2Q 2019 Investor Presentation August 2019 1 Important Disclosures - PowerPoint PPT Presentation

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 3) Gross, operated wells

Roan Snapshot Largest Contiguous Acreage Position in Core of Anadarko Basin Company Overview • ~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 SCOOP 27,200 • 2Q’19 Adjusted EBITDAX (2) of ~$79.3MM 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 50.8 46.5 48.9 SCOOP 37.7 36.1 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 4 1) Current net production is as of 2Q’19 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 • Focus on enhancing current liquidity position Liquidity - 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: Earl Red Bullet / • Average per well 30-day IP rate of 1,165 Boe/d (42% (6 wells) Silver Charm oil, 23% NGLs, 35% gas) from a normalized 10,000- (4 wells) foot lateral Victory Slide • Average well cost of ~$7.3 million (3 wells) Highlight 2Q 2019 results: Mad Play (4 wells) • Mad Play unit: WEST • Average per well 30-day IP rate of 1,601 Boe/d (44% CENTRAL oil, 20% NGLs, 36% gas) from a normalized 10,000- 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 (2 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 • 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 EAST Upper 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 WEST lateral from 4 wells EAST Mad Play • Average per well 90-day IP rate of unit 1,240 Boe/d (42% oil, 20% NGLs, 38% CENTRAL gas) • Actual average lateral length of 6,780 feet • 2 Woodford / 2 Mayes wells drilled; 500’ horizontal spacing between wellbores Mad Play unit (7-well design) • Average well costs of under $7MM per well Mayes • First unit in West Merge, considerable operated running room in this area for Future Roan 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’