Roan Resources Investment Update July 2018
Important Disclosures Forward-Looking Statements and Risk Factors Statements made in this presentation that are not historical facts are forward-looking statements. These statements are based on certain assumptions and expectations made by Linn Energy, Inc. ( LNGG ) which reflect management s experience, estimates and perception of historical trends, current conditions, and anticipated future developments. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of LNGG, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. These include risks relating to financial and operational performance and results of LNGG, timing of and ability to execute planned separation transactions and asset sales, continued low or further declining commodity prices and demand for oil, natural gas and natural gas liquids, ability to hedge future production, ability to replace reserves and efficiently develop current reserves, the capacity and utilization of midstream facilities, the regulatory environment, the uncertainty inherent in estimating reserves and in projecting future rates of production, the production potential of our undeveloped acreage, cash flow and access to capital and the timing of development expenditures. These and other important factors could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. Please read Risk Factors in LNGG s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and other public filings. LNGG undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. No Offer or Solicitation This communication is for informational purposes only and shall not constitute an offer to sell or the solicitation of an offer to buy any securities of LNGG or Riviera Resources, LLC ( RVRA ) or otherwise, nor shall there be any sale of securities in any jurisdiction in which the offer, solicitation or sale would be unlawful prior to the registration or qualification under the securities laws of any such jurisdiction. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended. Important Additional Information In connection with the proposed spinoff transaction between LNGG and RVRA, RVRA has filed a registration statement on Form S-1 containing a prospectus with the SEC. This communication is not a substitute for any documents that LNGG may file with the SEC or send to LNGG shareholders in connection with the spinoff transaction. SHAREHOLDERS OF LNGG ARE URGED TO READ ALL RELEVANT DOCUMENTS FILED WITH THE SEC, BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. When available, investors and security holders will be able to obtain copies of the documents that may be filed with the SEC with respect to the proposed transaction free of charge at the SEC s website, http://www.sec.gov, or as described in the following paragraph. The documents filed with the SEC by LNGG may be obtained free of charge at the applicable website (www.linnenergy.com) or by requesting them by mail at Linn Energy, Inc., 600 Travis, Suite 1400, Houston, TX 77002, Attention: Investor Relations, or by telephone at (281) 840-4110. 1
Important Disclosures Reserve Estimates The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC s definitions for such terms. LNGG may use terms in this presentation that the SEC s guidelines strictly prohibit in SEC filings, such as estimated ultimate recovery or EUR, resources, net resources, total resource potential and similar terms to estimate oil and natural gas that may ultimately be recovered. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially greater uncertainty of being actually realized. These estimates have not been fully risked by management. Actual quantities that may be ultimately recovered will likely differ substantially from these estimates. Factors affecting ultimate recovery include the scope of Roan Resources LLC s ( Roan ) actual drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place, and other factors. These estimates may change significantly as the development of properties provides additional data. Non-GAAP Measures Adjusted EBITDAX and Net Debt are financial measures not presented in accordance with generally accepted accounting principles in the United States ( GAAP ). Reconciliations of these non-gaap financial measures to the most directly comparable GAAP measures can be found in the appendix to this presentation. Industry and Market Data This presentation has been prepared by LNGG and includes market data and other statistical information from sources believed by LNGG to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on LNGG s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although LNGG believes these sources are reliable, they have not independently verified the information and cannot guarantee its accuracy and completeness. 2
