prichard capital partners energize 2010 conference - pritchard 2010-vf.pdf · 2017-01-16 ·...
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Prichard Capital PartnerspEnergize 2010 Conference
January 6, 2010(NYSE Amex: EPM)
© Evolution Petroleum Corporation 1
Evolution Petroleum CorporationThis presentation contains “forward-looking statements” within the meaning of the Private SecuritiesLitigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking statements give our current expectations or forecasts of future events. They include statementsregarding our future operating and financial performance. Although we believe the expectations andg g p g p g pforecasts reflected in these and other forward-looking statements are reasonable, we can give noassurance they will prove to have been correct. They can be affected by inaccurate assumptions or by knownor unknown risks and uncertainties. You should understand that the following important factors, could affect ourfuture results and could cause those results or other outcomes to differ materially from those expressed orimplied in the forward-looking statements relating to: (1) amount, nature and timing of capital expenditures; (2)p g g ( ) , g p p ; ( )drilling of wells and other planned exploitation activities; (3) timing and amount of future production of oil andnatural gas; (4) increases in production growth and proved reserves; (5) operating costs such as lease operatingexpenses, administrative costs and other expenses; (6) our future operating or financial results; (7) cash flow andanticipated liquidity; (8) our business strategy, and the availability of acquisition opportunities; (9) hedgingstrategy; (10) exploration and exploitation activities and property acquisitions; (11) marketing of oil and naturalstrategy; (10) exploration and exploitation activities and property acquisitions; (11) marketing of oil and naturalgas; (12) governmental and environmental regulation of the oil and gas industry; (13) environmental liabilitiesrelating to potential pollution arising from our operations; (14) our level of indebtedness; (15) timing and amountof future dividends; (16) industry competition, conditions, performance and consolidation; (17) natural eventssuch as severe weather, hurricanes, floods, fire and earthquakes; and (18) availability of drilling rigs and other oilfield equipment and servicesfield equipment and services.
We caution you not to place undue reliance on these forward-looking statements, which speak only as of thedate of this presentation or as of the date of the report or document in which they are contained, and weundertake no obligation to update such information. The filings with the SEC are hereby incorporated herein byreference and qualifies the presentation in its entiretyreference and qualifies the presentation in its entirety.
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Evolution Petroleum Corporation
Cautionary Note to U.S. Investors Regarding Oil and Gas Reserve Estimates:
The U S Securities and Exchange Commission permits oil and gas companies in theirThe U.S. Securities and Exchange Commission permits oil and gas companies, in theircurrent filings with the SEC, to disclose only “Proved” reserves that a company hasdemonstrated by actual production or conclusive formation tests to be economically andlegally producible under existing economic and operating conditions. The Company iscurrently prohibited from disclosing other categories of reserves in its SEC filings. We usey p g g gcertain terms in this press release such as "Probable” or “Possible” oil and gas reservesthat the SEC’s guidelines strictly prohibit us from including in filings with the SEC. U.S.investors are urged to consider closely the disclosure in our SEC filings, available from usat 2500 City West Blvd, Suite 1300, Houston, Tx 77042; Telephone: 713-935-0122. You canalso obtain these filings from the SEC by calling 1-800-SEC-0330. The reserve quantitiesreflected above were certified by W. D. Von Gonten & Company using the 1997 definitionsand standards of the Society of Petroleum Engineers and World PetroleumCongresses. These definitions and standards may result in estimates of proved reserveswhich are materially different from those disclosed in the Company’s filings with the SECwhich are materially different from those disclosed in the Company s filings with the SEC.
NOTE: ALL REFERENCES HEREIN TO PV-10 REFLECT SEC PRICING UNLESS NOTED AS ESCALATED.1P = Proved 2P = Probable 3P = Possible
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Our Business
We generate & implement projects that develop oil and natural gas reserves:gas reserves:
That are located in the onshore US,
Are generally well known, but bypassed historically due to
low commodity prices or lack of applied technology,
Based on a lower risk engineered approach andBased on a lower risk, engineered approach, and
Utilize our expertise and technology
Since the staff of EPM owns 21% of the company on a fully diluted basis, we are very focused on protecting and improving share value.
