3Q 2018 Investor Presentation November 2018 1 Important - - PowerPoint PPT Presentation

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November 2018

3Q 2018 Investor Presentation

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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

• f 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

• f 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

• ther 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

• therwise 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.

Important Disclosures

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Roan Highlights

Company Overview Largest Contiguous Acreage Position in Merge

Acreage Position

(Net Acres)

Merge 118,500 SCOOP 26,700 STACK 7,500 Other 17,300 Total 170,000

 46.5 MBoe/d net production (56% liquids) as of 3Q’18  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

22.9 25.7 37.7 36.1 46.5

3Q'17 4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 (Estimate) 2018 Exit (Estimate)

Average Daily Production (Mboe/d)

52-56 58-62

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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

Doris 1-36-10-6-1XH Spectacular Bid 18-11-6 2H McNeff Unit

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Roan Overview

 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 Large Scale, Contiguous Asset Base in a Premier Oil Basin Rate-of-Change Improvements in Development Program Ample, Organic Growth Potential, Supported by Large Base Production Best in Class Financial Flexibility Experienced Management Team  Attractive baseline well results established through horizontal development activity by Citizen and Linn  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  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  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  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

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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 Stratigraphic Cross Section Schematic A A A’ A’

Roan acreage

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

Merge

More favorable rock properties in the Merge: Merge has the best combination of the Mayes and Woodford

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Roan’s Premier Merge Acreage Position

 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

• perated(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

Woodford Oil Gravity Map

API Oil: Roan acreage

STACK Merge SCOOP

Premier Acreage in the Heart of the Merge

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%

1) Assumes any unit in which we have leased a minimum of 37.5% of the acreage in the unit

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De-Risked Inventory

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

Mayes (Sycamore) Woodford

Illustrative Merge Density Potential(2)

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
• 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
• perator 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

Base case development wells Upside development wells

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Operational Advancements: Targeting

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 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

% In Target Zone Wells

LNGG/Citizen Wells (2015-2017) Roan Wells (YTD 2018)

Geosteering Comparison

Roan Average 95% LNGG / Citizen Average 58%

Lateral targeting has improved dramatically since the Roan team assumed operations Advantages to successful targeting

• Optimizes drilling performance
• Improved hydraulic stimulation

performance

• Maximizes well productivity

66 operated gross drilled wells through 3Q 2018

• 58 wells producing
• 8 DUCs / wells completing

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27% average uplift at 90 days equates to an additional ~$1MM(2) in gross revenue per well 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’

90-Day Distribution of Roan Wells Shows Outperformance

Roan Industry Delta at 90 days Well Count 23 231 P50 (Boe) 63,801 53,603 19% Average (Boe) 79,143 62,017 27% P10 (Boe) 47,193 18,317 158% P90 (Boe) 116,625 115,283 1% P90/P10 2.47 6.29

• 61%

0% 20% 40% 60% 80% 100% 50,000 100,000 150,000 200,000 250,000

Ranking Cumulative Production (Boe) at 90-Days

90-Day Cumulative Production Distribution Plot(1)

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

Industry wells Roan selected, drilled & completed wells Roan average production up by ~27% Roan P50 production up by ~19%

23 Roan selected, drilled and completed wells outperforming industry at 90 days:

Roan P10 production up by ~158%

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Operational Advancements: Drill Times

Since taking over drilling operations in January, Roan has improved program average drill times by ~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

• Contracting higher performance

rigs

• Parameter optimization

Current records indicate further improvements to come:

• Record 2-mile Woodford lateral drilled

in 11.2 days

• Record 2-mile Mayes lateral drilled in

9.4 days

Drill Time Comparison: Spud to Total Depth(1)

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

23.3 22.0 27.3 30.0 12.5 12.8 18.1 18.3 13.2 11.2 13.8 19.2 5 10 15 20 25 30 35 1-Mile Mayes 1-Mile Woodford 2-Mile Mayes 2-Mile Woodford Days LNGG / Citizen 2Q'18 3Q'18

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Superior Midstream & Marketing Position

 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  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 Crude Oil Takeaway Current Gas Takeaway Infrastructure Local Takeaway and Sales Optionality

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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

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Roan’s ROCE & ROE vs Industry Leading Peers

2018 YTD ROCE(1) & 2019E EV / EBITDAX

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.

