3Q 2018 Investor Presentation. November 2018

3Q 2018 Investor Presentation November 2018 1

Important Disclosures Forward-Looking Statements and Risk Factors The information in this presentation includes forward-looking statements. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words could, believe, anticipate, intend, estimate, expect, project and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on certain assumptions and expectations made by Roan Resources, Inc. ( Roan or the Company ), 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 the Company, which may cause actual results to differ materially from those implied or anticipated in the forward-looking statements. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements found in the Company s filings with the Securities and Exchange Commission, including its Current Report on Form 8-K, filed September 24, 2018 and any subsequently filed quarterly reports on Form 10-Q or current reports on Form 8-K. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, or incidental to the development, production, gathering and sale of oil, natural gas and NGLs. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks. You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this presentation. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this release. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or cost increases. Non-GAAP Measures Adjusted EBITDAX, Adjusted Net Income, Adjusted Net Income per Share, 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 ROAN and includes market data and other statistical information from sources believed by ROAN to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on ROAN s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although ROAN believes these sources are reliable, they have not independently verified the information and cannot guarantee its accuracy and completeness. 2

Roan Highlights Company Overview 46.5 MBoe/d net production (56% liquids) as of 3Q 18 Largest Contiguous Acreage Position in Merge 170,000 total net acres with 118,500 of contiguous acreage in the Merge ~80% of acreage is in the oil and liquids-rich windows in Merge Multi-decade inventory of highly economic locations 8 rigs running with ~4 frac crews Well-capitalized balance sheet with significant financial flexibility 1.3x 3Q 18 annualized leverage ratio, 16% net debt to total capitalization Expected to be free cash flow positive in 1H 2020 Average Daily Production (Mboe/d) 22.9 25.7 37.7 36.1 46.5 52-56 58-62 Acreage Position (Net Acres) Merge 118,500 SCOOP 26,700 STACK 7,500 Other 17,300 3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 (Estimate) 2018 Exit (Estimate) Total 170,000 3

3Q 2018 Highlights 3Q 18 corporate highlights Reorganization process closed to form publicly traded Roan Resources, Inc. Uplisted to NYSE on November 9, 2018 3Q 18 operational highlights Total production increased 30% QoQ to 46.5 MBoe/d; liquids production increased 35% QoQ Drilled 27 gross operated wells - 44.6 gross miles drilled - Averaged ~7.5 rigs Brought 26 gross operated wells online (eight with 90+ days of production) - 43% average oil for eight wells at peak 90-day rates compared to 28% for 2Q wells Standout recent wells include: - Doris 1-36-10-6-1XH: 30-day peak rate of 2,398 Boe/d (52% oil, 71% total liquids) normalized to a 10,000-foot lateral (actual 9,915-foot lateral) targeting the Mayes - Spectacular Bid 18-11-6 2H: 30-day peak rate of 3,997 Boe/d (46% oil, 81% total liquids), normalized to 10,000-foot lateral (actual 4,915- foot lateral) targeting the Mayes - First Woodford density test at the McNeff unit generating positive early results Spectacular Bid 18-11-6 2H Doris 1-36-10-6-1XH McNeff Unit 4

Roan Overview Large Scale, Contiguous Asset Base in a Premier Oil Basin 170,000 net acres located in the Merge, SCOOP and STACK plays in Central Oklahoma 118,500 highly contiguous acreage in the high return oil and liquids-rich windows of the Merge play Over 130 operated horizontal wells developed as of Sept. 2018, ranking Roan as the most active developer and producer in the Merge play Stacked pay with multiple well-delineated benches with superior reservoir properties Merge acreage is ~78% operated (1) and is ~82% held by production (HBP d), allowing for high impact full-field development with decades of high quality inventory Oil production priced off Cushing WTI with all-in differential of less than $1.50 per barrel, with opportunities to improve differential Attractive baseline well results established through horizontal development activity by Citizen and Linn Rate-of-Change Improvements in Development Program Roan s subsurface and development team leverage in-basin experience, extensive seismic, and enhanced well control to produce differentiated development model Roan s technical approach and experience offers visibility to significant improvements in wellhead productivity and cost savings 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 8 rigs 4Q 2017 to 4Q 2018 projected to deliver YoY production growth of ~110% Development program in the Merge de-risked through 215 producing wells (132 operated and 83 non-operated) Sizable current base production of ~46.5 MBoe/d as of 3Q 18 Best in Class Financial Flexibility Well-capitalized balance sheet with significant current production and cashflow; LQA leverage of 1.3x at 3Q 18; net debt to total capitalization of 16% $391MM of Net Debt (2) at 3Q 18 (all debt held in the credit facility); current borrowing base of $675MM Line of sight to free cash flow generation by 1H 2020 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 90 years of combined experience from EOG and other top tier operators 1) Assumes any unit in which we have leased a minimum of 37.5% of the acreage in the unit 2) Net Debt is a non-gaap measure, please see slide 26 for a reconciliation of these measures to the most directly comparable GAAP measure 5