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O&G Core Assets(Net Reserves at 7/1/09)( )
East OK Shale17,780 net acres – in testing phaseTargeting low cost, shallow gas
Delhi Field75% of reservesTotal 1P + 2P Targeting low cost, shallow gas 75% of reservesCO2-EOR100% oil
Total 1P + 2P84% oil7% ngl9% gas
Giddings Field22% of reserves23 drilling locations + 6 pot’lHorizontal – naturally fractured
Neptune Project3% of reserves in 25 locations+ up to 92 more drilling locations
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Horizontal naturally fractured31% oil, 34% NGL, 35% gas
p g100% infill oil development
EPM Investment Highlights – Why Own EPM?
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EPM Investment Highlights
Focused primarily on building share value and increasing reservesAsset base with significant upside No debt & sufficient cash for 2010 budgetLow cost (per well & BOE) development projectsGrowing production and value in Delhi - production expected in mid-2010Attractive Valuation
12/24/09 market-based enterprise value per 1P+2P net reserves is $6.62 / BOE Unrisked PV-10 of at least $7.85 per diluted share based on 7/1/09 prices
EPM’s Unrisked PV-10 per Fully Diluted Share @ ~$66 oil & $3.88 gas
Giddings - $1.40(1P + 2P)
Proprietary Technology - ?
Delhi $6 00 (2P)
( )
Neptune - $.25(1P+2P+3P)
gy
OK Shales - ?
Working Capital $ 20
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Delhi - $6.00 (2P)Working Capital - $.20
EPM Track Record in Project Development
Engineering-driven project origination to create share value as of 7/1/09
Invested:
$6.8 MM
Project
Delhi EOR
Results (PV-10 unrisked)
$50 MM cash pretax +2P PV-10 = $196 6 MM
$0.6 MMNeptune Oil
2P PV-10 = $196.6 MM2P PV-10 peak (in 2015) = $292 MM
1P – 3P Reserves PV-10 = $8.1 MM
$5.5 MMOK Shale
& 92 additional locations pending
testing - significant low cost gas pot’l
$26.5 MM
$0 2 MM
Giddings
A tifi i l Lift T h
$7 MM cash from field, + 4 MMBOE of 1P+2P reserves PV-10 = $46 MM
Fi t fi ld t t f l t d t
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$0.2 MMArtificial Lift Tech First field test successful to date
FY 2010 Plan
Objectives of limited program:
Substantially expand & upgrade oil & gas reservesNeptune (South Texas) oil project – drill 2 producers & 1 injector
O fOklahoma gas shales – multiple well tests for pdn characteristics
First CO2 injection at Delhi
Initial production response to CO2 injectionInitial production response to CO2 injection
Commercialize artificial lift technology – install in field
Use Giddings cash income to cover overhead
Avoid high cost, risky capital sources
Maintain liquidity through FY2011 as Delhi cash flows increase
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EPM Assets: Delhi CO2 – EOR Project
Milestone Achieved –CO i j ti b 11/12/09
78 mile Delta Pipeline
CO2 injection began 11/12/09Targeted rate & pressure reached
78 mile Delta Pipelineto transport CO2 to Delhi Field
Construction of first phaseConstruction of first phase of produced gas facility for recycling CO2 at Delhi
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EOR - Delhi Field CO2 ProjectDelhi
7/1/09 Pb Net Reserves 13.6 MMBO$196 6 MM PV 10
Tinsley
JacksonDome
$196.6 MM PV-10Gross Production to date 192 MMBO
Original oil in place est. 357 MMBO in current(“OOIP”) project area;( OOIP ) project area;
Average depth 3,235’
Unit Size 13,636 acres
Formations Tuscaloosa &Paluxy
Reserves Basis Comparable Tinsley Field, ample subsurface control, pilot projects in same field committed proved COpilot projects in same field, committed proved CO2reserves, CO2 supply pipeline in place, & available funding to complete project – new SEC rules may apply in 2010
Upside Expand flood to additional 50+ MMBO of OOIP within unit;
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p pLouisiana approved project for severance abatement until ~2019
Delhi Field Development by EPM & DNR
2003: Purchased working interest in Delhi Field for $2.8 million
IC
(Calendar year)
2004: Increased production from 20 bopd to ~145 boep/d through ~$2.5 million of capex
2006: Sold farm-out to DNR for $50 MM - retained 25% reversionary working interest after payout Acquired separate 7 4% royalty interests for $1 5 MM
Hig
hR
O
interest after payout. Acquired separate 7.4% royalty interests for $1.5 MM
2007- 2010: DNR investing ~$342MM – EPM earns revenues from royaltyinterests
ue
Nov 2009: CO2 injection initiated
2010: 1st EOR production projected; 7.4% royalty interest cash flow begins to grow & is meaningful to EPM in 2H cal 2010
dit
ion
al V
al
g g g
2011- 2013: DNR to invest additional ~$122MM to complete project
2014: Independent reservoir engineer projects $200 million deemed payout to occur, based on flat $66 oil price; 25% WI (20% NRI) reverts to EPM
Ad
d
12
p ( )
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EOR Expands EPM’s Reserve Base & Value Denbury’s EOR project may recover substantially more oil due to greater reservoir volume than originally expected (based on 3D seismic), expansion of EOR to additional Tuscaloosa sand reservoirs within Unit and higher recovery factor than 15%, similar to DNR’s other projects
EPM’s 25% reversionary working interest commences after DNR generates ~$200 million in revenues less op exp – which is not affected by actual amount of DNR’s capital expenditures!