Spin Transaction Update Anticipated Separation Into Two Public Companies August 7 th LNGG is separating into two stand-alone, publicly traded companies: LNGG, which will initially hold 50% of Roan RVRA will hold mature low decline producing assets in Hugoton, Michigan, and Drunkards Wash, emerging high growth assets in Arkoma, East Texas, North Louisiana, and NW STACK, in addition to significant midstream assets with Blue Mountain Midstream LLC, a rapidly expanding midstream business centered in the core of the Merge LNGG shareholders on record date will receive 1 share of RVRA common stock for each share of LNGG common stock Working closely with our 50% ownership partner, Roan Holdings LLC, on definitive documentation to consolidate 100% of Roan s equity interest under LNGG Post consolidation, LNGG intends to uplist its common stock to NASDAQ or NYSE in 2018 and change from LNGG to ticker ROAN 3
Separation Overview LNGG shareholders on record date will receive 1 share of RVRA common stock for each share of LNGG common stock Distribution of 1 share of RVRA for each share of LNGG Immediately following Spinoff Transaction LNGG shareholders LNGG shareholders Distribution of Riviera Resources stock Riviera Resources, Inc. Riviera Upstream Assets Blue Mountain Midstream LLC LINN Energy, Inc. 50% equity interest Roan Resources LLC Roan Holdings, LLC 50% equity interest RVRA Share Riviera Resources, Inc. Riviera Upstream Assets Blue Mountain Midstream LLC LNGG Share LINN Energy, Inc. 50% equity interest Roan Resources LLC Roan Holdings, LLC 50% equity interest 4
Roan s Investment Thesis Only pure play operator with large scale, contiguous acreage position in the oil window of the Merge/SCOOP/STACK - Second most active basin in lower 48 based on rig count Multiple decades of inventory of high rate-of-return locations - Development opportunities with: - Rate of return (ROR) (1) of ~75% to +100% - Present value index (PVI) (1) of over 2.0x - 13 to 18 month payback period (1) per well - 4.9x recycle ratio (2) - Competitive with Tier 1 Permian plays Strong historic well results with expectation of substantial rate-of-change improvements driven by experienced management team WTI pricing and ample processing and takeaway capacity Robust production growth plus line of sight to free cash flow generation Strong Offset Activity and Well Results Demonstrates Asset Quality MRO STACK / Meramec Consistent outperformance of STACK volatile oil wells XEC Lone Rock Play Best Results to Date CLR SCOOP Springer Merge Alta Mesa STACK Oil Window Meramec / Osage EOG Eastern Anadarko Woodford Oil Window High-Return Premium Play in Crude Oil Window Well-capitalized balance sheet with significant financial flexibility Deeply analytical and experienced operations team with significant history running large scale assets in the Mid- Continent CLR SCOOP Woodford/Sycamore Acreage Position (Net Acres) Merge 117,000 SCOOP 29,000 GPOR SCOOP Woodford / Sycamore / Springer STACK 8,000 Total 154,000 Roan acreage 1) PVI, ROR, and payback period are based on $65 WTI and $2.75 HH; please see slide 20 for information on the related type curves 2) Please see slide 13 for recycle ratio calculation 5
Roan Production Production History and Guidance: 120 62% 65% MBoe/d 100 80 60 40 20 44% 20.1 46% 22.9 50% 25.7 56% 37.7 54% 45.0 61% 61.0 94.0 55% 45% 35% 25% 15% 5% % Liquids 0»» 2Q'17 3Q'17 4Q'17 1Q'18 Current rate Exit rate (1) 2018 Net Production % Liquids Exit rate (1) 2019-5% ~365% projected growth from 2Q 17 to Dec 19 1) Based on the midpoint of guidance 6
Roan Financial Overview Key Metrics / Guidance 1Q 18 Adjusted EBITDAX (1) ($MM) $74 1Q 18 Net Debt (1) ($MM) $204 Current DUC count (2) 13 Current Rig Count (2) 7 YE 18 Rig Count 8 2018 Estimated Production (MBoe/d) 43 46 2018 Adjusted EBITDAX (1)(3) $340 - $370 2019 Estimated Production (MBoe/d) 72 83 2019 Adjusted EBITDAX (1)(3) $625- $725 1) Adjusted EBITDAX and Net Debt are non-gaap measures, please see slide 34 for a reconciliation of these measures to the most directly comparable GAAP measure. Projected 2018 and 2019 Adjusted EBITDAX is not reconcilable at this time. 2) As of July 2018 3) Represents unhedged Adjusted EBITDAX based on $65 WTI and $2.75 HH flat pricing 7
Unique Investment Opportunity 1) Source: FactSet and public filings. Market data as of 7/20/2018. Publicly Traded U.S. E&P Universe filtered for companies with Enterprise Values >$500mm and that trade on the NYSE or NASDAQ. 8
