Exhibit 99.3

MANAGEMENT PRESENTATION EP ENERGY CORPORATION August 2019 Highly Confidential

CAUTIONARY STATEMENT LOOKING STATEMENTS REGARDING FORWARD 2 EP Energy Corporation This presentation includes certain forward-looking statements and projections of EP Energy. We have made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable, and complete. However, a variety of factors could cause actual results to differ materially from the projections, anticipated results or other expectations expressed, including, without limitation, the vola tility of and potential for sustained low oil, natural gas and NGL prices; the supply and demand for oil, natural gas and NGLs; the company’s ability to meet production volume targets; changes in commodity prices and basis differentials for oil and natural gas; the uncertainty of estimating proved reserves and unproved resources; the ability to develop proved undeveloped reserves; the future level of operating and capital costs; the availability and cost of financing to fund future exploration and production operat ions; the success of drilling programs with regard to proved undeveloped reserves and unproved resources; the company’s ability to comply with the covenants in various financin g documents, including making principal and interest payments or to obtain any necessary consents, waivers or forbearances thereunder; the company's ability to generate sufficient cash flow to meet its debt obligations and commitments; the possibility that the company may not be able to continue as a going concern if it is not successful in obtaining the necessary additional liquidity, refinancing any of its indebtedness on commercially reasonable terms or at all, executing on its strategic alterna tives and/or if there is not a sustained, significant increase in commodity prices; the company's limited ability to borrow under existing debt agreements to fund its operations; the company's ability to gener ate sufficient cash flow to meet it's debt obligations and commitments; the company’s ability to obtain necessary governmental approvals for proposed E&P projects and to successfully construct and operate such projects; actions by the credit rating agencies, including potential downgrades; credit and performance risk of our lenders, trading counterparties, customers, vendors, suppliers and third party operators; general economic and weather conditions in geographi c regions or markets served by the company, or where operations of the company are located, including the risk of a global recession and negative impact on oil and natural gas demand; the uncertainties associated with governmental regulation, including any potential changes in federal and state tax laws and regulations; competition; and other factors described in the company’s Securities and Exchange Commission filings. While the company makes these statements and projections in good faith, neither t he company nor its management can guarantee that anticipated future results will be achieved. Reference must be made to those filings for additional important factors that may affect actual results. EP Energy assumes no obligation to publicly update or revise any forward-looking statements made herein or any other forward-looking statements made by EP Energy, whether as a result of new information, future events, or otherwise. This presentation presents certain production and reserves-related information on an "equivalency" basis. Equivalent volumes are computed with natural gas converted to barrels at a ratio of six Mcf to one Bbl. These conversions are based on energy equivalency conversion methods primarily applicable at the burner tip and do not represent value equivalencies at the wellhead. Although these conversion factors are industry accepted norms, they are not reflective of price or market value differentials between product types. These materials are provided pursuant to and subject to a confidentiality agreement between the recipient of these materials (“Reci pient”) and EP Energy Corporation and its subsidiaries (such agreement, the “Confidentiality Agreement”). These materials constitute “Confidential Information” as defined in the Confide ntiality Agreement and material nonpublic information within the meaning of applicable securities laws. These materials are provided subject in all respects to Federal Rule of Evidence 408 and all federal and state rules of similar import. These materials are to be kept strictly confidential and are not for further dissemination, except as expressly set forth in the Confidentiality Agreement. Highly Confidential

OUR MISSION The EP Energy team is driven to deliver superior returns for our investors by developing the oil and natural gas that feeds America’s growing energy needs. The company focuses on enhancing the value of its high quality asset portfolio, increasing capital efficiency, maintaining financial flexibility, and pursuing accretive acquisitions and divestitures. EP Energy is working to set the standard for efficient development of hydrocarbons in the U.S. 3 EP Energy Corporation Highly Confidential

COMPANY OVERVIEW Highly Confidential

EP ENERGY COMPANY OVERVIEW CONTIGUOUS ACREAGE ACROSS THREE BASINS Operations Summary Eagle Ford 2H 2019 and 1H 2020 Completing DUCs only 5 Note: Net acres as of June 25, 2019. Production YTD average through May 31, 2019. EP Energy Corporation Asset Summary Northeast Utah (“NEU”) ~159,000 net acres Current net production of 15.4 MBoed (~65% oil) Eagle Ford ~120,000 net acres Current net production of 33.2 MBoed (~65% oil) Permian ~184,000 net acres Current net production of 23.9 MBoed (~29% oil) NEU NEU 2 rigs running continuously, each rig drills 12 wells/year Ramping to 3 rigs in 2H 2024, 4 rigs in 2025 and 5 rigs in 2026+ PERMIAN EAGLE FORD 2H 2020+ 1 rig drilling 36 wells/year through 1H 2024 Drilling program focused on the top 3 type curves based on single well returns Permian No rigs planned to run in the development plan Highly Confidential

CORPORATE HIGHLIGHTS STRONG OPERATIONAL PERFORMANCE FROM CAPITAL EFFICIENT ASSET BASE 6 [1] New horizontals through June 25, 2019 [2] 3Q’17 compared to 2019 YTD through May EP Energy Corporation Oil-weighted asset base focused on top-tier basins -Material size and scale of asset portfolio offers strong base of oil-weighted production complemented by deep inventory of long lateral development locations -Business plan generates significant free cash flow by optimizing capital efficiency and delivering strong cash returns -Recent NEU wells1 are ~71% oil and represent some of the best wells drilled in the Company’s history -Eagle Ford position provides predictable and stable production base with attractive near term development -Permian asset offers strong PDP base to fund growth in NEU and Eagle Ford Operating team delivering improved results -Highly experienced management team focused on low-cost operations with strong track record of operating multi-rig development programs -Reduction of 22% in G&A and 19% in LOE since 3Q’172, while also reducing the Company’s incident rate by 26% over the same period (0.13 incident rate) -Current generation completion design resulting in higher EUR/ft performance and completion optimization in recent NEU wells has resulted in higher productivity and lower costs Highly Confidential

BUSINESS PLAN PROJECTIONS BY YEAR MAINTAINING PRODUCTION LEVELS WHILE GENERATING UNLEVERED FREE CASH FLOW $573 73 $12 $11 7 Note: Corporate Adj. EBITDAX and CAPEX allocated to each area on the basis of each area’s percentage of total production $55.00 WTI / $2.75 HHUB price deck | All currency values shown in Millions EP Energy Corporation Production (MBoed)Adj. EBITDAX % Oil55%54%54%55%55%$660 $640 $653 $685 83 83 83 86 2H'19 2020 2021 2022 2023 2H'19 2020 2021 2022 2023 Annualized CapexTotal Adj. EBITDAX Less Capex $439 $466 $457 $497 $471 $250 $1,00 0 $200 $155 $800 $150 $600 $100 $400 $50 $200 $ - $ - 2H'19 2020 2021 2022 2023 2H'19 2020 2021 2022 2023 An nualized Annualized NEUEagle FordPermianCum Asset-Level CF $226 $279 $16 $229 $12 $225 $12 $247 $260 $225 $220 $213 $143 $194 $214 $183 $135 19 17 15 14 37 20 35 34 39 36 35 34 31 25 17 $44 $81 $62 $52 $357 $345 $100 $369 $340 $333 $283 $256 $237 $209 $140 Highly Confidential

RESOURCE SUMMARY STRONG PDP ASSET BASE WITH MULTI-YEAR DRILLING INVENTORY EF DUC 3% EF DUC 6% PDP 64% 8 Note: PDP value includes MVCs, Permian non-drill capital and other fixed expenses. Undeveloped values for Eagle Ford and NEU inclusive of non-drill capital costs. $55.00 WTI / $2.75 HHUB price deck. [1] EF DUCs as of June 11, 2019. Excludes 337 Eagle Ford and 121 Permian gross undeveloped locations that are not scheduled in the development plan. EP Energy Corporation 1 Commodity MixResource Category (Volumes)Asset-Level PV10 Distribution NGL 9% Gas PDP 36% Undev 53% Oil 33% Undev 55% 41% Oil/Cond. (MMBbl) Gas (Bcf) NGL (MMBbl) Equiv. (MMBoe) Capex ($Billion) Asset-Level PV10 ($Billion) Locations PDP 104 456 51 230 $0.1 $1.7 --Eagle Ford DUCs 11 22 4 18 0.2 0.2 47 NEU Undeveloped 235 957 --394 3.8 1.2 488 Eagle Ford Undeveloped 33 64 11 54 1.1 0.1 150 Total Resources 382 1,499 65 697 $5.1 $3.2 685 Highly Confidential

ASSET OVERVIEW Highly Confidential

ASSET PORTFOLIO DELINEATED PRODUCTION BASE WITH ATTRACTIVE ECONOMIC INVENTORY NEU (~159,000 NET ACRES) EAGLE FORD PERMIAN (~184,000 NET ACRES) (~120,000 NET ACRES) provide competitive returns resource base 10 Note: Net acres as of June 25, 2019. EP Energy Corporation Horizontal wells Lower 48 full cycle Rich oil-weighted Long life inventory Wolfcamp B bench is primary target, with potential for future upside in other benches Large contiguous acreage position supports efficient operating cost structure Low cost capital efficient program Delineated and proven reserve base with repeatable results Favorable market pricing Highly Confidential

FULLY LOADED SINGLE WELL ECONOMICS NEU LOCATIONS REPRESENT SOME OF THE HIGHEST RETURN WELLS AT THE COMPANY (SLC DIFFERENTIALS) 11 Note: $55.00 WTI / $2.75 HHUB price deck | Includes processing & gathering fees + expenses and non-drilling related capital expenditures. Gross Well Counts as of June 11, 2019, inclusive of DUCs. NEU single well economics assume Salt Lake City differentials. BTAX IRR (%) Gross Well Count EP Energy Corporation IRR @ $55/Bbl EPE Single Well Economic Comparison 70% 210 60% 180 50% 150 40% 120 30% 90 20% 60 10% 30 0% 0 NEU Eagle Ford Permian Highly Confidential

FULLY LOADED SINGLE WELL ECONOMICS NEU LOCATIONS REPRESENT SOME OF THE HIGHEST RETURN WELLS AT THE COMPANY (RAIL DIFFERENTIALS) 12 Note: $55.00 WTI / $2.75 HHUB price deck | Includes processing & gathering fees + expenses and non-drilling related capital expenditures. Gross Well Counts as of June 11, 2019, inclusive of DUCs. NEU single well economics assume Rail differentials. BTAX IRR (%) Gross Well Count EP Energy Corporation IRR @ $55/Bbl EPE Single Well Economic Comparison 70% 210 60% 180 50% 150 40% 120 30% 90 20% 60 10% 30 0% 0 NEU Eagle Ford Permian Highly Confidential

