfe Net Upside Potential Horizontal drilling is not currently built into development plan Mamm Creek (Piceance) 78 Net MMcfed(1) ~1,100 PDP Wells 416 Locations (Average WI: 92%) 0.5 Tcfe Net Upside Potential Elk Basin (Water Flood) 3 Net MBoed(1) 277 PDP Wells 20 MMBoe Net Upside Potential(2) 2016 Water Flood Pilot(2) Red Lake (Yeso & Tubb) 3 Net MBoed(1) 275 PDP Wells 63 Locations (Average WI: 87%) 3.8 MMBoe Net Upside Potential Arkoma Woodford 16 Net MMcfed(1) 140 PDP Wells (Operated) 1,508 Locations (Average WI: 33%) 1.5 Tcfe Net Upside Potential New Completion Design (SCOOP) East Haynesville (Conventional) 4 Net MMcfed(1) 56 PDP Wells (Operated) 40 Locations (Average WI: 93%) 76 Bcfe Net Upside Potential New 3D - High Reward Potential 22
36 32 87 89 89 89 83 141 213 168 177 182 Majority of PUD PV-10 Comprised of Low-Risk Opportunities in Proven Gas Resource Plays Key Field PV-10 ($MM) Proved PV-10 Breakdown at Strip 17 26 (1) (1) Other consists of Anadarko, Big Horn, Green River, Gulf Coast, Permian, Powder River, Williston, and Wind River (2) Includes Technical PUDs (2) 20% 19% 13% 48% Pinedale Piceance Woodford Other Total 3P PV-10: $2,146 MM $244 $270 $74 $931 $190 $132 $199 $84 $22 $-- $200 $400 $600 $800 $1,000 $1,200 $1,400 Pinedale Piceance Woodford All Other PDP/PDNP PUD PROB/POSS
36 32 87 89 89 89 83 141 213 168 177 182 Northern Division Overview 18
36 32 87 89 89 89 83 141 213 168 177 182 Northern Division Overview – Primarily Natural Gas – Primarily Oil Production By Area Production By Area 6% 4% 49% 31% 7% 3% Big Horn Wind River Green River Piceance Powder River Williston 19 (1) Q3 2016 Average Daily Net Production Piceance Basin Daily Net Production: 78 MMcfed(1) 923 PDP Wells (Operated) Average WI: 95% 66% Natural Gas Wind River Basin Daily Net Production: 9 MMcfed(1) 148 PDP Wells (Operated) Average WI: 93% 92% Natural Gas Williston Basin Daily Net Production: 1 MBoed(1) 57 PDP Wells (Operated) Average WI: 36% 94% Liquids Powder River Basin Daily Net Production: 16 MMcfed(1) 471 PDP Wells (Operated) Average WI: 61% 100% Natural Gas Big Horn Basin Daily Net Production: 3 Mboed(1) (without gas reinjection) 277 PDP Wells (Operated) Average WI: 70% 93% Liquids Green River Basin Daily Net Production: 129 MMcfed(1) 183 PDP Wells (Operated) Average WI: 13% 87% Natural Gas
36 32 87 89 89 89 83 141 213 168 177 182 Pinedale Overview & Upside 20
36 32 87 89 89 89 83 141 213 168 177 182 Pinedale Field Overview 3rd largest U.S. onshore field (U.S. EIA, 2010) Giant anticlinal fold with >1,000’ Closure 7,000’ thick section Lance and Mesaverde Reservoirs Stacked Fluvial-Deltaic low-perm sands (20 microdarcy) High EUR areas due to 1) thickness of enhanced porosity and perm, 2) enhanced natural fractures and 3) overpressure Normal pressure into Upper Lance at 8,700’ MD 0.9 psi/ft overpressure 8,700’ to TD Reservoir is not a single gas column but is rather composed of multiple overlapping compartments separated by imperfect seals Post-2001 technologies created economic success Stewart Point Half Moon Mesa Pole Creek Boulder Riverside Rainbow Stud Horse Butte Warbonnet 59 Tcfe OGIP 38 Tcfe EUR @ 5 Acres 9 Tcfe PDP EUR 29 Tcfe remaining Core: 5+ Bcfe Well EUR Pinedale Field Map Asset Overview 3,000 Producing Wells (Ultra: 60%; QEP: 35%) 21 Depth Avg. Net Pay Avg. Porosity HC Phase Area Area Lance 7,000’- 13,500’ 1,050’ 6% Gas / Cond Anticline 110 sq. mi Mesaverde 13,500’- 14,400’ 200’ 5% Gas / Cond Anticline 110 sq. mi 29 new Legend Structure Contour Active Well
