8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): October 7, 2016 (October 7, 2016)

Vanguard Natural Resources, LLC

(Exact name of registrant specified in its charter)

Delaware	001-33756	61-1521161
(State or Other Jurisdiction	(Commission	(IRS Employer
Of Incorporation)	File Number)	Identification No.)

5847 San Felipe, Suite 3000

Houston, TX 77057

(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code: (832) 327-2255

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01. Regulation FD Disclosure.

Vanguard Natural Resources, LLC (the “Company”) is making the disclosure herein of certain material non-public information (the “Management Presentation”), which was provided by the Company to certain third parties (the “Potential Financing Sources”) in connection with confidential discussions that have taken place regarding a potential refinancing and/or recapitalization of the Company’s existing capital structure. The Management Presentation was provided to the Potential Financing Sources, pursuant to the terms of non-disclosure agreements entered into with each of the Potential Financing Sources to support the parties’ due diligence processes. The discussions between the Company and the Potential Financing Sources regarding a potential transaction are ongoing. The Management Presentation is attached as Exhibit 99.1 hereto.

Any financial projections or forecasts included in the Management Presentation were not prepared with a view toward public disclosure or compliance with the published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants regarding projections or forecasts. The projections do not purport to present the Company’s financial condition in accordance with accounting principles generally accepted in the United States. The Company’s independent accountants have not examined, compiled or otherwise applied procedures to the projections and, accordingly, do not express an opinion or any other form of assurance with respect to the projections. The inclusion of the projections therein should not be regarded as an indication that the Company or its affiliates or representatives consider the projections to be a reliable prediction of future events, and the projections should not be relied upon as such. Neither the Company nor any of its affiliates or representatives has made or makes any representation to any person regarding the ultimate outcome of the Company’s potential refinancing or recapitalization compared to the projections, and none of them undertakes any obligation to publicly update the projections to reflect circumstances existing after the date when the projections were made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the projections are shown to be in error.

The information included in this Current Report on Form 8-K under Item 7.01 and Exhibit 99.1 is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to liabilities of that Section 18, unless the registrant specifically states that the information is to be considered “filed” under the Exchange Act or incorporates it by reference into a filing under the Exchange Act or the Securities Act of 1933, as amended.

Cautionary Note Regarding Forward-Looking Statements

This Form 8-K and the related exhibits contain forward-looking statements under the federal securities laws. These statements, including those relating to the intent, beliefs, plans or expectations of the Company are based upon current expectations and are subject to a number of risks, uncertainties and assumptions. It is not possible to predict or identify all such factors and the following list should not be considered a complete statement of all potential risks and uncertainties relating to the potential refinancing and recapitalization of the Company, including, but not limited to (i) the ability of the Company and its subsidiaries to negotiate, develop, confirm and consummate a plan of refinancing or recapitalization; (ii) the potential adverse effects of the potential refinancing or recapitalization on the Company’s liquidity or results of operations; (iii) increased advisory costs to execute the Company’s potential refinancing or recapitalization; (iv) the uncertainty that the potential refinancing or recapitalization will have on the market for the Company’s publicly traded securities; and (v) other risks and uncertainties. These risks and uncertainties could cause actual results to differ materially from those described in the forward-looking statements. For a more detailed discussion of risk factors, please see Part II, Item 1A, “Risk Factors” of the Company’s Quarterly Report on Form 10-Q for the six months ended June 30, 2016, and Part I, Item 1A, “Risk Factors” of the Company’s Annual Report on Form 10-K for the year ended 2015 for more information. The Company assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law.

Item 9.01 Financial Statements and Exhibits.

(d)    Exhibits. The following exhibits are filed as part of this Current Report on Form 8-K:

Exhibit No.	Description
99.1	Management Presentation, dated October 7, 2016.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	VANGUARD NATURAL RESOURCES, LLC
Dated: October 7, 2016	By:		/s/ Richard A. Robert
		Name:		Richard A. Robert
		Title:		Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

EXHIBIT INDEX

Exhibit No.	Description
99.1	Management Presentation, dated October 7, 2016.

EX-99.1

Management Presentation October 7, 2016

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 October 7, 2016. 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 & Upside  Red Lake Overview & Upside  Business Plan Overview 4 13 25 27 34 41 46 51 60 66 70 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  4.4 Tcfe of proved(1) reserves: 78% Gas, 35% PD, 29 year R/P  Reserves and production diversified across 10 basins spanning Rockies, Mid-Continent, West Texas and Gulf Coast  $1.42 billion PDP PV-10 at current Strip price deck(2)  11% projected base annual production decline across portfolio  Best-in-class corporate LTM G&A of $0.36/Mcfe (peer group(3) average of $0.62/Mcfe)  Best-in-class LTM LOE of $0.96/Mcfe (peer group(3) average of $1.95/Mcfe)  Excluding recent LRE and EROC mergers, the Company has reduced operated LOE by ~30% in 1Q 2016 vs. 4Q 2014  The Company foresees further cost reduction through integration of EROC and LRE  Over 2.8 Tcfe of low-risk proved(1) drilling opportunities, primarily in Pinedale, Piceance and Arkoma Woodford  PUDs contribute approximately $542 million(1) of PV-10 value at Strip price deck(2)  Pinedale and Piceance drilling opportunities average 26% and 21% IRRs, respectively, at Strip price deck  Arkoma Pittsburg & Cole County Woodford locations generate 20% ROR at Strip  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 $107 million of PV-10 value at Strip) (2) Strip as of 8/12/16 (Oil – 2016: $45.10, 2017: $49.01, 2018: $51.31, 2019: $52.83, 2020: $54.05; Natural Gas – 2016: $2.76, 2017: $3.04, 2018: $2.95, 2019: $2.95, 2020: $3.03) (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  At-the-Market Program (ATM) allows us to systematically sell equity at a much more cost effective means  In 2014 and 2015, VNR raised net proceeds of approximately $148 million and $36 million, respectively Company Overview Company Profile 25 Strategic Acquisitions Totaling ~$5.0 BN  ~4.4 Tcfe (~737 MMBoe) Proved Reserves(1)(2)  35% Proved Developed(1)  78% Natural Gas and 22% Liquids(1)  2014 Production: 327 MMcfed  2015 Production: 415 MMcfed  Q2 2016 Production: 415 MMcfed(3) Market Valuation Company Profile(4) ($ in millions) Common Units 131.0 MM Preferred Units 13.9 MM Equity Market Capitalization (Including Preferred) $526 Total Debt(5) $1,902 Enterprise Value $2,428 (1) Based on proved reserves as of 6/31/2016 from management reserve report; Pro forma for SCOOP/STACK divestiture (2) Includes 1.7 Tcfe of Technical PUDs which represent $107 million of PV-10 at Strip (3) Q2 2016 production pro forma for SCOOP/STACK divestiture (4) Market data as of 8/12/16 and includes 420,000 Class B units; Based on VNR closing price of $1.36 (5) Debt as of 8/31/16, pro forma for SCOOP/STACK divestiture