ASSET OVERVIEW NEU Highly Confidential

NEU SUMMARY 15.4 MBOED OF PRODUCTION AND ~159K NET ACRES Formation: Wasatch / Lower Green River 14 Note: Net acres as of June 25, 2019. Production YTD average through May 31, 2019. EP Energy Corporation Location: Duchesne & Uintah Counties, Utah Resources by Category Depth: 8,000 – 18,000 ft Undev Net Production: 15.4 MBoed (65% oil) 89% Net Acres: ~159,000 Operated PDPs: Avg. WI 79%; Avg. NRI 66% Non-Op PDPs: Avg. WI 2%; Avg. NRI 2% PDP Active PDP Wells: 360 operated; 85 non-operated 11% 488 gross undeveloped locations with 10,000’ average lateral length Commodity Mix NEU drilling promote for 6 additional completions o Partner pays 70% of development costs for 50% ownership Gas 35% Oil 65% Highly Confidential

NEU GEOLOGIC TYPE LOG, NET PAY, & STOOIP SUMMARY Uteland Butte Net Pay (ft) Uteland Butte ~500’ of gross section Up to 350’ of net pay Up to 25 MMBo per section Uteland Butte STOOIP (MMBo/Sec) 15 EP Energy Corporation NEU TYPE LOG Formations GARDEN GULCH DOUGLAS CREEK BLACK SHALE CASTLE PEAK UTELAND BUTTE WASATCH 5 WASATCH 4 WASATCH 3 WASATCH 2 WASATCH 1 W216 W220 W220.4 Highly Confidential

NEU GEOLOGIC SUMMARY STRATIGRAPHIC CROSS-SECTION & SSTVD STRUCTURE Uteland Butte SSTVD Structure A A’ GARDEN GULCH DOUGLAS CREEK BLACK SHALE CASTLE PEAK A’ UTELAND BUTTE WASATCH 5 A WASATCH 4 WASATCH 3 WASATCH 2 WASATCH 1 W216 W220 W220.4 16 EP Energy Corporation Highly Confidential

OFFSET OPERATORS SUCCESSFUL DRILLING PROGRAM WITH HIGH RETURNS Uteland Buttes | EUR: 1,066 MBoe 84% Oil 84% Oil Murray 2-17 3-2-8-5-3H 84% Oil 76 Mboe IP30: 1, h | EUR: 879 MBoe IP30: 1, od: 1/19 | LL: 9,500 3 4 8 13 16 9 11 16 h | EUR: 617 MBoe od: 3/18 | LL: 9,729’ h | EUR: 373 MBoe d: 10/17 | LL: 5,035’ 20 3-2-28-33-7H 456 Boed | 88% Oil Wasatch | EUR: 944 MBoe IP30: 2,149 Boed | 89% Oil 10 17 Source: IHS; EPE well EURs from 2018 YE reserves database EP Energy Corporation EP: Duchesne City 1-25-26-C5-2H Uteland Butte | EUR: 1,366 MBoe 1 IP30: 1,757 Boed | 85% Oil 1 Newfield: Pekev UT 2-29 3-1-29-32-1H 1 IP30: 2,044 Boed | 92% Oil First Prod: 8/18 | L L: 10,215’ 1 1 1 5 6 71 1920 10 1418 12 121517 1 1 1 First Pr od: 2/18 | LL: 9,772’ Crescent Pt: Wasatc 2 IP30: 2, First Pr Ute Tribal 4-23-3-1W-H1 h | EUR: 877 MBoe 034 Boed | 92% Oil od: 6/17 | LL: 4,441’ EP: Duchesne City 1-2 Wasatch | EUR: 81 2 IP30: 984 Boed | First Prod: 8/18 | 5-26-C5-1H 6 MBoe LL: 8,955’ Newfield: Kell Uteland Bu 3 IP30: 1, First Pr er UT 14-23 3-3-23-14-7H ttes | EUR: 1,021 MBoe 989 Boed | 89% Oil od: 2/17 | LL: 9,819’ EP: EP Energy 8-24 Uteland Butte | EUR: 3 IP30: 1,822 Boed | First Prod: 4/19 | -23-C5-2H 1,081 MBoe LL: 9,848’ Newfield: Uteland B 4 IP30: 1, First Pr uttes | EUR: 358 MBoe 977 Boed | 90% Oil od: 3/17 | LL: 9,828’ EP: EP Energy 8-24-Wasatch | EUR: 1,0 4 IP30: 1,166 Boed | First Prod: 4/19 | 23-C5-3H 81 Mboe LL: 9,827’ Newfield: M 5 Wasatc First Pr arie 15-22-15-3-3W-MW h | EUR: 540 MBoe 810 Boed | 88% Oil od: 9/14 | LL: 8,525’ EP: Lake Fork Ranch 5-5 Wasatch | EUR: 1,3 First Prod: 6/19 | 26-25-B4-1H LL: 9,822’ EP: Lake Fork Ranch 5-6 Uteland Butte | EUR: First Prod: 6/19 | 26-25-B4-2H 1,435 Mboe LL: 7,402’ Crescent Pt: Ut Wasatc First Pr e Tribal 13-21-16-3-1W-H1 525 Boed | 92% Oil EP: Lake Fork Ranch 5-7 Castle Peak | EUR: 1, First Prod: 6/19 | 26-25-B4-3H 376 MBoe’ LL: 9,856’ Crescent Pt: B Wasatc 7 IP30: 1, First Pr adger 1-26-35-3-1W-H4 481 Boed | 93% Oil Newfield: Oats UT 2-26 Uteland Buttes | EUR: 8 IP30: 2,540 Boed | First Prod: 5/17 | 3-3-23-14-1H 1,035 MBoe 89% Oil LL: 9,773’ Crescent Pt Wasatc 8 IP30: 1, First Pro : Kendall 2-18-3-1E-WS 477 Boed | 92% Oil Newfield: Bar-F UT 16-Uteland Buttes | EUR 9 IP30: 2,479 Boed | First Prod: 12/17 : 712 MBoe 90% Oil | LL: X’ Axia Energy: B Wasatch 9 IP30: 1, First Pr utcher Butte 32-144H-22 | EUR: 1,166 MBoe od: 7/17 | LL: 9,120’ 2 Axia Energy: Butcher Butte 32-34H-21 Wasatch | EUR: 1,009 MBoe 0 IP30: 1,369 Boed | 90% Oil First Prod: 1/17 | LL: 9,720’ Newfield: Leon UT 4-17 3-2-8-5-17H First Prod: 9/17 | LL: 9,427’ Hz. Rig (on 6-24-19) Vert. Rig (on 6-24-19) EP Well Newfield Well Crescent Point Well Axia Energy Well Horizontal Locations EP Acreage Highly Confidential

NEU RECENT HORIZONTALS THREE ADDITIONAL HORIZONTALS ONLINE 2Q 2019 Lake Fork Ranch 5-26-25-B4-1H 18 Note: Grey area includes gross oil production history from all existing horizontal producing operated wells in the Company’s 2018 YE reserve report. EP Energy Corporation Completed seven NEU horizontal wells with lateral length of 9,800 feet Gas Gathering capacity increased 3-4 MMcf per day at the end of the second quarter Lake Fork Ranch 5-26-25-B4-2H Expect to have 14 moreLake Fork Ranch 5-26-25-B4-3H horizontals online by the end of the year 7 Horizontal NEU wells compared to ALL EP wells Highly Confidential

NEU HORIZONTAL DRILLING INCREASED EFFICIENCY WITH REDUCED DRILLING DAYS CURVES operators wells 19 EP Energy Corporation Data includes offset operators and EP horizontal wells 4 out of 5 wells were faster than offset Drilling efficiencies driving cost improvement and enhanced single well economics Historic NEU Wells Axia Record: Butcher Butte 31-134H-21 Duchesne City 1-25-26-C5-2H Duchesne City 1-25-26-C5-1H EP Energy 8-24-23-C5-1H EP Energy 8-24-23-C5-2H Record Well: EP Energy 8-24-23-C5-3H Highly Confidential

NEU OPERATIONAL PERFORMANCE COMPLETION OPTIMIZATION IS DRIVING WELL PRODUCTIVITY AND LOWERING COSTS 20 Pumping Hours per Day Spud to RR Days TMD Feet Gross $MM $ per Foot EP Energy Corporation Drilling Cycle TimeCompletion Cost per Foot 34.5$682 2018201920182019 Pumping HoursTotal Well Cost 9.810.2$10.3$10.1 2018201920182019 $534 29.3 20,717 19,269 Highly Confidential

NEU GROSS LOE BY CATEGORY AVERAGE OF MONTHLY LOE AND WELL-COUNT BY PERIOD 352 $9.0 $8.0 335 330 329 4.0 3.7 $4.0 21 Note: Other includes Transportation & Compression. Well Count is gross operated wells. *Q2’19 = Apr-May only All Company values shown in millions. EP Energy Corporation $10.0362 342344345 $7.0 $6.0 $5.04.74.64.44.24.44.4 $3.0 $2.0 $1.0 $0.0 Q3'17Q4'17Q1'18Q2'18Q3'18Q4'18Q1'19Q2'19 OtherPower & FuelChemicalsDisposalMaintenance & RepairGeneral SuppliesLaborWell Count Highly Confidential

MARKETING ARRANGEMENTS CRUDE VOLUMES MOVING TO SALT LAKE REFINERY SYSTEM 22 EP Energy Corporation All products sold at the wellhead Natural Gas and NGLs under acreage dedication to 3rd party midstream provider through June 1, 2022: -Wet gas valued at 60% of residue and 35% of NGL resale (correlates to ~36% of CIG Rocky Mountain Index) -Gathering, compression, and treating (dehydration and H2S removal) fees captured in price (revenue recognition) -Processor supplies residue return gas to field for operational use Wax crude oil sales into trucks for delivery into Salt Lake City refinery market or via rail to Gulf Coast refineries Highly Confidential

UINTA BASIN OIL MARKET DYNAMICS Salt Lake City refinery demand remain undersupplied through summer into SLC pricing premium which offsets some of the rail cost (spot market LLS trading $5 above WTI) price producers are looking to create growth opportunities beyond SLC expansion of existing SLC refinery capacity given prohibitive cost and lengthy 23 EP Energy Corporation Local pricing improved since Q1-19 as available wax crude supply has dropped below Recent collapse in oil price has slowed Uinta Basin drilling activity, suggesting SLC market could Several producers railing crude out of Utah under term contracts, further reducing available supply SLC spot market pricing has rebounded to 85% of WTI from 70% in Q1-19 Indicative bids on term deals (6 months or longer) with SLC refineries now around 85% of WTI Rail costs to Gulf Coast still hovering around $18-$20/bbl, but railed barrels now receiving Gulf Coast SLC refineries currently operating at maximum rates, but upcoming fall maintenance could weigh on Increasing appetite for wax crudes outside of Utah, but dependent on rail economics Low sulfur marine bunker fuel specs appear to be driving renewed interest in wax crude, and Abundant transloading capacity available at multiple local rail terminals Local refined product demand growth remains resilient, but not sufficient to drive permitting process Highly Confidential

