Investor Update April 2015

2

Cautionary Statement Regarding Forward-Looking Statements

This presentation includes certain forward-looking statements and projections of EP Energy. EP Energy has 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 supply and demand for oil, natural gas and NGLs; changes in commodity prices and basis differentials for oil and natural gas; EP Energy’s ability to meet production volume targets; the uncertainty of estimating proved reserves and unproved resources; the future level of service and capital costs; the availability and cost of financing to fund future exploration and production operations; the success of drilling programs with regard to proved undeveloped reserves and unproved resources; EP Energy’s ability to comply with the covenants in various financing documents; EP Energy’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; credit and performance risk of EP Energy’s lenders, trading counterparties, customers, vendors and suppliers; general economic and weather conditions in geographic regions or markets served by EP Energy, or where operations of EP Energy 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 regulation; and other factors described in EP Energy’s Securities and Exchange Commission filings. While EP Energy makes these statements and projections in good faith, neither EP Energy 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. This presentation refers to certain non-GAAP financial measures such as “Adjusted EPS”, “Adjusted EBITDAX“, “Adjusted EBITDAX Margin Per Unit”, “Adjusted Cash Operating Costs” and “Discretionary Cash Flow Per Share”. Definitions of these measures and reconciliation between U.S. GAAP and non-GAAP financial measures are included in the Fourth Quarter 2014 Financial and Operational Reporting Package at epenergy.com.

3

EP Energy Oil-focused growth company

with four core asset areas

Leading operations

Low cost

Top-tier well results

Increasing efficiency

Strategic positions in resource-rich basins

~477,000 net acres

~5,700 risked drilling locations, 30+ years

Delivering results

Improved production rates and costs

Growing oil production

Leading hedge position

Notes: Acreage and gross drilling locations as 12/31/14.

Net Acres: ~82,000 2014 Net Daily Production (MBoe/d): 50.9 Gross Drilling Locations: 872

EAGLE FORD SHALE

EP Energy Acreage

Net Acres: ~180,000 2014 Net Daily Production (MBoe/d): 15.3 Gross Drilling Locations: 3,300

HAYNESVILLE SHALE Net Acres: ~38,000 2014 Net Daily Production (MMcf/d): 96 Gross Drilling Locations: 197

ALTAMONT Net Acres: ~177,000 2014 Net Daily Production (MBoe/d): 15.5 Gross Drilling Locations: 1,304

WOLFCAMP SHALE

4

Investment Thesis Strategic position in leading U.S. resource plays Growing reserve base Significant drilling inventory of low-cost plays

Large contiguous acreage positions Repeatable drilling and completions activities Top-tier operating cost performance

Large Portfolio of High Quality

E&P Assets

Driving out costs while improving production rates Higher well performance (avg. IP-30s up 20% 2012 to 2014) Lower well cost (avg. well cost down 17% 2012 to 2014)

Compelling relative multiples Well positioned to improve returns Upside potential – cost structure, well performance, add inventory

Balance cash flow and capital spending Significant liquidity supported by growing reserve base Strong hedge position enables stable development

Compelling Value

Strong Financial Position

Efficient Operations

Continuous Improvement

5

Continuous Improvement

Note: Current well costs and best recent well performance reflect Q1 2015 actual results. 1 Includes drilling, completing and well site facilities.

Eagl

e Fo

rd

Alta

mon

t W

olfc

amp

$8.3 $7.4 $7.2

$6.0

2012 2013 2014 Current Well

$5.9 $5.4 $5.2

$4.3

2012 2013 2014 Current Well

Gross Well Cost1 ($MM)

14 12 10 8

2012 2013 2014 Best Recent

Well

31

24 21

12

2012 2013 2014 Best Recent

Well

15

10 11

6

2012 2013 2014 Best Recent

Well

Rig Days (Spud to Rig Release)

4.7 6.5 6.9

8.8

2012 2013 2014 Best Recent

Well

2.3 2.9

3.5 4.1

2012 2013 2014 Best Recent

Well

4.7

6.2 5.3

7.0

2012 2013 2014 Best Recent

Well

Stimulation (Stages per day)

$569 $498 $489

$405

2012 2013 2014 Current Well

$472 $441 $425

$373

2012 2013 2014 Current Well

$534

$374 $407 $343

2012 2013 2014 Current Well

Total Well Cost per Foot1

($/ft.)

