Harrison and Panola. EnerCom Oil & Gas Conference Denver, CO August 22-26, 2010

Transcription

1 Harrison and Panola EnerCom Oil & Gas Conference Denver, CO August 22-26, 2010

2 Company Overview H/B & CVS Inventory Operates 85% of 42,400 net Haynesville/Bossier H/B acres 273 additional net potential H/B Hz drilling locations in Capital Core (22 H/B producers) Net potential acreage is already de-risked All acreage held by production Operates 84% of 62,500 gross Cotton Valley Sand CVS acres 1,382 net potential CVS / Travis Peak ( TP ) locations in Harrison & Panola Counties (325 CVS & 45 TP producers) 2009YE Proved reserves of 355 Bcfe 94% natural gas / 37% proved developed 1:1 PUD-PDP ( well count) Production History & Revenue Floors Q actual 4.3 Bcfe (47 mmcfe/d) 61% H/B, 36% CVS, 3% Oil Q1-Q2 Protected by 6.1 Bcfe of Bought Puts at $6.42 Q3-Q4 Protected by 7.2 Bcfe of Bought Puts at $6.37 Q3 Production Guidance of Bcfe (55 mmcfe/d) 2

3 1 st Filter for GMXR Shale Play: 160 Bcf per Section Type Log Gas-In-Place Initial core data gas-in-place values of 160 Bcf/640 acres based on Core Lab, Schlumberger, and Baker Hughes interpretations (Haynesville interval only) Middle Bossier 6.5 Bcf per well is 32.5% recovery factor (4,500 lateral on 80 acre spacing); Barnett Shale core area 30% to as high as 50% Gas Shows Haynesville Elevated Porosity 3

4 GMXR s Knowledge of Harrison/Panola is Amplified by Collaborations Superior Harrison/Panola control in addition to 22 GMXR completions (leading operator in area) 200 detailed well control points from Core Lab, Object Reservoir and Data Trades 21 rig-years worth of data Meaningful control for Elm Grove-Holly/Angelina Trough trend Geographically significant coverage over entire embayment Note: Map as of 7/28/10; sources include Core Lab, Object Reservoir and participating data swap companies. 4

5 Harrison & Panola Core Story : Abundant Vertical Fractures nanodarcy rock not driving early performance on HB Hz wells, fractures are primary production element in embayment Closely spaced Vertical Fractures in East Texas consistent with move to tighter spacing of perforation clusters and lower declines Elevated Vertical Fracture Index (VFI) in Harrison/Panola counties as compared to Elm Grove Holly will facilitate effective exploitation of entire interval A * Map depicts HB Hz activity as of 5/27/10 A A Rusk, TX A Vertical Fractures Harrison, TX Harrison, TX Harrison, TX Harrison, TX Harrison, TX Harrison, TX Harrison, TX Harrison, TX Harrison, TX Harrison, TX Caddo, LA Red River, LA 2 Ft. Examples of Vertical Fractures East Texas Core Sample Elevated Porosity Gas Shows 5

6 Vertical Fracture Illustration: Long Term Positive for GMXR Higher frequency of minor fractures results in less mechanical and reservoir risk in downspacing activities which will facilitate full exploitation of reservoir Harrison/Panola Counties Closely spaced vertical fractures Major faults in Elm Grove- Angelina created stress-reduction shadow promoting wide joint spacing Elm Grove-Angelina downspacing likely to be developed on pad-frac scheme to avoid partially depleted fractures compromising recovery and will require large scale procedures Lateral Fracture Zone Elm Grove-Angelina Wide spaced vertical fractures Matrix Porosity 6

