the data contained in this presentation that are not ... 2013 presentation.pdf · 5 transformed...
TRANSCRIPT
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
5
Transformed $8.3 MM Investment into $409 MM Proved PV10 + $174 MM Probable PV10 + WC*
-$100
$0
$100
$200
$300
$400
$500
$600
$700
Initial Investment 6/30/12 W/C Proved Delhi Probable Delhi Probable Ms Lime& Other
Total 2P Reserves
$M
M
$409 MM
$12 MM
$103 MM
$72 MM $596 MM
* Notes: 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. Excludes noncore assets, divested assets and sales proceeds.
6
0
5
10
15
20
25
30
MMBoe
Proved and Probable 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 – Monetizing Hz wells in Austin Chalk, Georgetown, Buda
900 net acres of Woodbine exposure being retained
S Lopez Field – Producing Vertical redevelopment of
previous waterflood, 100% oil
Scheduled for monetization
7
Ms Lime – Drilling Began May 2012 45% in JV spanning 38 sections (~5,400 net acres)
2 wells & 1 SWDW drilled to date
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 three
commercial wells in Giddings
8
$266
$375
$411
$64 $77
$172
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
2010 2011 2012
$MM
as of June 30
SEC Pretax PV10 *
Proved Probable
99.9%
0.1%
11.1 MMBOE Proved Reserves as of 6/30/2012 *
Oil NGL & Gas
77%
23%
12.2 MMBOE Probable Reserves as of 6/30/2012 *
Oil Liquids Rich Natural Gas
* Excludes reserves and PV10 for noncore properties divested or scheduled for divestment
Our Foundation Asset CO2 Enhanced Oil Recovery
10
Gross cum production 192 MMBO
Current production 5,057 gross BOPD (qtr ended 9/30)
6/30/2012 Reserves 7.5 MMBO Proved Developed (PV10: $326MM) 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
11
• 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 (FY2017)
• Royalty interest = 29% of EPM’s Delhi reserves volumes
• Delhi crude priced at LA Light Sweet (premium to WTI)
7.4% Royalty Interest
• $200 million payout projected to occur late Calendar YE 2013
• Payout when Net field cash flow = revenue minus (field Op Ex + CO2)
• After payout, EPM bears 23.9% of Cap Ex and Op Ex and owns 23.9% of field assets
• 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)
12
Operator completed a planned ~$64 MM of work during calendar 2012
2012 plan included three patterns and additional facilities
Operator expects Calendar 2013 capex of $40MM gross, with reversion to EPM in ~late 2013, reducing operator’s net production by 1,000-1,500 BOPD
2011 Activity expansion
2011 Activity
2010 Activity
2009 Activity
2012 Activity
Source: Denbury Resources Inc. Fall Analyst Meeting, November 2012 and September 2012 payout statement.
Reservoirs to be added later in this decade
2013E Activity ~$40MM gross
13
14
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
15
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
$100,000
$200,000
$300,000
$400,000
$500,000
$600,000
$700,000
$800,000
$900,000
$1,000,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
($000)
Cal Year
Cumulative Pretax NCF Rem'g NPV10
Peak 2P PV10 1/14/13
stock price
16
* 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 @ $8.90 LLS @ ~$111.40 1/14/13
17
Notes: From independent report of 6/30/2012 including proved and probable reserves at SEC LLS pricing of $113/bbl.
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 & frac’d, and depressurizing; 1st SWD well completed.
19
20
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
21
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
780 Bopd
o Vitruvian Bowling 2-32H
IP: 566 Boepd, ~3000' lateral
o Spyglass Shaw 1A-8H
IP: 500+ Boepd, 2228’ lateral
o 2 poor offsets located in bottom of
zone instead of desired upper section
EPM
Vitruvian Bowling 2-32H
IP 527 Bopd 566 Boepd
Spyglass Shaw 1A-8HZ
2,228' Miss Lime Hz 500+ Bopd
Spyglass Bird Creek 1A-15H
IP 210 Bopd
Range Resources Type Curve EUR 400-600 MBoe
Territory Beast 1-27H
IP 500-600 Bopd
Pablo Gilbert 1H-32 IP 657 Bopd
Triple Diamond Hofmeister 21-
1H IP 614 Bopd 780 Boepd
22
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
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
Four commercial installations completed demonstrating success
Risk-sharing participation model
24
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®
May add 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
25
26
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
27
LOPEZ FIELD – SOUTH TEXAS
• Steady 100% oil production of ~20+ BOPD from 1st two producers
• 37 drilling locations on existing leases – 100% working interest
• Lengthy expansion project development timeline = noncore asset
• Candidate for monetization
GIDDINGS (nonGARPR)
• Noncore due to high gas content
• Partially monetized in second fiscal quarter, balance pending
• Retaining 5% royalty interest in 900+ net acres in Woodbine play
• Proceeds to be re-invested in core projects
Conservative, Strong and Aligned
29
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
$20
Resources Rem'g FY13 Capex
$MM
Liquidity – Sources & Uses
4 FQFQCFFO
9/30/12 Working Capital
Credit Line
+ FQ2-4 CFFO
+ expansions
30
$0
$4
$8
$12
$16
$20
Investment W/C ProvedPV10Delhi
ProbablePV10Delhi
ProbablePV10
Ms Lime
TotalValue
Share Price(11/27/12)
Tota
l Pe
r Fu
lly D
ilute
d S
har
e
$8.95 Gap
$8.90
$17.85
*Note: Per-share values are based on 33.4 MM diluted shares and no debt. PV10 from 6/30/12 reserves report, excluding noncore and divested assets.
12% discount to Delhi Proved Developed PV10 alone!
31
Cash flow “Annuity” & debt free = continued growth w/o shareholder dilution
~$300+ million gap between intrinsic and market value (excluding GARP®)
Premium oil focused reserves (88% of 2P is oil, mostly LLS priced)
New exposure to oily Mississippian Lime Play
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