36 32 87 89 89 89 83 141 213 168 177 182 Organizational Structure Vanguard Natural Gas LLC VNR Finance Corp. Vanguard Operating, LLC VNR Holdings, LLC Encore Clear Fork Pipeline LLC Eagle Rock Energy Acquisition Co. II, Inc. Eagle Rock Upstream Development Company II, Inc. Eagle Rock Acquisition Partnership II, L.P. Eagle Rock Upstream Development Company, Inc. Eagle Rock Acquisition Partnership, L.P. Escambia Operating Co. LLC Escambia Asset Co. LLC 95% LP 1% GP 4% LP 1% GP 4% LP Eagle Rock Energy Acquisition Co., Inc. 8 (1) Jointly issued by VNR Finance Corp. $381.8 million Unsecured 7.875% Senior Notes Due 2020(1) $75.6 million Unsecured 7.000% Senior Notes Due 2023(1) $51.1 million Unsecured 8.375% Senior Notes Due 2019 $1.325 billion Senior Secured Reserve-Based Credit Facility

36 32 87 89 89 89 83 141 213 168 177 182 Current Capital Structure Current Capital Structure 1 9 Note: Strip as of 8/12/16 (1) As of 8/31/16 (2) Applicable margin range from L+150-250, based on utilization; commitment fee range from 0.375%-0.500%, based on utilization (3) Market value of equity is calculated by multiplying the share price of $1.01 on 9/29/16 by current shares outstanding of 131 million (4) PV-10 calculations include $64.3 million of COPAS value; Effective date as of 8/1/16; Pro forma for SCOOP / STACK divestiture 6/30/16 Cash Multiple of Percentage of Face Coupon Interest Maturity 2016E EBITDA 1P PV-10 at Strip Cash and Cash Equivalents (1) $41 First Lien Debt RBL Facility (1) (2) $1,372 L + 250 $46 Apr-18 Lease Financing Obligations 22 4.160% 1 Aug-20 Total First Lien Debt $1,393 $47 3.6x 69% Net First Lien Debt $1,352 3.5x 67% Other Secured Debt 7.000% 2L Notes due 2023 $76 7.000% $5 Feb-23 Total Secured Debt $1,469 $52 3.8x 72% Net Secured Debt $1,428 3.7x 70% 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 Total Debt $1,902 $86 5.0x 94% Total Net Debt $1,861 4.9x 92% Preferred Units & Equity: 7.875% Preferred Units (Series A) $62 7.875% $ - 7.625% Preferred Units (Series B) 169 7.625% - 7.750% Preferred Units (Series C) 104 7.750% - Market Value of Equity (3) 132 - Total Enterprise Value $2,328 $86 6.1x 115% Memo: 2016E PF Adj. EBITDA $382 1P PV-10 at Strip (4) 2,031 Liquidity RBL Facility Borrowing Base $1,325 Less: Amount Outstanding (1,372) Less: Letters of Credit (3) Revolver Deficiency ($49) Revolver Availability $ - Plus: Cash and Equivalents 41 Total Liquidity $41

36 32 87 89 89 89 83 141 213 168 177 182 Hedges Mitigate Commodity Price Risk Oil Hedges Natural Gas Hedges 39.1% 19.8% 10.5% 7.6% 22.1% 79.3% 19.8% -- 25.0% 50.0% 75.0% 100.0% 2016 2017 Swaps Collars Puts 3-way Collars % Hed ge d Effective Oil Price Effective Natural Gas Price 10 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $2.00 $2.50 $3.00 $3.50 $4.00 2016 2017 Eff ec tiv ePri ce Assumed NYMEX Price $40.00 $50.00 $60.00 $70.00 $80.00 $90.00 $100.00 $110.00 $30.00 $4 .00 $50.00 $60.00 $70.00 $80.00 2016 2017 Eff ec tiv ePri ce Assumed NYMEX Price 65.9% 50.3% 0.4% 11.7% 13.3% 10.0% 87.7% 64.0% -- 25.0% 50.0% 75.0% 100.0% 2016 2017 Swaps Collars 3-way Collars Put Spread % Hed ge d

36 32 87 89 89 89 83 141 213 168 177 182 Significant Operating Cost Reductions Achieved Over Last 6 Quarters 11 (1) Excludes LRE and EROC Reduction in Vanguard Operated LOE(1) LOE decreased by $18.4 MM (18%) in 2015 $23.0 $19.4 $18.5 $19.6 $18.5 $16.3 $15.2 $1.4 $0.5 $1.1 $1.5 $1.1 $1.2 $0.3 $1.4 $0.4 $0.8 $1.8 $1.6 $0.7 $0.4 $-- $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 LOE ( $M M) Lease Operating Expense Workover Facility AFE'D Expenses 38% LOE Reduction 2015 Average $21.2 MM / quarter

36 32 87 89 89 89 83 141 213 168 177 182 Key Highlights And Near-Term Strategy Opportunistic Hedging Live Within Cash Flows Continue to Make Accretive Acquisitions Reduce Leverage  Focused on achieving adequate rates of return on our development capital program; remain flexible and reallocate capital as appropriate  2015-2016 budgets designed to generate excess cash flow  Take advantage of opportunistic pricing shifts  Have added hedges throughout 2015 and 2016 YTD  Prudent stewards of balance sheet  Utilize equity to purchase assets (EROC/LRE Mergers)  Monetized assets (SCOOP/STACK properties)  Reduction and subsequent suspension of common and preferred distributions  Second lien debt exchange for unsecured notes  Reduced capital budget to improve excess cash flow  Excess cash flow to pay down credit facility  Took advantage of opportunities in 2015  Completed the LRE and EROC mergers in October 2015  Alternative financing strategies are being pursued to acquire additional assets (acquisition co type structures) 12