$7.7

$5.6 $6.2 $5.0

2012 2013 2014 Current Well

6

$3.82

$5.19 $5.44 $5.63

$6.03 $6.23

$7.49 $7.63 $7.64 $7.86 $8.23

Managing Efficient Operations Average LOE (1Q’13 – 4Q’14)

Note: Based on quarterly weighted average lease operating expenses for the period 1Q’13 through 4Q’14 as reported by peer companies; AREX, APC, CRZO, CLR, CXO, EOG, FANG, LPI, PXD and RSPP

$/Boe

EPE Peer A Peer B Peer J Peer C Peer D Peer E Peer F Peer H Peer G Peer I

7

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

EPE

CLR

WLL

RSPP

CXO

OAS AP

C

EOG

NBL

PXD

APA

TLM

EGN

NFX

EQT

SM DVN

XEC

ECA

WPX EC

R

CHK

GPO

R

RRC

SWN AR

MH

R

COG

$/Bo

e

Cash Margin per BOE (2015E at assumed $65/Bbl WTI)

Note: Base case volume expectations are hedged Source: Deutsche Bank

Delivering Strong Cash Margins

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Increased Reserves and Inventory

2013 2014

526²

622 Proved Oil & Gas Reserves (MMBoe)¹

1 Based on the first day 12-month average prices of $96.94 per Bbl and $3.67 per MMBtu in 2013 and $94.99 per Bbl and $4.34 per MMBtu in 2014. ² Excludes 21 MMBoe from South Louisiana Wilcox and Greater Holly assets sold in May 2014. ³ Includes price revisions and excludes acquisitions.

2013 2014

5,169

5,673

Future Drilling Locations

Proved Oil and Gas Reserves 18 percent increase from 2013 103 MMBoe in additions 66 percent in Eagle Ford

$16.93 per Boe reserve replacement cost³

343 percent reserve replacement ratio³ Core Program Drilling Inventory Added 500+ drilling locations from 2013 Eagle Ford 40-acre spacing Wolfcamp acquisition Altamont 80-acre spacing

30 year drilling inventory at 2015 activity levels

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Haynesville

Core Asset Overview

High-quality concentrated asset portfolio

Eagle Ford Wolfcamp

Altamont

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Returns Focused Investment

2015E: $1.2 – 1.3 billion

Wolfcamp 15%

Altamont 11%

Eagle Ford 66%

Haynesville 8%

Financial discipline – balance cash flows and capital

Drive out costs – expecting reductions in 2015; 15% capital costs 10% cash costs

Average 6 to 7 drilling rigs 160 to 190 well completions 10 percent oil volume growth

Oil & Gas Capital

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Eagle Ford: Franchise Oil Program

Highest-return program with significant growth

Five rigs and three stimulation crews

43 wells completed

Improved performance

Drilling efficiencies and execution

Completion optimization and higher production rates

Similar number of completion activities in cornerstone asset

Leveraging recent drilling and completion success

Development on 40-acre well spacing in black oil window

Continuing to drive out costs – capital and operating

4Q Highlights

2015 Outlook

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Eagle Ford: Value-added Cumulative Production

2013 Oil & liquids represent 67 percent of proved reserves and 91 percent of reserve value1 0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

0 10 20 30 40 50 60 70 80 90 100 110 120

Producing Days

2015 (Current Design)

2014 (Current Design)

2014

2013

2012

Average Cumulative Oil Production (Bbls)

66% more oil production at 80 days with current well designs versus 2012.

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Eagle Ford − Rapidly Improving Rates and EURs Eagle Ford: Continuous Improvement

691

885 972 926

-

200

400

600

800

1,000

1,200

2013 2014 2014 (89 Wells atCurrent Design)

Current TC

IP 30 (BOEPD)

IP 3

0 Pr

oduc

tion

(BO

EPD)

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Eagle Ford: 40-Acre Infill Pilot

2013 Oil & liquids represent 67 percent of proved reserves and 91 percent of reserve value1

>40% Increase In Recoverable Reserves Per Section

<15% Increase in F&D Costs Per Section

Well spacing 60-acres 40-acres

Wells per section 10 16

Average well performance outpacing type curve

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Wolfcamp: Rapidly Improving Program

Largest company resource base – rapidly improving

Four rigs and two stimulation crews 21 wells completed Technical advancements improved recent results Successfully completed initial A-Bench pilot

New completion design improving production

performance High grading drilling program

Highest-return areas Most technical knowledge Most cost efficient area near existing

infrastructure Reducing activities compared to 2014 Continuing B/C development Driving down capital and operating costs

4Q Highlights

2015 Outlook

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Wolfcamp: Mini-Chevron Optimization

WO

LFCA

MP

A W

OLF

CAM

P B

WO

LFCA

MP

C

A 0

A 2

A 1

B 0

C 4

C 3

C 1

C 2

B 1

Dean Top Wolfcamp

Full Development 7 wells per bench 21 per section

-- ~770’--

--- ~1,540’ ---

Drilling mini-chevrons within same zone 3-D seismic covering entire acreage position Identifies highest potential pay-zones Assist with drilling geo-steering