Value in Delhi increases with time (see exhibit on page 34)( g )
Delhi PV-10* vs. Gross Recovery, MMBO(at $60 oil + 3% escalation)
Delhi PV-10* vs. NYMEX Oil Price in 2010(15% Recovery & 3% escalation)
$/bbl - 201080
Gross UR - MMBO
$50
$100
60
65
70
75
80
Additional 50 MMBOOIP included
12/24/09oil price
$-$- $4 $8 $12
40
45
50
55
$4 $6 $8 $10 $12
NPV-10 per fully diluted share
Current 357 MMBOOIP in reserve report
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NPV-10 per fully diluted share* Unrisked & pretaxNPV-10 per fully diluted share
Impact of Delhi Production*
Annual Net Pre-tax Cash Flows from Delhi per fully diluted share
< Payout Occurs >
Gross Field Production = 1,000 BOPD
2,430 BOPD
5,600 BOPD
7,880 BOPD
10,000 BOPD
Pre & Post PayoutPre & Post Payout7.4% Royalty Interest = $0.05 $0.12 $0.27 $0.38 $0.48After Payout25% Reversionary WI = $0.62 $0.9825% Reversionary WI $0.62 $0.98Annual Net Pre-tax Cash Flows per Fully Diluted Share
$0.05 $0.12 $0.27 $1.00 $1.46
* From 7/1/09 DeGolyer & MacNaughton Probable Reserves Report & based on NYMEX price of $66.62 per barrel of oil with no escalation, and subtracts severance taxes that are likely to be waived due to approved EOR status. Royalty interest bears severance & ad valorem taxes, but no operating costs Reversionary interest bears same taxes and direct operating costs Total future
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operating costs. Reversionary interest bears same taxes and direct operating costs. Total future operating cash flows = ~$21/share.
EPM Conventional Re-development Assets:
Neptune Oil Project in South Texas
Artificial Lift TechnologyArtificial Lift Technology
Giddings Field in Central Texasg
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Neptune – Low Risk / Low Cost Oil Development
100% working interest and 79.7% net revenue interest; 1,710 net acres to date
Net 3P reserves from 4 re-entries and 21 locations of 542 MBO = PV-10 of $8.1 million
Up to 92 additional drilling locations projected from historical infill results – field has produced ~32 MMBO to date from 380 wells (no current production)
First 2 producers drilled and 1 injector expected to be drilled early in FY2010
~380 previous wells now P&A’d
First 2 producers drilled, and 1 injector expected to be drilled early in FY2010
Low cost – low risk with F&D cost projected at ~$11 per BOE
wells now P&A d~113 new infill locations –4 PUD, 21 Pb & 92 di
11 infill wells drilled in 1970’s :92 pending drilled in 1970 s : comparable examples for our program, made >50 MBO each
area drained by well
1616
50 MBO each on average
Proprietary Artificial Lift Technology
Conventional artificial lift• Fluid level eventually drops to a level where rod pump or gas lift are no longer effective• This can leave substantial volumes of oil and gas
Original fluid levelgas.