Introduction to the Merge Merge Highlights: Geologic sweet spot of Oklahoma s premier unconventional basin Multiple identified landing zones (Mayes/Woodford) with additional upside potential in the Hunton and Springer Basin well results competitive with Tier 1 L48 plays Substantial de-risking through over 400 horizontal wells with opportunity of step change in results through implementation of best-in-class Roan approach More favorable rock properties in the Merge: 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 Merge has the best combination of the Mayes and Woodford Roan acreage 6

Roan s Premier Merge Acreage Position Premier Acreage in the Heart of the Merge Woodford Oil Gravity Map Multiple stacked drilling targets throughout acreage position Several well-developed benches in the Mayes with great porosity and permeability that has been de-risked by historic vertical production Significant thickness of Woodford with superior reservoir properties Significant operational control through the high-return oil window 245 operated sections (80+%) in the Merge are in the oil and liquids-rich windows Pore pressure gradients ranging from 0.45 0.65 psi/ft through core area High degree of operational control with ~78% of our Merge acreage operated (1) Contiguous acreage throughout leasehold Optimal for pad development and efficient surface operations Operated acreage position largely HBP d Development program not dictated by need to hold acreage API Oil: STACK Merge SCOOP Merge SCOOP STACK Other Total Operated Sections (1) 245 35 6 28 314 % HBP 82% 66% 97% 99% 81% % of Total Acreage Operated (1) 78% 42% 29% 67% 69% Roan acreage 1) Assumes any unit in which we have leased a minimum of 37.5% of the acreage in the unit 7

De-Risked Inventory Roan has a deep inventory to be developed Merge operated gross locations (1) at different well assumptions - 12 wells per section = 2,940 gross operated locations Illustrative Merge Density Potential (2) - 16 wells per section = 3,920 gross operated locations - 20 wells per section = 4,900 gross operated locations Merge density tests underway McNeff Unit - first 6-well equivalent Woodford density test producing - Early results are positive and consistent with offset operator results - Anticipate low decline rates for several months due to pressure management - No significant communication between wells Multiple pattern tests planned: - Testing up to 8 wells per unit in the Woodford - Testing up to 6 wells per unit in the Mayes - Testing multi-zone test in Mayes and Woodford SCOOP / STACK acreage offer additional operated development horizons Mayes (Sycamore) Woodford Base case development wells Upside development wells 1) Includes all 245 operated sections in Merge. Operation control assumed if leasehold exceeds 240 acres in a section and 1-mile units 2) Theoretical density diagram not depicted to scale or to reflect current or future density tests 8

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 70% Optimizes drilling performance Improved hydraulic stimulation performance Maximizes well productivity % In Target Zone 60% 50% 40% LNGG / Citizen Average 58% 30% 20% 10% 0% 1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101 106 111 116 121 126 131 136 141 146 66 operated gross drilled wells through 3Q 2018 58 wells producing 8 DUCs / wells completing LNGG/Citizen Wells (2015-2017) Wells Roan Wells (YTD 2018) 9

