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1. EP Energy's Flagship - The Eagle Ford
Optimizing Spacing to Maximize Value
Greg Givens
Vice President, Eagle Ford
October 15, 2012

2. Cautionary Statement
In this presentation, EP Energy has disclosed its proved reserves using the SEC's definition of proved
reserves under rules effective December 31, 2009. Proved reserves are estimated quantities of
hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be recoverable
in the future from known reservoirs under the assumed economic conditions. In this presentation, EP
Energy has provided estimates of its “net risked resources,” “unproved resources” or “inventory” which are
different than probable and possible reserves as defined by the SEC. Net risked resources, unproved
resources or inventory are estimates of potential reserves that are made using accepted geological and
engineering analytical techniques.
This presentation presents certain production and reserves-related information on an "equivalency" basis.
Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf at a ratio of one
Bbl to six Mcf, and natural gas converted to barrels at a ratio of six Mcf to one Bbl. A Boe conversion ratio of
six Mcf of natural gas to one Bbl, and a Mcfe conversion ratio of one Bbl of crude oil or NGLs to six Mcf, is
based on an energy equivalency conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. Although these conversion factors are industry accepted
norms, they are not reflective of price or market value differentials between product types.
Certain of the production information in this presentation includes the production attributable to EP Energy’s
48.8 percent interest in Four Star Oil and Gas Company (“Four Star”). In addition, the proved reserves
attributable to its interest in Four Star represent estimates prepared by EP Energy and not those of Four
Star.
This presentation refers to the non-GAAP financial measures “Cash Operating Costs” and “Adjusted Cash
Operating Costs”. Definition of these measures and reconciliation between U.S. GAAP and non-GAAP
financial measures is included in the Appendix to this presentation.
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3. Company Update
 May 24, 2011 – Announced EPE spin-off
 October 16, 2011 – Kinder Morgan announced
acquisition of El Paso Corporation (with intent
to sell E&P assets)
 May 25, 2012 – Launched EP Energy
 Closed sale to private equity group
 More information on our new website
epenergy.com
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4. Strategy: How We’ll Get There
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5. Purpose: What We Do
At EP Energy, we have a passion
for finding and producing the
oil and natural gas that
enriches people's lives
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6. Vision: Where We're Going
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7. Values: How We Behave
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8. Competitive Advantages
Large, Diverse  4.0 Tcfe of proved reserves – PV-10 of ~$7 billion1
High Quality  Rapidly growing oil shale plays -- onshore U.S. unconventional
Asset Base  Producing wells currently 77% operated1
 20+ year drilling inventory -- ~4,500 locations, 85% oil - related1
Extensive Low-
Risk Inventory  Natural gas inventory is largely held-by-production
 2011 drilling success rate of 100% (233 gross wells)
 Industry leading well cost performance in key programs
Efficient  Top tier lease operating expense performance
Operations
 Manage returns and margin through commodity price cycles
 Leadership team comprised of former El Paso employees
Experienced
Team  Focused – build assets with repeatable programs/inventory
 Asset teams and culture remain in place
Strong  Base PDP assets (1.7 Tcfe)1 provide predictable cash flow
Financial  Favorable hedge position
Position  ~$1.6 billion liquidity2
1 As of 12/31/11. Pre-tax PV-10 value assumes SEC pricing, as of 12/31/11 8
2As of 6/30/12, proforma for the Financing Transaction completed on 8/13/12

9. High-Quality Asset Base
2011 Proved Reserves
Diversified Portfolio
Eagle Ford Brazil/Four Star
16% 2011 Reserves: 269 Bcfe
Production: 92 MMcfe/d3
Other Assets
42% Haynesville
23%
Central
Central
Altamont
14% Wolfcamp 2011 Reserves (Bcfe): 1,110
Wilcox
4%
ALTAMONT 4Q 2011 Production Bcfe3
2011 Reserves: 2,602
1%
(MMcfe/d): 153 MMcfe/d
Production: 603
Total: 4.0 Tcfe1
12/31/2011 PV-10: ~$7.0 billion2
Ave. Production - 6/30/12 HAYNESVILLE
Eagle Ford
10%
WOLFCAMP
S. LOUISIANA WILCOX
EAGLE FORD
Other Assets Haynesville
45% 35%
Eagle Ford
Southern
2011 Reserves : 642 Bcfe
Production: 91 MMcfe/d3 2011 Reserves: 474 Bcfe
Wilcox Altamont Wolfcamp
Production: 120 MMcfe/d3
2% 7% 1%
1Includesproportionate share of Four Star reserves and production.
Total: 906 MMcfe/d1,3
2PV-10 value assumes 2011 Pre-Tax SEC pricing. The proved developed reserves represents ~54% of the value.
3 Average daily production rate for six-month period ended June 30, 2012.
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10. Drilling Inventory Growth
Significant oil and natural gas inventory with high ownership and control
Net Risked Resources
Excluding PDP and PDNP (Tcfe) 2009 2010 2011
Liquids 6:1 34% 48% 59%
9.7
0.0
8.0 1.6
0.2 Domestic 82% 90% 99%
6.0 2.2
0.6
6.2
2.0
4.2 Core Prog1 46% 61% 78%
2.5
1.3 1.9
0.9
2009 YE 2010 YE 2011 YE Low-Risk 90% 97% 100%
PUD Unconventional
Conventional Lower Risk Conventional Higher Risk
1Core programs include Altamont, Eagle Ford, Haynesville (includes Middle Bossier), Wolfcamp and South Louisiana Wilcox
Note: Inventory includes unproved resources and proved undeveloped reserves; All inventory is risked, net to EP Energy’s interest 10