Our technology• Mobilizes remaining fluid to the pump
Fl id l l t • Cost $5 -10 of investment per net BOE• Installed in two wells
Fluid level at conventional abandonment
ReservoirRemaining gpotential
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Giddings Field, Central Texas7/1/09 Net Proved Reserves = 3.0 MMBOE $35.3 MM PV-10
Net Probable Reserves = 0.9 MMBOE $10.9 MM PV-10
Drilling locations Ave Gross Recovery Ave D&C cost/well D&C / BOE14 proved re-entries 111 MBOE/well $1.3 MM $14.647 proved grassroot & 270 MBOE/well $2.3 MM $10.652 probable grassroot
100% WI, ~80% NRI in 10 producers & ~18,000 net acres
Naturally fractured Austin Chalk, Georgetown & Buda – no hydraulic fracs required
Wells t picall prod ce at high initial rates ( 150 BOEPD for re entr ell 340Wells typically produce at high initial rates (~150 BOEPD for re-entry well, ~340 BOEPD for grassroots well) followed by steep initial declines, then stabilize with about half of estimated reserves produced in first two years
Reserves estimated to be 31% oil 34% gas liquids and 35% natural gas; and 14%Reserves estimated to be 31% oil, 34% gas liquids and 35% natural gas; and 14% developed. 2P reserves are associated with PUD locations.
Last 2 re-entries drilled in Giddings Field yielded average 8 day rate of 450 BOEPD
6 additional 1P+2P grassroots drilling locations leased that are economic at gas >$5
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Price Sensitivity of Giddings/Neptune Reserves*
EPM Giddings & Nepturne (1P + 2P) PV-10 per fully diluted share vs Blended Flat Commodity Price
$/Sh (31% oil, 34% ngl & 35% natural gas)
$1.60
$1.80
$2.00$/Share
ProvedProbable Prices as of 12/24
$1.00
$1.20
$1.40
Gas price increase begins to add back locations
$0 20
$0.40
$0.60
$0.80
$-
$0.20
$20 $25 $30 $35 $40 $45 $50 $55 $60
$/BOE NYMEX
Report as of 7/1/2009
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* Flat prices & costs
EPM Assets:
OK Low Cost Gas Shale Project
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Gas Shales in Eastern Oklahoma
WoodfordCompletions
Over 100 vertical and horizontal Woodford completions to date offsetting EPM acreage by other
EPM Acreage
Tulsa
offsetting EPM acreage by other operators in Wagoner County
Offset short lateral in Woodford on track to produce ~1.1 BCF in Haskell County
Main W df d
OklahomaWoodford
Trend
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Shallow = Low Cost
Developing substantial shale gas potential, targeting $0.80 - $1.25 per MCFShallow depth = small rig and low fracturing horsepower = low day ratesTwo shale zones identified and tested to date – Woodford & CaneyExpect D&C costs to be ~$200K for vertical Wagoner well (2 zone frac) at 1600’ depth, $500K for dual completion vertical well in Haskell at 4,000-5,000’ depth3 d ill d ll d 3 t i t t d ith 1 b EPM i W3 drilled wells and 3 re-entries tested with 1 core by EPM in WagonerIn Wagoner, EPM frac’d 1 well in Woodford and 1 well in Caney for extended production testOffset short horizontal Woodford well in Haskell projected to reach 1 1+ bcfOffset short horizontal Woodford well in Haskell projected to reach 1.1+ bcf
100% WI in ~17,850 net acres, average ~80% NRILease terms generally extend ~3 - 5 years from lease dateVertical well spacing expected to be ~40-60 acres
Substantial additional acreage is typically obtainable through forced pooling
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EPM Summary
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EPM Financial Strength
Strong balance sheet and excellent liquidityg q y
Substantial working capitalNo external funding required for conservative capital expenditure program in FY2010We control our assets and required capital expenditures
Financial Strategy: a conservative approach to optimize our asset values over the next few years without requiring external
capital raising on unfavorable terms.
