Investor Update

September 2014

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; 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; changes in commodity prices and basis differentials for oil and natural gas; 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; political and currency risks associated with international operations of EP Energy; competition; 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 EBITDAX”, and “Adjusted Cash Operating Costs Per Unit”. Definitions of these measures and reconciliation between U.S. GAAP and non-GAAP financial measures are included in EP Energy’s Second Quarter 2014 Financial and Operational Reporting Package at epenergy.com.

3

EP Energy (NYSE: EPE) Oil-focused growth

company with four core asset areas

~477,000 total net acres1

~5,644 risked drilling locations , 20+ years1

2Q’14 Results

53.3 MBbls/d oil production

96.7 MBoe/d total production

$372 MM Adjusted EBITDAX

12.5 rig average

68 completed wells

1 Pro forma for April 2014 acquisition. Notes: See the Second Quarter 2014 Financial and Operational Reporting Package, available at epenergy.com for the company’s non-GAAP reconciliation and definitions. Acreage and gross drilling locations as 12/31/13.

Net Acres: 91,675 2Q 2014 Net Daily Production (MBoe/d): 50.5 Gross Drilling Locations: 946

EAGLE FORD SHALE

EP Energy Acreage

Net Acres: 175,1731 2Q 2014 Net Daily Production (MBoe/d): 14.1 Gross Drilling Locations: 3,3751

HAYNESVILLE SHALE Net Acres: 36,865 2Q 2014 Net Daily Production (MMcfe/d): 97.8 Gross Drilling Locations: 197

ALTAMONT Net Acres: 173,110 2Q 2014 Net Daily Production (MBoe/d): 15.7 Gross Drilling Locations: 1,126

WOLFCAMP SHALE

TX

UT

TX

4

It’s All About Execution…

Results beat expectations each period reported since IPO (4Q’13, 1Q’14, 2Q’14)

Financial and operational metrics

Record oil production, well completions (2Q’14)

Increased 2014 Outlook (May and Aug.)

Increased Wolfcamp Type Well EUR (Aug.)

Portfolio enhancement (April, May, & Aug.)

Bolt-on Wolfcamp acquisition

Sold non-core gas assets

Completed Brazil exit

Improved operations in all oil programs

Completion optimization

Increased drilling efficiencies

Higher overall well level returns now ~50%

Solid multi-year hedges and significant liquidity

All programs performed above type curve

5

Altamont

Wolfcamp

Eagle Ford

…And Delivering Efficient Growth Focused execution in all areas delivers;

Significant long-term oil volume growth

Expanding unit cash margins

Continued EBITDAX growth

Total Company Oil Production

11.6

22.7

36.3

51.0

2011 2012 2013 2014 YTD

MBbls/d

6

Wolfcamp Eagle Ford

Altamont Haynesville

Core Asset Overview

High-quality concentrated asset portfolio

7

Eagle Ford: Franchise Oil Program

10.9

15.7

18.5 20.4

22.2

26.1 27.3

31.6

33.7

2Q

'12

3Q

'12

4Q

'12

1Q

'13

2Q

'13

3Q

'13

4Q

'13

1Q

'14

2Q

'14

Oil Production (MBbls/d)

Increased performance from high return asset

Five rigs now running

Two stimulation crews active

34 wells completed in 2Q

Record quarterly production in 2Q’14 of 50.5 MBoe/d (33.7 MBbls/d of oil)

Production optimization

Less downtime

Lower unit lifting cost

2H’14 initiatives

40-acre in-fill well spacing

On-going completion optimization

Continued execution delivers high-margin oil growth

8

Eagle Ford: Improved Results Across Position

Completion optimization

Increased number of stages

Increased proppant volumes

IP 30 rates exceeding type curve of 692 Boe/d

Efficiencies offsetting costs of completion optimization

Maltsberger 26H

930 BOPD, 1,551 Boe/d

Hixon TX 1H 680 BOPD, 1,095 Boe/d

Hinojosa 22H: 608 BOPD, 694 Boe/d

A23H: 594 BOPD, 679 Boe/d

Most Recent Wells with Enhanced Completions (IP 30)

Whitwell A Unit 02H: 668 BOPD, 802 Boe/d

20H: 859 BOPD, 1,027 Boe/d 22H: 867 BOPD, 1,014 Boe/d 24H: 806 BOPD, 979 Boe/d 26H: 668 BOPD, 807 Boe/d

