IPAA Oil and Gas Investor Symposium
September 24, 2012
San Francisco, CA
1
The data contained in this presentation that are not historical facts are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act. Such statements may relate to capital expenditures, drilling and exploitation activities, production efforts and sales volumes, proved, probable, and possible reserves, operating and administrative costs, future operating or financial results, cash flow and anticipated liquidity, business strategy, property acquisitions, and the availability of drilling rigs and other oil field equipment and services. These forward-looking statements are generally accompanied by words such as “estimated”, “projected”, “potential”, “anticipated”, “forecasted” or other words that convey the uncertainty of future events or outcomes. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. These statements are based on our current plans and assumptions and are subject to a number of risks and uncertainties such as potential litigation as further outlined in our most recent 10-K and 10-Q. Therefore, the actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement made by or on behalf of the Company. Cautionary Note to U.S. Investors –The SEC has recently modified its rules regarding oil and gas reserve information that may be included in filings with the SEC. The newly applicable rules allow oil and gas companies to disclose not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose proved, probable and possible reserves in our filings with the SEC. Our reserves as of June 30, 2012 were estimated by DeGolyer & MacNaughton, W.D Von Gonten & Co. (“Von Gonten”), and Pinnacle Energy Services, LLC (“Pinnacle”), independent petroleum engineering firms. In this presentation, we make reference to probable reserves and “2P” reserves that aggregate proved and probable reserves. These estimates are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. Please see Appendix.
2
3
Four Factors for Repeating Success and Building Value per Share Every Day
Innovative Engineering
Redeploying Internal
Cashflows
Known Oil Fields
Building Value per
Share
Staff Fully Aligned with Shareholders
4
Name/Title Background Achievements
Robert Herlin CEO & Chairman
Co-founded EPM in 2003, based on $8.3 MM in total common equity capital raised during 2003-06. B.S. and M.E. Chemical Engineering, Rice University. MBA, Harvard
30 years leadership experience in M&A, development, operations and finance in public and private sectors.
Sterling McDonald Chief Financial Officer
Joined EPM in late 2003. B.S. and MBA (University of Tulsa)
Former CFO for PetroAmerican Services, PetroStar Energy and Treasurer for Reading & Bates Corporation.
Daryl Mazzanti VP-Operations
Joined EPM mid-2005. B.S. Petroleum Engineering, Univ. of Oklahoma
Former Manager of US Business Development for Anadarko. Former Production Manager, Austin Chalk for Anadarko/UPRC responsible for 1200 wells, staff of 65 and 25,000 BOEPD of production. Innovator in horizontal drilling.
Edward Schell General Manager for Drilling and New Projects
Joined EPM in 2006. B.S. in Petroleum Engineering, University of Texas
30 years experience in oil & gas industry. Management positions in drilling, operations and business development with Anadarko Petroleum. Drilled 800 wells, 200 of them horizontal and 2/3rd in unconventional reservoirs.
-$100
$0
$100
$200
$300
$400
$500
$600
$700
InitialInvestment
6/30/12 W/C Proved Delhi Proved Other Probable Delhi Probable MsLime & Other
Total 2PReserves
$M
M
5
$632 MM
Transformed $8.3 MM Investment into $446 MM Proved PV10 + $174 MM Probable PV10 + WC
Notes: (1) PV10 values based on reports from independent reserve engineers and includes proved and probable reserves as of 6/30/2012 at SEC pricing of $96 WTI and $113 LLS per bbl.
$103 MM
$36 MM
$12 MM
$409 MM
$72 MM
6
0
5
10
15
20
25
30
MMBoe
2P Reserves
PD PUD Probable
$0
$2,000
$4,000
$6,000
$8,000
$10,000
$12,000
$14,000
$16,000
$18,000
$20,000$M
Revenue (Fiscal years ended June 30)
Delhi Field - Producing CO2 EOR - 100% oil
11.0 MMBO Proved
5.8 MMBO Probable
61% of 2P is developed
Giddings Field – Producing Hz wells in Austin Chalk, Georgetown, Buda
2,000 net acres of Woodbine exposure
2.3 MMBOE Proved, 21% developed
S Lopez Field – Producing Vertical redevelopment of
previous waterflood, 100% oil
7
Ms Lime – Drilling Began May 2012 45% in JV spanning 38 sections (~5,400 net acres)
2 wells & 1 SWDW drilled to date, fracs pending
112 gross drilling locations (24 net to EPM)
6.4 MMBOE Probable (57% oil, 43% rich gas)
Note: all reserves as of 6/30/2012
GARPTM
Patented artificial lift technology
for horizontal and vertical wells
Successfully installed in two
commercial ventures in Giddings
8
$266
$375
$446
$64 $77
$174
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
2010 2011 2012
$MM
as of June 30
SEC Pretax PV10
Proved Probable
86%
4%
10%
13.4 MMBOE Proved Reserves as of 6/30/2012
Oil NGL Natural Gas
78%
22%
12.7 MMBOE Probable Reserves as of 6/30/2012
Oil Liquids Rich Natural Gas
Application of Strengths to Grow Production, Reserves and Value
10
Phase 1: “Form the Base” Acquired and farmed-out Delhi, commenced EOR. Negative cash flow and no earnings.