90-Day Distribution of Roan Wells Shows Outperformance 100% 80% 90-Day Cumulative Production Distribution Plot (1) Industry wells Roan selected, drilled & completed wells Roan average production up by ~27% 23 Roan selected, drilled and completed wells outperforming industry at 90 days: Roan Industry Well Count 23 231 Delta at 90 days P50 (Boe) 63,801 53,603 19% Average (Boe) 79,143 62,017 27% Ranking 60% 40% Roan P50 production up by ~19% P10 (Boe) 47,193 18,317 158% P90 (Boe) 116,625 115,283 1% P90/P10 2.47 6.29-61% 27% average uplift at 90 days equates to an additional ~$1MM (2) in gross revenue per well 20% 0% Roan P10 production up by ~158% 0 50,000 100,000 150,000 200,000 250,000 Cumulative Production (Boe) at 90-Days 23 fully operated wells with at 90 days of production: - 1,560 Boe/d (35% oil, 67% total liquids) 90-day peak production rate, normalized to 10,000 lateral, with an average lateral length of 7,685 1) Data on a 20:1 Boe basis, normalized to 10,000 lateral; industry data sourced from IHS and non-op data 2) Gross revenue assumes $60 WTI 10

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 30 27.3 30.0 - Proprietary mud program - Utilization and optimization of high performance motors - Contracting higher performance rigs Days 25 20 23.3 22.0 19.2 18.1 18.3 - Parameter optimization Current records indicate further improvements to come: 15 10 13.2 12.5 12.8 11.2 13.8 Record 2-mile Woodford lateral drilled in 11.2 days Record 2-mile Mayes lateral drilled in 9.4 days 5 0 1-Mile Mayes 1-Mile Woodford 2-Mile Mayes 2-Mile Woodford LNGG / Citizen 2Q'18 3Q'18 1) Data is based on 76 LNGG / Citizen wells, 21 2Q 18 Roan wells and 22 3Q 18 Roan wells. Wells with completed lateral lengths between 4,000 and 6,500 are designated 1 mile wells; wells with completed lateral lengths between 9,000 and 11,500 are designated as 2 mile wells; chart excludes a total of 9 Roan wells that are classified as 0.5, 1.5 or 2.5 mile wells; spud is drill out of surface casing 11

Superior Midstream & Marketing Position Crude Oil Takeaway Current Gas Takeaway Infrastructure Local Takeaway and Sales Optionality Acreage is advantageously located in close proximity to Cushing (~65 miles) and several refineries Large number of potential crude purchasers Current oil price deduct is less than $1.50 per barrel, and based on trucking transportation Considering strategic opportunities to market directly to Cushing marketplace Reviewing proposals to transport oil on pipe to Cushing Local Takeaway and Sales Optionality 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 Current capacity at 250 MMcf/d Blue Mountain has begun initial design and engineering of a second train EnLink Midstream looping gathering system and adding compression capacity in Roan producing area Increased takeaway solutions in Oklahoma in 2019 Basis hedges in place through 2Q 20 12

Financial Highlights Industry leading balance sheet and credit profile - LQA Leverage of <1.5x - 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 - Corporate recycle ratio (2) of 4.4x - Unhedged 3Q 18 cash margin (3) of ~$21 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) See slide 15 for calculation of recycle ratio 3) Please see slide 25 for calculation of cash margin 13

Roan s ROCE & ROE vs Industry Leading Peers ROCE ROE 15% 10% 2018 YTD ROCE (1) & 2019E EV / EBITDAX 5% 0% 15% 10% 9.8% 4.3x 5.7x 9.4% 2018 YTD ROE (1) & 2019E EV / EBITDA 5% ROAN 10.8% 4.3x Peer Average 5.7x 7.7% 12.8% 6.4x 11.5% 6.1x 7.8x 10.5% 10.2% 10.0% 9.1% 5.9x 5.7x 4.9x 7.8% 4.4x 7.5% 5.3x 4.9x 4.8% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 12.1% 6.1x 11.1% YTD ROCE 4.9x 6.4x 9.2% 2019E EV / EBITDA 5.9x 8.2% 8.0% 5.3x 5.7x 7.6% 6.3% 6.0% 4.4x 7.8x 1.0% 4.9x 8.0x 6.0x 4.0x 2.0x 8.0x 6.0x 4.0x EV / EBITDAX EV / EBITDAX 0% ROAN Peer Average Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 2.0x YTD ROE 2019E EV / EBITDA 1) Please see slide 29 for calculation of Roan s YTD ROCE and ROE Source: Public filings and Bloomberg Consensus. Peers include: APA, CDEV, CPE, CXO, DVN, MTDR, PE, PXD and WPX. 14

