 Alta Mesa Holdings, LP Wells Fargo Securities 10 th Annual Pipeline, MLP, and E&P, Services and Utility Symposium Alta Mesa Holdings, LP December 6, 2011 Confidential Exhibit 99.1 |
Forward Looking Statements 2 Confidential This material includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These forward- looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Forward-looking statements may include statements about our: business strategy; reserves, including changes to our reserves presentation in accordance with newly adopted SEC rules; financial strategy, liquidity and capital required for our development program; realized natural gas and oil prices; timing and amount of future production of natural gas and oil; hedging strategy and results; future drilling plans; competition and government regulations; marketing of natural gas and oil; leasehold or business acquisitions; costs of developing our properties and conducting our gathering and other midstream operations; general economic conditions; credit markets; liquidity and access to capital; uncertainty regarding our future operating results; and plans, objectives, expectations and intentions that are not historical. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; and other risks. Except as otherwise required by applicable law, we disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms “estimated ultimate recovery,” “EUR,” “probable,” “3P,” “possible,” and “non-proven” reserves, reserve “potential” or “upside,” “unrisked potential” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that are not classified as proved reserves, may not have been calculated as defined by SEC regulations and SEC’s guidelines may prohibit us from including in any future filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. We believe these estimates are reasonable, but such estimates have not been reviewed by independent engineers. Estimates may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates. Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity Although we believe the forecasts are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions and data or by known or unknown risks and uncertainties. Market and industry data and forecasts used in this presentation have been obtained from independent industry sources as well as from research reports prepared for other purposes. Although we believe these third-party sources to be reliable, we have not independently verified the data obtained from these sources and we cannot assure you of the accuracy or completeness of the data. Forecasts and other forward-looking information obtained from these sources are subject to the same qualifications and uncertainties as the other forward-looking statements in this presentation. Alta Mesa Holdings, LP |
 3 Confidential Proved Reserves (SEC Case) Proved Reserves PV10 (SEC Case) Crude Oil Proved Reserves Future Total Proved Revenue from Oil % Proved Developed R/P Q3’2011 Production 2011E CAPEX (Drill, Workovers, Facilities) Net Acreage 325 BCFE $705 Million 26% 54% 66% 8.1x 119 MMCFED $180 Million 172,000+ Key Metrics 1 Core Operating Areas Alta Mesa Overview 1 Reserve statistics and R/P metric as of Year End 2010 SEC Reserve Report Privately held company, founded in 1987, engaged in onshore conventional oil and gas acquisition, exploitation, exploration and production Our diverse asset base is characterized by low-risk, repeatable opportunities in well-established fields, which allows us to cost effectively grow reserves and production Seasoned management and technical team that creates value by rigorously applying new technology and new knowledge in established fields and areas that are under-developed or over- looked Since 2007, increased proved reserves and production at 40% and 65% CAGR, respectively Corporate Overview High Quality & Diversified Asset Portfolio |
 Low-Risk Business Model Attractive Economics Repeatability Control Over Pace of Development Available Rigs and Services Proven Geology Established Infrastructure Stable Regulatory Environment We create value in under-developed and over-looked areas with the following characteristics Multiple Pay Zones 4 Confidential |