Phase 2: “Positioning for Growth” Delhi net proceeds reinvested into shale gas and oil projects. Breakeven cash flow and no earnings.
Phase 3: “Invest for Growth” Delhi and Giddings cash flow reinvested into new oil projects and GARP® technology. Growing operating cash flow and earnings.
Phase 4: “Consistent Growth” Ongoing development drilling to grow production, reserves and cash flow. Grow the franchise.
11
Onshore US Engineering Driven HZ Drilling Potential Repeatable Results Oil Weighted Known Oil & Gas Fields
Grow Value Per-Share
Our Foundation Asset CO2 Enhanced Oil Recovery
13
Gross cum production 192 MMBO
Current production 5,274 gross BOPD (qtr ended 6/30)
6/30/2012 Reserves 11.0 MMBO Proved (PV10: $409MM) 5.8 MMBO Probable (PV10 $103MM) 61% of 2P is developed 29% of 2P from royalty interests
Projected EOR recovery
13% Proved (% of Original Oil in Place) 4% Probable
Unit size 13,366 acres
Tax preferences Severance tax holiday until mid-FY17
Acquired by EPM in 2003 Total investment 2003-06 of $6.8 MM
Farm-out to DNR in mid-2006
Received $50 MM + DNR pays for EOR Development + Reversionary interest
Upside Potential • Original Oil in Place (OOIP) may be much greater – 3D seismic results • Higher EOR % recovery – high quality reservoir + residual secondary bbls • Accelerated development of smaller reservoirs now scheduled for decade-end
and totally categorized as Probable Reserves
Delhi Jackson
Dome
“Cash Annuity” to Fund Growth
14
• EPM owns 7.4% of gross revenues
• No Cap Ex or Op Ex…ever
• Exempt from state severance tax until project payout of all actual costs plus capital cost (mid-FY2017)
• Royalty interest = 29% of EPM’s Delhi reserves volumes
• Delhi crude priced at LA Light Sweet (premium to WTI)
7.4% Royalty Interest
• Late Calendar YE 2013 payout = projected net field cumulative cash flow of $200 million
• Net field cash flow = revenue minus field Op Ex (including CO2)
• After payout, EPM bears pro-rata Cap Ex and Op Ex and will own proportional field assets, reserves and CO2
• EPM projected to bear ~$16.8 MM total CapEx in FY14 for proved reserves and $12.9 MM late in this decade for probable reserves
23.9% Reversionary
Working Interest
(19.1% NRI)
Free Cash Flow
15
Denbury has already spent most of 2012 planned investment of $64 MM.
Developing three patterns and building additional facilities.
2011 Activity expansion
2011 Activity
2010 Activity
2009 Activity
2012E Activity
Source: Denbury Resources Inc. Fall Analyst Meeting, November 14, 2011 and July 2012 payout statement.
Reservoirs to be added later in this decade
2013 Projected Activity
16
Note: Based on report from independent reserve engineers, DeGolyer & MacNaughton, and includes proved and probable reserves as of 6/30/2012 at SEC LLS pricing $113/bbl .
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
($000)
Cal Year
Reversionary WI Royalty
17
Notes: Residual PV10 is the PV10 of remaining cash flows from given year to project end. Includes proved and probable reserves from independent report of 6/30/2012 at SEC LLS pricing of $113/bbl.
$0
$200,000
$400,000
$600,000
$800,000
$1,000,000
$1,200,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
($000)
Cal Year
Cumulative Pretax NCF Rem'g NPV10
Peak 2P PV10
9/14/12 Stock Price
18
* From independent report of 6/30/2012 including proved and probable reserves at SEC LLS pricing of $113/bbl . Diluted shares include 5.5 MM options and warrants without effect of exercise proceeds.