36 32 87 89 89 89 83 141 213 168 177 182 Asset and Operations Overview 13

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) 14 Green River Basin  Proved Reserves: 1.1 Tcfe  87% Natural Gas  33% Proved Developed  117 MMcfed Net Production Piceance Basin  Proved Reserves: 774 Bcfe  66% Natural Gas  40% Proved Developed  86 MMcfed Net Production Wind River Basin  Proved Reserves: 24 Bcfe  89% Natural Gas  100% Proved Developed  9 MMcfed Net Production Williston Basin  Proved Reserves: 5 MMBoe  95% Liquids  100% Proved Developed  7 MMBoed Net Production Powder River Basin  Proved Reserves: 13 Bcfe  100% Natural Gas  100% Proved Developed  18 MMcfed Net Production Big Horn Basin  Proved Reserves: 16 MMBoe  96% Liquids  99% Proved Developed  3 MBoed Net Production Anadarko Basin  Proved Reserves: 30 Bcfe  72% Natural Gas  99% Proved Developed  9 MMcfed Net Production Arkoma Basin  Proved Reserves: 1.7 Tcfe  93% Natural Gas  9% Proved Developed  44 MMcfed Net Production Permian Basin  Proved Reserves: 44 MMBoe  66% Liquids  88% Proved Developed  9 MBoed Net Production Gulf Coast Basin  Proved Reserves: 181 Bcfe  42% Natural Gas  64% Proved Developed  44 MMcfed Net Production – Primarily Natural Gas – VNR Major Operated Field – Primarily Oil – VNR Major Non-Operated Field  Proved Reserves: ~4.4 Tcfe (~737 MMBoe) (1)  78% Natural Gas and 22% Liquids(1)  35% Proved Developed(1)  R/P of 29 years(1) Note: Proved reserves based on management reserve report. Production based on Q2 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 40% 26% 18% 6% 4% 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 6/30/16 Management Reserve Database Low-Risk Proved Reserve Base with Significant PDP Component Reserves By Commodity Reserves By Category PV-10 By Category Note: PV-10 calculations include $64.3 million of COPAS value; Assumes Strip pricing as of 8/12/16, effective date as of 8/1/16; Pro forma for SCOOP / STACK divestiture 15 18 Net Cases Oil (MMBbl) Gas (Bcf) NGL (MMBbl) Total Volumes (Bcfe) % Gas PV-9 ($MM) PV-10 ($MM) PV-12 ($MM) PV-15 ($MM) PDP 7,757 50 935 37 1,457 64% $1,498 $1,422 $1,292 $1,138 PDNP 299 4 40 2 71 56% 73 67 57 46 PUD 1,874 12 1,029 23 1,242 83% 486 435 348 250 Technical PUDs 1,204 3 1,454 30 1,650 88% 135 107 67 31 Total 1P 11,134 69 3,458 91 4,420 78% $2,193 $2,031 $1,764 $1,464 PROB 159 5 26 2 66 40% 43 38 30 21 POSS 47 2 2 0 14 14% 12 10 7 4 Total 3P 11,340 76 3,486 94 4,501 77% $2,247 $2,079 $1,801 $1,489 Oil 10% Natural Gas 77% NGL 12% PDP 32% PDNP 2% PUD 28% Technical PUDs 37% PROB 1% POSS 0% PDP 68% PDNP 3% PUD 21% Technical PUDs 5% PROB 2% POSS 0%

36 32 87 89 89 89 83 141 213 168 177 182 Meaningful Inventory of Low-Risk Drilling Opportunities Shifted to PUDs YE 2015 SEC Reserve Database Proved Reserve Bridge 6/30/16 Management Reserve Database 16 19 2,289 2,035 4,420 (239) (83) 68 521 1,650 214 -- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 YE 2015 SEC Reserve Database Sale of SCOOP / STACK PDP Production Other Adjustments 6/30/16 SEC Reserve Database Rollforward Recategorization to PUDs Technical PUDs Price-Related Adjustment Updated 6/30/16 Reserve Database Res erv es ( Bcf e) Pre-Tax PV-10 Reserve Oil Gas NGL Total SEC Pricing Strip Pricing Category (MMBbl) (Bcfe) (MMBbl) (Bcfe) ($MM) ($MM) PDP 51 1,024 40 1,575 $1,441 $1,726 PDNP 3 46 2 78 76 53 PUD 9 484 16 636 205 386 Technical PUDs -- -- -- -- -- -- Total 64 1,554 58 2,289 $1,722 $2,166 Pre-Tax PV-10 Reserve Oil Gas NGL Total SEC Pricing Strip Pricing Category (MMBbl) (Bcfe) (MMBbl) (Bcfe) ($MM) ($MM) PDP 50 935 37 1,457 $1,256 $1,422 PDNP 4 40 2 71 54 67 PUD 12 1,029 23 1,242 264 435 Technical PUDs 3 1,454 30 1,650 36 107 Total 69 3,458 91 4,420 $1,610 $2,031

36 32 87 89 89 89 83 141 213 168 177 182 Low-Decline Base Production Average Annual Decline <11% Annual Projected Base Decline by Area(1) Quarterly Base PDP Decline (1) Compound annual decline from 12/31/16 to 12/31/20 17 -- 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 10.8% Average Annual Decline Through 12/31/20 6.0% 7.7% 8.0% 8.7% 9.3% 9.5% 9.8% 10.1% 10.1% 10.6% 12.8% 27.8% -- 5.0% 10.0 15.0% 20.0 25.0% 30.0 Big Horn Green River Williston Arkoma Gulf Coast East Central Anadarko Wind River Piceance Gulf Coast Permian Pinedale Powder River Base D ecline (%) (Excl. Pinedale)

36 32 87 89 89 89 83 141 213 168 177 182 Ability to Grow Collateral Value While Spending Within Cash Flow Proved PV-10 Roll Forward at Strip Price Deck ($MM) 18 21 $1,489 $1,498 $1,696 $1,946 $542 $565 $507 $380$2,031 $2,063 $2,203 $2,326 $-- $500 $1,000 $1,500 $2,000 $2,500 $3,000 6/30/16 12/31/16 12/31/17 12/31/18 PDP/ PDNP PUD (1) Note: Assumes Strip pricing as of 8/12/16 and effective date as of 8/1/16; Pro forma for SCOOP / STACK divestiture (1) Includes value from Technical PUDs

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 8/12/2016 Strip prices. (1) Q2 2016 Average Daily Net Production – Primarily Natural Gas – Primarily Oil 19 Vanguard Natural Resources, LLC 415 Net MMcfed(1) 10,500+ PDP Wells 6,730 Locations 2.8 Tcfe Net Upside Potential Pinedale (Vertical & Horizontal)  107 Net MMcfed(1)  2,620 PDP Wells (Non-Operated)  2,555 Vertical Locations (Weighted Average WI: 14%)  0.8 Tcfe Net Upside Potential  1,459 locations work now  Horizontal drilling is not currently built into development plan Mamm Creek (Piceance)  79 Net MMcfed(1)  924 PDP Wells (Operated)  524 Locations (Weighted Average WI: 94%)  0.5 Tcfe Net Upside Potential Elk Basin (Water Flood)  3 Net MBoed(1)  281 PDP Wells (Operated)  20 MMBoe Net Upside Potential  2016 Water Flood Pilot Red Lake (Yeso & Tubb)  3 Net MBoed(1)  268 PDP Wells (Operated)  128 Locations (Weighted Average WI: 88%)  3.1 MMBoe Net Upside Potential Arkoma Woodford  19 Net MMcfed(1)  140 PDP Wells (Operated)  1,573 Locations (Weighted Average WI: 61%)  1.6 Tcfe Net Upside Potential  New Completion Design (SCOOP) East Haynesville (Conventional)  6 Net MMcfed(1)  57 PDP Wells (Operated)  42 Locations (Weighted Average WI: 95%)  65 Bcfe Net Upside Potential  New 3D - High Reward Potential 22