Roan Management Team & Initial Board Top-Tier, Handpicked Management Team with Expertise in Mid-Continent Tony Maranto President, CEO and Director Mr. Maranto has 35 years of industry experience, with 21 years at EOG Resources, where he served as Vice President of its Mid-Continent division for more than a decade He earned his Masters of Business Administration from Centenary College and a Bachelor of Science in Petroleum Engineering from Louisiana Tech University Board of Directors Matthew Bonanno Member of LNGG Board of Directors York Capital Management Mark Ellis Member of LNGG Board of Directors Greg Condray EVP Geoscience & Business Development Joel Pettit EVP Operations and Marketing David Edwards Chief Financial Officer Mr. Condray has 22 years of industry experience and previously served as Exploration Manager in the Mid-Con division of EOG Resources Prior to that, he served as Geoscience Manager for Chesapeake Energy Corporation, where he was responsible for the identification and development of the Haynesville, Eagleford and Powder River Basin assets Mr. Condray earned a Master of Science and Bachelor of Science in Geology from University of Alabama Mr. Pettit has more than 35 years of industry experience, employed with Pennzoil for 22 years Previously, he served as Operations Manager in the Mid-Continent and Permian Divisions for EOG Resources Mr. Pettit earned a Bachelor of Science in Petroleum Engineering from Mississippi State University Mr. Edwards was the former CFO for Tapstone Energy since 2014 Prior experience includes various roles in Corporate Finance at Sandridge Energy and Equity Research at UBS, with a focus on the Energy sector Mr. Edwards holds a Bachelor of Science degree in Applied Mathematics from Brown University Evan Lederman Chairman of LNGG Board of Directors Fir Tree Partners John Lovoi JVL Partners Paul B. Loyd Jr. JVL Partners Tony Maranto President and CEO, Roan Resources Michael Raleigh JVL Partners Andy Taylor Member of LNGG Board of Directors Elliott Management Corporation James Woods Vice President of Land, Citizen Energy III 9
Roan Investment Highlights 154,000 net acres located in the Merge, SCOOP and STACK plays in Central Oklahoma Pure Play Merge / SCOOP / STACK Operator Over 110 operated horizontal wells developed as of July 2018, ranking Roan as the dominant developer and producer in the Merge play Stacked pay with multiple well-developed, benches with superior reservoir characteristics Roan has a ~76% average working interest throughout its Merge acreage that is ~80% held by production (HBP d), allowing for optimal fullfield development with decades of high quality inventory Oil sales price off WTI at Cushing with all-in differential of less than $1.50 per barrel Top-Tier Capital Efficiency Merge play offers single well ROR (2) of ~75% to +100%, superior to SCOOP / STACK and competitive to Tier 1 Permian economics Corporate recycle ratio (1) 4.9x; development opportunities with PVI (2) of over 2.0x and an average payback (2) of 13 to 18 months per well Base cash flows, high growth potential and capital efficiency position Roan for line of sight to free cash flow by 1H 2020 Attractive baseline well results established through horizontal development activity by Citizen and LNGG Rate-of-Change Improvements in Development Program Roan s subsurface and exploration team leverage in-basin experience and significant well control to produce differentiated development model Roan operations team technical approach and experience offers potential for significant improvements in development program results Advances in lateral targeting, drilling times and cost initiatives already evident in results Ample Organic Growth Potential, Supported by Large Base Production Substantial growth opportunities, with 7 rigs currently and increasing to 8 rigs by YE 18 2018 to 2019 projected to deliver YoY production growth of ~75% Development program de-risked through over 110 operated wells and over 225 non-operated wells Sizable current base production of ~45 MBoe/d Best in Class Financial Flexibility Well-capitalized balance sheet with high cash flowing asset base; LQA Leverage of 0.7x at 1Q'18 $204MM of Net Debt (3) at 1Q 18 (all debt held in the credit facility); current borrowing base of $425MM implied available liquidity of >$200MM at 1Q'18 Experienced Management Team Led by Tony Maranto, Roan s technical teams have extensive Merge experience and were integral in building EOG s current Mid-Con position Executive leadership has over 100 years of combined experience from EOG and other top tier operators 1) Please see slide 13 for how recycle ratio is calculated 2) ROR, PVI and payback period are based on $65 WTI and $2.75 HH; please see slide 20 for information on the related type curves 3) Adjusted EBITDAX and Net Debt are non-gaap measures, please see slide 34 for a reconciliation of these measures to the most directly comparable GAAP measure 10