RAIL COST ANALYSIS SAMPLE PRICES BASED ON ESTIMATED SALE OF 3,000 BBL/D TO U.S. GULF COAST REFINERY 24 EP Energy Corporation All-in cost approximately $19/bbl to the Gulf Coast (LLS) Truck hauling from wellhead to rail transloading site Transloading fee for moving crude from trucks to railcars Efficiency gains possible with high-volume unit train operations, but incremental charges also possible (storage, unloading, vapor recovery, steaming, etc.) Highly Confidential

NEU CRUDE SALES EPE HISTORICAL SALES THROUGH APRIL 2019 25 Average Daily Sales, bopd EP Energy Corporation 86%87%88%88%% of 25,00093%94%93%94%92%92%91%91%90%91%90%89%100% W90T%I 20,00080% 70% 15,00060% 50% 10,00040% 30% 5,00020% 10% -0% Highly Confidential

SWD INFRASTRUCTURE PIPELINE CAPACITY OF MORE THAN 115,000 BWPD 26 EP Energy Corporation More than 250 miles of SWD pipelines Approximately 88% of water is on pipe System capacity of more than 115,000 bwpd SWD Pipelines 3rd Party SWD Wells EPE Owned SWD Wells Highly Confidential

ASSET OVERVIEW EAGLE FORD Highly Confidential

EAGLE FORD SUMMARY 33.2 MBOED OF PRODUCTION AND 870 OPERATED PDP WELLS PROVIDES STABILITY TO DRIVE GROWTH Resources by Category Formation: Eagle Ford Shale Undev 33% 487 gross undeveloped locations with average lateral length of 7,000’ Commodity Mix Austin Chalk: Currently not included in business plan o 28 Note: Net acres as of June 25, 2019. Production YTD average through May 31, 2019. EF DUCs as of June 11, 2019 EP Energy Corporation Location:La Salle County, Texas Depth:7,000 – 9,800 ft Net Production:33.2 MBoed (65% oil) Net Acres:~120,000 Operated PDPs:Avg. WI 90%, Avg. NRI 67% Non-Op PDPs:Avg. WI 20%, Avg. NRI 15%PDP Active PDP Wells:870 operated; 34 non-operated56% DUC 11% oIncremental 47 DUCs oDrilled and completed an Austin Chalk lateral in La Salle County oOnline June 2019 with encouraging resultsGas EOR:17% o2 Enhanced Oil Recovery (“EOR” or “Huff-n-Puff”) pilots in the Eagle FordNGL oFirst pilot was operational in 2Q’18 and second pilot in 4Q’18Oil 18% oStill in proof of concept phase but early results are encouraging65% Highly Confidential

EAGLE FORD GEOLOGIC TYPE LOG, GROSS THICKNESS, & STOOIP SUMMARY Lower Eagle Ford Gross Thickness (ft) Lower Eagle Ford STOOIP (MMBo/Sec) n 29 EP Energy Corporation Formations Lower Eagle Ford Austin Chalk Upper Eagle Ford Lower Eagle Ford ~120-140’ of gross sectio 20-45 MMBo per section Buda Highly Confidential

EAGLE FORD GEOLOGIC SUMMARY STRATIGRAPHIC CROSS-SECTION & SSTVD STRUCTURE Lower Eagle Ford SSTVD Structure A’ A’ A 30 EP Energy Corporation A Highly Confidential

OFFSET OPERATORS STRONG WELL RESULTS FROM EP AND OFFSET OPERATORS AROUND THE EP POSITION Eagle Ford | EUR: 674 MBoe First Prod: 2/18 | LL: 8,572’ IP30: 2,962 Boed | 90% Oil Eagle Ford | EUR: 203 MBoe 12 3 5 17 IP30: 2,559 Boed | 85% Oil 9 Eagle Ford | EUR: 624 MBoe First Prod: 5/14 | LL: 6,899’ 11 4 6 IP30: 2187 Boed | 86% Oil IP30: 1,743 Boed | 89% Oil 10 20 IP30: 1,368 Boed | 97% Oil IP30: 1,641 Boed | 87% Oil 31 Source: IHS; EPE well EURs from 2018 YE reserves database EP Energy Corporation 1 EP: Maltsberger Unit C 101H Eagle Ford | EUR: 822 MBoe EP: Maltsberger 300H IP30: 2,083 Boed | 58% Oil First Prod: 12/17 | LL: 10,557’ Hz. Rig (on 6-24-19) EP Well EP EOR Project EOG Well Chesapeake Well Verdun Well Horizontal Locations EP Acreage 1 1 Austin Chalk 2 EP: Maltsberger Unit B 100H Eagle Ford | EUR: 722 MBoe IP30: 1,708 Boed | 60% Oil First Prod: 12/17 | LL: 10,398’ 1 2 EP: EOR Pilot 1 3 EP: Altito B 7B Unit 79H IP30: 1,607 Boed | 86% Oil 1 3 EP: EOR Pilot 2 4 EP: Maltsberger-DB Trust 201H Eagle Ford | EUR: 885 MBoe IP30: 1,581 Boed | 68% Oil First Prod: 10/18 | LL: 15,440’ 1 4 EOG: Lowe Pasture 11H Eagle Ford | EUR: 548 MBoe First Prod: 4/15 | LL: 5,288’ 5 EP: Altito B 7A Unit 75H Eagle Ford | EUR: 352 MBoe IP30: 1,518 Boed | 81% Oil First Prod: 1/17 | LL: 5,326’ 1016 151914 1 5 EOG: Exelco 16H IP30: 2,600 Boed | 88% Oil First Prod: 6/18 | LL: 12,007’ 7 8 6 EP: Maltsberger Unit B 99H Eagle Ford | EUR: 1,144 MBoe IP30: 1,498 Boed | 91% Oil First Prod: 9/18 | LL: 9,702’ 20 1 6 EOG: Dossett A 1H Eagle Ford | EUR: 802 MBoe First Prod: 11/17 | LL: 9,524’ 7 EP: Altito B 32B Unit 321H Eagle Ford | EUR: 627 MBoe IP30: 1,494 Boed | 84% Oil First Prod: 3/15 | LL: 8,630’ 18 1 1 2 E 7 OG: Naylor Jones Unit 127 2H IP30: 2,251 Boed | 77% Oil 8 EP: Altito B 32B Unit 322H Eagle Ford | EUR: 459 MBoe IP30: 1,453 Boed | 85% Oil First Prod: 3/15 | LL: 8,425’ 131 Ch 8 esapeake: Blakeway 1 C Dim 2H Eagle Ford | EUR: 1,005 MBoe First Prod: 3/17 | LL: 9,838’ 9 EP: Mumme Ranch A 101H Eagle Ford | EUR: 674 MBoe IP30: 1,442 Boed | 78% Oil First Prod: 11/18 | LL: 13,328’ 1 9 Verdun: Hanks Tom EF 40 Eagle Ford | EUR: 1,096 MBoe First Prod: 9/17 | LL: 10,013’ EP: Ritchie Farms 169H Eagle Ford | EUR: 711 MBoe C hesapeake: Valley Wells HC1 2H Eagle Ford | EUR: 1,013 MBoe First Prod: 7/18 | LL: 9,369’ First Prod: 8/18 | LL: 15,002’ Highly Confidential

EAGLE FORD REVENUE PER RPI GROWTH OF ~9% AT 400 NORMALIZED OIL DAYS INVESTMENT 32 Note: To produce a comparison of design efficiency, current realized prices, and current unit service costs were used for the calculation of both 2018 RPI and immediate Historical Offsets. This chart contains 2018 activity only in green versus immediate offset wells in blue EP Energy Corporation Current design wells are driving outperformance of historical revenue per investment by ~9% at 400 days on average RPI definition is: Realized $ per Boe x Cumulative NRI Boe WI Capex Historical offset is the most proximal or similar offset to the 2018 well RPI calculation does not include the benefit of any drilling carry Historical Offsets New Wells Historical Offsets Average New Wells Average Highly Confidential

EAGLE FORD DRILLING PROFILES IMPROVED DRILLING PROGRAM EFFICIENCY LOWERING DRILL DAYS in Q4’18 33 EP Energy Corporation Drilled record 15k lateral Previous 2018 Q1 2018 Q2 2018 Q3 2018 Q4 2019 Q1 2019 Q2 Highly Confidential

EAGLE FORD OPERATIONAL PERFORMANCE PROPPANT LOADING AND INCREASED FLUID PER FOOT DRIVING WELL PERFORMANCE 9.6 $552 9.0 $419 2,363 34 Pounds Per Foot Spud to RR Days Lateral Feet Barrels per Foot $ per Foot EP Energy Corporation Drilling Cycle TimeCompletion Cost per Foot $600 8.2 20162017201820192016201720182019 Proppant LoadingFluid per Foot 2,61355 20162017201820192016201720182019 2,0011,891 49 3534 7,871 8.0 6,765 6,327 7,349 $450 Highly Confidential

EAGLE FORD GROSS LOE BY CATEGORY AVERAGE OF MONTHLY LOE AND WELL-COUNT BY PERIOD 840 822 $12.0 802 784 7.5 $8.0 35 Note: Well Count is gross operated wells. *Q2’19 = Apr-May only All Company values shown in Millions. EP Energy Corporation 853860 $10.0666666 8.2 6.76.96.87.16.26.3 $6.0 $4.0 $2.0 $0.0 Q3'17Q4'17Q1'18Q2'18Q3'18Q4'18Q1'19Q2'19 Compression Labor General Supplies Chemicals Disposal Processing & Treating Fees Flowback Power & Fuel Transportation Gross Total Well Count Highly Confidential

MIDSTREAM ARRANGEMENTS EAGLE FORD CENTRAL GAS 36 . EP Energy Corporation Enterprise Hydrocarbons Firm Processing Enterprise Texas Pipeline Gathering ETC Texas Pipeline Camino Real Gas Gathering Frio LaSalle Pipeline Southcross Eagle Ford Gathering DCP Highly Confidential

MIDSTREAM ARRANGEMENTS EAGLE FORD CENTRAL OIL 37 Note: 3rd Party pipelines, terminals and interconnects not drawn to scale. EP Energy Corporation Approximately 75% of oil sales are currently on pipe Third-party gathering system with abundant capacity and interconnects to Hilcorp Gardendale and Cotulla pipelines to Corpus Christi and to Plains AV pipeline to Gardendale Remaining sales on truck from CPFs or wellhead Highly Confidential

EAGLE FORD SWD INFRASTRUCTURE PIPELINE CAPACITY OF MORE THAN 112,000 BWPD 38 EP Energy Corporation Almost 60 miles of SWD pipelines Approximately 40-50% of water is on pipe System capacity of 112,500 bwpd SWD Pipelines 3rd Party SWD Wells Highly Confidential