Minimizes offset flooding Provides development flexibility

Supports step change in well performance

Landing zones Land in highest TOC Minimize Ls interference

17

0

5

10

15

20

25

30

35

40

0 20 40 60 80 100 120 140 160

Cum

ulat

ive

Prod

uctio

n, M

BO

Time, Days

Wolfcamp Block 43: Completion Optimization Results

43-Block

Optimization yielding great results

43 Blk Non-Optimized (22 wells) 43 Blk Optimized (9 wells) Current TC

18

0

200

400

600

2013 Wells 2014 Wells Crockett Cty - avg. Q4'14wells

Crockett Cty - avg. Q1'15wells

Oil

Prod

uctio

n, B

OPD

Type Curve IP 30 (369 BOPD)

Wolfcamp: Continued Performance Improvement

Wolfcamp B&C IP 30 Results (BOPD)

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Wolfcamp: Positive Wolfcamp A Pilot Results

0

100

200

300

400

500

600

41-09-DH 44-11-MH 11-15-GH 11-25-AH 8-29-BH 8-24-CH

Oil

Prod

uctio

n, B

OPD

Wolfcamp A IP 30 Results (BOPD)

Type Curve IP 30 (369 BOPD)

Utilized current completion design

Utilized limited completion design

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8.1 7.9 8.3 8.9

9.5 9.8

11.7 11.8

12.8

4Q'1

2

1Q'1

3

2Q'1

3

3Q'1

3

4Q'1

3

1Q'1

4

2Q'1

4

3Q'1

4

4Q'1

4

Altamont: Steady Growth With Solid Returns

Step-change improvement in legacy asset Three rigs and one stimulation crew 11 wells completed Received approval for 80-acre well spacing Improved terms on oil sales contracts

High grading drilling program

Focus on highest-return wells in shallower, southwest area

Leveraging success and learnings from 2014 all-time best wells

Reducing activities compared with 2014 Continuing capital and operating cost

reduction Narrowing basis differentials

Oil Production (MBbls/d)

4Q Highlights

2015 Outlook

80-Acre Spacing Area

Focus of 2015 activity

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Haynesville: Resume Drilling in High Return Program

Premier acreage in core of the play

Strategic location near Gulf Coast and growing Southeastern markets

Top-tier drilling and production performance when last active

Restarting program at measured pace –

Mid 2015 Completion enhancements driving

higher EURs and higher returns Multi-pad drilling with longer laterals Piloting re-frac program

Highlights

2015 Outlook

Peak Month Gas (Mcf/d)

10,000+

7,500 to 9,999 5,000 to 7,499

0 to 4,999

EPE acreage

22

Type Well Economics

¹ Assumes $65 per Bbl (WTI) oil and $3.50 per MMBtu (HH) 2 Break-even oil price (WTI) required to generate a 10% pre-tax IRR using 5 year (2015 – 2019) inventory type well economics.

Long Short Vertical Holly Non Holly5 Year Inventory (2015- 2019)

Pre-Tax IRR1 52% 25% 37% 46% Breakeven Pricing ($/BBl or $/Mcf)2: At 20% Deflation $40.00 $47.00 $38.98 $2.35 At 30% Deflation $36.00 $42.50 $34.84 $2.14 At 40% Deflation $32.00 $38.00 $30.70 $1.93

Full Inventory (2015 - 2050)Lateral Length (feet) 5,300 7,500 4,500 NA 4,500 4,500Well Spacing (acres) 40-60 140 90 80-160 107 107Distance between wells (feet) 330-500 770 770 880 880IP 30 (Boe/d) 926 530 349 498 1,667 1,333Gross EUR (MBoe) 571 461 304 425 1,186 783% Liquids 77% 77% 77% 75% - -Gross Well Costs ($MM) $5.8 $4.9 $3.8 $5.4 $7.3 $7.3Net F&D Costs ($/Boe) $13.49 $14.27 $16.49 $15.27 $7.56 $11.86Average WI % 89% 97% 97% 75% 77% 88%

Average NRI % 67% 73% 73% 62% 62% 69%

Pre-Tax IRR1 50% 21% 15% 28% 46% 11%Gross Undrilled Locations (12/31/14) 872 2,696 604 1,304 116 81

Eagle Ford Wolfcamp Altamont Haynesville

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Solid Hedge Program Provides Multi-Year Price Protection

2015 2016

Oil Fixed Price Hedges

Fixed Price Swap Oil volumes (MMBbls)1 21.0 15.1

Average floor price ($/Bbl) $ 91.19 $ 85.41

Percent hedged – based on midpoint of 2015 guidance1 96% 70%

Fixed Price Hedges

Natural Gas volumes (TBtu) 62.1 7.3

Average floor price ($/MMBtu) $ 4.26 $ 4.20

Percent hedged – based on midpoint of 2015 guidance 96% 11%

Note: 2015 and 2016 hedge positions are as of February 10, 2015 (Contract months: January 2015 – Forward) ¹ The table includes 2015 Brent and 2016 LLS three way collars on 1.1 MMBbls and 1.5 MMBbls, respectively. ² 2015 strip prices used $60 per Bbl (WTI) and $3.50 per MMBtu (HH) For further details on the Company’s derivative program, see EP Energy Corporation’s Form 10-K for the year ended December 31, 2014.