Roan s Core Business Strategy To be the best-in-class disciplined operator of unconventional resources Maximize value across Roan s asset base - Applying best-in-class practices in the development of our resources based on EOG pedigree and experience - Continual pursuit of improvements to operations Maintain well-capitalized balance sheet and financial flexibility - Continual focus on credit profile; including line of sight to grow substantially within cash flow - Consistently evaluate and position for the proper application of risk in our business strategy Recruit and maintain top-tier employee base - Provide challenging, stimulating and supportive experience for motivated individuals Selectively pursue opportunities to expand the asset base through leasing and acquisitions - Seek expansion of the asset base only where a strategic advantage and accretive valuation is identified 11
Introduction to the Merge Merge Overview: The main target zones in the Merge are the Woodford and Mayes (Sycamore) The Woodford is between 75 and 175+ feet thick in the Merge and historically was the main horizontal target in the SCOOP The Mayes is between 40 and 250+ feet thick and has emerged as a viable, repeatable target zone Merge Highlights: Merge SCOOP STACK Porosity 4% - 10% 4% - 8% 3% - 8% Gross Thickness (ft) 70-400+ 125-400 100-500 Net to Gross 40% - 80% 50% - 80% 30% - 50% Primary Target Mayes / Woodford Woodford Meramec Stratigraphic Cross Section Schematic A A Merge A A Roan acreage 12
Roan Economics Best in Class ROR (1) @ $55 WTI / $3 HH 100% Peer Recycle Ratio (2) Comparison 5 4.9x 4.6x ROR (1) @ $55 WTI / $3 HH 80% 60% 40% 20% 74% 65% 63% 55% 54% 41% 41% 23% 4 3 2 1 4.2x 4.2x 41% ROR 3.2x 3.1x 2.6x 2.5x 2.4x 63% ROR 2.0x 2.0x 1.9x 1.7x 1.5x 23% ROR 0% 0 Highly competitive well level returns Drive peer-leading corporate capital efficiency 1) Source: RS Energy Group for economics other than Roan. Merge RORs based on type curves from Roan s YE 17 reserve report prepared by D&M, please see slide 20 for more detail. 2) Peers include AMR, CDEV, COG, CPE, CXO, FANG, JAG, LPI, MTDR, NFX, PE, PXD, XEC sourced from public filings; Recycle ratio is calculated as: (1Q 18 unhedged adjusted EBITDAX / 1Q 18 production)/(ye 17 proved undeveloped capital cost / undeveloped net reserves); Sourced from public filings. 13
Roan s Premier Merge Acreage Position Multiple stacked drilling targets throughout acreage position Woodford Oil Gravity Map Vast majority of acreage in high-return oil window Significant thickness of Woodford with superior reservoir properties Multiple well-developed benches in the Mayes with great porosity and permeability Mayes play de-risked by historic vertical production API Oil: Pore pressure gradients ranging from 0.45 0.52 psi/ft through core area Shallower depths reduce drilling costs High-quality leasehold, characterized as contiguous acreage with high working interest and predominantly HBP d Roan acreage 14
Roan s Premier Merge Acreage Position Continued Woodford Oil Gravity Map Merge SCOOP STACK Total STACK Operated Sections (1) 206 37 12 255 HBP d Operated Sections ~80% ~70% ~90% ~80% Significant operational control through the high-return oil window - ~175 operated sections in the Merge are in the oil and liquids-rich windows (~90% of acreage) Operated acreage position largely HBP d - Development program not dictated by need to hold acreage API Oil: Merge SCOOP Contiguous acreage throughout leasehold - Optimal for pad development and efficient surface operations Demonstrated ability to capture operations Roan acreage 1) Operation control assumed if leasehold exceeds 240 acres in a section and 1-mile units 15