Hinojosa A Unit 24H: 725 BOPD, 828 Boe/d

25H: 1,003 BOPD, 1,218 Boe/d 26H: 816 BOPD, 1,054 Boe/d

Altito A Unit 193H: 1,108 BOPD, 1,372 Boe/d 194H: 1,140 BOPD, 1,373 Boe/d

Altito B 23A Unit 324H: 837 BOPD, 1,062 Boe/d 325H: 962 BOPD, 1,209 Boe/d

Altito D 18A Unit 181H: 968 BOPD, 1,257 Boe/d 182H: 1,026 BOPD, 1,330 Boe/d

Hixon Trout B Unit 2H: 471 BOPD, 770 Boe/d 3H: 536 BOPD, 815 Boe/d 4H: 585 BOPD, 855 Boe/d

Note: As of August 7, 2014

9

1.2 1.4

1.6 1.5

2.9

4.3

5.5

7.2

7.9

2Q

'12

3Q

'12

4Q

'12

1Q

'13

2Q

'13

3Q

'13

4Q

'13

1Q

'14

2Q

'14

Wolfcamp: Execution Drives Significant Growth

Significant production growth

Fourth rig added in late March

Two stimulation crews running

23 wells completed in 2Q (ramped throughout)

Record quarterly production in 2Q’14 of 14.1 MBoe/d (7.9 MBbls/d of oil)

Increased natural gas and NGLs sales as a result of additional infrastructure

Successful integration of April 30th acquisition

Operations in-line with expectations

June average oil production of 9.0 MBbls/d

2H’14 initiatives

Drilled first Wolfcamp A wells in 2Q

On-going completion optimization and operational/capital efficiencies

Oil Production (MBbls/d)

10

Wolfcamp: Expanding Development

Region derisked by industry activity and tests

1,550+ horizontal wells in four county area1

~270 A and C Bench wells offsetting EPE acreage

Expanding our development in 2014 while maintaining efficiencies

~3,375 drilling locations2

1 Wells drilled below 5,000’ in Crockett, Reagan, Irion, and Upton counties between January 2009 and June 2014. 2 As of December 31, 2013 pro forma for 475 drilling locations from the April 2014 acquisition.

2013 Wells

2014 Wells

2014 Wolfcamp A –bench wells

11

Wolfcamp: Increased Type Curve 23

Results of combined B/C development exceed expectations

Increased estimated EUR from 400 MBoe to 450 MBoe

Larger completions with higher IP rates offset cost -- improve returns

Wolfcamp Long

Previous Update

Lateral Length (ft) 7,500 7,500

IP 30 (Boe/d) 373 521

Well Spacing (Distance between wells)

140 acres (770 ft)

140 acres (770 ft)

Gross EUR (Mboe) 400 450

% Liquids 75% 75%

Gross Well Costs ($MM) $5.8 $6.1

Net F&D Costs ($/Boe) $19.19 $18.07

Average WI % 95% 95%

Average NRI % 71% 71%

NRI Pre-Tax NPV - 10% ($MM)¹ $2.8 $4.0

Pre-Tax IRR¹ 30% 35%

Gross Undrilled Locations² 2,780 2,780

Wolfcamp B/C producing wells

Previous Type Curve 400 MBoe

Current Type Curve 450 MBoe

Wolfcamp B/C Development

0

100

200

300

400

500

600

700

800

900

1,000

Pro

du

cin

g R

ate,

BO

EPD

Normalized Time, Months

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Wolfcamp B/C Development

¹ Pretax rates based on $90/Bbl (WTI) and $4.50/MMBtu (Henry Hub). ² As of December 31, 2013 pro forma for 475 drilling locations from the April 2014 acquisition.

12

Wolfcamp: Increasing Take-away Options

Significant new capacity to accommodate growing supply

Midland

Colorado City

Crane

McCarney

Cushing, OK

Longview

Houston

Corpus Christi

Nederland

Borger

Western

Holly Navajo

Big Spring

McKee

Existing Capacity Expansion Capacity Centurion BridgeTex Basin Permain Express II WTG Cactus Permian Express I Longhorn