Oil and Gas Pricing Sensitivity: A $10/Bbl and $0.50/MMBtu discount to strip prices2 used for estimates generates: ~1% reduction to 2015 EBITDAX

Robust cash flow insulated from short term price movements

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Debt Summary

Note 12/31/14

($ in millions) Interest

Rate Maturity Moody’s/

S&P

$2.75B RBL $852 Libor + May 2019 n/a

$750M Term Loan $496 Libor + May 2018 B+ / Ba3

$400M Term Loan $150 Libor + April 2019 B+ / Ba3

$750M Secured Note

$750 6.875% May 2019 B+ / Ba3

$2B Unsecured Notes

$2,000 9.375% May 2020 B / B2

$350M Unsecured Notes

$350 7.750% September 2022

B / B2

Note: RBL facility matures May 2019 assuming the 2018 and 2019 Senior Secured Term Loans and Secured Notes are refinanced or retired six months before maturity.

1 As of December 31, 2014.

Net debt of $4.6 billion1

$1.8 billion of liquidity¹ Ba3 / BB – Corporate Family Rating $2.75 billion RBL facility Extended maturity to 2019 27 financial institutions included Value supported by;

PDP reserve adds Declining costs Strong hedges

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2015 Outlook Year/Year Change From 2014

Oil production (MBbls/d) 56 – 64 Up 10%1

Total production (MBoe/d) 94.5 – 109.5 Up 4%1

Capital program ($ billion) $1.2 – $1.3 Down >40%

Average drilling rigs Eagle Ford 3–4 Wolfcamp 1 Altamont 1 Haynesville 1 Wells completed Eagle Ford 115 – 130 Wolfcamp 15 – 20 Altamont 25 – 30 Haynesville 5 – 10 Total 160 – 190

Per-unit adjusted cash cost (per Boe) $10.50 – $13.50 Down 10% Transportation cost (per Boe) $2.90 – $3.35 DD&A rate (per Boe) $25.00 – $27.00

1 Growth rate compares mid-point of 2015 estimated production range with 2014 actual results from continuing operations.

26

Executing on all fronts

Operations performing well and results continuing to improve

Focused on further cost reductions

Maintain financial discipline and flexibility

Deliver strong results

Well Positioned For The Future

Compelling value

Investor Update April 2015

28

State Reported 24 Hour-IP Test Data Most recently reported 12 wells

Well Name Submission Date Oil (BOPD) Nat. Gas (MCFD) Total Equivalent (BOEPD)Eagle Ford (24 hr. type well 882 BOPD, 1,072 BOEPD)Ritchie Farms J Unit 73H 3/31/2015 1,115 631 1,220 Maltsberger-Hixon C Unit 3H 4/1/2015 522 5,216 1,391 Altito D 1710H 4/9/2015 721 331 776 Altito D 81H 4/7/2015 1,139 631 1,244 Maltsberger-Hixon C Unit 2H 4/1/2015 622 5,344 1,513 Altito D 82H 4/6/2015 1,096 538 1,186 Altito D 18B Unit 186H 4/6/2015 1,009 494 1,091 Altito A 30A Unit 301H 4/6/2015 1,127 1,162 1,321 Altito B 32B Unit 321H 4/7/2015 1,696 1,486 1,944 Maltsberger-Hixon C Unit 1H 4/1/2015 592 5,394 1,491 Altito B 32B Unit 322H 4/9/2015 1,654 1,461 1,898 Altito B 32B Unit 323H 4/12/2015 1,665 1,221 1,869 Wolfcamp (24 hr. type well 412 BOPD, 508 BOEPD)University East 4323EH 1/13/2015 938 1,474 1,184 University East 4324LH 1/14/2015 893 1,229 1,098 University East 4324KH 1/21/2015 461 339 518 University East 4324JH 1/27/2015 1,090 783 1,221 University East 4324FH 2/18/2015 1,237 942 1,394 University East 4324EH 2/16/2015 446 109 464 University East 4324DH 2/18/2015 1,357 1,262 1,567 University East 4109LH 4/2/2015 660 948 818 University East 4109JH 4/7/2015 1,152 1,168 1,347 University East 4109MH 4/8/2015 834 570 929 University East 4109NH 4/8/2015 734 791 866 University East 4109OH 4/7/2015 818 578 914

Test Data

Note: Total equivalent volumes are based on converting natural gas volumes to total equivalent volumes on a 6 to 1 basis.