Roan s De-Risked Inventory Roan has a deep inventory to be developed Merge operated gross locations (1) at different well assumptions - 12 wells per section = 2,418 gross operated locations - 16 wells per section = 3,224 gross operated locations - 20 wells per section = 4,030 gross operated locations Theoretical Merge Density Test (3) Mayes (Sycamore) Operated gross locations will take 15 to 25 years to develop with 10 rigs (2) Merge density tests underway Currently testing 880 spacing in the Woodford Multiple pattern tests planned: - Testing up to 8 wells per unit in the Woodford - Testing up to 6 wells per unit in the Mayes Woodford Base case development wells Upside development wells SCOOP / STACK acreage offer additional development horizons 1) Includes all operated sections in Merge; 206 operated sections for Mississippian and 197 operated sections for Woodford. Operation control assumed if leasehold exceeds 240 acres in a section and 1-mile units 2) Assumes 16 wells per rig per year 3) Theoretical density diagram not depicted to scale or to reflect current or future density tests 16
Key Merge Well Results Bomhoff 2H 20-12-7 (JONE) IP-30: 1,510 Boe/d Oil: 41% LL / Zone: 4,425 ; Mayes Bomhoff 1H 20-12-7 (JONE) IP-30: 846 Boe/d Oil: 32% LL / Zone: 4,195 ; Woodford Spectacular Bid 18-11-6 2H IP-30: 1,728 Boe/d Oil: 55%; Liquids: 75% LL / Zone: 4,915 ; Mayes Frank Eaton 36-1-11-6 1XH IP-30: 954 Boe/d Oil: 60%; Liquids: 79% LL / Zone: 10,170 ; Woodford Hinparr 31-6-10-5 1XH IP-30: 2,441 Boe/d Oil: 65%; Liquids: 81% LL / Zone: 9,900 ; Mayes Meyers 1H-2821X (XEC) IP-30: 2,586 Boe/d Oil: 24% LL / Zone: 7,980 ; Woodford Govenor James B Edwards 1H-32 IP-30: 2,143 Boe/d Oil: 65%; Liquids: 81% LL / Zone: 4,960 ; Mayes Dutch 1H-4-9 IP-30: 1,360 Boe/d Oil: 40%; Liquids: 66% LL / Zone: 7,475 ; Woodford Griffin 26-23-10-5 1XH IP-30: 2,476 Boe/d Oil: 63%; Liquids: 81% LL / Zone: 6,500 ; Woodford Dutch 1H-33-28 IP-30: 1,918 Boe/d Oil: 41%; Liquids: 67% LL / Zone: 9,700 ; Woodford Collins 10-3-9-5 1XH IP-30: 3,218 Boe/d Oil: 61%; Liquids: 78% LL / Zone: 10,100 ; Mayes Barbour 1-10-7 1H IP-30: 1,487 Boe/d Oil: 34%; Liquids:56% LL / Zone: 4,960 ; Mayes Collins 11-2-9-5 1XH IP-30: 3,492 Boe/d Oil: 52%; Liquids: 73% LL / Zone: 9,500 ; Mayes Paxton1H-30-19 IP-30: 1,774 Boe/d Oil: 29%; Liquids: 60% LL / Zone: 10,175 ; Woodford Renbarger 2H-26-23 IP-30: 1,978 Boe/d Oil: 32%; Liquids: 61% LL / Zone: 10,250 ; Mayes Gene Carroll 1H-18 IP-30: 2,537 Boe/d Oil: 17%; Liquids: 53% LL / Zone: 4,925 ; Mayes Umbach Estate 1H-28-21 (TPR) IP-30: 1,101 Boe/d Oil: 63% LL / Zone: 6,675 ; Mayes Leon 1H-2-35 IP-30: 2,624 Boe/d Oil: 37%; Liquids: 64% LL / Zone: 10,070 ; Mayes Curry 21X-1VH (EOG) IP-30: 1,762 Boe/d Oil: 91% LL / Zone: 10,600 ; Woodford Roan Operated Mayes Non-Operated Mayes Roan Operated Woodford Non-Operated Woodford IP-30 rates for Roan wells are on a 3-stream, peak rolling 30-day basis; other operator wells are on a 3-stream basis and assume a shrink of 0.8 and yield of 68 Bbl/MMcf; all wells assume a 6:1 Bbl:MMcf ratio 17
Key SCOOP Non-Operated Well Results Triple H 2-30-31HS (CLR) IP-30: 3,537 Boe/d Oil: 85% LL / Zone: 9,900 ; Springer Triple H 5-30-31HS (CLR) IP-30: 2,344 Boe/d Oil: 88% LL / Zone:10,200 ; Springer Triple H 3-30-31HS (CLR) IP-30: 2,629 Boe/d Oil: 86% LL / Zone: 10,200 ; Springer Pudge 1-7-6XH (CLR) IP-30: 2,419 Boe/d Oil: 4% LL / Zone: 7,500 ; Woodford Triple H 4-30-31HS (CLR) IP-30: 2,418 Boe/d Oil: 88% LL / Zone: 10,200 ; Springer Ernsteen 1-21X28H (GPOR) IP-30: 2,264 Boe/d Oil: 22% LL / Zone: 7,600 ; Woodford Harper Thomas 1-19H (Unit) IP-30: 2,416 Boe/d Oil: 87% LL / Zone: 5,140 ; Hoxbar Ernsteen 2-21X28H (GPOR) IP-30: 2,128 Boe/d Oil: 24% LL / Zone: 7,600 ; Woodford Rowell 1-1-12XH (CLR) IP-30: 2,558 Boe/d Oil: 1% LL / Zone: 5,400 ; Woodford Silver Stratton 1-6-31-XH (CLR) IP-30: 2,431 Boe/d Oil:35% LL / Zone: 10,040 ; Woodford Pauline 6-27X22H (GPOR) IP-30: 3,663 Boe/d Oil: 24% LL / Zone: 7,625 ; Woodford Fowler 4N6W 3-9X16H (GPOR) IP-30: 3,061 Boe/d Oil: 4% LL / Zone: 8,750 ; Woodford Bragg 3-35X02H (GPOR) IP-30: 3,200 Boe/d Oil: 1% LL / Zone: 9,600 ; Woodford Non-Operated Springer/Hoxbar Non-Operated Woodford Peak rolling 30-day rates for other operator wells are on a 3-stream basis; all wells assume a 6:1 Boe ratio 18
Industry Activity Gravitating to the Merge / SCOOP Active Rigs by Operator in Merge / SCOOP (1) Merge / SCOOP Rig Activity (1) 10 8 6 8 7 4 2 3 3 3 2 2 2 2 2 1 1 1 1 1 1 0 Horizontal Drilling Permits in the Merge (2) 61 136 20 125 20 56 35 93 14 69 11 15 2015 2016 2017 2018 YTD Other Operators LNGG Citizen Roan Roan Rigs Peer Rigs Roan Acreage 1) Source: Drilling Info as of July 2018 2) Source: IHS; 2018 YTD is as of July 2018 19