EPE Acreage Permian Basin

Refinery

Existing Take-away

Refineries (nameplate capacity) Mbopd

Big Spring 75

Holly Navajo 100

Borger 145

McKee 168

Western 128

Total 616

Oil Pipelines Mbopd

Basin Pipeline 450

Centurion Pipeline 100

WTG Pipeline 375

Longhorn Pipeline 275

Total 1200

Expansion Capacity

Oil Pipelines Completion Date Mbopd

BridgeTex Pipeline 3Q '14 300

Permian Express II 2Q '15 200

Cactus Pipeline 1Q '15 250

Total 750

13

7.1 7.4

8.1 7.9 8.3

8.9

9.5 9.8

11.7

2Q

'12

3Q

'12

4Q

'12

1Q

'13

2Q

'13

3Q

'13

4Q

'13

1Q

'14

2Q

'14

Altamont: Significant Growth Production growth from advantaged

position in Uinta Basin

Three rigs now running

11 wells completed

Record quarterly production in 2Q’14 of 15.7 MBoe/d (11.7 MBbls/d of oil)

Production up ~65% since 2Q 2012

Lowered average well costs with improved well performance

Focused on production optimization

Increased oil sales capacity

Expanded local refinery sales

Several new rail markets

2H’14 initiatives

Evaluating infill opportunities

Oil Production (MBbls/d)

14

Altamont: Executing and Improving Efficiencies

Three of our all-time best Altamont wells completed in 2Q’14

Average IP 30 rates performing above type curve of 525 Boe/d

Improved stimulation design

Expanded completion intervals

Increased proppant volumes

Improved fluid design

IP 30 Progression (Boe/d)

381

543 525 587

2012 2013 Current TypeCurve

2014 YTD

Significant resource base generating improved results

15

Financial Execution Strong financial performance from core assets driven by successful

execution

Record production volumes delivering growing EBITDAX, per unit margins, and returns

Solid hedge positions in 2014–2016 support cash flows

Costs remain in line with expectations

Ample financial capacity

$2.0 billion of liquidity at 6/30/141

Net asset value enhancement Increased inventory, efficiencies, margins and Wolfcamp type curve

Well positioned for future growth

1 Based on available revolver capacity under our RBL Facility and cash on hand.

16

Focused Oil & Gas Capital Expenditures

2014 Budget: $2 billion

Weighted average well level returns of ~50%¹

¹ Pre tax IRR assumes a $90/Bbl (WTI) and $4.50/MMBtu (Henry Hub).

Drilling & Completions

Wolfcamp 36%

Altamont 14%

Eagle Ford 50%

125-130 well completions

35-40 well completions

95-105 well completions

88%

9% 3%

Facilities, lease & seismic

Other

17

Solid Hedge Program

2014 2015 2016

Fixed Price Hedges1

Oil volumes (MMBbls) 9.7 21.0 15.5

Average floor price ($/Bbl) $ 97.77 $ 91.19 $ 90.60

Percent hedged – based on updated 2014 guidance ~90% +100% ~77%

Natural Gas volumes (TBtu) 38.4 62.1 7.3

Average floor price ($/MMBtu) $ 4.02 $ 4.26 $ 4.20

Percent hedged – based on updated 2014 guidance +100% ~90% ~11%

Eagle Ford Hedges2

Oil volumes (MMBbls) 3.3 3.7 8.2

Effective floor price ($/Bbl) $ 100.57 $ 96.24 $ 92.33

Note: Positions are as of June 30, 2014 (Contract months: (July 2014 – Forward). 1 Oil fixed price hedges include WTI, Brent and LLS fixed price swaps and floors. 2 Reflects combination of oil fixed prices and basis hedges that effectively floor Eagle Ford oil prices. Floor prices do not include any customary refinery or contractual deductions.

18

Increased 2014 Outlook

Updated 5/7/14 Year/Year Growth Rate

Updated 8/7/14 Year/Year Growth Rate

Oil production (MBbls/d) 52 – 55¹ 46%² 54 – 56¹ 52%² Total production (MBoe/d) 93.5 – 99.5¹ 19%² 96 – 100¹ 21%2

Capital program ($ billion) Drilling and completion $1.73 $1.76 Facilities, lease and seismic $0.20 $0.18 G&A, interest and other $0.07 $0.06 Total3 $2.00 $2.00

Average drilling rigs Eagle Ford 5 – 6 5 Wolfcamp 3 – 4 4 Altamont 3 – 4 3 Wells completed Eagle Ford 135 – 145 125 – 130 Wolfcamp 95 – 105 95 – 105 Altamont 35 – 40 35 – 40 Total 265 – 290 255 – 275

Per-unit adjusted cash cost (per Boe) $12.25 - $14.25 $12.90 - $13.90 Transportation cost (per Boe) $3.00 - $3.50 $3.00 - $3.25 DD&A rate (per Boe) $24.00 - $26.00 $24.35 - $25.35

1 Oil and equivalent production excludes the asset divestitures completed in May 2014 of primarily non-core natural gas assets. ² Growth rate compares mid-point of 2014 estimated production range with 2013 actual results from continuing operations. 3 Excludes approximately $154 million of acquisition capital.