ASSET OVERVIEW PERMIAN Highly Confidential

PERMIAN SUMMARY 23.9 MBOED OF PRODUCTION WITH OVER 100 UNDEVELOPED LOCATIONS IN THE WOLFCAMP B Formation: Wolfcamp B Net Acres: Operated PDPs: ~184,000 Avg. WI 91%; Avg. NRI 70% NGL operational in 2Q’19 39% 40 Note: Net acres as of June 25, 2019. Production YTD average through May 31, 2019. EP Energy Corporation Location:Crockett, Reagan, Irion & Upton Counties, TexasResources by Category Depth:5,800 – 8,500 ft Net Production:23.9 MBoed (29% oil) PDP 100% Non-Operated PDPs: Avg. WI 23%; Avg. NRI 18% Active PDP Wells:359 operated; 13 non-operated 121 gross undeveloped locations with average lateral length of 10,000’Commodity Mix 1 Enhanced Oil Recovery (“EOR” or “Huff-n-Puff”) pilot in the Permian,Gas 33% Oil 29% Highly Confidential

WOLFCAMP GEOLOGIC TYPE LOG & STOOIP SUMMARY TYPE LOG – SOUTHERN MIDLAND BASIN Wolfcamp A + B STOOIP (MMBo/Sec) Wolfcamp A + B ~500’ of gross section of Wolfcamp A & B 70-80 MMBo per section 41 EP Energy Corporation Primary Targets Permian GR RESD NEUT DEN Highly Confidential

WOLFCAMP GEOLOGIC SUMMARY STRATIGRAPHIC CROSS-SECTION & SSTVD STRUCTURE Wolfcamp A SSTVD Structure A A’ A A’ 42 EP Energy Corporation Highly Confidential

OFFSET OPERATORS EP’S POSITION HAS BEEN SIGNIFICANTLY DE-RISKED BY OFFSET OPERATORS AND EP’S PRODUCING WELLS Wolfcamp B | EUR: 911 MBoe Wolfcamp B | EUR: 859 MBoe 9 Wolfcamp | EUR: 1,421 MBoe First Prod: 9/18 | LL: 12,793’ 6 10 Wolfcamp B | EUR: 625 MBoe 11 oe Wolfcamp B | EUR: 348 MBoe 12 43 Source: IHS; EPE well EURs from 2018 YE reserves database EP Energy Corporation 1 EP: University Central 0811AH Wolfcamp | EUR: 453 MBoe IP30: 885 Boed | 93% Oil First Prod: 10/18 | LL: 8,425’ 3 7 E arthstone: Benedum 3-6 1BL IP30: 1,594 Boed | 89% Oil First Prod: 9/18 | LL: 7,453’ 8 2 EP: EOR Pilot Wolfcamp 8 Pioneer: Brook A-2 8H IP30: 1,586 Boed | 85% Oil First Prod: 5/18 | LL: 9,722’ 7 5 3 Parsley: Taylor 45-33 4601H Wolfcamp C | EUR: 1,942 MBo IP30: 2490 Boed | 73% Oil First Prod: 2/17 | LL: 10,379’ e 4 9 10 Pioneer: Rocker B 139H IP30: 1,444 Boed | 85% Oil 11112 4 SEM: University 9 2719WC Wolfcamp C | EUR: 940 MBoe IP30: 1,873 Boed | 88% Oil First Prod: 11/18 | LL: 7,859’ Tau bert: Farmar AH Unit S711HU Wolfcamp | EUR: 709 MBoe IP30: 1,376 Boed | 68% Oil First Prod: 3/18 | LL: 7,480’ 5 Pioneer: University 2-20 76H Wolfcamp D | EUR: 1,084 MBo IP30: 1,680 Boed | 66% Oil First Prod: 4/18 | LL: 9,747’ e 2 Bold: Bold WTG 5-234 1HM IP30: 1,279 Boed | 79% Oil First Prod: 1/17 | LL: 9,332’ Hz. Rig (on 6-24-19)Earthstone Well EP WellTaubert Well EP EOR ProjectBold Well Parsley WellSable Well SEM WellHorizontal Locations Sable: Woods RE 210 27HA IP30: 1,269 Boed | 67% Oil First Prod: 1/18 | LL: 5,078’ 6 Earthstone: WTG Unit 4-232 A 2 Wolfcamp B | EUR: 1,001 MB IP30: 1,620 Boed | 87% Oil First Prod: 7/18 | LL: 10,339’ BL Pioneer Well EP Acreage Highly Confidential

PERMIAN REVENUE PER INVESTMENT RPI GROWTH OF ~19% AT 400 NORMALIZED OIL DAYS 44 Note: To produce a comparison of design efficiency, current realized prices, and current unit service costs were used for the calculation of both 2018 RPI and immediate Historical Offsets. This chart contains 2018 activity only in green versus immediate offset wells in blue EP Energy Corporation Current design wells are driving outperformance of historical revenue per investment by ~19% at 400 days on average RPI definition is: Realized $ per Boe x Cumulative NRI Boe WI Capex Historical offset is the most proximal or similar offset to the 2018 well RPI calculation does not include the benefit of any drilling carry Historical Offsets New Wells Historical Offsets Average New Wells Average Highly Confidential

PERMIAN GROSS LOE BY CATEGORY AVERAGE OF MONTHLY LOE AND WELL-COUNT BY PERIOD 388 388 388 385 383 $9.0 4.7 4.7 4.5 $5.0 45 Note: Other includes Transportation & Compression. Well Count is gross operated wells. *Q2’19 = Apr-May only All Company values shown in millions. EP Energy Corporation $10.0 $8.0365370 $7.0351 $6.0 $4.03.94.03.63.33.2 $3.0 $2.0 $1.0 $0.0 Q3'17Q4'17Q1'18Q2'18Q3'18Q4'18Q1'19Q2'19 LaborMaintenance & RepairCompressionDisposalChemicals Power & FuelGeneral SuppliesFlowbackOtherWell Count Highly Confidential

NATURAL GAS PROCESSING & MARKETING SUFFICIENT TAKEAWAY CAPACITY FROM MIDSTREAM PARTNERS 46 EP Energy Corporation Acreage dedications to 4 different midstream companies (must-take agreements) that handle gathering, treating, processing and sales Midstream partners have ample plant capacity and hold substantial downstream takeaway capacity and sales commitments on numerous pipelines ensuring product flow Approximately 80% of physical residue gas priced off Waha index and 20% priced off Houston Ship Channel index NGLs priced off Mont Belvieu index Highly Confidential

PERMIAN SWD INFRASTRUCTURE PIPELINE CAPACITY OF 71,000 BWPD 47 EP Energy Corporation Almost 93 miles of SWD pipelines Approximately 98% of water is on pipe System capacity of 71,000 bwpd SWD Pipelines 3rd Party SWD Wells EPE Owned SWD Wells Highly Confidential

BUSINESS PLAN Highly Confidential

BUSINESS PLAN OVERVIEW A SUSTAINABLE PLAN THAT GENERATES UNLEVERED FREE CASH FLOW 49 EP Energy Corporation Goal(s): Maintaining production volumes, generate free cash flow, drill high oil-cut wells Assumptions / Inputs Pricing: $55/Bbl, $2.75/MMBtu, $16.10/Bbl EF NGLs, $15.62/Bbl Permian NGLs Diffs+Deducts (Oil, Gas): NEU -$10.27, -$1.87 | EF +$0.55, -$0.10 | Permian -$0.80, -$1.42 No inflation EOR: (2019) continue 2 EF projects, +1 Permian (no incremental EOR projects) NEU 2 rigs running continuously, each rig drills 12 wells/year Ramping to 3 rigs in 2H’24, 4 rigs in 2025 and 5 rigs in 2026+ Eagle Ford 2H’19 – 1H’20 Completing DUCs only 2H’20+ 1 rig drilling 36 wells/year through 1H’24 Drilling program focused on the top 3 type curves based on single well returns 28 DUCs expected to be completed and come online in 2H’19 Permian No rigs planned to run in the development plan Highly Confidential

BUSINESS PLAN PROJECTIONS BY YEAR MAINTAINING PRODUCTION LEVELS WHILE GENERATING UNLEVERED FREE CASH FLOW $573 73 $12 $11 50 Note: Corporate Adj. EBITDAX and CAPEX allocated to each area on the basis of each area’s percentage of total production $55.00 WTI / $2.75 HHUB price deck | All currency values shown in Millions EP Energy Corporation Production (MBoed)Adj. EBITDAX % Oil55%54%54%55%55%$660 $640 $653 $685 83 83 83 86 2H'19 2020 2021 2022 2023 2H'19 2020 2021 2022 2023 Annualized CapexTotal Adj. EBITDAX Less Capex $439 $466 $457 $497 $471 $250 $1,00 0 $200 $155 $800 $150 $600 $100 $400 $50 $200 $ - $ - 2H'19 2020 2021 2022 2023 2H'19 2020 2021 2022 2023 An nualized Annualized NEUEagle FordPermianCum Asset-Level CF $226 $279 $16 $229 $12 $225 $12 $247 $260 $225 $220 $213 $143 $194 $214 $183 $135 19 17 15 14 37 20 35 34 39 36 35 34 31 25 17 $44 $81 $62 $52 $357 $345 $100 $369 $340 $333 $283 $256 $237 $209 $140 Highly Confidential

BUSINESS PLAN SENSITIVITY TO PRICE MOVEMENT IN COMMODITY PRICES HAS AN IMPACT ON ADJUSTED EBITDAX AND UNLEVERED FREE CASH FLOW $685 $660 $653 $640 $640 $277 $277 $250 $752 $697 $160 $685 $660 $640 51 Note: Sensitivity cases assume a +/-$1.00/Bbl change in NGL prices EP Energy Corporation Adj. EBITDAX $743$733$747$782 $566$573$626$546$558$588 2H'19 Annualized2020202120222023 Adj. EBITDAX Less Capex $311 $747$$271842 $89 2H'19 Ann2uHa'l1iz9eAdnnualized 20202020 22002211 2022022 20232023 -$5.00/Bbl & -$0.25/MMBtu (WTI/HHUB) $55.00/Bbl & $2.75/MMBtu (WTI/HHUB) +$5.00/Bbl & +$0.25/MMBtu (WTI/HHUB) $201$194 $183 $733 $65$3155 $558 $588 $117 $611 $ 567 $128$$153255 $546 $61 Highly Confidential

RESOURCE SUMMARY STRONG PDP ASSET BASE WITH MULTI-YEAR DRILLING INVENTORY EF DUC 3% EF DUC 6% PDP 64% 52 Note: PDP value includes MVCs, Permian non-drill capital and other fixed expenses. Undeveloped values for Eagle Ford and NEU inclusive of non-drill capital costs. $55.00 WTI / $2.75 HHUB price deck. [1] EF DUCs as of June 11, 2019. Excludes 337 Eagle Ford and 121 Permian gross undeveloped locations that are not scheduled in the development plan. EP Energy Corporation 1 Commodity MixResource Category (Volumes)Asset-Level PV10 Distribution NGL 9% Gas PDP 36% Undev 53% Oil 33% Undev 55% 41% Oil/Cond. (MMBbl) Gas (Bcf) NGL (MMBbl) Equiv. (MMBoe) Capex ($Billion) Asset-Level PV10 ($Billion) Locations PDP 104 456 51 230 $0.1 $1.7 --Eagle Ford DUCs 11 22 4 18 0.2 0.2 47 NEU Undeveloped 235 957 --394 3.8 1.2 488 Eagle Ford Undeveloped 33 64 11 54 1.1 0.1 150 Total Resources 382 1,499 65 697 $5.1 $3.2 685 Highly Confidential

