Bank of America Merrill Lynch Energy Credit …

1 Bank of America Merrill LynchEnergy Credit ConferenceJune 6, 20182 Forward Looking StatementThis presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, anticipate, plan, intend, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation.

2 These statements are based on certain assumptions made by the Company based on management s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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 expressed by the forward-looking statements. These include risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company s business plan, the Company s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected.

3 Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this communication, the Company uses the term unproved reserves which the SEC guidelines prohibit from being included in filings with the SEC. Unproved reserves refers to the Company s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques.

4 Unproved reserves may not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or proposed SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company s core assets provide additional data. In addition, 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 drilling cost presentation contains financial measures that have not been prepared in accordance with Generally Accepted Accounting Principles ( non-GAAP financial measures ) including LTM EBITDA and certain debt ratios.

5 The non-GAAP financial measures should not be considered a substitute for financial measures prepared in accordance with Generally Accepted Accounting Principles ( GAAP ). We urge you to review the reconciliations of the non-GAAP financial measures to GAAP financial measures in the Diversified Energy Company101065514 Casper Casper Arkoma BasinMarcellusNorth La/ East Texas BasinGulf Coast BasinAnadarko BasinPermian Basin95 Unit RigsE&P OperationsMidstream OperationsOffice Location Tulsa based, incorporated in 1963 Integrated approach to business allows Unit to capture margin from each business segmentHouston Houston Oklahoma CityOklahoma CityTulsa HeadquartersTulsa HeadquartersPittsburghPittsburghMississi ppianBasin4 Investment Highlights Opportunity-rich upstream portfolio with compelling economics provides optionality Upstream capital allocated to areas generating highest rates of return in the Company s portfolio Contract drilling segment activity level rebounding Sale of 50% equity stake in Superior highlights asset value and provides growth capital to benefit all three Unit Business segments Conservative balance sheet with corporate net debt < 2X EBITDA and philosophy of spending within cash flow5 Core Upstream Producing AreasGasNGLsOil54%28%18%Q1 2018 Daily Production: MBoe/dMid Continent RegionUpper Gulf Coast RegionWilcoxHoxbar/STACKG ranite WashKey focus areas include:Gulf Coast.

6 Wilcox (Southeast Texas)Mid-Continent: Granite Wash (Texas Panhandle) Hoxbar (Western Oklahoma) STACK (Western Oklahoma)0102030405060201320142015201620 172018 estNatural GasOil / NGLs47-484647505544 Average Production (MBoe/d)Net Wells Drilled:91 121 35 10 26 ~346 Natural GasOil / NGLsTrack Record of Reserve Growth-150%0%150%300%450%200120022003200 4200520062007200820092010201120122013201 4201520162017(119%)030609012015018020012 0022003200420052006200720082009201020112 01220132014201520162017 Annual Reserve Replacement161%171%176%202%204%261%221%1 86%Average: 176%113%1161606979869596104150337%179 Proved Reserves (MMBoe)13511815058484542285%166%169%161% (1%)300%7 Core Area Cash MarginsNote: Assumes 6:1 gas to oil ratio. Adjusted base represents the weighted average commodity price per Mcfe of the area s production ( using WTI, Henry Hub and Mont Belvieu propane for NGL).

7 Adjusted Base also includes 50% of applicable midstream margin for Granite Wash and Wilcox. % Gas 17% 25% 42% 60%63%99%$ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Adjusted Base$ Adjusted Base$ Adjusted Base$ Adjusted Base$ Adjusted Base$ Adjusted Base$ Gas Base, $ $ $ $ $ $ $ $ $ $ $ $ OilSTACKC ondensateWilcoxGranite WashSTACK Dry Gas$/McfeDifferential - AdjustedLOE & TaxesCash Margin*Differentials adjusted forproduction stream mix*Type Cur veMarchand5,000 Marchand7,500 IP - 30 (Boe/d)667933 ROR119%171%EUR (Mboe)524737% Liquids83%83%Lateral Length 5,000 7,500 Well Cost ($mm)$ $ OilLateralLengthSchmidt #1-10 HUnit9/17687805,000 Nina #1-22 HUnit8/171,124764,855 McConnell #1-11 HUnit10/171,091634,943 Schenk Tr. #1-17 HXLUnit11/172,343797,825 Liv. Land #1 HXLUnit1/18499727,985 Torralba 10-5-8 #1 HKaiser1/17575704,839 Amanda 21-6-8 #1 HKaiser3/17540715,0501235 Marchand VerticalMarchand Horizontal4 Denotes Unit non-op working interest.