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EPM Operational Strength for Growth
EPM Intangibles
E i d St ffExperienced StaffSuccessful Team Record
Tight sand/horizontal expertise6 Year Track Record
FY2010
6 ea ac eco dTechnology
EPM Tangible AssetsValue Catalysts
Delhi producingEPM Tangible Assets$6.6 MM WC & no debt
13.6 MMBO Delhi EOR 2P4 MMBOE Giddings 1P-2P
p gOK confirmation
Neptune producingOptimize Giddings
Commercialize technology4 MMBOE Giddings 1P 2P0.5+ MMBO Neptune 1P-3P
Above is 91% oil price related+
17 850 t h l
Commercialize technology
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17,850 net acres shale gas
(NYSE Amex: EPM)
Company Contact: St li M D ld VP & CFO
IR Contact:Li Elli tt / l lli tt@dSterling McDonald, VP & CFO
(713) [email protected]
Lisa Elliott / [email protected] Jack Lascar / [email protected]&E / 713-529-6600
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Exhibits
Quick Facts
Li iditLiquidity
EPM Growth in Reserves
2009 Events and 2010 Catalysts
Effect of Different Recoveries on EPM’s Delhi Interests
Accretion of Value over Time at Delhi
Illustration of Giddings Developmentg p
Management team
Board of DirectorsBoard of Directors
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Quick Facts about EPM
Ticker Symbol EPMFiscal Year-End June 30Fiscal Year-End June 30Market Cap ~$122 million as of 12/24/2009Enterprise Value ~$116 MM (based on 9/30/09 WC)
• 27.1 MM shares outstanding• 32.9 MM shares fully diluted• ~39% owned by institutionsy
Financial Strength $6.6 MM in WC & no debt as of 9/30/09Assets low risk development projects created by EPMTeam Record 6 year successful record in creating and
implementing 4 major projects
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EPM Liquidity
9/30/09 (unaudited)
Selected AssetsWorking Capital $6,605,879
Properties & Equipment, net 29,456,824Other Assets 54,566Total Assets $37,476,554
Long Term Liabilities & EquityLong Term Debt $0Other Liabilities (primarily deferred income tax) 5,662,709Total Long Term Liabilities 5,6662,709
Equity $31,813,845
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2009 Events 2010 Catalysts
Accomplishments in FY 2009p2 Giddings PUD’s averaged initial gross 450 BOEPD per wellCompletion of Denbury’s Delta CO2 pipeline to DelhiPositive test results in OK low cost gas shale resourceSuccessful first field test of artificial lift technology in GiddingsMaintained liquidity and strong balance sheet with no debt
Growth Catalysts for FY 2010Growth Catalysts for FY 2010Continued testing of low cost shale resource in OKCommencement of drilling in Neptune So. Texas oil projectInitiation of CO2 injection at DelhiInitiation of CO2 injection at DelhiProduction response from CO2 injection at Delhi
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EPM Revenues Growth by Fiscal Year
$7,000
$5,000$6,000
$2 000$3,000$4,000
$0$1,000$2,000
$02004 2005 2006 2007 2008 2009
• Revenues in thousands• 2007 revenues decreased by farm-out to DNR2007 revenues decreased by farm out to DNR• June 30 fiscal year-end
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EPM Reserves by Fiscal Year (MMBOE)
14
8
10
12
Proved
4
6
8 Giddings 2PDelhi 2PNeptune 1P-3P
0
2
2004 2005 2006 2007 2008 2009• Reserves as at fiscal year end of June 30• Does not include low cost shale gas resource in Oklahoma & additional Neptune locations• 2009 downward revisions due to commodity price changes (from $140/BO to ~$70/BO &
$13.09/MMBTU to ~$3.88/MMBTU)
2004 2005 2006 2007 2008 2009
$13.09/MMBTU to $3.88/MMBTU) • FYE 06 proved reserves decreased by farm-out of Delhi working interest
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Effect of Different Recoveries on Delhi Volumes
Estimated EPM Net Probable Reserves in Delhi CO2-EOR Project
(at $66.62 oil, SEC pricing)
Gross Recovery in Project 45 MMBO 54 MMBO 72 MMBO
EPM royalty interest (7.4%) 3.3 4.0 5.3 Other royalty interests (12 6%) 5 7 6 8 9 1Other royalty interests (12.6%) 5.7 6.8 9.1 Total royalties (20%) 9.0 10.8 14.4
100% WI reserves (80% of RI) 36.0 43.2 57.7 WI bbls produced before Payout 4.9 4.9 4.9 WI bbls - remaining after Payout 31 1 38 3 52 8WI bbls - remaining after Payout 31.1 38.3 52.8
EPM 25% WI after Payout 7.8 9.6 13.2 EPM 7.4% Royalty (from above) 3.3 4.0 5.3 Total Net EPM bbls at Delhi 11.1 13.6 18.6