APPENDIX Highly Confidential

ORGANIZATIONAL STRUCTURE 54 EP Energy Corporation 100%100% 100% 100%100% 100% EP Energy Management, L.L.C. (Delaware) 1% (GP) 100% 99% (LP) EP Energy E&P Company, L.P. (Delaware) EP Energy Resale Company, L.L.C. (Delaware) EP Energy Global LLC (Delaware) Everest Acquisition Finance Inc. (Delaware) EP Energy LLC (Delaware) EPE Employee Holdings II, LLC (Delaware) EPE Acquisition, LLC (Delaware) EP Energy Corporation (Delaware) Highly Confidential

CURRENT HEDGE POSITION 55 [1] Hedge positions are as of June 26, 2019 (Contract months: July 1, 2019 – Forward) EP Energy Corporation 2H 2019 2020 2H 20192020 Fixed Price: mm bbls $/bbl mm bbls $/bbl Fixed Price: tBtu $/mmBtu tBtu $/mmBtu Swaps - $ - - $ - Swaps 5.52 $3.01 - $ - Costless Collar Ceiling 0.736 69.81 - - Collar Ceiling 7.36 4.26 - $ - Costless Collar Floor 0.736 57.50 - - Collar Floor 7.36 2.75 - $ - Three-way Ceiling 6.072 66.01 11.712 65.11 Average Ceiling 12.88 $3.72 - $ - Three-way Upper Floor 6.072 55.76 11.712 55.90 Average Floor 12.88 $2.86 - $ - Three-way Lower Floor 6.072 45.00 11.712 45.00 Average Ceiling 6.808 $66.41 11.712 $65.11 Average Floor 6.808 $55.93 11.712 $55.90 Basis: Waha Swaps3.68$0.39-$ - Basis: Mid/Cush Swaps 0.736 ($5.23) 1.464 $0.46 WTI Roll 0.244 $0.25 - $ - Crude oil option structures allow for significant upside participation as WTI price rises Percentage Hedged 6% 0% Percentage Hedged 62% 83% Percentage Hedged 39% 0% Percentage Hedged 93% 75% Percentage Hedged 56% 0% Natural Gas (Tbtu) Crude Oil (MMbbls) Highly Confidential

TOTAL COMPANY NET LIFTING AVERAGE OF MONTHLY LOE AND WELL-COUNT BY PERIOD COSTS 1585 1593 $20.0 1570 1540 1517 1483 1393 1369 $18.0 $16.0 14.5 14.2 13.7 $14.0 12.2 11.8 $12.0 10.5 $10.0 $8.0 $6.0 $4.0 $2.0 $0.0 Q3'17 Q4'17 Q1'18 Q2'18 Eagle Ford Q3'18 Permian Q4'18 Q1'19 Q2'19 NEU Well Count 56 Note: Well Count is gross operated wells. *Q2’19 = Apr-May only All currency values shown in Millions. EP Energy Corporation 13.2 12.4 4.2 3.7 3.7 3.4 5.9 6.1 6.16.0 4.1 3.9 3.3 3.0 3.4 3.0 7.7 5.4 3.43.4 2.8 6.1 3.3 2.4 4.8 3.3 Highly Confidential

TOTAL COMPANY ADJUSTED GROSS CASH G&A MONTHLY ADJUSTED GROSS CASH G&A 1585 1593 $12.0 1570 1540 1517 1483 1393 1369 $10.0 $8.0 $6.0 $4.0 $2.0 $0.0 Q3'17 Q4'17 Q1'18 Q2'18 Q3'18 Well Count Q4'18 Q1'19 Q2'19 Total Note: Well Count is gross operated wells. *Q2’19 = Apr-May only All currency values shown in Millions. 57 EP Energy Corporation 8.7 8.0 7.6 7.0 7.0 6.7 6.4 6.1 Highly Confidential

SUMMARY OF FT AGREEMENTS 58 EP Energy Corporation Description Counterparty Commodity Region Financial Commitment Ends Eagle Ford-CRGS Gas Gathering Camino Real Gathering Company LLC Natural Gas Eagle Ford Sep-22 Eagle Ford-Enterprise Texas Pipeline Enterprise Texas Natural Gas Eagle Ford Nov-21 Eagle Ford-Enterprise Hydrocarbon Processing Enterprise Hydrocarbons Natural Gas Eagle Ford Nov-21 ETC Texas Pipeline LTD Energy Transfer Natural Gas Eagle Ford Mar-23 Camino Real Oil Gathering Camino Real Oil Gathering Crude Oil Eagle Ford Feb-23 Eagle Ford Gathering Eagle Ford Gathering LLC Natural Gas Eagle Ford Dec-21 Ruby Pipeline LLC Ruby Pipeline LLC Natural Gas Other Jul-21 Highly Confidential

UINTA BASIN WAX CRUDE PRODUCTION 59 Note: Wax Crude Oil Production Source: Utah Department of Oil & Gas (Jan-18 through Dec-18), estimated Jan-19 forward kb/d EP Energy Corporation Total nameplate wax crude capacity of five SLC refineries = 90.9 kb/d Frequent scheduled and unscheduled refinery outages limit total wax crude demand Alternative feedstock crude competes with wax on price Incremental wax supply above SLC demand must be stored or moved outside Utah on rail Highly Confidential

MANAGEMENT PRESENTATION ADDENDUM 1 EP ENERGY CORPORATION August 2019 Highly Confidential

RESOURCE SUMMARY STRONG PDP ASSET BASE WITH MULTI-YEAR DRILLING INVENTORY EF DUC 3% EF DUC 6% PDP 64% Note: PDP value inclusive of: $154MM in Eagle Ford fixed transport cost, $114MM in field expenses and $130MM in Permian non-drill capital, assumed downtime and other charges. Undeveloped values for Eagle Ford and NEU inclusive of non-drill capital costs. $55.00 WTI / $2.75 HHUB price deck. [1] EF DUCs as of June 11, 2019. Excludes 337 Eagle Ford and 121 Permian gross undeveloped locations that are not scheduled in the development plan. 2 EP Energy Corporation 1 Commodity MixResource Category (Volumes)Asset-Level PV10 Distribution NGL 9% Gas PDP 36% Undev 53% Oil 33% Undev 55% 41% Oil/Cond. (MMBbl) Gas (Bcf) NGL (MMBbl) Equiv. (MMBoe) Capex ($Billion) Asset-Level PV10 ($Billion) Locations PDP 104 456 51 230 $0.1 $1.7 --Eagle Ford DUCs 11 22 4 18 0.2 0.2 47 NEU Undeveloped 235 957 --394 3.8 1.2 488 Eagle Ford Undeveloped 33 64 11 54 1.1 0.1 150 Total Resources 382 1,499 65 697 $5.1 $3.2 685 Highly Confidential

PRELIMINARY BUSINESS PLAN PROJECTIONS ILLUSTRATIVE SUMMARY MODEL OUTPUT ASSUMING $55 WTI / $2.75 HHUB 3 Source: EP Corporate Model EP Energy Corporation 2H'19 2020 2021 2022 2023 Pricing WTI ($/Bbl) $55.00 $55.00 $55.00 $55.00 $55.00 HH ($/MMBtu) 2.75 2.75 2.75 2.75 2.75 Realized Oil ($/Bbl) $52.34 $51.46 $51.01 $50.83 $50.48 Realized Gas ($/MMBtu) 1.74 1.71 1.60 1.55 1.66 Realized NGL ($/Bbl) 15.86 15.88 15.87 15.87 15.91 Revenues Oil $383 $841 $842 $850 $870 Gas 36 91 90 88 96 NGL 39 81 70 64 71 Other 10 - - - - Total Revenue $468 $1,013 $1,002 $1,002 $1,037 Expenses Transportation $49 $80 $75 $58 $52 Direct Lifting Costs 79 150 153 156 163 Severance Tax 23 52 51 51 53 Ad Valorem Tax 5 12 12 12 12 Adjusted General & Administrative 33 67 67 67 67 Gas Purchases & Other 0 - - - - Taxes Other than Income 2 5 5 5 5 Total Expenses $192 $366 $363 $349 $352 Hedge Settlements $10 $13 $ - $ - $ - EBITDAX $286 $660 $640 $653 $685 Highly Confidential

SENSITIVITY OF BUSINESS SELECTED ILLUSTRATIVE EXPENSE DETAIL PLAN EXPENSES 1 1 1 1 All currency values shown in Millions 4 [1] LTM as of June 1, 2019 [2] Range reflective of 2H ’19 annualized EP Energy Corporation NEU Eagle Ford Permian Corporate 2H '19 - 20232 2H '19 - 20232 2H '19 - 2023 22H '19 - 2023 2 LTM Illustrative LTM Illustrative LTM Illustrative LTM Illustrative Actual Low High Actual Low High Actual Low High Actual Low High LOE $40 $36 $52 $74 $71 $80 $39 $35 $42 $--$--$--Transportation ---- --79 45 80 12 7 10 9 --9 Adjusted G&A --0 0 1 1 1 1 1 1 65 64 65 Highly Confidential

Prepared at Request of Counsel Attorney Client Privilege Draft-Subject to Material Change Subject to FRE 408 and all State Law Equivalents Preliminary; Subject to Change 13-Week Cash Flow Forecast Project Explorer Prepared August 24, 2019 This document (the “Document”) has been prepared solely for informational and discussion purposes only from information supplied by EP Energy Corporation and its wholly owned subsidiaries (collectively, "EP" or the "Company). This document is subject to material change. By accepting this Document, the recipient acknowledges and agrees to the following: This Document includes certain statements, estimates and projections provided by the Company with respect to the anticipated future performance of the Company. Such statements, estimates and projections reflect various significant assumptions and subjective judgments made by the Company concerning anticipated results, which may or may not prove to be correct. No representations or warranties are made as to the accuracy or completeness of such statements, estimates or projections as such statements. Estimates and projections were prepared for internal planning purposes only and not with a view to public disclosure and therefore are not necessarily in compliance with published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants regarding projections or forecasts. Historical information provided in the Document may not have been prepared in accordance with US GAAP standards. You are cautioned not to rely on these forecasts and you should understand that many important factors, in addition to those discussed or referenced in this Document, could cause the Company’s results to differ materially from those expressed in forward-looking statements. For these reasons, you should not regard the inclusion of forecasts in this Document as an indication that the Company or any of its affiliates, subsidiaries or representatives considers that such forecasts are or will prove to be correct, and the forecasts should not be relied on as such. The recipient acknowledges and agrees that all of the information contained herein is strictly confidential. This Document and its contents are confidential to the person to whom it is delivered and should not be copied or distributed in whole or in part or disclosed by such persons to any other person without the prior written consent of EP. This Document incorporates information, which is either non-public, confidential or proprietary in nature, and is being furnished on the express basis that this information not be used in a manner inconsistent with its confidential nature or be disclosed to any other person. 8/24/2019 1

