2Q 2019 Investor Presentation

August 2019

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 annual report on Form 10-K, 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, cash G&A 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 2Q 2019 Highlights

Enhanced liquidity by ~$100MM Production of 50.8 MBoe/d (26% oil, through term loan facility 29% NGLs, 45% gas), up ~4% QoQ

Adjusted EBITDAX(1) of ~$79.3MM, Drilled 17 wells(2) and turned online 22 up 9% QoQ wells(3)

CAPEX of ~$114MM, down ~34% Drill and completion costs per foot QoQ reduced by 25% and 20%, respectively, QoQ

Entered into definitive agreements LOE of $2.44 per Boe, down ~28% for crude oil to be gathered, blended QoQ and shipped, expected to decrease crude transportation costs on gathered barrels by ~50%

1) Adjusted EBITDAX is a non-GAAP measure, please see slide [21] for a reconciliation of this measure to the most directly comparable GAAP measure 2) Gross, operated wells that have been rig released 3) Gross, operated wells 3 Roan Snapshot

Company Overview Largest Contiguous Acreage Position in Core of Anadarko Basin • ~50.8 MBoe/d current net production(1) with 26% being oil Acreage Position • 3 rigs running (Net Acres)

• 22 wells turned online 2Q’19 Merge 117,300 • 2Q’19 Adjusted EBITDAX(2) of ~$79.3MM SCOOP 27,200 STACK 7,400 • ~$150 million of liquidity as of 6/30/19 Other 30,100 • Well hedged for 2019 with over 95% of oil hedged at $60.39 and STACK Total 182,000 ~75% of gas hedged at $2.90 • Focused on achieving free cash flow positive by YE 2019 while growing production 15% to 22% FY 2018 to FY 2019 • ~117,300 of contiguous acreage in the Merge ‒ ~75% of acreage is in the oil and liquids-rich windows in Merge ‒ ~66% average working interest in Merge MERGE

Average Daily Production (MBoe/d)

54.1 46.5 48.9 50.8 37.7 36.1 SCOOP 25.7

4Q'17 1Q'18 2Q'18 3Q'18 4Q'18 1Q'19 2Q'19 48 rigs running in the Anadarko Basin on this map 1) Current net production is as of 2Q’19 4 2) Adjusted EBITDAX is a non-GAAP measure, please see slide [21] for a reconciliation of this measure to the most directly comparable GAAP measure 2019 – Focus, Focus, Focus

Liquidity • Focus on enhancing current liquidity position - Secured $100MM term loan facility • Focus on achieving cash flow neutrality/positive by YE’19

Results • Focus on optimizing locations and well spacing • Focus on delivering on guidance - 2Q’19 beat on production, CAPEX & EBITDAX

Strategic • Exploring strategic alternatives to enhance value for shareholders Alternatives - Outright sale - Basin consolidation - Non-core, credit-enhancing asset divestitures • Focus on reducing completed well costs - Currently trending at ~$7MM, below original projections Costs • Focus on reducing LOE and G&A - LOE down ~28% QoQ; G&A down ~22% QoQ

5 2Q 2019 Results

2Q 2019 results: 2Q 2019 Activity Map: • All 22 gross operated wells turned online: Red Bullet / Earl Average per well 30-day IP rate of 1,165 Boe/d (42% • (6 wells) oil, 23% NGLs, 35% gas) from a normalized 10,000- foot lateral (4 wells) • Average well cost of ~$7.3 million Victory Slide (3 wells) Highlight 2Q 2019 results: Mad Play • Mad Play unit: (4 wells) • Average per well 30-day IP rate of 1,601 Boe/d (44% WEST oil, 20% NGLs, 36% gas) from a normalized 10,000- CENTRAL foot lateral EAST • Red Bullet / Silver Charm unit: • Average per well 30-day IP rate of 1,545 Boe/d (41% oil, 26% NGLs, 33% gas) from a normalized 10,000- foot lateral • Earl unit (3 Mayes wells): • Average per well 30-day IP of 1,466 Boe/d (39% oil, 24% NGLs, 37% gas) from a normalized 10,000-foot lateral • Victory Slide (2 Mayes wells): Zenyatta • Average per well 30-day IP rate of 1,170 Boe/d (67% (2 wells) oil, 15% NGLs, 18% gas) from a normalized 10,000- foot lateral • Zenyatta unit: • Average per well 30-day IP rate of 1,104 Boe/d (32% oil, 32% NGLs, 36% gas) from a normalized 10,000- foot lateral 6 Merge Cross Section