8 670%50%100%150%200%250%300%350%$60 / $ Nymex$70 / $ $80 / $ %Marchand 5kMarchand Well EconomicsOperatorSOHOT Low Cost, High ROR Oil Play26753415/1/2018 Strip Price Deck with 1stProduction Starting 5/1 Q2 2018 Economic Prices in Appendix (also available at )9 Geology Marchand stacked lenses provide multiple oil drilling targets Medrano proved gas potentialLand 23,000 contiguous net acres 65% HBP Majority operated Working interest 50-70% 40 to 50 location inventory steady with continued acquisition of bolt on acreage Waterflood potentialOperations Running one Unit Drilling rig Incremental optimization of drilling and completion process has kept cost low without sacrificing EUR Extended laterals (XL) improving capital efficiencySOHOT Growing Oil Production and Improving Capital EfficiencyQuarterly Net BOE0100,000200,000300,000400,000500,0006 00,000Q1'17Q2'17Q3'17Q4'17Q1'18 GasNGLOilWellSpudDateIP-30 MMcfe/dGas%LateralLengthDixon 5554 XL #1H Unit2 ,503 Dixon 5554 EXL #4 HUnit2 ,474 Carr 1357 EXL #1 HUnit3 ,891 Carr 1357 EXL #2 HUnit5 ,663 Francis 5859 EXL #2 HUnit9 ,442 Dixon 5554 EXL #5 HUnit6 ,802 Meek 6836 HUnit5 ,375 10 Granite Wash Low Risk Wet Gas Condensate Play with NGL Price UpsideType Cur veGranite Wash C1 Granite Wash GGranite Wash BIP - 30 (Mcfe/d)9,9609,0007,902 ROR43%44%26%EUR (Bcfe) Gas48%77%52%Lateral Length7,500 7,500 7,500 Well Cost ($mm)

9 $ $ $ C1 Single Well EconomicsUnitTecoloteJones FourPointLe Norman BPGW B1GW G23456712345670%20%40%60%80%100%120%$60 / $ Nymex$70 / $ $80 / $ %Granite Wash C1 Granite Wash GGranite Wash BOperator15/1/2018 Strip Price Deck with 1stProduction Starting 5/1 Q2 2018 Economic Prices in Appendix (also available at )11 Granite Wash Competitive Advantages Drive Differentiated ValueGasNGLOilGeology 11 Stacked Granite Wash lenses significantly improves capital efficiency Sands present across acreageLand 9,000 net largely contiguous acres allow for extended lateral (XL) drilling 90% HBP and Operated Average working interest 90% 150-200 potential XL locations Continuing to expand positionOperations/Infrastructure/Proces sing Running one Unit Drilling rig Incremental process improvements continue to decrease drilling days SWD network lowers disposal costs 80% Water recycling pits lower frack costs Electricity across field lowers lifting costs Superior processes the gas improving cash marginBuffalo Wallow Quarterly Net MMcfe05001,0001,5002,0002,5003,0003,5004 ,000Q1'17Q2'17Q3'17Q4'17Q1'18 Type Cur veOil WindowCondensate WindowDry Gas* WindowIP - 30 (Boe/d, Mcfe/d*)1,7061,77315,415*ROR108%68%15%EU R (Mboe/Bcfe*)1,9391, *% Liquids/Gas65%58%99%Lateral Length10,000 10,000 10,000 Well Cost ($mm)

10 $ $ $ DateIP-30 MMcfe/dGas %Lateral Length Anderson HalfContinental 2 ,676 Edith MaeContinental 6 ,743 Abbott ComCimarex8/2017 Flowing Back10,385 Hicks BIAM arathon7 ,652 Reece JaneContinental 2 ,898 WyattContinental 8 ,805 EagleContinental 9/2017 WOC9,679 Gripe FIUC ontinental8 ,175 LeaseOperatorSpud DateIP-30 Boe/dLiquids %Lateral Length JordanDevon4/20171,63651%10,050 MLDevon9/20161,76648%4,676 CarpenterCimarex10/2017 WOC4,786 PrivottDevon10/20164,30857%10,112 LoreneContinental 7/20175,48330%10,186 Geronimo89 Energy6/201789558%4,797 Rafter J RanchMarathon7/20171,01727%4,11112 Single Well EconomicsSTACK Core - Provides High ROR Oil/Wet Gas with Dry Gas Optionality123456798 OilCondensateDry GasUnit s AcreageMeramec Woodford13245689101112131415710 Denotes Unit working interest0%50%100%150%200%250%$60 / $ Nymex$70 / $ $80 / $ %Stack CondensateStack Dry GasStack Oil111214131515/1/2018 Strip Price Deck with 1stProduction Starting 5/1 Q2 2018 Economic Prices in Appendix (also available at )Type Cur veSTACK ExtMeramecSTACKO sageIP - 30 (Boe/d)1,0401,203 ROR77%35%Total EUR (Mboe)920956% Liquids63%57%Lateral Length5,000 5,000 Well Cost ($mm)