 Alta Mesa’s Focus Areas 5 Confidential Reserve statistics and R/P metric as of Year End 2010 SEC Reserve Report 44 BCFE $129.2 46% 62% 19.9x 946 BOEPD 48% 36,878 Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage Oklahoma East Texas Hilltop South Louisiana Eagle Ford Shale Other AMH Properties 93 BCFE $111.9 100% 56% 5.5x 55.2 MMCFED 100% 16,998 Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 63 BCFE $153.9 74% 84% 11.2x 15.3 MMCFED 61% 41,594 Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 76 BCFE $229.2 72% 74% 6.1x 30.5 MMCFED 52% 36,505 Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 47 BCFE $67.7 58% 53% 14.9x 6.4 MMCFED 65% 36,627 Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 3 BCFE $13.2 13% 52% 6.5x 964 BOEPD 10% 3,611 |
 Proved Reserves 1 Includes revisions. Reserve statistics as of Year End 2010 SEC Reserve Report 6 Proved Reserves by Type (Bcfe) Annual Reserve Additions as a % of Production Proved Reserves by Commodity (Bcfe) Proved PV-10 by Region ($MM) PV-10 Value of $705.2 million 66% of Proved Reserves are Developed Confidential 0% 100% 200% 300% 400% 500% 600% 700% 800% 900% 2007 2008 2009 2010 Purchases Extensions Average Annual Reserve Replacement Rate of 495% 0 50 100 150 200 250 300 350 2007 2008 2009 2010 Oil Gas PDP 120 BCFE 37% PDNP 95 BCFE 29% PUD 111 BCFE 34% Deep Bossier $112 MM East TX $154 MM South Louisiana $229 MM Oklahoma $129 MM Other $81 MM 1 |
 Revenue 1 Growth ($MM) EBITDAX Growth ($MM) Production Growth (Bcfe) Lease and Plant Operating Expense ($/Mcfe) Operating Efficiency & Profitable Growth 7 1 Excludes unrealized hedging gains and other revenues. 2 Pro forma adjustments for Meridian for entire 1H 2010. Confidential $56.7 $99.0 $102.3 $238.4 $341.9 0 50 100 150 200 250 300 350 400 2007 2008 2009 PF 2010 & Q3 2011 Annualized² $40.9 $63.9 $58.2 $145.5 $200.0 $- $50.0 $100.0 $150.0 $200.0 $250.0 2007 2008 2009 PF 2010 & Q3 2011 Annualized² 7.7 9.6 13.9 34.5 43.7 0 5 10 15 20 25 30 35 40 45 50 2007 2008 2009 PF 2010 & Q3 2011 Annualized² $1.89 $2.15 $1.71 $1.35 $1.49 $- $0.50 $1.00 $1.50 $2.00 $2.50 2007 2008 2009 PF 2010 & Q3 2011 Actual² |
 Liquids-rich gas from over 40 potential pay sands in the Yegua and Wilcox formations Anne Parsons field produces out of the Austin Chalk formation Low-risk expansions of well established fields discovered in 1950s and 1960s by Amoco and other large companies Applying modern geological analysis and engineering techniques to drive production and reserve growth Took over Cold Springs operations in Q2’2011 East Texas – Overview Increasing Reserves and Production from Established Fields 8 Confidential Overview 1 East Texas Assets Map 1 Reserve data as of YE 2010 SEC reserve report Proved Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 63 BCFE $153.9 74% 84% 11.2x 15.3 MMCFED 61% 41,594 |
 Urbana – 3P EUR (Bcfe) Cold Springs – 3P EUR (Bcfe) Urbana – Overview Cold Springs – Overview Urbana and Cold Springs Field Source: Internal reserve report. 9 Confidential Wilcox Discovery Famcor Purchase Purchased remaining 50% of Famcor East CS WI; Rediscover 7900’ oil sand Urbana A-8 confirms low- resistivity pay Alta Mesa purchases 50% Famcor, other WI West Cold Springs extension proved Milestones *Does not include oil/condensate, 60 BO/MM Reserves (BCF) Cum EUR* 0 0 25 27 53 80 55 82 60 189 72 195 Known structure with multiple pay zones Like Urbana, but larger with more development potential Acquired > 50% working interest in past three years Initiated development drilling and recompletions – Very low-resistivity pay (<0.8 ohms) – Modern logging technology and fracture stimulations Field re-development and expansion – Confirmed 1,500-acre western field extension in multiple Wilcox Sands – 3D survey planned to identify Yegua potential and delineate the Wilcox formation – 19 PUDs documented Known structure with multiple pay zones Field re-development since buying Famcor WI Recent advances have led to increased reserves – Low resistivity pay: modern logging – Fracture stimulations – Gas lifting and lowering surface system pressure New 3D data will drive additional development – One of four new fault blocks to be tested in Dec’2011 – Deeper pay potential to be tested in 2012-2013 Wilcox Discovery Amoco sale to Famcor & Alta Mesa Urbana A-8 confirms low- resistivity pay Alta Mesa drilling confirms added pay Urbana 3-D complete Milestones *Does not include oil/condensate, 25 BO/MM 0 0 35 37 53 65 60 113 64 160 Reserves (BCF) Cum EUR* 0 50 100 150 200 1951 1989 2005 2008 2009 BCF Cumulative to Date 0 100 200 1951 1989 2005 2007 2009 2011 BCF Cumulative to Date |