36 32 87 89 89 89 83 141 213 168 177 182 Pinedale Capital Program Capital Spend: $79.7 MM Average WI: 13% Average Lease NRI: 78% Wells: 152 Gross (19 Net) Average D&C: $3.7 MM Gross ($0.48 MM Net) Average EUR/well: 4.3 Bcfe Gross F&D: $0.86/Mcfe Non-Consents: 62 2016 Capital Program Capital Budget: $36-37 MM Average WI: 14% Average Lease NRI: 78% Wells: 114 Gross (14 Net) Type Curve D&C: $2.7 MM Gross ($0.35 MM Net) Average EUR/Well: 4.7 Bcfe Gross F&D: $0.55/Mcfe To date Non-Consents: 25 (operators are drilling in the core areas this year) 2014 Capital Program 2015 Capital Program Capital Spend: $62.6 MM Average WI: 12% Average Lease NRI: 78% Wells: 149 Gross (17 Net) Average D&C: $3.3 MM Gross ($0.40 MM Net) Average EUR/well: 4.5 Bcfe Gross F&D:$0.73/Mcfe Non-Consents: 48 Pinedale Operating Partners Allocating Capital to Pinedale One of the largest operators in the Green River Basin Currently running 1 rig Continuing to enhance well design by increasing sand mesh from 50 to 100 Reduced D&C costs by 14% Gross well AFE drilling and completion costs of $3.0 MM including facilities and plunger lift Remaining locations average 8.8% WI / 7.1% NRI across QEP QEP Resources Ultra Petroleum 22 37 68,000 net acre position in the Pinedale (operates 90% of acreage) Currently running 4 rig program Plans to ramp up to 10 operated rigs by 2018 Average well cost of $2.6 MM down 16% from $3.1 MM in 2Q 2015 Average Spud to TD of ~8.9 days and average rig release to rig release of 10.7 days Remaining locations average 13.3% WI / 10.7% NRI across Ultra
36 32 87 89 89 89 83 141 213 168 177 182 EUR: 4.7 Bcfe (95% Gas) WI / NRI: 12.4% / 9.9% IP30: 3.2 MMcfd Representative well curve decline parameters are initially 51. 5%, decreasing to a minimum of 7% with b values at 1.3 Condensate Yield: 9.5 Bbl/MMcf NGL Yield: 13.7 Bbl/MMcf Shrink: 9% Well Cost: $2.6MM(1) Opex: $3,600/well/month and $0.06/Mcf F&D Cost(2): $0.46/Mcfe Pinedale Engineering Overview Key Highlights Pinedale Rate of Return Sensitivity Note: Price sensitivities run at $55 WTI (1) Reflects Ultra well cost in database (2) Representative of a 4.7 Bcfe well 23 0% 10% 20% 30% 40% 50% $2.00 $2.50 $3.00 $3.50 $4.00 R O R (% ) Gas Price ($/Mcf) 4.7 Bcfe
36 32 87 89 89 89 83 141 213 168 177 182 Piceance Overview & Upside 24