Prepared at Request of Counsel Attorney Client Privilege Draft-Subject to Material Change Subject to FRE 408 and all State Law Equivalents Project Explorer 13 Week Cash Flow Prepared August 24, 2019 $ in 000's August 8, 2019 Strip Pricing: $53.81 WTI, $2.32 HH Through 3/2020 Preliminary; Subject to Change Operating Cash Receipts Oil Sales Gas Sales NGL Sales Non-Operated Production Receipts Joint Interest Billing Receipts Hedge Receipts / Disbursements 2,149 - - - 1,138 666 1,376 - - - 1,816 2,461 98,957 - - - 799 - - 5,305 - - 311 - 19 1,178 613 67 968 (539) 2 (353) 1,291 13 1,117 2,742 263 - - - 448 - 99,581 - - 390 3,149 - - 5,484 8,155 - - - - - - - 5,398 953 - - - 470 - 2,074 - - - - 12,330 - 202,346 11,614 10,060 940 27,475 8,357 Operating Disbursements Payroll Benefits Royalties Capex LOE Transportation Severance, Ad Val Tax G&A (Incl. Rent, Insurance) Other (23,180) (185) (304) (13,036) (2,448) (40) (4,231) (1,787) (2,706) (2,114) (523) (1,253) (11,071) (3,515) (729) (15) (587) - - (93) - (9,687) (3,858) (1,511) (1,622) (2,134) - - (85) (8,705) (10,171) (3,985) (340) (3,287) (399) (296) (1,882) (599) (28,732) (7,773) (2,075) (2,681) - (2,355) (269) - (110) - (11,669) (3,421) (984) - (310) (86) (2,304) (497) (862) (12,933) (2,387) (3,827) (19) (439) (288) - (126) - (15,533) (2,475) (6,191) (7,045) (278) (250) (2,018) (584) (30,104) (15,533) (2,475) (1,191) - (278) (250) - (157) - (15,533) (2,475) (2,589) - (643) (250) (2,365) (506) - (32,608) (5,348) (1,589) - (504) (250) - (157) - (17,075) (2,873) (1,589) - (226) (250) (33,863) (3,622) (69,961) (172,621) (37,337) (23,260) (16,219) (9,939) (4,894) Interest & Fees RBL Interest & Fees 1.125 Lien Interest & Fees 1.25 Lien Interest & Fees 1.5 Lien Interest & Fees Unsecured Bond Interest & Fees Other Interest & Fees (314) - - - - - - - - - - - - - - - - (3) (1,536) - - - - - - - - - - - - - - - - - - - - - - - (1,600) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - (3,450) - - - - (3) Beginning Cash Balance Net Cash Flow RBL Borrowings / (Repayments) Change in Float 68,847 (44,225) - (5,516) 18,298 (14,057) 40,000 (7,548) 36,193 81,148 - (175) 116,916 (23,114) (60,000) 8,242 41,544 (44,034) 267,891 (405) 264,320 (11,485) - (5,291) 246,896 (22,769) - (2,724) 220,229 69,622 - (3,392) 286,460 (38,793) - - 247,666 (15,296) - - 232,371 (40,626) - - 191,745 (9,840) - - 68,847 (113,469) 247,891 (16,808) Beginning RBL Balance Change in RBL Balance 355,000 - 355,000 40,000 395,000 - 395,000 (60,000) 335,000 267,891 602,891 - 602,891 - 602,891 - 602,891 - 602,891 - 602,891 - 602,891 - 355,000 247,891 Liquidity Ending Cash Balance (+) Revolver Commitment (-) Revolver Balance (-) RBL Letters of Credit 18,298 629,421 (355,000) (26,530) 36,193 629,421 (395,000) (26,530) 116,916 629,421 (395,000) (26,530) 41,544 629,421 (335,000) (26,530) 264,320 629,421 (602,891) (26,530) 246,896 629,421 (602,891) (26,530) 220,229 629,421 (602,891) (26,530) 286,460 629,421 (602,891) (26,530) 247,666 629,421 (602,891) (26,530) 232,371 629,421 (602,891) (26,530) 191,745 629,421 (602,891) (26,530) 181,904 629,421 (602,891) (26,530) 181,904 629,421 (602,891) (26,530) Notes: 1) Net Cash Flow under Actuals (through August 9) excludes restructuring professional fees. Ending Cash Balance under Actuals ties to week end bank balances. (2) Cash flow forecast excludes interest payments for the 1.5L Notes and Unsecured Notes for illustrative purposes only. 1 $ 181,904 Liquidity $ 266,189 $ 244,084 $ 324,807 $ 309,435 $ 264,320 $ 246,896 $ 220,229 $ 286,460 $ 247,666 $ 232,371 $ 191,745 $ 181,904 $ 602,891 Ending RBL Balance $ 355,000 $ 395,000 $ 395,000 $ 335,000 $ 602,891 $ 602,891 $ 602,891 $ 602,891 $ 602,891 $ 602,891 $ 602,891 $ 602,891 $ 181,904 Ending Cash Balance $ 18,298 $ 36,193 $ 116,916 $ 41,544 $ 264,320 $ 246,896 $ 220,229 $ 286,460 $ 247,666 $ 232,371 $ 191,745 $ 181,904 $ (113,469) Net Cash Flow $ (44,225) $ (14,057) $ 81,148 $ (23,114) $ (44,034) $ (11,485) $ (22,769) $ 69,622 $ (38,793) $ (15,296) $ (40,626) $ (9,840) $ (3,454) Total Interest & Fees $ (314) $ - $ (3) $ (1,536) $ - $ - $ - $ (1,600) $ - $ - $ - $ - $ (110,015) Operating Cash Flow $ (43,911) $ (14,057) $ 81,152 $ (21,578) $ (44,034) $ (11,485) $ (22,769) $ 71,223 $ (38,793) $ (15,296) $ (40,626) $ (9,840) $ (371,715) Total Operating Disbursements $ (47,917) $ (19,808) $ (18,906) $ (27,269) $ (46,365) $ (16,579) $ (23,554) $ (31,897) $ (52,433) $ (21,647) $ (43,170) $ (22,170) $ 261,700 Total Operating Cash Receipts $ 4,006 $ 5,751 $ 100,057 $ 5,690 $ 2,331 $ 5,094 $ 785 $ 103,120 $ 13,640 $ 6,352 $ 2,544 $ 12,330 Jul. 5 - Sep. 20 Total Week Ending –> Jul 5, 19 Jul 12, 19 Jul 19, 19 Jul 26, 19 Aug 2, 19 Aug 9, 19 Aug 16, 19 Aug 23, 19 Aug 30, 19 Sep 6, 19 Sep 13, 19 Sep 20, 19 Forecast / Actuals –> Act Act Act Act Act Act Act Fcst Fcst Fcst Fcst Fcst

Prepared at Request of Counsel Attorney Client Privilege Draft-Subject to Material Change Subject to FRE 408 and all State Law Equivalents Project Explorer 13 Week Cash Flow Model - 6 Month Chapter 11 Case Sources & Uses for Emergence Prepared August 24, 2019 $ in 000's Preliminary; Subject to Change Assumed Emergence Date: 3/27/2020 Sources Uses Balance Sheet Cash Pre-Professional Fees Exit Facility LC Issuance Equity Rights Offering (TBD) Exit Facility Draw 73,239 17,861 500,000 42,995 Success Fees & Outstanding Pro. Fees Pay Off DIP Facility Balance Pay Off RBL Facility Balance Cash Collateralize DIP Facility LC's Cash Collateralize RBL Facility LC's GUC Pool Cash to Balance Sheet 52,030 100,000 454,204 17,861 - TBD 10,000 8/24/2019 1 Total Uses$634,096 Total Sources$634,096

Highly Confidential Subject to NDA Tax Attribute Discussion Materials for Sponsors (Cleansing Version) September 2019

Confidential Introduction EP Energy Corporation (the “Parent”; collectively with its direct and indirect subsidiaries, the “Company”) is the owner of U.S. federal income tax attributes that may be of value under certain circumstances (as discussed further below, the “Tax Attributes”). These materials provide an overview of the Tax Attributes and certain potential implications for the Parent and its subsidiaries that are obligors on the Company’s funded debt (together, the “Credit Group”). The issues addressed herein are being presented on a highly confidential basis to the four major stockholders of the Parent (each, a “Sponsor”). These materials are intended to supplement a discussion with the Sponsors and their respective advisors. 1 Excludes EPE Employee Holdings II, L.L.C., which is believed to be immaterial to the analysis set forth in these materials. 1

Confidential The Company’s Corporate and Capital Structure 2

Confidential The Company’s Corporate and Capital Structure (cont’d) Parent is the only relevant taxable entity in the Company’s corporate structure. The only other taxable entity in the structure is Everest Acquisition Finance Inc. (“FinanceCo”). •But FinanceCo has no assets and no financial activity. It is a co-issuer of the Company’s notes that permits marketing to and trading by funds that are restricted in their ability to own bonds issued by non-corporate entities (a commonly used financing structure where the issuer is a limited liability company). All of the other entities in the Credit Group are disregarded for U.S. federal income tax purposes. •EP Energy E&P Company, L.P. is a state law limited partnership. •All other entities in the Credit Group are limited liability companies. The Parent is not part of the Credit Group. The Parent is not an obligor on the Company’s funded debt, and its assets are not subject to the liens of the Company’s secured creditors. Subject to confirmatory diligence, the only other currently known claims against the Parent are purported litigation claims (currently believed to have a $0–225,000 aggregate exposure range and likely subject to motions to dismiss by the parent) and potentially state law tax liabilities (if any). There are no known intercompany claims against the Parent. Although the Parent’s equity in its direct subsidiary, EPE Acquisition, LLC, potentially has little or no value, the Tax Attributes are believed to have value under certain circumstances. The Company does not have a tax sharing agreement. As a result, absent the application by a court of extraordinary remedies such as substantive consolidation, veil piercing/alter ego, or other equitable remedies, or the consent of the Parent, the Credit Group may not be entitled to any portion of the Tax Attributes or the value thereof. 3

Confidential Overview of the Tax Attributes In particular, the Tax Attributes consist of the following (projected as of December 31, 2019)1: • • • Federal net operating losses (“NOLs”): $3.5 billion. Deferred interest deductions: $480 million. Tax basis in assets: $4.2 billion. U.S. federal income tax rules generally permit a corporation to carry forward its NOLs to reduce future taxable income, thereby reducing its tax liability in future periods (at a 21% tax rate). •Similarly, tax basis in assets is generally available to be depreciated and amortized over time for federal income tax purposes, thereby reducing future taxable income or, in the event of a sale of assets, reducing gain or giving rise to a loss. As discussed further below, the Tax Attributes appear to be assets of the Parent, not its subsidiaries, which are generally disregarded entities for U.S. federal income tax purposes. The Tax Attributes are subject to potential limitations on their use (discussed below) but nevertheless might have value in at least two potential scenarios: Scenario A – S p o n sors “utilize ” T a x A tt rib u te s: Sponsors capitalize the Parent (prior to the closing of the restructuring) without causing a greater than 50% change in ownership and acquire, for good business reasons, profitable assets or businesses with them, using the Tax Attributes to reduce taxable income of such profitable enterprise up to approximately $3 billion over time. Creditors take the existing business. Scenario B – Shareholders receive consideration for Tax Attributes: In connection with a chapter 11 restructuring of the Company, the Tax Attributes continue to be available for use to offset incremental cash tax liabilities of the existing business. Shareholders of the Parent receive consideration for the value provided to the reorganized Company. 1 All amounts in this presentation are approximations based on figures provided by the Company and have not been independently verified by Weil or PwC. 4