Merge Returns Drive Best-in-Class Efficiency 5 3Q 18 Peer Recycle Ratio (1) Comparison 4.5 4 4.4x 4.4x 4.2x 4.0x 4.0x 3.8x 3.5 3.2x 3 2.5 2 2.6x 2.5x 2.3x 2.0x 1.7x 1.5 1 0.5 0 Roan Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer-leading corporate capital efficiency Peers include: CDEV, CLR, CPE, CRZO, GPOR, JAG, LPI, MTDR, NFX, PE, WRD 1) Sourced from public filings; Recycle ratio is calculated as: (3Q 18 unhedged adjusted EBITDAX / 3Q 18 production)/(ye 17 proved undeveloped capital cost / undeveloped net reserves) 15

Capitalization & Credit Metrics Capitalization & Credit Metrics Peer 3Q'18 LQA Leverage (3) $MM 3Q 2018 Capitalization Cash Credit Facility Debt Total Debt Net Debt (1) Borrowing Base Amount (2) Total Capitalization Financial & Operating Metrics Quarterly Adjusted EBITDAX (1) LQA Adjusted EBITDAX (1) Production (MBoe/d) YE 17 PD PV10 Credit Metrics (1) Net Debt / LQA Adjusted EBITDAX Net Debt / PD PV10 Net Debt / Total Capital (4) Liquidity Borrowing Base (2) (Borrowings Outstanding) (Letters of Credit) Cash Available Liquidity $4 395 $395 $391 $675 $2,487 $75 $302 46.5 $668 1.3x 0.58x 16% $675 (395) - 4 $284 2.5x 2.2x 2.0x 2.0x 1.6x 1.6x 1.2x 1.3x 1.3x 1.4x 1.4x 1.5x 1.5x 1.5x 1.0x 0.7x 0.7x 0.5x 0.0x 1 2 3 ROAN 4 5 6 7 8 9 10 11 12 Peer 3Q'18 Net Debt / Total Capitalization (3)(4) 60% 50% 46% 50% 50% 40% 37% 37% 38% 28% 28% 31% 30% 20% 19% 16% 13% 13% 10% 0% 1 2 ROAN 3 4 5 6 7 8 9 10 11 12 1) Adjusted EBITDAX and Net Debt are non-gaap measures, please see slide 26 for a reconciliation of these measures to the most directly comparable GAAP measure 2) 3Q'18 Borrowing Base reflects amount effective from the Fall 2018 redetermination as of 9/27/18 3) Figures sourced from public filings and internal reports. LQA represents last quarter annualized. Peers include: AMR, CDEV, CLR, CPE, CRZO, GPOR, JAG, LPI, MTDR, NFX, PE and WRD 4) Net Debt / Total Capitalization calculated as (Total Debt - Cash) / (Total Liabilities + Book Equity) 16

Updated 2018 Guidance Guidance 1Q 18 Actual 2Q 18 Actual 3Q 18 Actual 4Q 18 Estimate FY 2018 Estimate Production (MBoe/d) 37.7 36.1 46.5 52-56 43-44 Total Liquids Production as % of total 56% 54% 56% ~57% ~56% LOE ($ per Boe) $2.46 $2.14 $3.44 $2.60 - $2.90 $2.70 - $2.80 Production Tax (% of Revenue) 2.2% 2.5% 5.2% 5.2% - 5.3% 3.9% - 4.1% Cash G&A ($ per Boe) $3.45 $3.12 $2.39 $2.10 - $2.40 $2.67 - $2.75 D&C Capex ($MM) $103.9 $144.3 $226.5 $175 - $195 $650 - $670 Other Capex ($MM) $4.8 $60.8 $17.7 $25 - $30 $110 - $115 Total Capex ($MM) $108.7 $205.1 $244.2 $200 - $225 $760 - $785 2018 exit rate production is projected to be between 58 62 MBoe/d Formal 2019 guidance to be provided with or before YE 18 results 17