36 32 87 89 89 89 83 141 213 168 177 182 Piceance Basin Overview Piceance Basin Map Asset Overview Initiate single rig drilling program Add to gas lift system where facilities and pipelines are already in place 25 Silt, CO office, VNR acquired 2012 & 2014 (BBC) 40 employees, average oilfield experience 10 years Personnel: 1 superintendent, 1 field engineer, 7 foremen, 19 operators, 5 mechanics, 1 tech, 2 roustabouts, 4 admin and environmental Average (Operated) WI 95%; NRI: 78% 3Q 2016 net production of 78 MMcfed 2016 YTD LOE $0.47/Mcfe 1 Field, 1 zone of interest 930 PDP (Operated), 4 SWD, 1 SI wells 2 Gathering facilities Developed Acreage – 16,112 gross / 10,477 net Total Acreage – 24,040 gross / 16,075 net 38 2017 Plans
36 32 87 89 89 89 83 141 213 168 177 182 Producing Wells: 1,071 (924 operated) Total Undeveloped Locations: 385 (Assumes 10-Acre Spacing) 295 locations have greater than 1.3+ Bcfe EUR 90 remaining additional drilling locations Seismic Control: 3D Avg. Depth(ft) Avg. Net Pay Avg. Porosity HC Phase Trap Area (acre) Mesaverde 5000 800 10% Gas/NGLs Stratigraphic 16,000 26 Mamm Creek (Piceance) Overview Encana Operated VNR Operated Mamm Creek Highlights
36 32 87 89 89 89 83 141 213 168 177 182 100 1,000 10,000 0 12 24 36 48 60 Av era ge Da ily Ga s Months Wells Drilled in 2008 - 2012 Wells Drilled in 2013 - Present Piceance Type Curve - 1.8 Bcfe Piceance Recoveries Have Been Adjusted Upward by 25% to Account for Completion Improvements in the Williams Fork / Mesaverde Reservoir Since Last Development in 2012 Piceance Completion Improvements Time-Normalized Williams Fork Type Curves by Vintage 27 32% Average Increase in Recoveries due to Completion Improvements 45
36 32 87 89 89 89 83 141 213 168 177 182 EUR: 1.4 Bcfe (96% Gas) WI / NRI: 91.8% / 76.4% IP30: 1.2 MMcfd Representative well curve decline parameters are initially 65%, decreasing to a minimum of 7% with b values at 1.6 Condensate Yield: 6.47 Bbl/MMcf NGL Yield: 65.77 Bbl/MMcf Shrink: 12% Average Well Costs: $1.35MM Opex: $836/well/month and $0.19/Mcf F&D Cost(1): $0.71/Mcfe Mamm Creek Engineering Overview Key Highlights Mamm Creek Rate of Return Sensitivity Note: Price sensitivities run at $55 WTI 28 0% 10% 20% 30% 40% 50% $2.00 $2.50 $3.00 $3.50 $4.00 R O R (% ) Gas Price ($/Mcf) 1.4 Bcfe
36 32 87 89 89 89 83 141 213 168 177 182 East Central Division Overview 29
36 32 87 89 89 89 83 141 213 168 177 182 East Central Region Overview East Central Gulf Coast Basin Daily Net Production: 14.MMcfed(1) Number of Operated Wells: 151 206,693 Gross Acres (107,026 Net) Production By Area i Arkoma & Anadarko Basins Daily Net Production: 55 MMcfed(1) Number of Operated Wells: 357 619,749 Gross Acres (241,222 Net) – Primarily Natural Gas – Primarily Oil Production By Area 30 (1) Q3 2016 Average Daily Net Production 80% 20% Arkoma /Anadarko Gulf Coast East Central
36 32 87 89 89 89 83 141 213 168 177 182 Arkoma Overview 2017 Plans Initiate single rig drilling program Arkoma Basin Overview 31 Net Operated Production: 26 MMcfed(1) 4 Operated Districts with +/- 281 Gross Wells Operated District Asset Overviews: District Well Count Production Woodford 141 16 MMcfed(1) Potato Hills 53 6 MMcfed(1) PHGG, LLC Assets Other 87 4 MMcfed(1) (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 Net Operated Production: 2 MMcfed(1) 2 Operated Districts with +/- 75 Operated Wells District Asset Overviews: District Well Count Production Anadarko