Appendix: Tax Rules and Certain Tax Considerations

Confidential General Section 382 Overview Section 382 of the U.S. Internal Revenue Code (the “Code”) limits the use of certain tax attributes if a corporation has an “Ownership Change.” As indicated, an Ownership Change generally occurs if (i) statutorily defined 5% shareholders increase their ownership (ii) during any 3-year period (iii) in excess of 50 percentage points. All purchases and sales of stock by a “5% shareholder” and all stock issuances and repurchases by the Parent generally count (by treating all less-than-5% shareholders as a single “5% shareholder” group). As of December 31, 2018, the Company estimates a total owner shift (further described on the following slide) of approximately 6.2%. Annual Limitation: In connection with an Ownership Change, Section 382 of the Code generally imposes an annual limitation on the future use of pre-change losses, equal to (i) a specified rate (currently, ~2%) times (ii) the Parent’s equity value at the time of the Ownership Change. In bankruptcy, where the change occurs pursuant to a confirmed chapter 11 plan, the annual limitation is computed by reference to the reorganized equity value of the Parent with certain limitations, as opposed to the pre-change equity value (the “Section 382(l)(6) rule”). The annual limitation also applies to the Parent’s net unrealized built-in losses (“NUBIL”), which could result in the deferral of tax deductions arising from depreciation and amortization of assets with a basis in excess of its value or the disposition of such assets. • An IRS technical rule permits the Parent to calculate its net built-in gain or loss for limitation purposes by assuming the Company’s assets have a value equal to the Company’s pre-restructured debt, even though the actual value is significantly less. - Proposed regulations were recently issued which potentially could change this treatment. •As a result, a second ownership change post-restructuring (after the debt has been equitized or discharged) should be avoided, since the full economic built-in loss could then be subject to limitation. One potential means of reducing the risk of a second ownership change is the imposition of a charter restriction. 6

Confidential Section 382(l)(5) Bankruptcy Exception Alternatively, if the bankruptcy ownership change qualifies for the special exception under Section 382(l)(5) of the Code, and the Parent does not elect out: No annual limitation on the Parent’s use of NOLs applies; Any interest deductions previously taken on debt converted to equity would have to be charged back; and It is important to avoid a second ownership change but particularly within 2 years, since a change within 2 years would render any then existing NOLs completely useless. The Section 382(l)(5) exception applies if the Parent’s shareholders and/or so-called “old and cold” creditors of the Credit Group receive or retain at least 50% of the vote and value of the reorganized Parent. An “old and cold” creditor is any creditor that holds “qualified” debt. Qualified debt generally is: (i) debt outstanding since at least 18 months before the petition date, and continuously held since then by the same creditor; (ii) debt incurred in the Company’s ordinary course of business (e.g., trade debt), and continuously held by the same creditor; and (iii) the above types of debt, except that even though the debt has not been continuously held by the creditor, the creditor does not become a 5% shareholder of reorganized Parent. Whether or not the Parent qualifies for Section 382(l)(5) will depend in large part on the which creditors receive the majority of the equity of the reorganized Parent. Regardless of whether the Parent may qualify, the practical value of the incremental benefits may not justify imposing claims trading restrictions to protect potential qualification. 7

Confidential New Proposed Section 382(l)(6) Regulations On September 9th, the U.S. Internal Revenue Service (the “IRS”) issued proposed regulations that would remove, under certain circumstances, the current rule that permits the calculation of net built-in gain or loss for limitation purposes by assuming the assets have a value at least equal to a corporation’s pre-restructured debt. The current rule would allow the Parent the future use of its existing large tax basis (~$4 billion) without limitation. The current rule is based on a 2003 IRS Notice upon which the Parent can continue to rely pending the finalization of regulations. In the explanation accompanying the proposed regulations, the IRS indicated that it intended to completely remove the benefit of the higher tax basis. However, as currently drafted, the regulations only apply this change to recourse debt of a taxpayer. Nonrecourse debt is treated differently. Significantly, the IRS has informally taken the view that recourse debt of a disregarded limited liability company is generally treated as nonrecourse with respect to its parent. Thus, all liabilities of the Credit Group may be considered nonrecourse to the Parent. So treated, the proposed regulations would have little practical effect on the projected tax impact of the proposed restructuring. However, when finalized, the regulation may be changed, or the IRS could change its view regarding the treatment of recourse debt of a disregarded limited liability company. The IRS has expressed the desire to finalize these regulations by the end of 2019 and has asked for comments by November 12th. 8

Confidential Potential Value of Tax Attributes to Shareholders If the creditors of the Credit Group were to receive equity in reorganized EPE Acquisition LLC, rather than the stock of the Parent, the Parent would retain possibly close to $3 billion in U.S. federal NOLs. Approximately 70% of the remaining NOLs would expire between 2032 and 2037, if unused. The remaining NOLs would have an indefinite life (subject to an 80% limitation on use in any year). The value of the Tax Attributes depends on the Parent’s ability to generate future income, and thus requires significant capital investment. Initial capital would have to be raised from existing shareholders owning >50% of the Parent’s stock to avoid triggering an Ownership Change. An Ownership Change would effectively eliminate the use of the NOLs. Third party equity capital could be raised so long as its doesn’t trigger an Ownership Change, which is tested on a rolling three-year basis. It may also be possible, under certain circumstances, for existing shareholders to contribute a commonly-held company, provided the principal purpose for the contribution is not tax avoidance. Approximately 75% of the Parent’s stock is held by four groups of shareholders (based on the latest 10-K): Apollo funds - 39.1% Access funds - 13.7% Riverstone funds - 12.2% KNOC - 12.2% 9

Confidential – Subject to FRE 408 For Discussion Purposes Only DRAFT 9/9/19 Project Explorer: Cash Collateral/DIP and Exit Term Sheets THESE TERM SHEETS DO NOT CONSTITUTE (NOR WILL THEY BE CONSTRUED AS) AN OFFER WITH RESPECT TO ANY SECURITIES OR A SOLICITATION OF ACCEPTANCES OR REJECTIONS AS TO ANY PLAN OF REORGANIZATION, IT BEING UNDERSTOOD THAT SUCH AN OFFER, IF ANY, ONLY WILL BE MADE IN COMPLIANCE WITH APPLICABLE PROVISIONS OF SECURITIES, BANKRUPTCY, AND/OR OTHER APPLICABLE LAWS. THESE TERM SHEETS DO NOT PURPORT TO SUMMARIZE ALL OF THE TERMS, CONDITIONS, REPRESENTATIONS, WARRANTIES, AND OTHER PROVISIONS WITH RESPECT TO THE TRANSACTIONS DESCRIBED HEREIN, WHICH TRANSACTIONS WILL BE SUBJECT TO THE COMPLETION OF DEFINITIVE DOCUMENTS INCORPORATING THE TERMS SET FORTH HEREIN. THE CLOSING OF ANY TRANSACTION WILL BE SUBJECT TO THE TERMS AND CONDITIONS SET FORTH IN SUCH DEFINITIVE DOCUMENTS. EXCEPT AS SET FORTH IN THE RSA (AS DEFINED BELOW), NO BINDING OBLIGATIONS WILL BE CREATED BY THESE TERM SHEETS UNLESS AND UNTIL BINDING DEFINITIVE DOCUMENTS ARE EXECUTED AND DELIVERED BY ALL APPLICABLE PARTIES. Transaction Summary • • Prenegotiated chapter 11 cases for EP Energy Corporation and [certain of] its direct and indirect subsidiaries (“Debtors” or “Company”). Chapter 11 cases to be funded through (i) [•]1% roll-up of the obligations under the prepetition RBL Credit Agreement2 (“RBL Claims”) into a senior secured priming first lien superpriority revolving DIP facility and (ii) consensual use of cash collateral. Chapter 11 emergence funded by: • $[500] million equity rights offering fully backstopped by certain holders of 1.5L Notes, and Exit facility of at least $[629] million (the “Exit Facility”) potentially consisting of two tranches: (a) a committed first-out revolving RBL tranche o o (the “First Out Tranche”) with L/C participations and (b) a second-out term loan tranche (the “Second Out Tranche”). The Exit RBL Agent (as defined below) shall also agree to use best efforts to obtain commitments to upsize the Exit Facility by $[200–300] million at closing of the Exit Facility, which new money shall be part of the First Out Tranche. Chapter 11 Plan (as defined below) to be consistent with terms of Restructuring Support Agreement (“RSA”) and Restructuring Term Sheet attached thereto entered into with prepetition RBL lenders holding more than 50% of prepetition RBL commitments and certain holders of 1.5L Notes and structured as follows: • o o DIP Claims (as defined below) to convert dollar for dollar into the First Out Tranche of the Exit Facility. RBL Claims to be rolled up into the Second Out Tranche of the Exit Facility; provided, that each holder of RBL Claims may instead elect to participate in the First Out Tranche by consenting to the RSA and providing a commitment with respect to the First Out Tranche. Each holder of RBL Claims making such election must make such election with respect to all, and not just a portion, of its RBL Claims. 1.125L Notes and 1.25L Notes to be reinstated. 1.5L Notes secured claims to receive [•]% of reorganized equity and unsecured claims to receive [•]% of reorganized equity or cash equivalent; provided, that if classes of unsecured claims and equity interests both vote to accept Chapter 11 Plan, then: o o    1.5L Notes will waive [•]% of their deficiency claims in unsecured claims class; Holders of remaining unsecured claims will receive [•]% of reorganized equity (or cash equivalent); and Holders of existing Class A common shares will receive [•]% of reorganized equity. • Anticipated chapter 11 timeline: Anticipated petition date (“Petition Date”): September [15], 2019 o o Anticipated effective date of Chapter 11 Plan (“Effective Date”): [6–9] months from Petition Date 1 NTD: Subject to ongoing discussion. 2 NTD: Roll-up mechanics of principal, interest and any other RBL obligations to be discussed. WEIL:\97156491\16\42780.0003