Rest of 2014

19

Executing Across the Board

Focused on execution and operational improvements

Improving LOE per barrel in core oil programs

Significant EBITDAX margin expansion

Improve operational efficiency

$2 billion capital program

Directed entirely to Eagle Ford, Wolfcamp and Altamont ~ 50% avg. well level IRR²

88 percent drill-bit focused

Growing cash flows narrow capex funding gap

Programs well positioned for growth

50+ percent increase in oil volumes now

Improved results from production and completion optimization

Continued production

growth1

Eagle Ford down spacing

Wolfcamp A program initiated

Altamont infill wells

Successful acquisition and divestiture enhanced portfolio

Enhancing drilling inventory

1 Pro forma for completed and pending divestitures. ² IRR represents before tax rate of return per internal estimates. IRR based on $90.00/Bbl (WTI) and $4.50/MMBtu (Henry Hub) price deck. Weighted average well level IRR weighed by 2014E capital.

Investor Update

September 2014

21

Appendix

22

Type Well Economics

Note: IRR and NPV metrics per internal EPE estimates and assume $90.00/$4.50 price deck. NPV calculated at 10% discount rate, before income tax, and stated in ($MM).

¹ 13,320’ total vertical depth. ² Wolfcamp Long based 1.5 sections (960 acres) due to 7,500’ laterals. ³ As of December 31, 2013 pro forma for 475 drilling locations from the April 2014 acquisition.

Central North Long Short Vertical ¹ Horizontal Holly Non-Holly

Lateral Length (ft) 5,600 5,600 7,500 4,500 N/A 3,960 4,500 4,500

Well Spacing ²

(Distance between wells)

60 acres

(500 ft)

60 acres

(500 ft)

140 acres

(770 ft)

90 acres

(770 ft)

160 acres 160 acres 107 acres

(880 ft)

107 acres

(880 ft)

IP 30 (Boe/d) 692 223 521 344 525 613 1,980 1,750

Gross EUR (Mboe) 663 311 450 296 455 310 967 694

% Liquids 77% 96% 75% 75% 73% 68% 0% 0%

Gross Well Costs ($MM) $7.2 $6.7 $6.1 $4.7 $6.3 $7.1 $7.9 $7.9

Net F&D Costs ($/Boe) $14.59 $28.78 $18.07 $21.12 $18.90 $27.97 $10.02 $14.83

Average WI % 89% 93% 95% 99% 73% 71% 81% 76%

Average NRI % 67% 70% 71% 74% 61% 58% 66% 58%

NRI Pre-Tax NPV - 10% ($MM) $7.0 $2.7 $4.0 $2.0 $3.6 $1.4 $3.8 $1.0

Pre-Tax IRR 58% 26% 35% 24% 36% 24% 47% 21%

Gross Undrilled Locations (12/31/2013) 3800 146 2,780 595 776 350 104 93

Eagle Ford Wolfcamp Altamont Haynesville

23

Haynesville – Premier Shale Gas Resource

~37,000 net acres in core of De Soto Parish in NE Louisiana

Acreage 100% HBP

No current drilling activity

197 drilling locations1

Able to quickly commence program with commodity price improvement

Attractive economics with gas prices of $4.00 − $4.50, yielding single-well IRRs of 33% − 47%2

Access to growing Gulf Coast markets

Source: DI Desktop and EP Energy estimates 1 As of 12/31/2013. 2 Type well economics for Holly area wells

Peak Month Gas (Mcf/d)

10,000+

7,500 to 9,999

5,000 to 7,499

0 to 4,999

EPE acreage

Fairway

Haynesville: Premier Shale Gas Resource

24

Proven Management Team Name Position Industry Yrs. Experience

Brent Smolik Chairman, President & CEO 29

Clay Carrell EVP & COO 25

Dane Whitehead EVP & CFO 29

Marguerite Woung-Chapman

SVP, General Counsel 22

Joan Gallagher SVP, HR & Admin. Services 20

Frank Falleri SVP, Central 28

Greg Givens VP, Eagle Ford 17

Richard Little VP, Southern 17

Scott Anderson VP, Business Development 29

Kyle McCuen VP, Planning & Treasury 17

Dennis Price VP, Marketing 20

Frank Olmsted VP, Controller 23

Delaney Bellinger VP, Info. Tech. 30

Energy