36 32 87 89 89 89 83 141 213 168 177 182 Macro Gas Outlook 20 2016 & 2017 Supply/Demand Balance Analyst Gas Price Forecast Rockies Natural Gas Production US Dry Natural Gas Production Source: Wall Street Research, Factset $-- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 2017 2018 RBC Capital Markets Raymond James BMO Capital Markets Scotia Jefferies Wells Fargo Securities Deutsche Bank Guggenheim Securities Average: $3.09 Average: $3.22 73.3 75.3 74.9 74.9 (3.5) (0.2) (4.5) (1.1) 5.7 5.6 -- 10.0 0.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 Lower 48 Supply CAD Imports Mexico Exports LNG Exports Lower 48 Demand Lower 48 Supply CAD Imports Mexico Exports LNG Exports Lower 48 Demand Bc fd 20172016 10.5 11.0 11.5 12.0 12.5 13.0 13.5 14.0 14.5 Bc fd Production Trendline -2.0% 0.0% 2.0% 4.0% 6.0% 8.0% 58.0 60.0 62.0 64.0 66.0 68.0 70.0 72.0 74.0 76.0 78.0 Bcfd (yoy)B cfd Monthly Pro uction Annual Growth

36 32 87 89 89 89 83 141 213 168 177 182 Rockies Differentials Attractive Relative to Appalachia Producing Region Source: Bloomberg Major Natural Gas Hubs El Paso Permian Spot: $2.71 Differential: ($0.24) SoCal CityGate Spot: $2.00 Differential: ($0.94) SoCal Border Spot: $2.93 Differential: ($0.01) AECO Spot: $2.00 Differential: ($0.94) Opal Spot: $2.73 Differential: ($0.21) Marcellus Spot: $1.30 Differential: ($1.64) Dominion South Spot: $1.34 Differential: ($1.60) NY Transco 6 Spot: $2.04 Differential: ($0.91) TETCO M2 Spot: $1.34 Differential: ($1.60) El Paso San Juan Spot: $2.78 Differential: ($0.16) Cheyenne Spot: $2.64 Differential: ($0.30) Legend Anadarko Cheyenne Plain Colorado Interstate DCP East Cheyenne Encana Noble Platte River Power Public Services of CO Southern Star TIGT Trailblazer Henry Hub Spot: $2.94 New York City Gate Spot: $1.40 Differential: ($1.54) TETCO M3 Spot: $1.40 Differential: ($1.54) 21 24 US Monthly Gas Production Forecast 64 66 68 70 72 74 76 78 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month ly Produc tion Fore ca st, Bc f/d 2014 2015 2016 2017 ($0.30) ($0.25) ($0.20) ($0.15) ($0.10) ($0.05) $-- 2016 2017 2018 2019 2020 2021 2022 2023 Cheyenne CIG Rocky Mountains NW Opal WY Rockies Differentials PG&E Citygate Spot: $3.26 Differential: $0.32 US Dry Natural Gas Production US LNG Market Projections (2.0) 0.0 2.0 4.0 6.0 8.0 58.0 60.0 62.0 64.0 66.0 68.0 70.0 72.0 74.0 76.0 78.0 Bcf/d (y/y)Bc f/d Monthly Production Annual Growth 0.0 0.5 1.0 1.5 2.0 2.5 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Bc f/d LNG Imports LNG Exports

36 32 87 89 89 89 83 141 213 168 177 182 Significant Low-Risk Upside Potential Achieves 15% IRR at Current Prices 22 Upside Present Value as of Q2 2016 ($MM) Upside Cases as of Q2 2016 Large Portion of Inventory Economic at Today’s Prices, with Significant Upside in a Modest Price Recovery Scenario (1) PV-10 (2) PV-15 (3) Includes Technical PUDs 23 $1,422 $1,496 $1,581 $1,666 $67 $67 $71 $75 $126 $147 $182 $218 $51 $56 $70 $84 $60 $73 $97 $120 $43 $44 $48 $51 $1,770 $1,883 $2,048 $2,215 $-- $500 $1,000 $1,500 $2,000 $2,500 $3,000 Strip $3.25 / $52.50 Flat $3.50 / $52.50 Flat $3.75 / $52.50 Flat PDP PDNP Pinedale PUDs Piceance PUDs Woodford PUDs Other Undeveloped (1) (2) (3) (2) (3) (2) (3) (2)(3) (1) $114 MM Additional PV $164 MM Additional PV $167 MM Additional PV 336 336 376 384 1,758 1,795 1,948 2,075 884 887 914 939 306 297 350 407 3,284 3,3 5 3,588 3,805 -- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 Strip $3.25 / $52.50 Flat $3.50 / $52.50 Flat $3.75 / $52.50 Flat Piceance Pinedale Woodford Other 31 Additional Cases 273 Additional Cases 217 Additional Cases

36 32 87 89 89 89 83 141 213 168 177 182 Significant Low-Risk Upside Potential Achieves 15% IRR at Current Prices 23 Upside Present Value as of Q2 2016 ($MM) Upside Cases as of Q2 2016 Diversified Portfolio Benefits from Recovery in Oil Prices as well as Gas Prices (1) PV-10 (2) PV-15 (3) Includes Technical PUDs 23 $1,422 $1,432 $1,772 $2,117 $67 $64 $83 $102 $126 $137 $212 $293 $51 $52 $83 $116 $60 $72 $101 $129 $43 $39 $64 $95 $1,770 $1,796 $2,315 $2,852 $-- $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 Strip $3.25 / $50.00 Flat $3.50 / $60.00 Flat $3.75 / $70.00 Flat PDP PDNP Pinedale PUDs Piceance PUDs Woodford PUDs Other Undeveloped (1) (2)(3) (2)(3) (2)(3) (2)(3) (1) $27 MM Additional PV $518 MM Additional PV $537 MM Additional PV 336 333 389 434 1,758 1,758 2,051 2,247 884 873 928 947 306 267 457 545 3,284 3,231 3,825 4,173 -- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 Strip $3.25 / $50.00 Flat $3.50 / $60.00 Flat $3.75 / $70.00 Flat Piceance Pinedale Woodford Other 53 Fewer Cases 594 Additional Cases 348 Additional Cases

36 32 87 89 89 89 83 141 213 168 177 182 23% 17% 10% 50% Pinedale Piceance Woodford Other 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 24 Total 3P PV-10: $2,079 MM $259 $248 $67 $915 $224 $111 $138 $69 $48 $-- $200 $400 $600 $800 $1,000 $1,200 $1,400 Pinedale Piceance Woodford All Other PDP/PDNP PUD PROB/POSS 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)