Other 59 1.7 MMcfed(1) Putnam 16 0.4 MMcfed(1) Anadarko Operated Overview Anadarko Basin Overview 32 2017 Plans Limited maintenance and optimization capital planned (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 Net Operated Production: 14 MMcfed(1) 2 Operated Districts with +/- 36 Gross Well Count District Asset Overviews: District Well Count Production Alabama 27 12 MMcfed(1) BEC Gas Plant Assets Parker Creek 9 230 Bopd(1) East Central Gulf Coast Overview 2017 Plans BEC debottlenecking project Flomaton Pumping Station Unmanning Operation = Reduction in Company Labor Overtime Well Production Recovery in BEC Field = Important Recovery of Critical Wells Gulf Coast EC Overview 33 52 (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 Arkoma Woodford Overview & Upside 34
36 32 87 89 89 89 83 141 213 168 177 182 Depth Avg. Net Pay Avg. Porosity HC Phase Area WDFD SW 6,700’-11,200’ 50’ 13% Gas / Condensate 109 sq. mi WDFD NW 5,500’-10,000’ 95’ 15% Gas / Condensate 392 sq. mi WDFD NE 7,700’-9,700’ 55’ 12% Gas 172 sq. mi Arkoma Woodford Overview 54 Key Highlights Arkoma Overview Map 35 Legend VNR OP VNR NONOP 3D Seismic PDP Reserves PDP as of 1/1/17 with 12/09/2016 Strip pricing Producing Wells: 698 (140 Operated / 558 Non-Operated) Gas: 113 Bcf NGL: 1.8 MMBbl 124 Bcfe Average WI : 24.2% Avg. Lease NRI: 19.5% Undeveloped Locations 1,508 locations (384 Operated / 1,124 Non-Operated) 5.5 Tcfe gross, 1.5 Tcfe net undrilled potential Additional upside: refrac older wells Ability to pick up additional working interest due to forced pooling
36 32 87 89 89 89 83 141 213 168 177 182 --% 20.0% 40.0% 60.0% 80.0% 100.0% 120.0% $2.00 $2.50 $3.00 $3.50 $4.00 RO R ( %) Gas Price ($/Mcf) Pittsburg County Hughes County Atoka County Coal County Arkoma Woodford Returns Arkoma Woodford Operated ROR Sensitivity 64 36 IP-30 Condensate NGL Yield Well Cost Opex Opex F&D Cost Net Well County EUR (Bcfe) % Gas (Mcfd) De b factor Dmin Yield (Bbl/MMcf) (Bbl/MMcf) Shrink ($MM) ($/Mcfe) ($/Month) ($/Mcfe) Avg WI Avg NRI Count Pittsburg 7.4 100% 7,600 68 1.35 6 -- 41.4 2% $4.0 $0.05 $2,700 $0.54 31% 25% 214 Hughes 4.6 5, 74 .50 -- 50.6 6 3.6 . , .78 16 12 86 Atoka 3.1 95% 2,800 67 1. 6 20.0 44.2 8% . 0.05 $2,700 1.16 31% 25% 2 Coal 7.2 100 8,6 71 .30 -- 58.4 9 4.0 . 3,5 0.5 12 10 3 Note: Price sensitivities run at $55 WTI
36 32 87 89 89 89 83 141 213 168 177 182 Southern Division Overview 37
36 32 87 89 89 89 83 141 213 168 177 182 South Region Overview Gulf Coast Basin Daily Net Production: 25 MMcfed(1) Operated Wells: 151 Permian Basin Daily Net Production: 9 Mboed(1) Operated Wells: 1,633 – Primarily Natural Gas – Primarily Oil Production By Area Production By Area 38 (1) Q3 2016 Average Daily Net Production 25% 75% Permian Gulf Coast