 Overview 1 Oil Zones Actively Being Pursued Along Trend 2 Hilltop – Overview Primary objective is lower Bossier sand between 15,000 and 20,000 feet deep Field is highly productive with multiple pays, low F&D and low LOE Value derived through active participation with Operator on engineering, operations and geology/geophysics – EnCana operates approximately 85% of Alta Mesa’s production Large Position in a Highly Prolific, Expanding Play 10 Confidential 1 Reserve data as of YE 2010 SEC reserve report 2 Only HZL wells with permitted target of Woodbine and Eagle Ford formations Permitted HZL Wells¹ (Since January 1, 2010) Producing HZL Wells¹ (Drilled Post - January 1,2010) 93 BCFE $111.9 100% 56% 5.5x 55.2 MMCFED 100% 16,998 Proved Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage |
 Hilltop Net Production by Operator (MMcf/d) Prolific, Low Cost Gas Play Major North American Gas Basin Breakevens ¹ 11 Confidential Additional potential in other zones and application of horizontal drilling Source: Credit Suisse. Data excludes land costs. Deep Bossier breakeven based on AMH analysis. 1 |
 Overview 1 Oklahoma Activity Map Oklahoma – Current Activity Long-lived, Stable Oil Production 12 Confidential East Hennessey Waterflood Expansion Re-Drill Locations Lincoln North Unit Waterflood Expansion Dover Unit Infill Drilling Lincoln North Unit Infill Drilling Lincoln Southeast Waterflood Expansion Principal assets are large fields developed by Conoco, Texaco and Exxon on 80-acre spacing, unitized and waterflooded Oil dominated, long life assets with shallow declines and steady cash flow Potential to more than double production and reserves with down-spacing and waterflood Key area players include: Chaparral, Chesapeake and Devon 1 Reserve data as of YE 2010 SEC reserve report Proved Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 7.3 MMBOE $129.2 46% 62% 19.9x 946 BOEPD 48% 36,878 |
 Oklahoma Production Growth 13 Confidential Historic 8/8ths Field Production (BOEPD) Oklahoma Assets Producing at Multi-Decade High - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Actual Field Production Projected Field Decline Wedge Equates to ~4 MMBOE of added production since AMH took over assets |
 Regional Development of Mississippian Formation Wells Targeting Mississippian Formation AMH Currently Identifying and Testing Mississippi Locations on its Acreage 14 Confidential AMH Acreage |
 Eagle Ford Shale – Overview Significant Acreage Position Concentrated in Karnes County 15 Confidential Karnes County is industry recognized core area of Eagle Ford Trend 120 well development program underway with operator Murphy; 2 rigs currently operating • Based on 160 acre spacing Infrastructure & facilities to handle production Optimizing initial rates to maximize ultimate recovery 1 Reserve data as of YE 2010 SEC reserve report Proved Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage Enduring Resources PXP AMH / Murphy Conoco Marathon EOG Pioneer Eagle Ford Map Overview 1 0.6 MMBOE $13.2 13% 52% 6.5x 964 BOEPD 10% 3,611 |
 Production and EUR highly sensitive to drawdown – Early EFS wells exhibit severe well damage from high drawdown – Theoretically, high drawdown may be “collapsing” the near well bore frac zone, crushing proppant, and limiting connectivity to the reservoir – Since mechanism of failure is mechanical, it is unlikely that damaged wells can be repaired by restricting the rate once the damage is done – Recent presentations/discussions by PetroHawk, Pioneer, and Chesapeake support this theory Our wells demonstrate positive effects with restricting rate early in well life – Post high IP’s, wells experience severe decline; lower IP’s equate to lower decline Restricting rate has flattened decline and potentially enhanced EUR Eagle Ford Shale – Maximizing EUR and Profitability 16 Confidential Time Normalized Average AMH Karnes County Oil Well Decline Profile 30 Day Average Rate 670 BOEPD 60 Day Average Rate 652 BOEPD 90 Day Average Rate 626 BOEPD 120 Day Average Rate 598 BOEPD 150 Day Average Rate 588 BOEPD 1 10 100 1,000 Days |