Roan s Type Curve Economics Avg. Roan 2018 Mayes Oil Well Performance (1) vs. YE 17 Mayes Oil Curve (1) Avg. Roan 2018 Wdfd Oil Well Performance (1) vs. YE 17 Wdfd Oil Curve (1) Cumulative production (Boe) 200,000 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 Avg. 2018 Mayes wells YE 17 curve Cumulative production (Boe) 200,000 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 Avg. 2018 Woodford wells YE 17 curve - - 30 60 90 120 150 180 Days on production - - 30 60 90 120 150 180 Days on production YE 17 Mayes Oil Curve (1) Overview YE 17 Mayes Oil Curve YE 17 Woodford Oil Curve (1) Overview YE 17 Woodford Oil Curve IP 30 EUR Mix $65 WTI / $2.75HH IP 30 EUR Mix $65 WTI / $2.75HH Oil Gas NGL Oil Total Liquids AFE ($MM) ROR Payout period (months) PVI Oil Gas NGL Oil Total Liquids AFE ($MM) ROR Payout period (months) PVI 1,075 3,130 290 31% 56% ~$8.5 +100% 13 2.06 545 1,350 125 53% 70% ~$8.5 75% 18 2.14 1) Normalized to 10,000 lateral on a 20:1 Bbl/MMcf; oil curve is average of 1,700, 3,000 and 4,800 GOR curves from the YE 17 reserve report prepared by D&M. 2018 wells represent well developed by Roan and include those that correspond to the represented type curve area and came to first sales in 2018. Wells that had been materially impacted by midstream limitations are excluded from the averages 20
Operational Advancements: Targeting Geosteering Comparison Lateral targeting has improved dramatically since the Roan team assumed operations 100% 90% 80% Roan Average 95% Advantages to successful targeting Optimizes drilling performance Improved hydraulic stimulation performance Maximizes well productivity 43 operated gross drilled wells in 1H 2018 24 wells producing (1) 6 wells completing % In Target Zone 70% 60% 50% 40% 30% 20% Citizen / LNGG Average 58% 13 DUCs 10% 0% 1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101 105 109 113 117 121 LNGG/Citizen Wells (2015-2017) Wells Roan Wells (1H 2018) 1) Some wells have been temporarily shut in for midstream constraints or for fracking offset wells 21
Targeting Results and Subsurface Data Advancements Advantages of Successful Targeting Evident in Well Results Well Oppel 1H-16-21 (pre 2018) Dutch 1H-33-28 (Roan operated) Treated Lateral Length % in Optimal Zone 9,851 66% 9,708 99% 3D Seismic Overview Since assuming operations, Roan has significantly expanded 3D seismic coverage Benefits of expanded coverage include: - Improved lateral targeting - Improved identification of key structural features 10,000' Normalized Cumulative MBoe 90 80 - Implementation of seismic attributes in reservoir quality evaluation - Geohazard avoidance Cumulative MBoe 70 60 50 40 30 20 10 +85% in 45 days Evolution of Subsurface Data 2016 2017 2018 Roan LAS (# of wells) 2,500 2,500 30,000 Raster (# of wells) 1,230 8,330 56,000 3D Square Miles 250 ~315 ~800 0 0 10 20 30 40 Days on Production OPPEL Oppel 1H-16-21 (Woodford) - WDFD DUTCH Dutch 1H-33-28 (Woodford) - WDFD 22
Operational Advancements: Drill Times Since taking over drilling operations in January, Roan has improved program average drill times by ~35%+ Drill Time Comparison: Spud to Total Depth (1) 35 Improvements have been achieved by: - Cohesive drilling team with proven performance driven track record - Proprietary mud program - Utilization and optimization of high performance motors Days 30 25 20 23.3 22.0 27.3 18.1 30.0 16.9 - Contracting higher performance rigs 15 14.1 12.7 - Aggressive parameter optimization Current records indicate further improvements to come: Record 1-mile Woodford lateral drilled in 8.6 days 10 5 Record 2-mile Woodford lateral drilled in 11.7 days 0 1-Mile Mississippian 1-Mile Woodford 2-Mile Mississippian 2-Mile Woodford LNGG / Citizen Roan 1) Data is based on 76 LNGG / Citizen wells and 33 Roan wells. Wells with completed lateral lengths less than 6,500 are designated 1 mile wells; wells with completed lateral lengths greater than 9,000 are designated as 2 mile wells; spud is drill out of surface casing 23
The Roan Mid-Continent Advantage Substantially stronger Mid-Continent price realizations - Oil prices benefit from proximity to Cushing markets - Gas takeaway solutions in the Mid-Continent are more imminent than the Permian Producer Net Revenue Interests are typically higher in the Mid-Continent - Standard Royalty Interest of ~20% in the Mid-Continent are advantaged to the 25-30% royalties exhibited in the Permian Development advancements are exhibiting a greater rateof-change in the Mid-Continent as compared to the Permian Operational infrastructure is less stressed in the Mid- Continent, resulting in more efficient and lower risk to production and development Mid-Continent vs Permian Regional Gas Prices (1) $0.00 ($0.50) ($1.00) ($1.50) Historical Future ($2.00) Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19 PEPL WAHA Permian Crude Price Discount to WTI $5.00 (1) $0.00 ($5.00) ($10.00) Ability to expand operational control by forced pooling ($15.00) - In Oklahoma the dominate acreage position in a single or multi-section spacing unit typically wins operatorship - Roan has ~76% operated working interest in the Merge allowing for organic growth through forced pooling and drilling longer laterals ($20.00) ($25.00) Jul-17 Sep-17 Historical Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Future Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19 1) Pricing as of July 26, 2018 24