Multiple zones Required Multiple zones possible where Reservoir is present Reservoir acting as one zone

WEST CENTRAL Upper EAST Mayes Upper Mayes

Lower Lower Lower Mayes Mayes Mayes

Woodford Woodford

Merge Central: Merge East: Merge West: • Multiple zones possible where quality • One primary target zone Multiple zones are required • reservoir is present and sufficient • Target Lower Mayes for access due to quality reservoir and thickness to both Mayes and Woodford sufficient thickness • Target Lower Mayes, Upper Mayes • Target Lower Mayes, Upper and Woodford where high quality Mayes and Woodford reservoir exists

7 West Merge - Mad Play Unit

Mad Play unit: • Average per well 30-day IP rate of 1,601 Boe/d (44% oil, 20% NGLs, 36% gas) from a normalized 10,000-foot lateral from 4 wells WEST EAST • Average per well 90-day IP rate of Mad Play 1,240 Boe/d (42% oil, 20% NGLs, 38% unit gas) CENTRAL • Actual average lateral length of 6,780 feet • 2 Woodford / 2 Mayes wells drilled; 500’ horizontal spacing between wellbores • Average well costs of under $7MM per Mad Play unit (7-well design) well Mayes • First unit in West Merge, considerable operated running room in this area for Roan Future wells Future units will target Upper Mayes, Lower Mayes and Woodford

Woodford

8 Note: Offset well rates are 30-day IP rates normalized to 10,000’ West Merge – Red Bullet / Silver Charm

Red Bullet / Silver Charm unit: Red • Average per well 30-day IP rate Bullet / of 1,545 Boe/d (41% oil, 26% Silver NGLs, 33% gas) from a Charm normalized 10,000-foot lateral WEST EAST from 4 wells

• Actual average lateral length of CENTRAL 9,500 feet • 2 Woodford / 2 Mayes wells drilled; 800’ to 1,160’ horizontal spacing and ~200 vertical spacing between wellbores • Average well costs of ~$8MM Red Bullet / Silver Charm unit (5-well design) per well Mayes • Turned to first sales middle of June Future units will target Upper Mayes, Lower Mayes and Woodford

Woodford

9 Central Merge - Earl Unit

Earl unit (3 Mayes wells): • Average per well 30-day IP of 1,466 Boe/d (39% oil, 24% NGLs, 37% gas) from a normalized 10,000-foot lateral for the 3 Mayes wells WEST • Average per well 90-day IP of 1,222 EAST Boe/d (32% oil, 24% NGLs, 44% gas) Earl unit • Actual average lateral length of 10,160 CENTRAL feet • Average well costs of approximately $7.4MM per well

• 3 Woodford / 3 Mayes wells; 500’-800’ horizontal spacing between wellbores Earl unit (6 wells) • Learning: the 3 Woodford wells Mayes were not optimal because Mayes wells communicated with the Woodford due to the Woodford wells being spaced too close to the Mayes wells

Woodford

10 Note: Offset well rates are 30-day IP rates normalized to 10,000’ East Merge - Victory Slide

Victory Slide (2 Mayes wells): • Average per well 30-day IP rate of 1,170 Boe/d (67% oil, 15% NGLs, 18% gas) from a normalized 10,000- foot lateral for the 2 Mayes wells WEST • Average per well 60-day IP rate of EAST 1,091 Boe/d (64% oil, 17% NGLs, 19% gas) CENTRAL • Actual average lateral length of 9,900’ 2Q’19 Victory • Average well costs of ~$6MM per well Slide wells

• Woodford well not optimal for unit • Learning: suboptimal completion design for rock Victory Slide • Extensive operated running room in Mayes this area for Roan • Several strong offset operated producing wells Future wells Woodford

11 Note: Offset well rates are 30-day IP rates normalized to 10,000’ Southern SCOOP - Zenyatta

Zenyatta: • Average per well 30-day IP rate of 1,104 Boe/d (32% oil, 32% NGLs, 36% gas) from a Zenyatta normalized 10,000-foot lateral • Average per well 90-day IP of 1,004 Boe/d (27% oil, 34% NGLs, 39% gas) • Actual average lateral length of 9,750 feet • 2 Woodford wells drilled with ~1,000’ horizontal spacing between wellbores Zenyatta pad (2 wells) • Tested two different zones within the Woodford Upper Woodford