36 32 87 89 89 89 83 141 213 168 177 182 Net Operated Production: 8 Mboed(1) Wells: 2,430 Total 1,839 Prod/176 SWI/415 SI Office in Odessa Permian Overview OPERATIONS MAP Personnel 46 Vanguard Employees / 26 Contract 1 Superintendent / 4 Admin 2 Production Engineers (Odessa) 10 Foremen 2 Well Techs 27 Operators / 26 Contract Operators 39 Permian Basin Operations Highlights 2017 Plans Salt Water Disposal Systems Optimization Production Efficiencies and Recompletion Opportunities Marginal Well Optimization Waterflood Conformance Optimization (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 New Mexico North Wells: 625 Prod/10 SWI/25 SI Field office in Riverside New Mexico South Wells: 233 Prod/12 SWI/4 SI Field office in Eunice New Mexico Operated Totals Net Operated Production: 4 Mboed(1) Wells: 909 Total 858 Prod/22 SWI/29 SI Production from 70 Fields / 114 Pools New Mexico Operations Highlights Key Highlights 40 Acreage Map – Primarily Oil (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 North Wells: 159 Prd/36 SWI /75 SI Managed out of Odessa Central West Wells: 154 Prd/42 SWI/134 SI Field office in Monahans Central East Wells: 174 Prd/34 SWI/67 SI Managed out of Odessa West Wells: 54 Prd/3 SWI/23 SI Managed out of Odessa East Wells: 163 Prd/35 SWI/80 SI Office in the field South Wells: 254 Prd/5 SWI/17 SI Field office in Christoval Permian Texas Operations Highlights 41 Permian Texas Operated Totals Net Operated Production: 3 MBoed(1) Wells: 1521 Total 981 Prod/154 SWI/386 SI Production from 65 Fields/110 Pools (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 Glasscock County Glasscock County Acreage Opportunity – Significant Multi-Zone Horizontal Activity and Results in the Area Legend Vanguard 3,500 Net Acres Parsley/BTA Acreage Lower Spraberry Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Flanagan 14 Lloyd A 21H Pioneer IP-30: 885 Boepd (89% Oil) 1 Priddy Fischer 10-4H Pioneer IP-24: 922 Boepd (87% Oil) 2 Abel 1607LS Oxy IP-24: 1,332 Boepd (89% Oil) 3 Zant #4732SH XTO IP-24: 1,287 Boepd (92% Oil) 4 Calverley 9-4 3H RSP Permian IP-30: 780 Boepd (81% Oil) 5 Daniel SN 7-6 4 #504H Energen IP-30: 1,213 Boepd (70% Oil) 6 Woody 4 1H RSP Permian IP-30: 946 Boepd (83% Oil) Short Lateral 8 Clark 1 1201H Encana IP-30: 758 Boepd (83% Oil) 9 Calverly 9-4 #1H RSP Permian IP-30: 1,757 Boepd (83% Oil) 11 Lawson 2703H Encana IP-30: 983 Boepd (76% Oil) 12 Barbee C 1-1 #2RU Laredo IP-30: 675 Boepd (75% Oil) 13 Lane Trust C-E 421HU Laredo IP-30: 1,183 Boepd (76% Oil) 14 Woody 4 2H RSP Permian IP-30: 1,027 Boepd (83% Oil) Short Lateral 15 Shackelton 31 W 3H Apache Ip-30: 1,886 Boepd (83% Oil) 16 Calverly 2H RSP Permian IP-30: 1,877 Boepd (83% Oil) 17 Riley C 1807WB Diamondback IP-30: 1,025 Boepd (83% Oil) 18 McDaniel 2413 1H CrownQuest IP-30: 664 Boepd (86% Oil) 19 Cook Books 5409-2409 H Encana IP-30: 639 Boepd (72% Oil) 20 Abel 1640CL Unit Oxy IP-24: 783 Boepd (93% Oil) 21 Cole Ranch 35 #307H Energen IP-30: 1,065 Boepd (82% Oil) 22 Brazos SN 17-8 #304H Energen IP-30: 664 Boepd (67% Oil) 23 Lacy Creek 22-27 Alloc B Laredo IP-24: 1,934 Boepd (57% Oil) 24 Lazy E #1402H Laredo IP-24: 1,175 Boepd (63% Oil) 25 Powell Ranch 151HC Oxy IP-24: 777 Boepd (85% Oil) Short Lateral 27 Calverley 5-44 6NC Laredo IP-30: 976 Boepd (69% Oil) 28 Houston Ranch 12 Fowler A 1H Pioneer IP-24: 1,755 Boepd (74% Oil) 26 70 3 42 Parsley/BTA Transaction TV: $400 million Net acres: 9,140 Production: 270 Boed TV/Adj Net Acres (1) : $42,730/acre (1) Assumes $35,000 per Boed Dwight Gooden 6-7-01AH Parsley IP-30: 1,161 Boepd (82% Oil) 7 Riley B 1807WA Diamondback IP-30: 1,309 Boepd (85% Oil) 10 7