Roan Midstream & Marketing: Crude Crude Oil Acreage is advantageously located in close proximity to Cushing (~65 miles) and several refineries Local Takeaway and Sales Optionality Ponca City - Large number of potential crude purchasers Current oil price deduct is less than $1.50 per barrel, and based on trucking transportation Cushing Considering strategic opportunities to market directly to Cushing marketplace - Reviewing proposals to transport oil on pipe to Cushing Wynnewood (CVR) Ardmore Roan acreage 25
Roan Midstream & Marketing: Gas & NGLs Natural Gas and NGLs Current Gas Takeaway Infrastructure Acreage dedications to Blue Mountain Midstream (~50%) and EnLink Midstream (~50%) Similar fixed cost structure and proportional NGL revenue reduction at both midstream providers - Contracts based on Mont Belvieu pricing Blue Mountain Midstream currently expanding plant capacity - June capacity of 60 MMcf/d increasing to 150 MMcf/d in July and then to 250 MMcf/d by 4Q 18 - Blue Mountain evaluating second train in 2019 EnLink Midstream looping gathering system and adding compression capacity in Roan producing area (proposed) Increased takeaway solutions in Oklahoma in 2019 Roan dedication Basis hedges in place through 2Q 20 26
Roan Financial Highlights Industry leading balance sheet and credit profile - LQA Leverage of <1.0x - High cash flowing production base Strong credit profile supplemented by high asset quality - Deep inventory of de-risked development locations - Significant cash flow margins Superior capital efficiency - F&D (1) of $4.72 per Boe - ~75% to +100% ROR (2) - Corporate recycle ratio (3) of 4.9x - PVIs (2) of over 2.0x - Unhedged 1Q 18 cash margin (4) of ~$23 per Boe Active hedge program - Limits financial risk and provides development funding visibility Substantial financial flexibility - High capacity to adjust development program: Acreage largely HBP d; Rigs on 12-month or less contracts; nominal minimum volume commitments Line of sight to continued growth plus free cash flow generation by 1H 2020 1) F&D is calculated by: YE 17 proved undeveloped capital cost / undeveloped net reserves 2) ROR and PVI are based on $65 WTI / $2.75 HH 3) See slide 11 for calculation of recycle ratio 4) Please see slide 36 for calculation of cash margin 27
Capitalization & Credit Metrics Capitalization & Credit Metrics Peer 1Q'18 LQA Leverage (4) 3.5x 3.0x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x 0.3x 0.5x 0.7x 0.7x 0.8x 1.1x 1.3x 1.4x 1.4x 1.5x 1.6x 1.6x 1.7x 0.0x 1 2 Roan 3 4 5 6 7 8 9 10 11 12 13 Peer 1Q'18 Net Debt / Total Capitalization (4)(5) 60% 53% 53% 50% 43% 45% 40% 35% 30% 20% 10% 8% 10% 10% 11% 15% 19% 22% 22% 23% 0% 1 2 Roan 3 4 5 6 7 8 9 10 11 12 13 1) Adjusted EBITDAX and Net Debt are non-gaap measures, please see slide 34 for a reconciliation of these measures to the most directly comparable GAAP measure 2) 1Q'18 Borrowing Base reflects amount effective from the Spring 2018 redetermination 3) From the 2017 Roan reserve report, prepared by D&M; PV10 amount incorporate $65 WTI and $2.75 HH pricing, see slide 35 for reconciliation from SEC pricing to $65 WTI and $2.75 HH 4) Figures sourced from public filings and internal reports. LQA represents last quarter annualized. Peers include: AMR, CDEV, CLR, CPE, CXO, FANG, JAG, LPI, MTDR, NFX, PE, XEC and WRD 5) Net Debt / Total Capitalization calculated as (Total Debt - Cash) / (Total Liabilities + Book Equity) 28
Roan Guidance 2018 Production (MBoe/d) 43 46 Production Rates 100 94.0 Exit Rate Production (MBoe/d) 58 64 Adjusted EBITDAX (1)(2) ($MM) $340 - $370 D&C Capex ($MM) $565 - $605 Other Capex $110 - $120 MBoe/d 80 60 40 25.7 37.7 61.0 Total Capex ($MM) $675 - $725 20 4Q18 Operated Rig Count 8 0 4Q'17 1Q'18 Exit rate 2018 Exit rate 2019 2019 Adjusted EBITDAX (1)(2) Production (MBoe/d) 72 83 Exit Rate Production (MBoe/d) 88 100 Adjusted EBITDAX (1)(2) ($MM) $625 - $725 D&C Capex ($MM) $670 - $750 Other Capex $80 - $100 Total Capex ($MM) $750 - $850 2019 Rig Count 8 $ in MM 800 700 600 500 400 300 200 100 0 $355 $675 2018 2019 1) Adjusted EBITDAX is a non-gaap measures as defined on slide 34. Projected 2018 and 2019 Adjusted EBITDAX is not reconcilable at this time and excludes the impact of hedges. 2) Based on $65 WTI and $2.75 HH; excludes the impacts of hedges 3) CAGR represents the periods from 4Q 17 to exit rate 2019 4) Exit rate production numbers and adjusted EBITDAX numbers are the midpoint of guidance 29