Louisiana Light Sweet (LLS) Oil Price Impact on Delhi 2P PV10 per Fully Diluted Share
$-
$2
$4
$6
$8
$10
$12
$14
$16
$18
$60 $70 $80 $90 $100 $110 $120 $130
$ / Fully-Diluted Share
PV-10* vs LLS Oil Price EPM @ $8.50 LLS @ $116.17 9/14/12
19
Notes: From independent report of 6/30/2012 including proved and probable reserves at SEC LLS pricing of $113/bbl. Diluted shares include 5.5 MM options and warrants without effect of exercise proceeds.
Total 2P PV10 Heavily Driven by Proved Reserves Production
10
100
1,000
MBO/month
Forecasted production over first 16 years of 36+ year life
Delhi Gross Production Forecast as of 6/30/2012
Proved
Probable
7/1/2012
Growing Per-Share Value
Fits selection criteria:
Oil-prone, horizontal drilling, onshore U.S., IRR(e) > 30%, known oil field, accessible, running room, repeatable
Kay County, Oklahoma – oily region of play
JV holds ~12,000 net acres in 38 sections (24,320 acres)
EPM owns 45% share of JV
112 gross, 24 net probable undrilled locations
Horizontal drilling in area previously developed with
vertical wells – RRC and DVN active in Kay County
Drilling and completion cost per well ~$3.2 MM, including water disposal
Running room with multi-year development
JV increasing its leasehold through pending bolt-on acquisitions
Investment sink for Delhi cash flow – develop ~5 BOE reserves from 1 barrel of Delhi production and fully utilize intangible drilling tax deduction to defer income tax
2 Ms Lime wells drilled and waiting on frac, 1st SWD well completed, production results expected in quarter ended 12/31/12
21
22
Joint venture acreage in oil-prone area, east of the Nemaha ridge.
Multi-year visible growth potential for reinvesting early Delhi free cash flow.
Devon, Calyx, Pablo, PQ, Range, Ram, SDR, Spyglass, Century, Territory, Vitruvian
Calyx, Pablo, Range, Redfork, Spyglass,
Territory
CHK, SDR, Vitruvian, PQ
CHK, Chaparral, Eagle, SDR
Spyglass, Vitruvian, Orion, Century
SD, PQ
D
E
V
O
N
H
K
DVN &
Sinopec
EPM
23
Mississippian Lime is well
defined by old vertical wells
o Numerous vertical logs show
thick, continuous pay
o Interpretation of well data and
logs shows geologic continuity
with offset wells
Vertical average EURS:
o Kay County: 97 MBOE
o Osage County: 80 MBOE
o Cowley County: 60 MBOE
Horizontal Results:
o Triple Diamond Hofmeister 21-1H
IP 600 Bopd
o Vitruvian Bowling 2-32H
IP: 500+ Boepd, ~3,000' lateral
o Spyglass Shaw 1A-8H
IP: 500+ Boepd, 2,228' lateral
EPM
Vitruvian Bowling 2-32H IP 500+ Bopd
Spyglass Shaw 1A-8HZ
2,228' Miss Lime Hz 500+ Bopd
Spyglass Bird Creek 1A-15H
IP 210 Bopd
Range Resources Type Curve EUR Now 600 MBoe
Territory Beast 1-27H
IP 500-600 Bopd
Pablo Gilbert 1H-32 IP 657 Bopd
Triple Diamond Hofmeister 21-1H
IP 600 Bopd
24
Assumptions:
EUR: 268 MBOE (75% oil)
$3.2 MM drilling and completion
cost (our 1st two at ~$3.1MM)
Includes SWD facilities
Rich gas is minor contributor
Commodity prices in economics: WTI $85/Bbl (before $5 differential)
Natural gas rising from $2.50 to $4.00/MMBtu
by 2014 (then flat)
IRR > 30% at base case EUR
Range recently upped their Kay
County well estimates to 600
MBOE for 4,000’ laterals
0
50
100
150
200
250
300
350
0 40 80
BO
EPD
Month
Estimated Mississippian Lime Type Curves by Operator
Range 485 MBOE SDR 450 MBOE EPM JV 268 MBOE
EPM assumes a declining GOR, thus initial BOE decline rate appears higher and with more
0%
100%
200%
300%
400%
$40 $50 $60 $70 $80 $90 $100 $110
Ms Lime Sensitivity IRR vs Wellhead Oil Price
EPM Base Case 267 MBOE
Industry 400 MBOE
Previously waterflooded field plugged out
in the 1990’s at low oil price
EPM developing 10-20 BOPD per well of
long life, low decline production at a cost
of ~$550K, or $35K to $70K per net BOPD
1st producer drilled in FY12 averaging 16
BOPD, confirming oil cut and capability of