• Multiple potential benches for Middle Woodford future drilling

12 Anticipated Remaining 2019 Drill Schedule

2019 anticipated drill plans: 2019 Focused Activity Map: • Activity focused in core areas of the Merge

• Barbara Campbell – completed drilling & will be WEST CENTRAL EAST turned to first sales in August (3 Mayes wells)

• Battleship pad (3 Mayes wells) • pad (4 Mayes wells) Northern • – completed drilling (2 Mayes wells) Dancer Skywalker & Tater • Don’s Ranch – completed drilling & will be turned to Gallant first sales in August(3 Mayes wells) Fox Finn • Duke (3 Woodford wells) Birdstone (completed drilling) • Eight Belles (4 Mayes wells) • Finn (3 Mayes wells) Don’s Duke Battleship Ranch • (2 Mayes wells) (completed drilling) • (3 Mayes well) Big Brown Barbara • Omaha (2 Woodford wells, 1 Mayes well) Campbell Eight (completed drilling) • Skywalker (2 Mayes wells) Belles

• Tater (2 Mayes wells) ROAN DRILL UNIT ROAN LEASEHOLD • Unbridled (2 Mayes wells, 1 Woodford well) • Whirlaway (2 Mayes wells, 1 Woodford)

• Several strong offset producing wells 13 10+ Years of Quality Inventory

• 2018 tested Woodford and Mayes designs, co-completions and independent spacing

STACK • 2019 program will co-develop of Woodford and Mayes to produce maximum unit efficiency within our large, contiguous acreage position

MERGE • Operated and non-operated spacing tests have demonstrated unit intensity of 5 to 8 wells will appropriately balance unit returns and per well capital efficiency

• Provides 10+ years of drilling at SCOOP current pace

1) Operation control assumed if leasehold exceeds 37.5% working interest in a unit 14 2) Excludes horizontal developed locations 2019 Cost Optimization

Strategic focus on reducing completed well costs • ~$200k reduction in drilling costs 2019 improvement in per well CWC ($ in MM) : • Decreased drill times $9.0 $8.5 ~$0.2 • Increased equipment efficiency ~$0.8 • ~$800k reduction in completion costs $7.5 ~$0.5 ~$7.0 • Service cost reductions • Design optimization $6.0 • In-basin sand • Recent 2-mile well completions have come in at ~$7MM per well • ~$500k better than 2019 target • Further design optimization $3.0 Strategic focus on reducing operating costs • LOE • Water disposal agreement with Blue Mountain Midstream began early 2Q’19, which we expect will $0.0 save ~$8MM in 2019 2018 A Drilling Completion 2019 Target 2019 Cost Current CWC • G&A Reductions Reductions Reductions • Focus on overall reduction of G&A costs

15 Updated 2019 Guidance Summary

May 2019 Updated 2019 2019 Plan Highlights Guidance Guidance Total Capex ($MM) $515 - $555 $495 - $525 • Reducing capital activity to focus Production (MBoe/d) 51.5 – 55.5 50.5 – 53.5 on generating free cash flow by Oil Mix 25.5% – 27.5% 25.5% – 27.5% fourth quarter 2019 Liquids Mix 51.5% – 59.5% 51.5% – 59.5% • Capital activity anticipated to be LOE ($/Boe) $2.90 - $3.20 $2.80 - $3.10 Cash G&A ($/Boe)(1) (non-GAAP) $1.95 - $2.15 $2.00 - $2.20 $495 - $525MM, a ~34% Production Taxes (% of Production Revenues) 5.2% – 5.4% 5.2% – 5.4% reduction as compared to 2018 Gross Operated Spuds (Rig Released) ~60 ~60 and $30MM lower from the top Gross Operated Wells Turned Online ~70 ~70 end of the range of previous Capex ($ in MM) Production (MBoe/d) guidance

• Development activity expected to $773 50.5 – 53.5 result in ~15%-22% Y/Y production $495 – $525 43.7 growth

• 2H’19 wells are focused on de- risked core areas and optimal well spacing 2018 2019 (Estimate) 2018 2019 (Estimate)

Notes: Guidance now assumes ethane rejection for remainder of year 16 1) Cash G&A is a non-GAAP measure and is equal to total G&A less equity-based compensation expense and expense for allowance for doubtful accounts. Appendix

