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.

4

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

5

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

7

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) 935-0122smcdonald@evolutionpetroleum.com

Lisa Elliott / lelliott@drg-e.com Jack Lascar / jlascar@drg-e.comDRG&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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