Key Take-Aways Success Criteria Pure play operator with large acreage position in Merge oil and liquids-rich windows Ample midstream availability with WTI oil pricing Long-lived inventory with predictable production profiles that are high ROR Roan ~80% of Merge acreage is in oil and liquids-rich windows Transportation costs to Cushing < $1.50 per barrel; midstream providers adding capacity ~3,000 gross operated locations in Merge (12 wells per section) Strong base production ~46,500 Boe/d as of 3Q 18 Robust production growth with vision to free cash flow Projecting 110% YoY production growth; free cash flow by 1H 2020 Superior financial metrics LQA leverage ratio: 1.3x Top-tier, experienced in-basin operations team Seasoned team with combined 90+ years of experience 18

Contact Information Roan Resources: Investor Relations Alyson Gilbert Phone: 405-896-3767 Email: ir@roanresources.com 19

Appendix 20

Oklahoma Industry Activity Active Rigs by Operator in Oklahoma (1) Oklahoma Rig Activity (1) 20 18 16 14 12 10 8 6 4 2 0 19 10 8 8 6 6 5 4 4 4 3 3 2 2 2 2 Horizontal Drilling Permits in Oklahoma (1) 350 327 300 250 200 181 150 125 100 81 79 50 42 24 0 Kingfisher Grady Blaine McClain Canadian Garvin Stephens 1) Source: Drilling Info as of October 2018 21

Key Merge Well Results # Operator Well name IP-30 (1) (Boe/d) LL (ft.) % Oil 1 ROAN Collins 10-3-9-5 1XH 3,387 9,500 61% 14 15 2 ROAN Cowboy 1H-27-22 1,371 10,245 29% 3 ROAN Paxton 1H-30-19 1,784 10,175 28% 11 5 2 7 4 6 9 4 ROAN DKB 1H-31-30 1,905 9,990 27% 5 ROAN Dutch 1H-33-28 2,225 9,700 37% 6 ROAN Spectacular Bid 18-11-6 2H 3,998 4,915 46% 7 ROAN Barbour 11-14-10-7 1XH 2,313 9,975 21% 8 ROAN Campbell Farms 11-9-6 2H 2,680 4,915 34% 3 9 ROAN Doris 1-36-10-6-1XH 2,398 9,915 52% 8 1 10 ROAN Eight Belles 36-25-9-6 2XH 1,448 9,365 58% 11 XEC Meyers 1H-2821X 3,241 7,980 24% 13 10 12 EOG Curry 21X-1VH 1,662 10,600 91% 13 TPR Umbach Estate 1H-28-21 1,649 6,675 63% 14 JONE Bomhoff 2H20-12-7 3,412 4,425 41% 12 15 JONE Bomhoff 1H20-12-7 2,017 4,195 32% Wells that Roan has an interest in 1) IP-30 rates are normalized to 10,000 laterals. 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 22

Key SCOOP Non-Operated Well Results # Operator Well name IP-30 (1) (Boe/d) LL (ft.) % Oil 1 GPOR Pauline 6-27X22H 4,804 7,625 24% 2 CLR Triple H 2-30-31HS 3,573 9,900 85% 2 5 11 9 3 GPOR Bragg 3-35X02H 3,333 9,600 1% 10 6 8 13 4 GPOR Fowler 4N6W 3-9X16H 3,498 8,750 4% 5 CLR Triple H 3-30-31HS 2,577 10,200 86% 6 CLR Rowell 1-1-12XH 4,737 5,400 1% 7 CLR Silver Stratton 1-6-31-XH 2,421 10,040 35% 12 1 8 CLR Pudge 1-7-6XH 3,225 7,500 4% 9 CLR Triple H 4-30-31HS 2,371 10,200 88% 4 7 10 UNIT Harper Thomas 1-19H 4,700 5,140 87% 11 CLR Triple H 5-30-31HS 2,298 10,200 88% 12 GPOR Ernsteen 1-21X28H 2,979 7,600 22% 13 GPOR Ernsteen 2-21X28H 2,800 7,600 24% 3 *Roan has an interest in all listed wells 1) IP-30 rates are normalized to 10,000 laterals. Peak rolling 30-day rates for other operator wells are on a 3-stream basis; all wells assume a 6:1 Boe ratio 23