36 32 87 89 89 89 83 141 213 168 177 182 Northern Division Overview 25

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 41% 34% 6% 3% 7% 6% 3% Pinedale Piceance Big Horn Williston Powder River Green River Wind River 26 (1) Q2 2016 Average Daily Net Production Piceance Basin  Daily Net Production: 86 Mcfed(1)  925 PDP Wells (Operated)  Average WI: 70%  66% Natural Gas Wind River Basin  Daily Net Production: 10 Mcfed(1)  141 PDP Wells (Operated)  Average WI: 47%  89% Natural Gas Williston Basin  Daily Net Production: 7 MBoed(1)  60 PDP Wells (Operated)  Average WI: 21%  95% Liquids Powder River Basin  Daily Net Production: 18 Mcfed(1)  467 PDP Wells (Operated)  Average WI: 27%  100% Natural Gas Big Horn Basin  Daily Net Production: 16 MBoed(1) (without gas reinjection)  281 PDP Wells (Operated)  Average WI: 56%  96% Liquids Green River Basin  Daily Net Production: 117 Mcfed(1)  184 PDP Wells (Operated)  Average WI: 11%  87% Natural Gas

36 32 87 89 89 89 83 141 213 168 177 182 Pinedale Overview & Upside 27

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%) 28 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 Sublette 2 1 3 5 4 6 Pinedale Offset Operator Update Select Recent Well Results Stewart Point 8A3-29 Questar IP-30: 10,313 Mcfed 95% Gas 1 Legend Vanguard Non-Op Acreage Ericson Fort Union Lance Mesaverde Wardell Other Stewart Point 9A1-29 Questar IP-30: 9,656 Mcfed 95% Gas 1 Stewart Point 5D1-28 Questar IP-30: 8,021 Mcfed 95% Gas 1 Stewart Point 12B4-28 Questar IP-30: 7,857 Mcfed 95% Gas 1 Stewart Point 12C4-28 Questar IP-30: 8,467 Mcfed 95% Gas 1 Stewart Point 9D4-29 Terra Energy Partners IP-30: 7,673 Mcfed 95% Gas 1 Stewart Point 10A4-29 Questar IP-30: 7,788 Mcfed 95% Gas 2 Mesa 2A1-18 Questar IP-30: 7,761 Mcfed 96% Gas 3 Riverside 4A2-13D Ultra IP-30: 7,604 Mcfed 97% Gas 4 Riverside 9C2-13D Ultra IP-30: 8,771 Mcfed 95% Gas 5 Warbonnet 4A2-13D Ultra IP-30: 8,201 Mcfed 90% Gas 6 Stewart Point 7D3-29 Questar IP-30: 9,383 Mcfed 95% Gas 2 Stewart Point 8B3-29 Questar IP-30: 10,692 Mcfed 95% Gas 2 Stewart Point 9B2-29 Questar IP-30: 8,593 Mcfed 95% Gas 2 Stewart Point 8D3-29 Questar IP-30: 9,244 Mcfed 95% Gas 2 Riverside 15B2-13D Ultra IP-30: 8,378 Mcfed 96% Gas 5 Riverside 16A1-13D Ultra IP-30: 9,273 Mcfed 95% Gas 5 Riverside 16A2-13D Ultra IP-30: 7,837 Mcfed 94% Gas 5 33 4 29

36 32 87 89 89 89 83 141 213 168 177 182 Pinedale Field Overview (cont’d) 6 Month Cumulative Production Operator Acreage Map 30 Legend Rig Location (8/1/16) Pinedale Bcfe Contour Vanguard Non-Op QEP Resources Samson Resources Jonah Energy Ultra Petroleum Sublette County Sublette County Legend Rig Location Vanguard Acreage 130,000 120,000 110,000 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 FIRST 6 MONTH MCF 30

36 32 87 89 89 89 83 141 213 168 177 182 -- 600 1,200 1,800 2,400 3,000 3,600 -- 300 600 900 1,200 1,500 1,800 Ja n- 97 Ja n- 98 Ja n- 99 Ja n- 00 Ja n- 01 Ja n- 02 Ja n- 03 Ja n- 04 Ja n- 05 Ja n- 06 Ja n- 07 Ja n- 08 Ja n- 09 Ja n- 10 Ja n- 11 Ja n- 12 Ja n- 13 Ja n- 14 Ja n- 15 Ja n- 16 Num be r of W ellsGas (M Mc fe d) Gas (MMcfed) Number of Wells Pinedale Production History  12” pipeline in 1996 and 20” pipeline established in Sept 1999 with added compression opened up drilling programs  Technological advances & innovative thinking leads to commercialization Pre 1997: First well drilled in 1939/no market for gas Nuclear detonation plans abandoned in 1969 McMurry Oil began programs in late 1995 Jan 2014 NYMEX $5.00 Drilling activity resumes Pinedale Historical Production Jan 2012 NYMEX $2.00 Caused reduction in drilling activity 31 Source: Industry data Seasonal fluctuations in activity  Technology Evolution  D&C Costs decreased from $7MM in 2006 to $2.7 MM in 2016  High density development led to clustering wells onto pads which revolutionized the Pinedale area  Drilling days reduced from 80 days in 2006 to 11 days in 2016  Underbalanced Drilling reduces costs/increases ROP  Frac technology has evolved to optimize multi-stage completion design, interval staging, proppant types, proppant volumes, transport fluids, cycle time acceleration and far less environmental impact Jan 2016 NYMEX $2.00 Drilling activity reduced 33

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 Forecasted 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: 8 (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 $2.9 MM including facilities and plunger lift QEP Resources Ultra Petroleum 32 37  68,000 net acre position in the Pinedale (operates 90% of acreage)  Currently running 2 rig program  Plans to ramp up to 10 operated rigs by 2018  Average well cost of $2.7 MM down 13% from $3.1 MM in 2Q 2015  Average Spud to TD of ~8.1 days and average rig release to rig release of 9.9 days

36 32 87 89 89 89 83 141 213 168 177 182  EUR: 4.7 Bcfe (88% Gas)  AVG WI / NRI: 11.5% / 8.8%  IP30: 4.95 MMcfd  Average type curve decline rates/yr are initially 68%, decreasing to a minimum of 7% with b values at 1.5  Condensate Yield: 5.3 Bbl/MMcf  NGL Yield: 13.7 Bbl/MMcf  Shrink: 9%  Average Well Cost: $2.7MM(1)  Opex: $3,600/well/month and $0.06/Mcf  F&D Cost(2): $0.55/Mcfe Pinedale Engineering Overview Key Highlights Pinedale Rate of Return Sensitivity Note: Price sensitivities run at $52.50 WTI (1) Represents average well cost in database (2) For a 4.7 Bcfe well 33 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 34

36 32 87 89 89 89 83 141 213 168 177 182 Piceance Basin Overview Piceance Basin Map Asset Overview  Add to gas lift system where facilities and pipelines are already in place 2016 Plans 35  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 91%; Average Lease NRI: 74%  Current gross production of 73 MMcfd & 710 Bcd 6/2016, Net 51 MMcfd & 605 Bcd  2016 YTD LOE $0.50/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