36 32 87 89 89 89 83 141 213 168 177 182 Net Operated Production: 10 MMcfed(1) Wells: 373 287 Prod/10 SWI/76 SI 15 Fields in 11 Pools Office in Poynor, Texas Gulf Coast Overview Personnel Production Efficiencies and Recompletion Opportunities Marginal Well Optimization 43 Gulf Coast Basin Operations Highlights 2017 Plans 25 Vanguard Employees/10 Contract 1 Superintendent / 2 Admin 3 Foremen 11 Plant Operators / 3 Contract Relief 8 Operators / 7 Contract Operators (1) Q3 2016 Average Daily Net Production
36 32 87 89 89 89 83 141 213 168 177 182 East Haynesville Wells: 48 Prod/20 SI Managed out of Poynor Field office in Haynesville Fairway Wells: 179 Prod/10 SWI/23 SI Managed out of Poynor Fairway gas plant is <50% utilized with 40 MMcfd of 89 MMcfd capacity Eustace Area Wells: 29 Prod/19 SI Managed out of Poynor East TX / North LA Operations Highlights 44
36 32 87 89 89 89 83 141 213 168 177 182 New Year’s Ridge Wells: 15 Prod/6 SI Managed out of Poynor George West Wells: 10 Prod/2 SI Managed out of Poynor Stratton Wells: 6 Prod/6 SI Managed out of Poynor South Texas Operations Highlights 45
36 32 87 89 89 89 83 141 213 168 177 182 East Haynesville Field Overview & Upside 46
36 32 87 89 89 89 83 141 213 168 177 182 Depth Avg. Net Pay Avg. Porosity HC Phase Trap Area Haynesville 9,000’ SSTVD 100’ 10% Gas/Cond. Structural/Stratigraphic 9,700 acres Smackover 9,500’ SSTVD 25’ 15% Oil/Gas Structural/Stratigraphic 1,850 acres East Haynesville Field Overview Key Highlights Discovered in 1945 in Gloyd and Kilpatrick zones (4,100’ SSTVD) First Smackover zone (9,500 SSTVD) wells in 1946 Taylor sand (8,300’ SSTVD) developed in 1960 Haynesville Sand (9,000’ SSTVD0) development in 1985 28 Development Locations Development Strategy – Infill drilling Exploratory Potential – Untested Smackover fault blocks Seismic Control – 37 sq.m. PSTM 3D (2015) 47
36 32 87 89 89 89 83 141 213 168 177 182 EUR: 1.7 Bcf, 86 MBbl IP: 2.0 MMcfd, 150 Bopd B factor: 1.2(gas), 1 (oil) De Gas: 68% De Oil: 75% Dmin: 6% 48 Haynesville Sand Type Curve
36 32 87 89 89 89 83 141 213 168 177 182 Haynesville Sand Economics Haynesville Sand Rate of Return Sensitivity Key Highlights Undeveloped Locations: 28 Average WI: 93% Average Lease NRI: 78% 52.9 Bcfe Net Undeveloped Economics: EUR: 1.7 Bcf, 86 MBbl Well Cost: $1.75 MM 82 49 0% 20% 40% 60% 80% 100% 120% $2.00 $2.50 $3.00 $3.50 $4.00 R O R (% ) Gas Price ($/Mcf) 2.2 Bcfe Note: Price sensitivities run at $55 WTI
36 32 87 89 89 89 83 141 213 168 177 182 EUR: 1.1 Bcf, 70 MBbls IP: 590 Mcfd, 50 Bopd B factor: 1.1 (oil),1.3(gas) De Oil: 47% De Gas: 43% Dmin: 6% Smackover Type Curve Smackover Type Curve 50
36 32 87 89 89 89 83 141 213 168 177 182 Smackover Economics (1) $3.00/Mcf gas price held flat for life 84 Smackover Rate of Return Sensitivity Key Highlights Undeveloped Locations: 12 Average WI: 91% Average Lease NRI: 76% 12.7 Bcfe Net Undeveloped Economics: EUR: 1.1 Bcf, 70 MBbl Well cost: $1.5 MM 51 0% 10% 20% 30% 40% 50% $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 $70.00 R O R (% ) Oil Price ($/Bblf) 1.5 Bcfe