17 Merge Spacing Assumptions

Merge is divided into 3 regions Gross Thickness (Mayes+Woodford) • East – Woodford + Mayes < 275’ • Central – Woodford + Mayes = 275’ – 375’ WEST • West - Woodford + Mayes > 375’ Spacing assumptions for each region A • East = ~5 wells/unit EAST ‒ One primary target zone (Lower Mayes) • Central = 5-7 wells/unit ‒ Multiple zones possible (Upper Mayes, Lower Mayes, Woodford) CENTRAL A’ • West = 8 wells/unit (potential upside) ‒ Multiple zones (Upper Mayes, Lower Mayes, Woodford)

WEST CENTRAL EAST A A’

Upper Mayes Lower Mayes Woodford

Hunton 375’ 275’ 18 Updated Production Guidance Walk

Ethane recovery vs 2019 Guidance as of: May 14, 2019 August 7, 2019 rejection impact Full-Year Production (MBoe/d) 51.5 – 55.5 (~1.9) 50.5 – 53.5 Oil Mix 25.5% – 27.5% - 25.5% - 27.5% Liquids Mix 51.5% – 59.5% - 51.5% - 59.5%

Reasons for changes in production guidance

• May 2019 guidance assumed ethane recovery for June and 2H’19

• Updated guidance now reflects ethane rejection for June and 2H’19

• Ethane recovery vs. rejection impacts monthly production by ~3.3 MBoe/d;

• ~3.3 MBoe/d x 7/12 = ~1.93

19 Current Hedge Summary

As of August 7, 2019:

3Q19 4Q19 Bal 2019 2020 2021 Oil Hedges Volume Hedged Daily (Bbls/d) 14,151 13,051 13,601 9,370 4,740 Average Hedge Price ($/Bbl) $60.04 $60.74 $60.39 $60.57 $56.08

Natural Gas Hedges Volume Hedged Daily (MMBtu/d) 110,000 120,000 115,000 43,730 9,863 Average Hedge Price ($/MMBtu) $2.91 $2.90 $2.90 $2.64 $2.86

NGL Hedges Volume Hedged Daily (Bbls/d) 3,000 3,000 3,000 1,500 - Average Hedge Price ($/Bbl) $32.25 $32.25 $32.25 $24.50 -

Gas Basis Hedges Volume Hedged Daily (MMBtu/d) 80,000 80,000 80,000 30,000 - Average Hedge Price ($/MMBtu) ($0.60) ($0.60) ($0.60) ($0.49) -

20 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 (benefit) expense, depreciation, depletion, amortization and accretion, exploration expense, non-cash equity-based compensation expense, aborted offering costs expense, severance and employee matters expense, expense for allowance for doubtful accounts, (gain) loss on sale of other assets, loss (gain) on derivative contracts, and cash (paid) received upon settlement of derivative contracts, including amounts on contracts settled prior to contract maturity. 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 on the credit facility and term loan, exclusive of any discounts or fees, less cash on hand.

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 Net Debt Reconciliation

(in thousands) 1Q 2019 2Q 2019 2Q 2018 (In thousands) 2Q 2019 Net Income (Loss) ($58,056) $27,246 ($22,757) Credit Facility $659,639 Plus Adjustments: Term Loan, net 44,924 Unamortized original issue discount Interest Expense 1,250 6,744 8,462 1,087 on Term Loan Deferred financing costs on Term Income Tax (Benefit) Expense (22,897) 13,410 - Loan 3,826 Depreciation, Depletion, Amortization & Accretion 41,572 44,893 24,601 Funded Debt $709,639 Exploration Expense 12,488 11,406 10,633 Less: Cash 5,428 Non-Cash Equity-Based Compensation 3,065 (3,222) 2,835 Net Debt $704,211 Aborted Offering Costs - 2,155 - Severance and Employee Matters - 687 -

Allowance for Doubtful Accounts 1,481 3,857 - (Gain) Loss on Sale of Other Assets (664) 50 -

Loss (Gain) on Derivative Contracts 83,642 (37,054) 54,602 Cash Received (Paid) Upon Settlement of Derivative Contracts(1) 5,382 7,361 (9,773) Adjusted EBITDAX $72,757 $79,251 $61,228 Annualized $291,028 $317,005 $244,912 21 1) Includes cash received upon settlement of derivative contracts prior to the original contractual maturity Investor Relations Alyson Gilbert Phone: 405-896-3767 Email: [email protected]

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