Current Hedge Summary As of November 9, 2018: Oil Gas Period Swap Volumes Hedged (MBbls) Swap (weighted average $) Swap Volumes Hedged (MMcf) Swap (weighted average $) Basis Volumes Hedged (MMcf) Basis (weighted average $) 4Q 2018 1,233 $57.09 8,004 $2.94 4,600 ($0.54) 2019 5,541 $59.86 36,500 $2.87 21,900 ($0.58) 2020 1,560 $63.14 12,325 $2.63 3,640 ($0.62) Period NGL Swap Volumes Hedged (MBbls) Swap (weighted average $) 4Q 2018 230 $34.03 2019 913 $34.03 24

2018 Cash Margin Production Summary 1Q 18 2Q 18 3Q 18 Oil Sales (MBbls/d) 11.5 9.6 11.8 Natural Gas Sales (MMcf/d) 99.0 100.6 124.1 NGLs Sales (MBbls/d) 9.7 9.7 14.0 Total (MBoe/d) (1) 37.7 36.1 46.5 Cash Margin Summary (in thousands) 1Q 18 $ / Boe (1) 2Q 18 $ / Boe (1) 3Q 18 $ / Boe (1) Oil, Natural Gas and NGLs Sales Revenue (2) $100,970 $29.72 $90,567 $27.55 $120,152 $28.09 Cash Operating Expenses: Production Expense $8,355 $2.46 $7,019 $2.14 $14,737 $3.44 Gathering, Transportation and Processing (2) - - - - - - Production Taxes 2,386 0.70 2,296 $0.70 6,210 $1.45 Cash General and Administrative (G&A) Expense (3) 11,728 3.46 10,251 3.12 10,244 2.39 Total Expenses: $22,469 $6.62 $19,566 $5.94 $31,191 $7.28 Cash Margin $78,501 $23.11 $71,001 $21.60 $88,961 $20.81 Cash Loss on Derivatives Contracts ($4,138) ($1.22) ($9,773) ($2.97) ($13,551) ($3.17) Gain on Early Termination of Derivative Contracts (377) (0.11) - - - - Adjusted EBITDAX $73,986 $21.78 $61,228 $18.64 $75,410 $17.64 1) Assumes a 6:1 Bbl:MMcf ratio 2) Please see slide 28 for reconciliation to new revenue recognition accounting standard adopted in 2018. 3) Cash G&A expense is a non-gaap measure, which is defined as total general and administrative expense as determined in accordance with GAAP less equity-based compensation expense. Cash G&A expense should not be considered as an alternative to, or more meaningful than, total general and administrative expense as determined in accordance with GAAP and may not be comparable to other companies similarly titled measures. 25

Non-GAAP Reconciliations Adjusted EBITDAX is a non-gaap financial measure. We define Adjusted EBITDAX as net income (loss) adjusted for interest expense, income tax expense, depreciation, depletion, amortization and accretion, exploration expense, non-cash equity-based compensation expense, gain (loss) on early termination of derivative contracts, and cash (paid) received upon settlement of derivative contracts. Adjusted EBITDAX is not a measure of net income (loss) as determined by GAAP. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus, we have not incurred historical income tax expenses. 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 2Q 2018 3Q 2018 Net Income (Loss) $35,081 ($22,757) ($301,240) Plus Adjustments: Interest Expense $1,799 $1,087 $2,092 Income tax expenses - - 299,662 Net Debt Reconciliation (In thousands) 1Q 2018 2Q 2018 3Q 2018 Long-Term Debt $206,639 $284,639 $394,639 Less: Cash (2,743) (24,376) (3,900) Net Debt $203,896 $260,263 $390,739 Depreciation, Depletion, Amortization & Accretion 21,865 24,601 37,164 Exploration Expense 7,850 10,633 11,646 Non-Cash Equity-Based Compensation 2,292 2,835 2,933 Cash (Paid) Received Upon Settlement of (377) - - Derivative Contracts (1) Non-Cash Loss on Derivative Contracts 5,476 44,829 23,153 Total Adjustments: $38,905 $83,985 $376,650 Adjusted EBITDAX $73,986 $61,228 $75,410 Annualized $295,944 $244,912 $301,640 1) Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity 26