11. Key Programs Provide
Multi-Year Drilling Opportunity
KEY DRILLING
PROGRAMS LOCATIONS1
Haynesville 673
Eagle Ford 1,246
Wolfcamp 983
Altamont 1,336 ALTAMONT
Wilcox 260
Total 4,498
HAYNESVILLE
WOLFCAMP
Oil Resources
Gas Resources WILCOX
EAGLE FORD
(Northern/Central)
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1As of 12/31/11 (includes PUD locations and is shown on a risked basis)

12. Extensive Drilling Inventory—Low Breakeven Prices
10% IRR After-tax Return Threshold
Gas Directed Drilling Inventory Oil Directed Drilling Inventory
$8.00 $100
$7.00 $90
$80
$6.00
$70
($/MMBTU)
$5.00
($/BBL)
$60
$4.00 $50
$3.00 $40
$30
$2.00
$20
$1.00
$10
$0.00 $0
0
0 500 1,000
1,000 1,500
1,480 2,000
1,980 2,500
2,480 3,000
2,980 0
0 200
200 400
399 600
599 800
799 1,000
999
(Bcfe) (MMBoe)
~90% of 9.7 TCFE of Inventory economic below
$5.00/MMBTU* and $60/BBL*
* Based on NYMEX pricing for Henry Hub and WTI 12

13. 2012 Capital Budget
$1.5 - $1.6 Billion1
3%
6%
8%
12%
13%
> 90% allocated to oil-focused key programs
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1Includes ~$100 MM of capitalized interest, information technology and capitalized direct labor costs

14. Favorable Program Economics
Initial Average
Capital EUR Production Working
($MM) 1 (Mboe) 1 (Boe/d)1,2 IRR3 Interest
Eagle Ford, Central 8.0 – 8.4 500 – 600 750 – 900 45 – 65% 92%
Wolfcamp 8.0 – 8.4 465 – 510 575 – 675 20 – 30% 100%
Altamont 4.6 – 7.7 300 – 450 400 – 600 20 – 40% 89%
Wilcox 6.0 – 7.0 320 – 440 500 – 900 30 – 70% 85%
Focused investments delivering excellent returns
1 Based on 100 percent working interest
2 Based on initial 24 hours of production
3 After-tax internal rate of return net to EP Energy interest based on $3.50 per MMBtu (HH) and $90.00 per Bbl (WTI) 14

15. Continuous Improvement
First 3 Wells Current (median)
10.9
9.8
8.2 8.2 8.2
6.6 6.5
6.2
Gross Capital
Cost Per Well
($MM)
Eagle Ford Wolfcamp Altamont Wilcox
$1.72
$1.71
$1.69
$1.66
Adjusted Cash
Operating Costs
($/Mcfe)
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16. Oil Impact is Growing Rapidly
 Oil volumes up ~60%1
 1H’12 vs. 1H’11
 Growing revenue impact2
 57% (1H’12) vs. 35% (1H’11)
 85% of future drilling inventory
located in oil-focused reservoirs
 91% of 2012 capex oil-directed
Tremendous growth
in inventory
plus shift in capital
1 Includes proportionate share of Four Star production volumes. 16
2 Oil and NGLs revenue, excluding realized and unrealized gains on financial derivatives.