RI = revenue interest = share of gross productionWI = working interest = cost-bearing interest, earns gross production less royaltiesPayout = deemed payout = $200 MM of 100% WI revenues less field operating expenseRoyalty = revenue interest bearing no capital or operating costsSwept OOIP = original oil in place in portion of reservoir swept by CO2
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p g p p p y 2CO2 Recovery is in addition to additional primary + secondary recovery of 2 MMBO
Delhi PV-10 Accretion With Time
Delhi Pretax PV-10* Per Diluted EPM Share(PV-10 of remaining net cash flows)
$12.00
$14.00
D&M 7/1/09 Report Adj'd D&M for Inflation + Tax Holiday
$6.00
$8.00
$10.00
$2.00
$4.00
$
Peak PV-10, after collecting $37 MM ($1.13/share) of cash flows in prior years
$-
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
Years* NCF from D&M Report - f ixed $66.62 oil price and fixed costs; payout projected in 2014Adjusted PV-10 includes 3% inflation in prices & costs and includes severance tax holiday Adjusted PV-10 includes 3% inf lation in prices & costs, and includes severance tax holiday
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Giddings Field – Infill Development
Lease boundary -mandatory distance
lease boundarymandatory distancebetween vertical wellboreand lease boundary
plug
Austin Ch lk
Naturally occuring fracturesbearing oil and gas
Existing horizontal wellborepenetrating multiple fracturesthat contain oil and gas
New horizontal wellborepenetrating undrained fractures
Chalk
that contain oil and gas
35
Our Management Team
Robert Herlin, CEO & Chairman$Co-founded EPM in 2003 and built company using $8.3 million of equity capital
27 years of leadership experience in M&A, development, operations and finance in public and private sectors$800 million in transactions completedOriginated and led horizontal drilling team in early years of horizontal drilling adoption by industryMember of Board of Directors – Boots & CootsB.S. and M.E. in chemical engineering (Rice University) and MBA (Harvard)
Sterling McDonald, CFOCFO since 2003Former CFO for PetroAmerican Services, PetroStar Energy and Treasurer forFormer CFO for PetroAmerican Services, PetroStar Energy and Treasurer for Reading & Bates Corporation Responsible for raising ~$4 billion in capitalB.S. and MBA (University of Tulsa)
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Our Management Team
Daryl Mazzanti, VP-OperationsJoined team in mid-2005; 21 years of experience in oil & gas industryFormer Manager of US Business Development for AnadarkoFormer Production Manager, Austin Chalk for Anadarko/UPRC responsible for 1200 wells, staff of 65 and 25,000 BOEPD of productionResponsible for numerous innovations in horizontal drilling, completions and
tifi i l liftartificial lift B.S. in Petroleum Engineering (University of Oklahoma)
Edward Schell, General Manager for Drilling and UnconventionalEdward Schell, General Manager for Drilling and Unconventional Development
Joined team in late 2006; 25 years of experience in oil and gas industryVarious management positions in drilling, operations and business development at Anadarko Petroleumat Anadarko PetroleumParticular expertise in horizontal drilling and tight gas reservoirsDrilled ~800 wells, 200 being horizontal and 2/3rds being in unconventional reservoirsB S in Petroleum Engineering (University of Texas)B.S. in Petroleum Engineering (University of Texas)
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Our Board of DirectorsRobert Herlin, CEO, Chairman & Co-founderLaird Cagan, Director & Co-founderM i Di t C M Af C it l P tManaging Director – Cagan McAfee Capital PartnersFormerly with Goldman Sachs and Drexel Burnham Lambert
E.J. DiPaolo, DirectorEnergy Partner with Growth Capital Partners, L.P.
G S f GFormer Halliburton Group Senior Vice President of Global Business Development
Gene Stoever, DirectorRetired Partner with KPMG Peat MarwickFormer SEC Reviewing Partner for KPMGCPA in the State of Texas and member of the AICPA
Bill Dozier, DirectorFormer SVP-Business Development for Vintage Petroleum Former SVP-Operations for Vintage PetroleumFormerly in operations for Santa Fe Minerals and Amoco
Kelly W. Loyd, DirectorDirector with JVL Advisors, LLC, a private energy investment companyFormerly Associate with RBC Capital marketsy pFormerly Founder of L.A.B. sports and Entertainment and Managing Partner of Tigre Leasing, LLP
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