Non-GAAP Reconciliations Adjusted net income and adjusted net income per share are non-gaap performance measures. The Company defines adjusted net income and adjusted net income per share as net (loss) income and net (loss) income per share excluding non-cash gains or losses on derivatives, gains on early terminations of derivative contracts, gain on the sale of property, certain exploration expenses and the income tax expense associated with our deferred tax liability as a result of the Reorganization. Management uses adjusted net income and adjusted net income per share as an indicator of the Company's operational trends and performance relative to other oil and natural gas companies. Adjusted net income and adjusted net income per share should not be considered an alternative to net income (loss), operating income, or any other measure of financial performance presented in accordance with GAAP or as an indicator of our operating performance. Adjusted Net Income Reconciliation For the Three Months Ended September 30, 2018 September 30, 2017 (in thousands) (per diluted share) (in thousands) (per diluted share) Net Income (Loss) ($301,240) ($1.97) $10,710 $0.11 Adjusted for: Loss (gain) on Derivative Contracts 36,704 0.24 (131) 0.00 Cash (paid) Received Upon Settlement of Derivative Contracts (1) (13,551) (0.09) - - Exploration Expense 11,171 0.07 4,229 0.04 (Gain) Loss on Sale of Oil & Natural Gas Properties - - (838) (0.01) Income Tax Expense Resulting from Reorganization 299,662 1.96 - - Total Tax Effect of Adjustments (2) (571) (0.00) - - Adjusted Net Income $32,175 $0.21 $13,970 $0.14 Adjusted Net Income Reconciliation For the Nine Months Ended September 30, 2018 September 30, 2017 (in thousands) (per diluted share) (in thousands) (per diluted share) Net Income (Loss) ($288,916) ($1.90) $28,837 $0.35 Adjusted for: Loss (gain) on Derivative Contracts 100,920 0.66 (2,385) (0.03) Cash (paid) Received Upon Settlement of Derivative Contracts (1) (27,839) (0.18) 130 0.00 Exploration Expense 25,642 0.17 4,475 0.05 (Gain) Loss on Sale of Oil & Natural Gas Properties - - (838) (0.01) Income Tax Expense Resulting From Reorganization (2) 299,662 1.97 - - Total Tax Effect of Adjustments (2) (571) (0.00) - - Adjusted Net Income $108,898 $0.72 $30,219 $0.36 1) Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity 2) Computed by applying a combined federal and state statutory tax rate of 25.7% for the period subsequent to the Reorganization. No tax effect is presented for periods prior to the Reorganization 27

Revenue Recognition Reconciliation The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The adoption does not have a material impact on the timing of the Company s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company s presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08. The following table shows the impact of the adoption of ASC 606 on the Company s current period results as compared to the previous revenue recognition standard, ASC Topic 605, Revenue recognition ( ASC 605 ): Three Months Ended September 30, 2018 Under ASC 606 Under ASC 605 (in thousands) (per Boe) (in thousands) (per Boe) Revenues: Oil sales Natural gas Natural gas liquid sales $74,987 $18,059 $27,106 $68.86 $1.58 $21.08 $75,062 $21,739 $35,195 $68.93 $1.90 $27.37 Operating expenses Gathering, transportation and processing - - $11,844 $2.77 Nine Months Ended September 30, 2018 Under ASC 606 Under ASC 605 (in thousands) (per Boe) (in thousands) (per Boe) Revenues: Oil sales Natural gas Natural gas liquid sales $197,356 $48,956 $65,377 $65.70 $1.66 $21.49 $197,431 $60,919 $83,735 $65.72 $2.07 $27.53 Operating expenses Gathering, transportation and processing - - $30,396 $2.77 28

Year-to-Date ROE and ROCE Reconciliation ROE and ROCE For the Nine Months Ended September 30, 2018 ($ in millions) Adjusted Net Income $108.9 Annualized Adjusted Net Income $145.2 3Q Equity $1,343.8 ROE 10.8% Adjusted EBITDAX $210.6 Less: DD&A (83.6) Adjusted EBIT $127.0 Annualized EBIT $169.3 Net Debt $390.7 3Q Equity $1,343.8 Total $1,734.6 ROCE 9.8% 29

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