36 32 87 89 89 89 83 141 213 168 177 182 Red Lake Overview & Upside 52
36 32 87 89 89 89 83 141 213 168 177 182 Infill Drilling San Andres, Yeso and Tubb Dolomitized Reservoirs Primarily deepening into Yeso and Tubb Vertical multi-stage fracs & commingled pay zones Red Lake/Artesia Red Lake Field – Permian Basin Key Highlights 53
36 32 87 89 89 89 83 141 213 168 177 182 EUR: 40 MBbls B factor: 1.25 IP: 90 Bopd De: 82% Dmin: 6% Red Lake Type Curve 54 Type Curve Developed from PDP Wells
36 32 87 89 89 89 83 141 213 168 177 182 Red Lake Economics (1) $3.00/ Mcf Gas price held flat for life Undeveloped Locations: 45 Average WI: 90% Average Lease NRI: 77% NGL Yield: 124 Bbl/MMcf 2.1 MMBoe Net Undeveloped Economics: EUR: 40 MBbl and 125 MMcf Well Cost: $0.8 MM 0% 5% 10% 15% 20% 25% 30% 35% $45.00 $50.00 $55.00 $60.00 $65.00 R O R Flat WTI Oil Price ($/MMBtu)(1) 83 55
36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Overview 56
36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Assumptions Management utilized the Pinedale Non-Operated, Piceance Operated and Arkoma type curves in the development of the Business Plan drilling schedule, as summarized below: Pinedale Piceance Arkoma Arkoma Type Curve Formation: Non-Operated Operated Pittsburgh Coal Gross 30-Day IP Rate (MMcfed) 3.2 1.2 7.6 8.6 Gross EUR Summary (Bcfe) 4.7 1.4 7.4 7.2 % Gas 95% 96% 100% 100% Working Interest (%) 12.4% 91.8% 38.2% 18.4% Net Revenue Interest (%) 9.9% 76.4% 30.8% 14.9% D&C Capital Expenditures ($MM) $2.6 $1.35 $4.0 $4.0 Lease Operating Expenses Variable LOE ($/Mcfe) $0.06 $0.19 $0.05 $0.05 Fixed LOE ($/Month) $3,600 $836 $2,700 $3,500 Other Expenses Severance Tax Rate 7.4% 1.4% 7.2% 7.2% Ad Valorem Tax (%) 7.4% 3.7% -- -- Price Differentials Oil - WTI ($ deduct) ($7.47) ($11.70) ($12.53) ($1.66) Natural Gas - HHUB ($ deduct) ($0.46) ($0.10) ($0.63) ($0.89) NGL (% of WTI Oil) -- 26.0% 37.0% 37.0% Type Curve Assumptions Pinedale (Non-Operated) Drilling Piceance (Operated) Drilling Arkoma Drilling 57 Non-Operated Gross Net CapEx Rigs Active Wells ($MM) 2017E 5.2 175 59.3 2018E 11.4 382 118.8 2019E 11.8 396 95.4 2020E 12.8 430 79.4 Operated Gross Net CapEx Rigs Wells ($MM) 2017E 0.8 18 32.7 2018E 1.2 28 61.3 2019E 1.0 25 31.4 2020E 1.0 23 28.0 Operated Gross Wells Net CapEx Rigs Pittsburgh Coal ($MM) 2017E 0.3 -- 3 10.8 2018E 1.1 10 3 37.2 2019E 1.0 12 -- 47.2 2020E 1.0 12 -- 48.3
36 32 87 89 89 89 83 141 213 168 177 182 Summary of Business Plan Strip Price Case Projected Quarterly Daily Production(1) Projected Quarterly Capital Expenditures by Area(1) 58 -- 200.0 400.0 600.0 800.0 (MM cfed ) Base Production Drilling Production - Pinedale Drilling Production - Piceance Drilling Production - Arkoma Drilling Production - Other $-- $25.0 $50.0 $75.0 $100.0 ($ in Millions ) Pinedale Piceance Arkoma Permian Gulf Coast East Central Gulf Coast Big Horn Williston Powder River Green River Anadarko ind River (1) Q3 2016 reflects actuals