 South Louisiana – Overview Long-standing focus area of Alta Mesa team Primary fields are South Hayes and Weeks Island Historically prolific areas originally developed by Shell, Texaco and Exxon Significant multi-pay opportunities with oil and liquids rich gas targets Multiple low risk exploration and development targets Outstanding reservoir quality that yields high rates, quick payouts and strong ROI Expect to materially increase PDP, PDNP and PUD reserves through rigorous analysis and development of fields Historically Prolific Area Originally Developed by Majors 17 Confidential 1 Data is inclusive of all assets in Louisiana. 2 Reserve data as of YE 2010 SEC reserve report Proved Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 76 BCFE $229.2 72% 74% 6.1x 30.5 MMCFED 52% 36,505 Overview 1,2 South Louisiana Assets Weeks Island Biloxi Marshland South Hayes Ramos Turtle Bayou Humphreys St Gabriel Gibson |
 Weeks Island - Overview High Value Oil Field with Significant Upside Potential 18 Confidential Discovered by Shell in 1945 Significant oil field characterized by low-risk, multi-pay targets Continuous 2H’2011 drilling program underway 18 PDNP and 13 PUD locations booked, with multiple additional locations identified for 20+ MMBOE potential Drilling targets developed through intense, multi-discipline analysis of geologic, geophysical, and engineering data Ability to increase production and lower costs by optimizing facilities Proved Reserves PV10 ($MM) % Gas (Reserves) % Proved Developed R/P Q3 2011 Production % Gas (Production) Net Acreage 3.0 MMBOE $81.1 30% 57% 4.9x 1,923 BOEPD 5% 5,256 Oil & Gas bearing sediments Piercement Salt Dome Overview 1 Weeks Island: Multiple Oil Pay Zones Reserve data as of YE 2010 SEC reserve report 1 |
 Weeks Island Development 19 Confidential Development Drilling Exploration Drilling Secondary Recovery Facility Optimization Exploitation Opportunities Drilling Results - Past 36 Months Well Costs ($MM) IP (BOEPD) Current Rate (BOEPD) EUR (MBOE) Goodrich Cocke #6ST $5.21 250 80 162 Goodrich Cocke #7ST $3.30 800 800 969 State Weeks Bay #15ST $4.20 350 150 269 Goodrich Cocke #5 $2.76 150 70 82 State Weeks Bay #19ST $3.34 600 1180 65 State Weeks Bay #20ST $2.24 250 50 77 Goodrich #25ST $2.23 200 65 164 Myles Salt #34ST $2.94 350 350 745 Goodrich Cocke #9* $4.80 800 800 1825 Myles Salt #45 $0.31 500 800 832 *Production number is estimate, awaiting completion. Historic Field Production (BOPD) Cumulative Field Production of 280 MMBO & 1 TCF Exxon / Shell Stone / Meridian AMH - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 |
 2011 CAPEX Forecast Planned Drilling & Recompletion CAPEX by Field ($000s) 2010E 2011E 20 Confidential % Liquids 57% % Gas 43% % Liquids 67% % Gas 33% $144 $180 $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 2010E 2011E Other Other SLA Oklahoma Other South Texas Weeks Island Eagle Ford East Texas Deep Bossier ($5) $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 -100% -50% 0% 50% 100% 150% 200% 250% 300% 350% Projected Annual CAPEX CAPEX Focus Year over Year Change in CAPEX $50 |
 2012 CAPEX Plan Planned Drilling & Recompletion CAPEX by Field ($000s) Manage to cash flow neutral position, with total Capex for the year expected to range between $220 and $240 million Significant HBP positions in core areas allow management to accelerate / defer projects as economics dictate Over 80% of 2012E drilling and recompletion dollars directed to oil and liquids rich properties Capital reallocated from “gas only” Deep Bossier to oily prospects at Weeks Island, Oklahoma, East Texas and Eagle Ford Oil and liquids expected to generate greater than 35% of production (equivalent basis) in 2012 Multi-year drilling inventory with over 125 identified PUD locations CAPEX Focus 21 Confidential Continued Focus on High Margin Liquids Rich Projects 2011E 2012E Other SLA Oklahoma Other South Eagle Ford East Texas Year over Year Change in CAPEX % Liquids 67% % Gas 33% % Gas 82% % Liquids 18% Hilltop Texas |
