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.
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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
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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
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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
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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
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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
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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
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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.
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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
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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.