36 32 87 89 89 89 83 141 213 168 177 182 1 2 3 5 4 7 6 8 9 11 10 13 14 12 Mesa Delta Gunnison Garfield Pitkin Piceance Offset Operator Update Select Recent Well Results Legend Vanguard Acreage Mancos Mesaverde Niobara Rollins Williams Fork Other PA 701-32-HN1 Terra Energy Partners IP-30: 11,504 Mcfed 100% Gas 1 BAT 33A-18-07-95 Ursa IP-30: 5,228 Mcfed 100% Gas 8 Shell 797-09-HN1 Oxy IP-30: 9,058 Mcfed 100% Gas 9 Puckett GM 701-28-HN1 Terra Energy Partners IP-30: 4,390 Mcfed 100% Gas 2 GM 728-14-33-HN1 Terra Energy Partners IP-30: 12,057 Mcfed 100% Gas 3 GM 703-4-HN1 Terra Energy Partners IP-30: 7,253 Mcfed 100% Gas 4 GM 706-4-HN2 Terra Energy Partners IP-30: 7,064 Mcfed 100% Gas 4 Federal GM 702RD-4-HN1 Terra Energy Partners IP-30: 5,729 Mcfed 100% Gas 5 Bosely SG 702-23-HN1 Terra Energy Partners IP-30: 7,130 Mcfed 100% Gas 6 Shell 797-09-HN1 Laramie IP-30: 6,731 Mcfed 100% Gas 9 Homer Deep Unit 9-11AH Black Hills IP-30: 7,286 Mcfed 100% Gas 10 Homer Deep Unit 9-11BH Black Hills IP-30: 6,560 Mcfed 100% Gas 10 Homer Deep Unit 9-11 CH Black Hills IP-30: 5,233 Mcfed 100% Gas 10 Homer Deep Unit 9-41AH Black Hills IP-30: 5,781 Mcfed 100% Gas 11 Homer Deep Unit 9-41BH Black Hils IP-30: 6,807 Mcfed 100% Gas 11 Homer Deep Unit 9-41CH Black Hills IP-30: 6,357 Mcfed 100% Gas 11 Iron Point Unit Hotchkiss 1291 13-24D H1 Gunnison IP-30: 4,619 Mcfed (100% Gas) 12 Falcon Seaboard 11-90-12 3 SG Interests I IP-30: 6,258 Mcfed 100% Gas 13 DGU Hotchkiss Federal 1289 18-H1 Gunnison IP-30: 4,372 Mcfed (100% Gas) 14 Puckett SG 714-44-23-HN1 Terra Energy Partners IP-30: 13,211 Mcfed 100% Gas 7 5 36

36 32 87 89 89 89 83 141 213 168 177 182 Piceance Basin Overview (cont’d) 6 Month Cumulative Production Operator Acreage Map 37 Legend Rig Location (8/1/16) Vanguard Acreage Black Hills Dejour Enterprises Encana G2X Energy Laramie Energy Legacy Resources Terra Energy Ursa Resources XTO Energy Garfield County Mesa County Delta County Rio Blanco County Mesa County Delta County Garfield County Rio Blanco County Legend Rig Location Vanguard Acreage Mesa County Garfield County 39 130,000 120,000 110,000 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 FIRST 6 MONTH MCF

36 32 87 89 89 89 83 141 213 168 177 182  Producing Wells: 954 (924 operated)  Total Undeveloped Locations: 525 (Assumes 10-Acre Spacing)  358 locations have greater than 1.3+ Bcfe EUR  180 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 38 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 39 32% Average Increase in Recoveries due to Completion Improvements 45

36 32 87 89 89 89 83 141 213 168 177 182  EUR: 1.8 Bcfe (66% Gas)  AVG WI / NRI: 88% / 71.5%  IP30: 2.8 MMcfd  Average type curve decline rates/year are initially 83%, decreasing to a minimum of 7% with b values at 1.4  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): $0.76/Mcfe Mamm Creek Engineering Overview Key Highlights Mamm Creek Rate of Return Sensitivity Note: Price sensitivities run at $52.50 WTI 40 0% 10% 20% 30% 40% 50% $2.00 $2.50 $3.00 $3.50 $4.00 R O R (% ) Gas Price ($/Mcf) 1.8 Bcfe

36 32 87 89 89 89 83 141 213 168 177 182 East Central Division Overview 41

36 32 87 89 89 89 83 141 213 168 177 182 East Central Region Overview Gulf Coast Basin  Daily Net Production: 14 MMcfed  Number of Operated Wells: 151  206,693 Gross Acres (107,026 Net) Production By Area Pro i Arkoma & Anadarko Basins  Daily Net Production: 62 MMcfed  Number of Operated Wells: 357  619,749 Gross Acres (241,222 Net) – Primarily Natural Gas – Primarily Oil 51% 17% 32% Arkoma Gulf Coast East Central Anadarko Production By Area 42

36 32 87 89 89 89 83 141 213 168 177 182 Arkoma Overview 2016 Optimization Initiatives  Arkoma Operations Restructuring Initiative = Right-size the Ops Group post Scoop/Stack Sale  Potato Hills Gas Gathering Asset Purchase = Needed protection for Vanguard Operating, LLC well economics  Potato Hills Compression Project  Stroud SPSU Water Flood Project = Map & Study Flood Characteristics for Optimal Sweep Arkoma Basin Overview 43  Current Gross Operated Production: 48 MMcfed  4 Operated Districts with +/- 281 Gross Wells  Operated District Asset Overviews: District Well Count Production Woodford 141 31 MMcfed Potato Hills 53 12 MMcfed  PHGG, LLC Assets Stroud (SPSU) 9 200 Bopd Other 87 5 MMcfed

36 32 87 89 89 89 83 141 213 168 177 182  Current Gross Operated Production: 5 MMcfe/d  2 Operated Districts with +/- 75 Operated Wells  District Asset Overviews: District Well Count Production Anadarko Other 59 4 MMcfed Putnam 16 1 MMcfed Anadarko Operated Overview Anadarko Basin Overview 44 2016 Optimization Initiatives  Post SCOOP / STACK sale, limited maintenance and optimization capital planned

36 32 87 89 89 89 83 141 213 168 177 182  Current Gross Operating Production: 41 MMcfed (FWS)  2 Operated Districts with +/- 36 Gross Well Count  District Asset Overviews: District Well Count Production Alabama 27 38 MMcfe/d  BEC Gas Plant Assets Parker Creek 9 500 Bopd Gulf Coast Overview 2016 Optimization Initiatives  Flomaton Pumping Station Unmanning Operation = Reduction in Company Labor Overtime  Parker Creek Operations Restructuring Initiative  Well Production Recovery in BEC Field = Important Recovery of Critical Wells Gulf Coast EC Overview 45 52