2018 YTD ROE(1) & 2019E EV / EBITDA

9.8% 9.4% 12.8% 11.5% 10.5% 10.2% 10.0% 9.1% 7.8% 7.5% 4.8% 4.3x 5.7x 6.4x 6.1x 7.8x 4.9x 5.9x 5.7x 4.4x 5.3x 4.9x 2.0x 4.0x 6.0x 8.0x 0% 5% 10% 15% ROAN Peer Average Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 YTD ROCE 2019E EV / EBITDA 10.8% 7.7% 12.1% 11.1% 9.2% 8.2% 8.0% 7.6% 6.3% 6.0% 1.0% 4.3x 5.7x 6.1x 4.9x 6.4x 5.9x 5.3x 5.7x 4.4x 7.8x 4.9x 2.0x 4.0x 6.0x 8.0x 0% 5% 10% 15% ROAN Peer Average Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 YTD ROE 2019E EV / EBITDA

ROCE ROE EV / EBITDAX EV / EBITDAX

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Merge Returns Drive Best-in-Class 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)

3Q’18 Peer Recycle Ratio(1) Comparison

4.4x 4.4x 4.2x 4.0x 4.0x 3.8x 3.2x 2.6x 2.5x 2.3x 2.0x 1.7x 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 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

16 0.7x 0.7x 1.2x 1.3x 1.3x 1.4x 1.4x 1.5x 1.5x 1.6x 1.6x 2.0x 2.2x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 1 2 3 4 5 6 7 8 9 10 11 12 13% 13% 16% 19% 28% 28% 31% 37% 37% 38% 46% 50% 50% 0% 10% 20% 30% 40% 50% 60% 1 2 3 4 5 6 7 8 9 10 11 12

Capitalization & Credit Metrics

Capitalization & Credit Metrics Peer 3Q'18 LQA Leverage(3) Peer 3Q'18 Net Debt / Total Capitalization(3)(4)

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)

ROAN

ROAN

$MM 3Q 2018 Capitalization Cash Credit Facility Debt Total Debt Net Debt(1) Borrowing Base Amount(2) Total Capitalization $4 395 $395 $391 $675 $2,487 Financial & Operating Metrics Quarterly Adjusted EBITDAX(1) LQA Adjusted EBITDAX(1) Production (MBoe/d) YE’17 PD PV10 $75 $302 46.5 $668 Credit Metrics(1) Net Debt / LQA Adjusted EBITDAX Net Debt / PD PV10 Net Debt / Total Capital(4) 1.3x 0.58x 16% Liquidity Borrowing Base(2) (Borrowings Outstanding) (Letters of Credit) Cash Available Liquidity $675 (395)

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$284

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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

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Key Take-Aways

Success Criteria Roan

Pure play operator with large acreage position in Merge oil and liquids-rich windows ~80% of Merge acreage is in

• il and liquids-rich windows

Ample midstream availability with WTI oil pricing Transportation costs to Cushing < $1.50 per barrel; midstream providers adding capacity Long-lived inventory with predictable production profiles that are high ROR ~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

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Contact Information

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

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Appendix

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Oklahoma Industry Activity

Horizontal Drilling Permits in Oklahoma(1)

1) Source: Drilling Info as of October 2018

Oklahoma Rig Activity(1) Active Rigs by Operator in Oklahoma(1)

19 10 8 8 6 6 5 4 4 4 3 3 2 2 2 2 2 4 6 8 10 12 14 16 18 20 327 181 125 81 79 42 24 50 100 150 200 250 300 350

Kingfisher Grady Blaine McClain Canadian Garvin Stephens

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Key Merge Well Results

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

# Operator Well name IP-30(1) (Boe/d) LL (ft.) % Oil 1 ROAN Collins 10-3-9-5 1XH 3,387 9,500 61% 2 ROAN Cowboy 1H-27-22 1,371 10,245 29% 3 ROAN Paxton 1H-30-19 1,784 10,175 28% 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% 9 ROAN Doris 1-36-10-6-1XH 2,398 9,915 52% 10 ROAN Eight Belles 36-25-9-6 2XH 1,448 9,365 58% 11 XEC Meyers 1H-2821X 3,241 7,980 24% 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% 15 JONE Bomhoff 1H20-12-7 2,017 4,195 32%

14 15 13 12 1 5 3 11 6 9 2 4 7 8 10

Wells that Roan has an interest in

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Key SCOOP Non-Operated Well Results

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

3 7 4 1 12 13 6 10 8 11 9 2 5

# 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% 3 GPOR Bragg 3-35X02H 3,333 9,600 1% 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% 8 CLR Pudge 1-7-6XH 3,225 7,500 4% 9 CLR Triple H 4-30-31HS 2,371 10,200 88% 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%

*Roan has an interest in all listed wells

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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 $) 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) NGL Period Swap Volumes Hedged (MBbls) Swap (weighted average $) 4Q 2018 230 $34.03 2019 913 $34.03 As of November 9, 2018:

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2018 Cash Margin

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.

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

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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

• ur 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

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 Derivative Contracts(1) (377)

• 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

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

1) Excludes cash received upon settlement of derivative contracts prior to the original contractual maturity

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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 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

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

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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,

• r 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

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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%

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