17. Eagle Ford
Avg. Net Production Growth  Highest return and highest value
asset in portfolio
18.0
Gas NGL Oil
15.0
Advantaged acreage position in
12.0
Central Area (La Salle/Dimmit Co.)
MBoe/d
9.0
6.0 Significant inventory of oil
3.0 opportunities (1246 locations1)
0.0
1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q
2010 2010 2010 2010 2011 2011 2011 2011 2012 2012 Major source of future oil
production and reserve adds
 157,000 total net acres1  2012 Program
 77,000 in Central area
 642 Bcfe estimated net proved  Drilling 86 wells
reserves1  Currently running 5 rigs
 88 net producing wells2
 ~$896 MM capex
1 As of December 31, 2011 17
2 As of June 30, 2012

18. Activity Continues to Heat Up
July 2012 Production (from TRRC)
310,370 BOPD
51,676 BCPD
1.21 BCFD
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19. Operational Efficiency Improves over time
Rig Days Stimulation Initial 24 hr rate1
(Spud to Rig Release) (Stages/Day) (BOE/Day)
21 4.5 1036
3.7
16 763
15 14 2.9 723 721
2.3
2010 1H 2011 2H 2011 1H 2012 2010 1H 2011 2H 2011 1H 2012 2010 1H 2011 2H 2011 1H 2012
1 Rig line now drills Higher efficiency Well performance
>20 wells per year lowers total well cost continues to improve
1 Maximum continuous 24 hours 19
Note: Based on Central Area wells only

20. Field Gathering/Central Facilities
Oil, Gas &
Water Flow Midstream
Lines Oil & Gas
Lines
Well Paths Common  Wells within 3-4 miles
Facility gathered at Central
Production Facility (CPF)
LACT
 Oil and Gas connected
to regional pipelines
through midstream
Road gathering lines
Frac Pond  Maintain option to truck
Potential
Future Well oil
Locations
 30-40 wells connected
to each CPF at full
development
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21. Central Production Facility
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22. Eagle Ford Oil & Gas Infrastructure
OIL LA SALLE In-field Gathering
Gardendale Rail
Facility  Owned and operated by EP Energy
Hilcorp Gardendale  Wellhead gathering to 12 central batteries currently;
Hilcorp Cotulla additional batteries under construction
Camino Real Gathering System*
 Natural gas system capacity of 150–170 MMcf/d
 Oil system capacity of
VOLATILE OIL 90,000 Bbls/d, with blending capability
 Additional connections to new lines under
DIMMIT construction in area would substantially increase
capacity
ETC
DIMMI
EP acreage
Camino Real Gas line Takeaway
T interconnects
Gas WET GAS  Sufficient downstream processing and transportation
Camino Real Oil line Kinder/Copano capacity to accommodate aggressive gas volume
Oil interconnects Enterprise growth
Oil terminal
DRY GAS  Long-term oil sales agreements with premium pricing
Regency to WTI
Began oil deliveries to downstream
markets via pipeline 1Q 2012
*Camino Real is owned and operated by Kinder Morgan 22

23. Spacing Pilots
110 wells drilled
91 wells completed
88 wells online
as of 6/30/2012
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24. Microseismic Surveys
700 ft well spacing
 Microseismic used to determine
extent of fracture network
875 ft well spacing
 Production testing and reservoir
simulation aid in selecting the
optimal between well spacing
60 acre drainage area 24

25. Initial Pilots holding up well
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26. Increased density successful to date
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27. Keys to success
Sound development strategy
Long range planning
Infrastructure build-out takes time
Evaluate & test options early
Continuous improvement
culture
Cost management
Utilize latest technology
“Little things add up when you are drilling 1000 wells”
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28. Thank you
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29. Additional Non-GAAP Information
EP Energy uses the non-GAAP financial measures of Cash Operating Costs and Adjusted Cash Operating Costs. We believe these supplemental
measures provide meaningful information to our investors; however, due to the limitations of these measures as analytical tools, we rely primarily
on our GAAP results.
Cash Operating Costs and Adjusted Cash Operating Costs. We monitor cash operating costs required to produce our oil and natural gas
production volumes. Cash operating costs is a non-GAAP measure calculated on a per Mcfe basis and includes total operating expenses less
depreciation, depletion and amortization expense, ceiling test and other impairment charges, exploration expense and transportation costs and
costs of products. Adjusted cash operating costs reflects cash operating costs adjusted for non-recurring transition and restructuring costs,
advisory fees paid to our sponsors, and non-cash equity based compensation expense. We believe cash operating costs and adjusted cash
operating costs per unit are valuable measures to provide management and investors reflecting operating performance and efficiency; however, as
non-GAAP measures, these measures may not be comparable to similarly titled measures used by other companies, have limitations as analytical
tools, and should not be considered in isolation.
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