use of all cash as cash collateral, subject to customaty terms and conditions including customaty material to the DIP agent, DIP lenders, prepetition RBL agent and prepetition RBL lenders, with the facility upon ently of a fmal order approving DIP roll up and use of cash collateral (the "Final Out Tranche of the Exit Facility Facility; provided, that each holder ofRBL Claims that consents to the RSA may instead elect to • Prepetition RBL lenders holding greater than [50%] of prepetition RBL commitments have usual and customary for loans of this type • Minimum availability tmder the DIP facility of $[•] million at closing after applying cash paydown ("Monthly Cash Flow Forecast") postpetition 2 WEIL:\97156491\16\42780.0003 CASH COLLATERAL AND DIP TERM SHEET Consent to Use of Cash Collateral •Prepetition RBL agent and prepetition RBL lenders that consent to the RSA shall consent to Debtors' tennination provisions Chapter II Plan • Debtors will pursue conflllllation of a chapter 11 plan that is substantially consistent, in all respects Restmcturing Term Sheet (the "ChaQter 11 Plan") DIP Roll-Up • Roll-up of [•]% of RBL Claims into senior secured priming first-lien superpriority revolving DIP Order '), applied pro rata among the exposures of prepetition RBL lenders consenting to the RSA • Remaining [•]% of RBL Claims to remain outstanding during the pendency of the chapter 11 cases Chapter II Plan Treatment of DIP Cla;ms and Prepet;t;on RBL Cla;ms • Upon the Effective Date, DIP Claims (as defmed below) to conve1t dollar for dollar into the First • Upon the Effective Date, RBL Claims to be rolled up into the Second Out Tranche of the Exit participate in the First Out Tranche 0Each holder of RBL Claims making such election must make such election with respect to all, and not just a po1tion, of its RBL Claims Cond;t;ons to Effect;veness of DIP • Ently of Final Order approving DIP Roll-Up consented to the RSA • Execution of satisfacto1y DIP credit agreement and other related defmitive legal documentation • Minimum hedging of [80]% of PDP related to oil reserves for [12] months from the Petition Date • Delivery of a cash flow fore.cast on a monthly basis for the period from closing through emergence Hedg;ng • All hedging agreements with prepetition RBL lenders in effect prepetition shall remain in effect

liens tmder the RBL Facility, subject to customary exclusions • Junior lien on all other property subject to valid, perfected and non-avoidable liens (such first and Priming liens on prepetition collateral (junior to DIP Liens), with customary exclusions 0 Replacement liens on prepetition collateral and superpriority administrative expense claims, in 0 3 WEIL:\97156491\16\42780.0003 CASH COLLATERAL AND DIP TERM SHEET DIP Liens • Consensual priming first priority lien security interests in and liens on all assets cunently subject to • First priority lien on all tmencumbered assets junior priority liens, collectively, the "DIP Liens") DIP Claims • Superpriority administrative expense claims, subject to customary exclusions ("DIP Claims") Adequate Protection • For RBL Claims, to the extent of diminution of value: 0First liens on tmencumbered assets (junior only to DIP Liens), with customary exclusions 0No consensual priming liens without the consent of requisite prepetition RBL lenders 0Superpriority administrative expense claims, junior to DIP Claims, subject to customary exclusions 0Scheduled cash payments of interest at non-default rate 0Payment of ordinary course monthly hedge settlements (if any) owing to RBL lenders 0Payment of reasonable and documented advisor fees and out-of-pocket expenses, in each case, to extent provided in existing Credit Agreement • For 1.125L notes, 1.25L notes, and 1.5L notes secured claims, to the extent of diminution of value: same priorities as existing capital structure, subject to customary exclusions 0Subject to existing intercreditor agreements 0[For all three tranches of notes collectively, payment of reasonable and documented fees and out-of-pocket expenses for three law finns and three financial advisors] Interest Rate • L + 35 0 bps. LIBOR shall be calculated without a LIBOR floor. Unused Line Fee • Maturity • 12 months from effectiveness of the DIP facility with ability to extend such mahrrity date with the consent of the DIP lenders Milestones • Ently of Final Order within [45] days of Petition Date

rep01ting) that no variance test shall be required • Notice of any material change to projected disbursements in an aggregate amotmt in excess of $20 cash) tested at the end of each day of $25 million DIP plus RBL Claims that were not rolled into DIP facility) > [1.25x] for facilities of this type (including bankruptcy milestones and customary bankruptcy related events IP claims required to be paid in fhll or conve1ted to equity at emergence An·anger (as defined below) within one business day after the bankruptcy court approves the interim cash collateral/DIP order o mptcy cotnt approves the interim cash collateral/DIP order 4 WEIL:\97156491\16\42780.0003 CASH COLLATERAL AND DIP TERM SHEET Reporting • Substantially consistent with prepetition RBL credit agreement (including with respect to reserve • Rolling 13 week cash flow forecast with variance repo1ting delivered every four weeks, provided, • Updates to the Monthly Cash Flow Forecast every four weeks million through anticipated emergence • Consolidated monthly balance sheet and income statement Financial Covenants • Minimum liquidity (to be defmed to include availability under the DIP Facility and unrestricted • Monthly Minimum Asset Coverage test: (Total PDP PV-10 + Hedges) I (Total Utilization under the 0Calculation of Total PDP PV-10 to be updated only for the following: changes in strip prices for oil and natural gas, wells brought online or divested, production forecast for wells with less than six-months of production, and other inputs (e.g. LOE, production taxes) if materially changed from most recently delivered reserve repo1t Affirmative and Negative Covenants and Events of Default • Substantially similar to the prepetition RBL facility with such changes as are usual and customary of default for DIP facilities to be agreed upon) Junior Lien DIP Capacity • • • Ability t amotmt Junior D Junior D to !! nk o incur a jtmior lien DIP facility during the pendency of the chapter 11 case in an aggregate up to $[150] million IP claims to be junior to DIP Claims and RBL Claims Arrangement Fee • • on prepetition RBL commitments of the prepetition RBL lenders that consent to the RSA, n $629 million prepetition RBL facility paid to the An·anger within one business day after

potentially a Second Out Tranche, with the initial Bonowing Base to be detennined by the Exit RBL Facility by $[200-300] million at closing (the "Incremental Connnitments"), which new money shall Required Revolver Lenders (as defmed below) having the right to one wildcard redetennination 3 NTD: The interest rate and ce1tain economic provisions and covenants related to the Second Out Tranche are to be detenuined after further review. 5 WEIL:\97156491\16\42780.0003 EXIT FACILITY TERM SHEET Borrower •EP Energy LLC Exit Facility • $[629] million Exit Facility at Petition Date, consisting of a connnitted First Out Tranche and Agent and the lenders in the First Out Tranche in connection with effectiveness of the Exit Facility • The Exit RBL Agent shall also agree to use best efforts to obtain connnitments to upsize the Exit be part of the First Out Tranche • Connnitment period of 12 months Letters of Credit •$100 million sublimit Guarantors • Same as tmder prepetition RBL facility Administrative Agent •JPMorgan Chase Bank, N.A. (the "Exit RBL Agent") Lead Arranger I Bookrunner •J.P. Morgan (the "Ananger") Security •Substantially similar to the prepetition RBL facility Borrowing Base •Bonowing Base subject to redete1minations on November 1 and May 1, with both the Bonower and between scheduled redete1minations; the first redetennination to occur on the first November 1 or May 1 that is at least six months after the Effective Date Interest Rate 3 • L + 250-350 floor bps, based on bonowing base utilization. LIBOR shall be calculated without a LIBOR Unused Line Fee • based on bonowing base utilization Maturity • The earlier to occur of (i) four and a half years from the Effective Date and (ii) July 31, 2024 Arrangement Fee • on any Incremental Connnitments, payable to the Ananger on the closing date of the Exit

benefit of the lenders conunitting to provide the Exit Facility, ofwhich shall be paid one business day after the banlauptcy cotut approves the intenm cas collateral/DIP order which shall be paid within one business day after the bankmptcy cotut approves the cas RBL Agent, for the benefit of the lenders conunitting to provide the Exit Facility, of hall be paid within one business day after the bankmptcy court approves the interun cas incremental lenders providing the Incremental Conunitments, on the closing date of the Exit Facility the Effective Date, with unlimited cash netting; provided, that cash netting shall be capped at $50 Effective Date, with the ability to include remaining RBL availability as current assets for facilities of this type4 4 For the avoidance of doubt, the Exit Facility Credit Agreement and its covenants are to be negotiated using the prepetition fonu of Credit Agreement w'ith customaty and usual modifications for exit financings of this type. 6 WEIL:\97156491\16\42780.0003 within andof fina Ex1t which collate bankm . EXIT FACILITY TERM SHEET UpfrontFee • • • o s ra pt o n the portion of prepetition RBL facility rolled into the DIP, payable to the Exit RBL Agent, collateral/DIP order on the portion ofprepetition RBL fa<ility which is not rolled into the DIP, pae l/DIP order and of which shall be paid within one business day after the cy cotut approves the final cash collateral/DIP order n any Incremental Conunitments, payable to the Exit RBL Agent, for the benefit of such Agent Fee • annually Ranking I Borrowing Base Coverage •Substantially similar to the prepetition RBL facility Financial Maintenance Covenants •Total Leverage Ratio: 4.0x, tested quarterly, conunencing with the first full fiscal qua1ter following million at any time there are loans outstanding tmder the First Out Tranche •Current Ratio: l.Ox, tested qua1terly, conunencing with the first full fiscal quarter following the Affirmative and Negative Covenants • Substantially similar to the prepetition RBL facility with such changes as are usual and customary

vacated, stayed, or othetwise modified without the prior written consent of the DIP Agent and DIP • Usual and customaty conditions to closing for facilities and transactions of this type, including: Nonpayment of principal, interest or fees when due (subject to customaty grace period for 0 • Borrowing Base reductions I reaffliTllations: 66 2/3% of First Out Tranche lenders ("Required • Ordinary course amendments: 50% of First Out Tranche lenders 7 WEIL:\97156491\16\42780.0003 EXIT FACILITY TERM SHEET Conditions Precedent • Final Order approving DIP roll-up remains in full force and effect and has not been reversed, lenders • Enny of order confirming Chapter 11 Plan 0Minimum hedging of [•]% of PDP related to oil reserves for [12] months from the Effective Date 0Execution of reasonably satisfact01y exit credit agreement and other related definitive legal documentation usual and customaty for loans of this type 0Ftmding of (backstopped) rights offering 0Total debt at emergence net ofunresn·icted cash on the balance sheet not to exceed $1,600 million; provided that (a) total debt shall be comprised of(x) $1,500 million in respect of 1.125L notes and 1.25L notes and (y) up to $100 million of principal amotmt of loans tmder the Exit Facility, (b) unresn·icted cash on the balance sheet shall be netted from the calculation so long as the aggregate amotmt of such tmrestricted cash is equal to or greater than 50% of the amotmt of any loans outstanding under the Second Out Tranche and (c) in no event shall the principal amotmt of loans outstanding under the First Out Tranche exceed $100 million on the closing date Events of Default •Substantially similar to the prepetition RBL facility, including: failure to pay interest and fees) 0Nonperf01mance of covenants within standard grace periods 0Material judgments against Borrower or any Guarantor 0Change of control Voting •Borrowing Base increases: 100% of First Out Tranche lenders Revolver Lenders") •Financial covenant amendments: 50% of First Out Tranche lenders