36 32 87 89 89 89 83 141 213 168 177 182 Arkoma Woodford Overview & Upside 46

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 47 Legend VNR OP VNR NONOP 3D Seismic PDP Reserves  PDP as of 2Q16 with 8/12/2016 Strip pricing  Producing Wells: 705 (140 Operated / 565 Non-Operated)  Gas: 114 Bcf  NGL: 1.7 MMBbl  125 Bcfe  Average WI : 16%  Avg. Lease NRI: 13% Undeveloped Locations  1,573 locations (395 Operated / 1,178 Non-Operated)  6.1 Tcfe gross, 1.6 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 6 11 10 13 12 1 3 2 4 5 7 8 9 Pushmataha Atoka Pittsburg Latimer Le Flore Haskell McIntosh Hughes Coal Okfuskee Arkoma Offset Operator Update Legend Vanguard Acreage Atoka Booch Cromwell Gilcrease Hartshorne Red Oak Spiro Woodford Other Tonya 3-20H Petroquest IP-30: 6,511 Mcfed 100% Gas 1 Roger 3-21H Petroquest IP-30: 6,500 Mcfed 100% Gas 2 Shannon 1-27H Petroquest IP-30: 6,030 Mcfed 100% Gas 3 Larissa 2-26H Petroquest IP-30: 6,097 Mcfed 100% Gas 4 Shannon 2-27H Petroquest IP-30: 6,750 Mcfed 100% Gas 3 Cable 2-13 H Petroquest IP-30: 7,512 Mcfed 100% Gas 5 Cable 3-13H Petroquest IP-30: 6,958 Mcfed 100% Gas 5 Cable 2-24H Petroquest IP-30: 7,975 Mcfed 100% Gas 5 Sandmann 1H-9X Newfield Exploration IP-30: 12,095 Mcfed 100% Gas 8 Ellis 2H-34XX Newfield Exploration IP-30: 13,122 Mcfed 100% Gas 9 Ellis 3H-34XX Newfield Exploration IP-30: 12,226 Mcfed 100% Gas 9 Payden 1H-12XX Newfield Exploration IP-30: 14,856 Mcfed 100% Gas 7 Pamela 3-23H Petroquest IP-30: 7,901 Mcfed 100% Gas 6 Pamela 2-23H Petroquest IP-30: 7,648 Mcfed 100% Gas 6 Ina 3-11H BP America IP-30: 6,591 Mcfed 100% Gas 10 Smalley 4-12H BP America IP-30: 8,392 Mcfed 100% Gas 11 Phillips 3-28H BP America IP-30: 6,596 Mcfed 100% Gas 12 Phillips 4-28H BP America IP-30: 7,112 Mcfed 100% Gas 12 Phillips 2-28H BP America IP-30: 7,758 Mcfed 100% Gas 13 Cable 3-24H Petroquest IP-30: 7,969 Mcfed 100% Gas 5 6 48

36 32 87 89 89 89 83 141 213 168 177 182 49 Arkoma Woodford Overview (cont’d) Operator Acreage Map 6 Month Cumulative Production Rig Location Arkoma Btu Contour Vanguard Acreage BP America Bravo Legend Chesapeake Jones Newfield Panhandle PetroQuest Muskogee County Okmulgee County Okfuskee County McIntosh County Johnston County Bryan County Pushmataha County Seminole County Atoka County Latimer County Coal County Hughes County Haskell County Pittsburg County Pontotoc County Legend Rig Location Vanguard Acreage Muskogee County McIntosh County Okmulgee County Okfuskee County Seminole County Hughes County Pontotoc County Coal County Johnston County Choctaw County Pushmataha County Latimer County Haskell County Pittsburg County Atoka County 130,000 120,000 110,000 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 FIRST 6 MONTH MCF

36 32 87 89 89 89 83 141 213 168 177 182 --% 10.0% 20.0% 30.0% 40.0% 50.0% 60.0% 70.0% 80.0% $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 50 Note: Price sensitivities run at $52.50 WTI IP-30 Condensate NGL Yield Well Cost Opex F&D Cost Net Well County EUR (Bcfe) % Gas (Mcfd) De b factor Dmin Yield (Bbl/MMcf) (Bbl/MMcf) Shrink ($MM) ($/Mcfe) ($/Mcfe) Avg WI Avg NRI Count Pittsburg 6.9 100% 7,600 68 1.4 6 -- -- 2% $4.0 $0.32 $0.58 30% 24% 214 Hughes 5.5 78 5,600 74 1.5 6 -- 50.0 6 3.6 0.32 0.65 15 12 86 Atoka 3.5 73% 2,800 67 1.5 6 20.0 44.0 8% 3.6 0.32 1.03 31% 25% 26 Coal 9.0 72 8,600 71 1.3 6 -- 58.0 9 4.0 0.32 0.44 15 12 30

36 32 87 89 89 89 83 141 213 168 177 182 Southern Division Overview 51

36 32 87 89 89 89 83 141 213 168 177 182 South Region Overview Gulf Coast Basin  Daily Net Production: 29 MMcfed  Operated Wells: 151 Permian Basin  Daily Net Production: 9 MBoed  Operated Wells: 1,633 – Primarily Natural Gas – Primarily Oil Production By Area 66% 34% Permian Gulf Coast Production By Area 52

36 32 87 89 89 89 83 141 213 168 177 182  Gross Operated Production: 11 MBoed  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 53 Permian Basin Operations Highlights 2016 Optimization Initiatives  Salt Water Disposal Systems Optimization  Production Efficiencies and Recompletion Opportunities  Marginal Well Optimization  Waterflood Conformance Optimization

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  Wells: 909 Total  858 Prod/22 SWI/29 SI  Production from 70 Fields / 114 Pools New Mexico Operations Highlights Key Highlights 54 Acreage Map – Primarily Natural Gas – Primarily Oil

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 55 Permian Texas Operated Totals Daily Production: 4 MBoed Wells: 1521 Total 981 Prod/154 SWI/386 SI Production from 65 Fields/110 Pools

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 7 56 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  Gross Operated Production: 23 MMcfed  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 57 Gulf Coast Basin Operations Highlights 2016 Optimization Initiatives  25 Vanguard Employees/10 Contract  1 Superintendent / 2 Admin  3 Foremen  11 Plant Operators / 3 Contract Relief  8 Operators / 7 Contract Operators

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 58

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 59

36 32 87 89 89 89 83 141 213 168 177 182 East Haynesville Field Overview & Upside 60

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  27+ Development Locations  Development Strategy – Infill drilling  Exploratory Potential – Untested Smackover fault blocks  Seismic Control – 37 sq.m. PSTM 3D (2015) 61

36 32 87 89 89 89 83 141 213 168 177 182 EUR: 1.7 Bcf, 82 MBbl IP: 2.0 MMcfd, 150 Bopd B factor: 1.2 De: 78% Dmin: 6% 62 Haynesville Sand Type Curve