 Production Shift from Gas to Oil Historic and Projected Production Mix Oil Production is Expected to Grow from 14% of Production to >40% Over Next 18 Months Confidential 22 Future Oil Growth Driven by Weeks Island and Eagle Ford Material Oil Reserves Remain to be Developed Production from these Fields is Primarily Oil 50% Proved Developed 52% Proved Developed 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Gas Oil 83% 17% Eagle Ford Weeks Island Total Proved PROB POSS |
 23 Confidential Balance Sheet Protection, Active Management of Portfolio Management of Commodity Price Risk Cost-effectively limit downside risk, while minimizing cash outlays Active management across a five-year window Tactically switching portion of WTI for Brent due to high correlation of LLS / Brent Portfolio Swaps Put Spreads, Call Spreads 3-Way Collars Natural Gas Henry Hub HSC Basis Crude oil Brent WTI Strong Track Record of Using Hedges to Maximize Profitability Since 2009, hedges have increased revenue by $67mm or 13% As of November 1 st , AMH’s hedge book ensures a minimum of $545mm of revenue over the next 5 years Over 55% of 2012 expected production is hedged at an average $8.68/mcfe $0 $2 $4 $6 $8 $10 $12 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 Avg Sales Price (per Mcfe) Unhedged Incremental Sales Gain due to Hedges |
 % of PDP Hedged - Natural Gas Average Floor Price – Natural Gas Note: Hedge positions as of 12/2/11; NYMEX strip as of 11/25/11. 2011 calculations are for Oct 1, 2011 forward. Commodity Price Risk Management Confidential 24 % of PDP Hedged - Oil Average Floor Price – Oil 55% 97% 116% 131% 86% 12% 0% 20% 40% 60% 80% 100% 120% 140% Q4'2011 2012 2013 2014 2015 2016 $85.28 $98.39 $90.69 $85.81 $87.57 $95.00 $75 $80 $85 $90 $95 $100 Q4'2011 2012 2013 2014 2015 2016 AMH Average Floor Price NYMEX as of 11/25/2011 54% 85% 113% 46% 22% 7% 0% 20% 40% 60% 80% 100% 120% Q4'2011 2012 2013 2014 2015 2016 $5.80 $5.27 $5.25 $6.23 $5.91 $5.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $6.50 Q4'2011 2012 2013 2014 2015 2016 AMH Average Floor Price NYMEX as of 11/25/2011 |
 LLS Basis Trading at Premium to WTI Historic and Forward LLS vs WTI Spread 69% of Q3 oil production indexed against LLS, resulting in $12.51 spread to WTI $5 $0 $5 $10 $15 $20 $25 $30 $0 $20 $40 $60 $80 $100 $120 $140 $160 25 Confidential WTI LLS LLS (Forecast) WTI (Forecast) Spread Spread (Forecast) 2004 Through 2010 Average Differential of $1.95/BBL 2011 Forward Average Differential of $10.07/BBL |
 Divergence in Historic LLS Correlations from WTI to Brent 26 Confidential Historic Prices Price Correlation $25 $45 $65 $85 $105 $125 $145 Brent WTI LLS 86% 88% 90% 92% 94% 96% 98% 100% 2004 2005 2006 2007 2008 2009 2010 2011 WTI:LLS Brent:LLS Brent:WTI |
 Strong Management Team with Proven Track Record Average 25+ years industry and technical experience Successfully completed over $250mm of acquisitions at $1.27/mcfe 1 Since 2007, increased proved reserves and production at 40% and 65% CAGR, respectively Operational Control and Low F&D Costs 83% of wells are controlled by operations 3 All-source 4-year avg. F&D of $2.14/Mcfe compares favorably to peers Less than 9% of core property leases expire by end of 2011 Low-Risk & Multi-Year Drilling Inventory Multi-year drilling inventory with 125 current PUD locations Significant positions in Deep Bossier play, East Texas Wilcox and South Louisiana; upside potential from Eagle Ford shale position 72% of PDP volume hedged through 2016 High Quality & Diversified Asset Portfolio Diverse asset base with significant drilling opportunities 25% of Q3’11 production from oil and liquids (53% of Q3’11 revenue 2 ) 2010 LOE of $1.37/mcfe Key Considerations 27 1 Statistic for 2007 through 2010. 2 Excludes unrealized hedging gains and other revenues. 3 Excludes Deep Bossier resource play which constitutes approximately 16% of AMH’s PV-10 value and where EnCana is the principal operator. Confidential |
 Hal Chappelle, President & CEO Phone: 281-943-1353 Email: hchappelle@altamesa.net Michael McCabe, Vice President & CFO Phone: 281-530-0991 Email: mmcabe@altamesa.net Lance Weaver, Investor Relations Manager Phone: 281-943-5597 Email: lweaver@altamesa.net www.altamesa.net Contact Information 28 Confidential |