high fluid rate production and injection
Second producer drilled in FY12 waiting
on revised permit to begin production
Evaluating potential
25
8,154 net acres
Net production ~189 BOEPD average for fiscal 2012
Proved undeveloped reserves in 9 drilling locations
Reserves in Georgetown, Austin Chalk and Buda formations
Exposure to new Woodbine oil play in retained 1,100 net acres and royalty interest in 900 net acres
~44% oil and NGL content by volumes
Transitional asset & candidate for harvesting
26
Innovation for Increasing Recovery
Industry at risk of losing vast quantities of reserves and production as mature horizontal wells encounter liquid loading
Our technology re-establishes economic production of the “Tail” reserves at risk due to the liquid loading, as it:
Supplements & enhances existing rod pump
Mobilizes remaining fluid to rod pump inlet
Three commercial installations completed demonstrating success
Risk-sharing participation model
28
BEFORE: Conventional Rod Pump
Either fluid level eventually drops to a level where rod pump or gas lift are no longer effective, or
Fluid production in gas well builds and eventually shuts off gas production
This can leave substantial volumes of oil and gas unrecovered (the “Tail”)
AFTER: GARP®
Adds substantial new reserves at low cost
Benefit = up to 25% incremental recovery
Benefit = extends life of lease(s)
Low development cost per net BOE
Patented
29
30
1
10
100
2/1/2012 3/1/2012 4/1/2012 5/1/2012 6/1/2012 7/1/2012 8/1/2012 9/1/2012
BOPD
Selected Lands #2 w/GARP®
Daily Rate versus Time BOPDPre-GARP BOPD
Downtime for repairs of inherited equipment
Installed GARP®
1
10
100
1,000
0 50,000 100,000 150,000 200,000 250,000
BOPD
Cumulative Production, bbls oil
Selected Lands #2 Daily Rate versus Cumulative Production
GARP® targeted recapture of “Tail”
Restored production rate from marginal 1 BOPD to 18+ BOPD due to GARP®
Production decline due to well loading up
Conservative, Strong and Aligned
32
0%
38% 43% 44%
67% 69%
97% 105%
0%
20%
40%
60%
80%
100%
120%
EPM PQ
WR
ES
DN
R
AX
AS
MH
CW
EI
CX
PO
Debt to Market Cap (as of 9/17/12)
$-
$2
$4
$6
$8
$10
$12
$14
$16
$18
Resources FY13 Capex
$MM
Liquidity – Sources & Uses
4 FQFQCFFO
6/30/12 Working Capital
Credit Line
+ FY2013 CFFO
+ expansions
$
$
$
$
2012
2013
2014
2015
Free Cash Flows to be
Redeployed
GARP®
Mississippian Lime Oil Project
Other Projects
33
34
-$100
$0
$100
$200
$300
$400
$500
$600
$700
Investment W/C ProvedPV10
Delhi (1)
ProbablePV10
Delhi (1)
ProvedPV10
Other (2)
ProbablePV10
Ms Lime &Other (3)
TotalValue
MarketCap
9/14/12 (4)
Tota
l Val
ue
, $M
M
$396 MM Gap to 2P NAV
$236 MM
$632 MM
Notes: (1) PV10 values based on report from independent reserve engineers and include proved and probable reserves as of 6/30/2012 at SEC pricing of $96/bbl WTI and $113 LLS. (2) Giddings properties are being evaluated for monetization. (3) based on 114 gross (25 net) locations. (4) Market capitalization based on 27.82 MM shares outstanding.
35
$0
$4
$8
$12
$16
$20
Investment W/C ProvedPV10Delhi
ProbablePV10Delhi
ProvedPV10Other
ProbablePV10
Ms Lime
TotalValue
SharePrice
(9/14/12)
Tota
l Pe
r Fu
lly D
ilute
d S
har
e
$10.54 Gap to NAV
$8.50
$19.04
Note: Per-share values are based on 33.2 MM diluted shares and no debt. PV10 from 6/30/12 reserves report.
36
Cash flow “Annuity” & debt free = continued growth w/o shareholder dilution
$390+ MM gap between intrinsic and market value (excluding GARP®)
Premium oil focused reserves (84% oil on Gulf Coast, mostly LLS priced)
New exposure to oily Mississippian Lime Play (excellent economics)
GARP® upside (harvesting the “tails”)
Balance sheet aligned with business strategy (conservative, internally funded)
Employees beneficially own 20% of diluted shares
Result = Total alignment with accretive growth per share strategy