36 32 87 89 89 89 83 141 213 168 177 182 Haynesville Sand Economics (1) $45.00/Bbl oil price held flat for life Haynesville Sand Rate of Return Sensitivity Key Highlights  Undeveloped Locations: 11  Average WI: 100%  Average Lease NRI: 82%  19.2 Bcfe Net  Undeveloped Economics:  EUR: 1.7 Bcf, 82 MBbl  Well Cost: $1.75 MM 82 63 --% 20% 40% 60% 80% 100% 120% 140% 160% $2.00 $2.50 $3.00 $3.50 $4.00 R O R Flat Henry Hub Gas Price ($/Mcf)(1) 2.1 Bcfe 2.6 Bcfe

36 32 87 89 89 89 83 141 213 168 177 182 EUR: 1.1 Bcf, 70 MBbls B factor: 1.25 IP: 590 Mcfd, 50 Bopd De: 43% Dmin: 6% Smackover Type Curve Smackover Type Curve 64

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: 16  Average WI: 100%  Average Lease NRI: 82%  19.5 Bcfe Net  Undeveloped Economics:  EUR: 1.1 Bcf, 70 MBbl  Well cost: $1.55 MM 65 --% 20% 40% 60% 80% 100% 120% 140% 160% $30.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00 R O R Flat WTI Oil Price ($/Bbl)(1) 1.5 Bcfe 4.1 Bcfe

36 32 87 89 89 89 83 141 213 168 177 182 Red Lake Overview & Upside 66

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 67

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 68 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 69

36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Overview 70

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 (MMcfd) 5.0 1.7 7.6 8.6 Gross EUR Summary (Bcfe) 5.2 1.3 6.9 9.0 % Gas 89.8% 93.9% 100.0% 72.0% Working Interest (%) 8.2% 68.9% 30.0% 15.0% Net Revenue Interest (%) 6.6% 56.3% 24.0% 12.0% D&C Capital Expenditures ($MM) $2.7 $1.4 $4.0 $4.0 Lease Operating Expenses Variable LOE ($/Mcfe) $0.06 $0.19 $0.32 $0.32 Fixed LOE ($/Month) $3,600 $836 $3,363 $3,363 Other Expenses Severance Tax Rate 7.4% 1.4% 7.2% 7.2% Ad Valorem Tax (%) 7.4% 3.7% -- -- Price Differentials Oil - WTI (% deduct) 18.0% 28.0% 4.0% 4.0% Natural Gas - HHUB (% deduct) 20.0% 5.0% 28.0% 39.0% NGL (% of WTI Oil) -- 26.0% 63.0% 63.0% Type Curve Assumptions Pinedale (Non-Operated) Drilling Piceance (Operated) Drilling Arkoma Drilling 71 Non-Operated Gross Net CapEx Rigs Active Wells ($MM) 2H2016 4 76 $18.0 2017E 6 231 70.4 2018E 11 393 105.2 2019E 9 341 99.9 2020E 9 325 93.2 Operated Gross Net CapEx Rigs Wells ($MM) 2H2016 -- -- $-- 2017E 1 13 20.7 2018E 1 24 26.5 2019E 1 24 31.3 2020E 1 24 32.3 Operated Gross Wells Net CapEx Rigs Pittsburgh Coal ($MM) 2H2016 -- -- -- $-- 2017E 1 7 -- 25.2 2018E 1 12 -- 46.3 2019E 1 12 -- 47.3 2020E 1 12 -- 30.4  2016E cash G&A expense of ~$37 million decreasing to ~$35 million in 2018 and held flat for the remainder of the Business Plan forecast

36 32 87 89 89 89 83 141 213 168 177 182 Summary of Business Plan $52.50 / $3.25 Price Case Quarterly Daily Production Quarterly Capital Expenditures by Area 72 -- 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 $75.0 ($ in Millions ) Pinedale Piceance Arkoma Permian Gulf Coast East Central Gulf Coast Big Horn Williston Powder River Green River Anadarko ind River

36 32 87 89 89 89 83 141 213 168 177 182 Summary of Business Plan (cont’d) $52.50 / $3.25 Price Case Quarterly EBITDA Quarterly Unlevered Free Cash Flow 73 $-- $30.0 $60.0 $90.0 $120.0 $150.0 ($ in Mill ions ) Unhedged EBITDA Hedging Gains ($200.0) $-- $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

36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Sensitivities Annual EBITDA Annual Unlevered Free Cash Flow 74 Cumulative Unlevered Free Cash Flow $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 Mill ions ) Strip $50 / $3.25 $55 / $3.50 $60 / $3.75 $848 $651 $571 $1,042 (2) (2) (2) (2) (2) (2) (2) (2) (2) (1) Note: Sources and Uses for pro forma transaction detailed on page 7 (1) Strip as of 8/12/16 (Oil – 2016: $45.10, 2017: $49.01, 2018: $51.31, 2019: $52.83, 2020: $54.05; Natural Gas – 2016: $2.76, 2017: $3.04, 2018: $2.95, 2019: $2.95, 2020: $3.03) (2) 2016 assumes Strip pricing in all cases (1) (1)

36 32 87 89 89 89 83 141 213 168 177 182 Business Plan Financial Summary $52.50 / $3.25 Price Case Business Plan Financial Summary 75 For the Years Ending December 31, 2016E 2017E 2018E 2019E 2020E Commodity Prices Crude Oil ($/Bbl) $41.92 $52.50 $52.50 $52.50 $52.50 Natural Gas ($/MMBtu) 2.47 3.25 3.25 3.25 3.25 Net Production Oil (MMBbl) 4.8 4.6 4.8 4.8 4.8 Gas (Bcf) 109.3 109.6 137.1 151.2 155.0 NGLs (MMBbl) 3.7 3.5 4.1 4.3 4.3 Total Net Production (Bcfe) 160.0 158.4 190.3 205.9 209.5 Daily Production (MBoed) 437.2 433.9 521.4 564.2 572.5 Net Revenue Oil Revenue $170.9 $209.2 $217.5 $220.6 $217.8 Gas Revenue 182.6 273.0 341.0 376.4 386.5 NGL Revenue 40.8 52.4 54.0 48.9 43.6 Hedging Revenue 248.2 58.7 (0.3) -- -- Total Net Revenue $642.6 $593.3 $612.2 $645.8 $647.8 Net Expenses Severance Taxes ($19.1) ($30.7) ($33.7) ($35.0) ($35.1) Ad Valorem Taxes (23.7) (27.7) (31.1) (32.3) (32.1) Lease Operating Expenses (155.5) (150.3) (158.2) (163.1) (165.5) General and Administrative Expenses (37.5) (35.6) (34.8) (34.8) (34.8) Adjusted EBITDA $406.8 $349.0 $354.5 $380.7 $380.3 Change in Net Working Capital (61.9) 23.0 (5.5) (3.0) (9.7) Capital Expenditures (67.1) (188.3) (258.3) (241.3) (231.4) Unlevered Free Cash Flow $277.9 $183.7 $90.7 $136.3 $139.3