Roan s Investment Thesis Investment criteria Pure play operator with large acreage position in Merge oil window Ample midstream availability with WTI oil pricing Decades of high ROR (1) inventory (~75% to +100% ROR) Strong base production Roan ~90% of Merge acreage is in oil and liquids-rich windows Transportation costs to Cushing < $1.50 per barrel; midstream providers adding capacity Up to ~4,000 gross operated locations ~45,000 Boe/d Robust production growth with vision to free cash flow Projecting 75% YoY production growth; free cash flow by 1H 2020 Superior financial metrics LQA leverage ratio: 0.7x Top-tier, experienced in-basin operations team Legacy EOG team 1) ROR is based on $65 WTI / $2.75 HH 30
Contact Information Linn Energy, Inc.: Investor Relations Phone: 281-840-4100 Email: IR@linnenergy.com 31
Appendix 32
Roan s Current Hedge Summary Oil Gas Period Swap Volumes Hedged (MBbls) Swap (weighted average $) Swap Volumes Hedged (MMcf) Swap (weighted average $) Basis Volumes Hedged (MMcf) Basis (weighted average $) 2018 3,962 $56.70 29,854 $2.94 16,440 ($0.54) 2019 4,608 $58.66 29,200 $2.86 21,900 ($0.58) 1H 2020 410 $60.19 5,005 $2.69 3,640 ($0.62) 1) Hedge position as of August 3, 2018 33
Non-GAAP Reconciliations Adjusted EBITDAX is a non-gaap financial measure. Roan defines Adjusted EBITDAX as net income (loss) adjusted for interest expense, depreciation, depletion, amortization and accretion, exploration costs, non-cash equity-based compensation expense, gain on early termination of derivative contracts, and non-cash loss on derivative contracts. Adjusted EBITDAX is presented as it allows management and analysts to more effectively evaluate Roan s operating performance and compare the results of its operations from period to period and to peers without regard to financing methods or capital structure. Adjusted EBITDAX should not be considered an alternative to net income (loss) as defined by GAAP. Net Debt is a non-gaap financial measure equal to long-term debt outstanding less cash on hand as of the date presented. Roan s computations of Adjusted EBITDAX and Net Debt may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts. Adjusted EBITDAX Reconciliation (in thousands) 1Q 2018 4Q 2017 Net Income (Loss) $35,081 $(9,176) Plus Adjustments: Interest Expense $1,799 $1,020 Depreciation, Depletion & Amortization 21,865 15,234 Exploration Expense 7,850 28,154 Net Debt Reconciliation (In thousands) 1Q 2018 4Q 2017 Long-Term Debt $206,639 $85,339 Less: Cash (2,743) (1,471) Net Debt $203,896 $83,868 Non-Cash Equity-Based Compensation 2,292 379 Gain on Early Termination of Derivative Contracts (377) - Non-Cash Loss on Derivative Contracts 5,476 9,501 Total Adjustments: $38,905 $54,288 Adjusted EBITDAX $73,986 $45,112 Annualized $295,944 $180,448 34
Reconciliation of Standardized Measure of Discounted Net Cash Flows to PV-10 PV-10 PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows of reserves. Roan s calculation of PV-10 herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes and including the impact of helium, rather than after income taxes and not including the impact of helium, using the average price during the 12- month period, determined as an unweighted average of the first-day-of-the-month price for each month. Roan s calculation of PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC. Proved Reserves ($ in millions) Dec 31, 2017 Standardized Measure of Discounted Net Cash Flows $668.3 Present Value of Future Net Income Tax Expense Discounted at 10% - PV-10 $668.3 Effects of Calculating Reserves and Pricing Using $65 WT & $2.75 HH 128.6 PV-10 of $65 WTI and $2.75 HH Proved Reserves 796.9 35
1Q 2018 Cash Margin Production Summary 1Q 2018 Oil Sales (MBbls/d) 11.6 Natural Gas Sales (MMcf/d) 98.7 NGLs Sales (MBbls/d) 9.7 Total (MBoe/d) (1) 37.7 Cash Margin Summary (in thousands) 1Q 2018 $ / Boe (1) Oil, Natural Gas and NGLs Sales Revenue $110,073 $32.42 Cash Operating Expenses: Production Expense $8,355 $2.46 Gathering, Transportation and Processing 9,103 2.68 Production Taxes 2,386 0.70 General and Administrative (excluding non-cash items) 11,728 3.46 Total Expenses: $31,572 $9.30 Cash Margin $78,501 $23.12 Cash Loss on Derivatives Contracts ($4,138) ($1.22) Gain on Early Termination of Derivative Contracts (377) (0.11) Adjusted EBITDAX $73,986 $21.79 1) Assumes a 6:1 Bbl:MMcf ratio 36