36 32 87 89 89 89 83 141 213 168 177 182 Summary of Business Plan (cont’d) Strip Price Case Projected Quarterly EBITDA(1) Projected Quarterly Unlevered Free Cash Flow(1) 59 $-- $30.0 $60.0 $90.0 $120.0 $150.0 ($ in Mill ions ) Unhedged EBITDA Hedging Gains $-- $200.0 $400.0 $600.0 $800.0 $1,000.0 $-- $20.0 $40.0 $60.0 $80.0 $100.0 ($ in Millions)($ in Mill ions ) Unlevered Free Cash Flow Hedging Gains Cumulative Unlevered Free Cash Flow (1) Reflects $54.0 million of hedge monetizations (hedge contracts sold consisted of contracts expiring after December 31, 2016); Q3 2016 reflects actuals
36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Sensitivities Projected Annual EBITDA(1) Projected Annual Unlevered FCF(1) 60 Projected Cumulative Unlevered Free Cash Flow(1) $250 $300 $350 $400 $450 $500 2016 2017 2018 $ i n M illi on s Strip $50 / $3.25 $55 / $3.50 $60 / $3.75 $0 $50 $100 $150 $200 $250 $300 $350 2016 2017 2018 $ i n M illi on s Strip $ 0 / $3.25 $55 / $3.50 $60 / $3.75 $-- $200.0 $400.0 $600.0 $800.0 1,000.0 $1,200.0 ($ in Milli ons) Strip $50 / $3.25 $55 / $3.50 $60 / $3.75 $780 $619 $591 $995 (3) (3) (3) (3) (3) (3) (3) (3) (3) (2) Sources and Uses for pro forma transaction detailed on page 7 (1) Reflects $54.0 million of hedge monetizations (hedge contracts sold consisted of contracts expiring after December 31, 2016) (2) Strip as of 12/9/2016 (3) 2016 assumes Strip pricing in all cases (2) (2)
36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Financial Summary Strip Price Case Business Plan Financial Summary(1)(2) 61 For the Years Ending December 31, 2016E 2017E 2018E 2019E 2020E Commodity Prices Crude Oil ($/Bbl) $43.26 $54.19 $54.94 $54.88 $55.22 Natural Gas ($/MMBtu) 2.46 3.52 3.08 2.89 2.90 Net Production Oil (MMBbl) 4.8 4.2 4.5 4.5 4.3 Gas (Bcf) 109.8 103.9 127.8 147.6 149.5 NGLs (MMBbl) 3.7 3.4 4.1 4.5 4.3 Total Net Production (Bcfe) 160.5 149.8 179.1 201.7 201.3 Daily Production (MMcfed) 438.5 410.3 490.6 552.5 549.9 Net Revenue Oil Revenue $175.7 $195.5 $211.3 $214.1 $205.6 Gas Revenue 178.8 284.4 295.5 316.5 328.9 NGL Revenue 45.1 67.3 77.8 85.3 82.2 Hedging Revenue 241.8 -- -- -- -- Total Net Revenue $641.4 $547.2 $584.6 $615.9 $616.8 Net Expenses Severance Taxes ($19.4) ($31.1) ($32.0) ($32.9) ($32.4) Ad Valorem Taxes (23.8) (28.7) (30.2) (31.2) (31.2) Lease Operating Expenses (157.2) (150.2) (151.1) (154.3) (153.6) General and Administrative Expenses (38.0) (36.4) (35.6) (35.6) (35.6) Adjusted EBITDA $403.0 $300.8 $335.7 $361.9 $364.0 Change in Net Working Capital (85.2) (27.0) (1.7) (3.4) 0.1 Capital Expenditures (63.6) (154.7) (290.0) (226.3) (195.4) Unlevered Free Cash Flow $254.2 $119.1 $44.0 $132.2 $168.7 (1) Reflects $54.0 million of hedge monetizations (hedge contracts sold consisted of contracts expiring after December 31, 2016) (2) Strip as of 12/9/16 (Oil – 2016: $43.26, 2017: $54.19, 2018: $54.94, 2019: $54.88, 2020: $55.22; Natural Gas – 2016: $2.46, 2017: $3.52, 2018: $3.08, 2019: $2.89, 2020: $2.90) (3) Only includes cash G&A (3)