7 Fractures Exposed in Regulatory Filings Confirm Core Story Reports of hydraulic stimulation of highly conductive wide spaced fractures (or joints) impacting wells over 3000 ft removed from one another within the Elm Grove-Angelina region is not unusual Conducive to high IP s. Problematical high density development and constrained by Gas-in-place Map illustrates major faults and tectonic features EOG Texas Railroad Commission Exhibit on Gas Unit Sizing Hill #1H 1st of 3 EOG Wells; Hydrocarbon production started Aug. 15, 2009 Hassel #1H 2nd of 3 EOG Wells; wellbore approx. 3,200 ft. from Hill #1H wellbore. Within 3 days of Hassel #1H Hydraulic Fracture Treatment, Hill #1H gas production decreased by approx. 25% and water production spiked. Chemical Frac Tracer analysis on Hassel #1H and Pop Pop #1H found only unique tracer fluids were fluids used during the fracture stimulations of Hassel #1H and Pop Pop #1H wells. In support of Devon s request for 640 acre spacing, it should be known that EXCO has experienced communication between two Haynesville wells in De Soto Parish, Louisiana during a recent fracture stimulation. These wells were over 2000 apart, and the producing well offsetting the well undergoing stimulation almost immediately and unexpectedly started making large amounts of water. 7

8 Best of Class Rate of Penetration Supports Core Story 7,500' 60 GMXR Bit Run Length (1) (ft) 7217' 57 7,000' Other Operators Bit Run Length (1) (ft) 55 6,500' Rate Of Penetration (ft/hr) Length of Bit Run 6,000' 5,500' 5,000' ' 5638' 5083' 5214' 5392' 5673' 5015' 5033' 5790' 5877' ' ' 5009' 5409' 6146' ' 5474' ' ' 5159' 5045' 5446' ' ' ' 5005' ROP (ft/hr) 4,500' 4,000' Closely spaced (easy to drill) Vertical Fractures in East Texas consistent with ROP statistics GMXR has 3 out of top 5 ROP runs (Texas and Louisiana data) GMXR has Top 5 Bit Run Lengths Driver on Best of Class Drilling Costs Source: Bit Vendor, July 27, 2010: Publicly available bit records (1) Run length includes curve and lateral 8

9 Learning Curve is Bought: GMXR Acreage at Beginning of Full Exploitation Represents one of the most intensely studied areas of the Haynesville 35 vertical penetrations with Open Hole Logs with relatively uniform character 5 wells with whole core analysis Operational and production Infrastructure in place 9.85 IP Byrne Hazel 3 #1H Berry Oil Middle Bossier Completion Note: 420 Square Mile Study Area 9

10 Harrison and Panola ROCKS! Redefining IP: 90 Day Normalized Production Too many variables in the 24 hour IP story The 90 day normalized number represents combination of completion efficiency and 1st indicator of rock quality- best analogue to traditional vertical completions Major upgrade in these numbers in Caddo Parrish in 2009 reflected refined completion schemes in area thought to be similar to GMXR area Recognized parameter (1) as first indicator of SRV Note: Map as of 7/28/10; source IHS production and well data (1) SRV: Stimulated Reservoir Volume 10

11 GMXR Completion/Stimulation Strategy Delivering Better Results Longer Laterals, reduced perforation spacing plus more proppant equals better wells Increasing stage length to lower CAPEX, a benefit of 5 ½ casing Wells Number of Stages Number of Clusters / Stage Average Spacing 1 thru 2 8 to ' 3 thru 6 8 to ' 7 thru to ' 15 thru 20 9 to 12 9 to 11 40' 21 thru 23 (future wells) 11 to ' to 45' 11

12 1 st Generation Completion Scheme Delivered on Promise Harrison/Panola Long Lateral (Wells > 4500') 12 Month Cumulative Production 1,000,000 GMXR 5.4 bcfe 1 st year recovery 0.91 Cumulative MCF 100, bcfe Type Curve All Other Offsets GMXR Wells Note: All curves are representation of partial first month data on wells 5.4 BCF Type Curve 11 GMXR wells with 90 days or longer at June 30 and public domain data on 31 wells from other operators 10, Month Meeting and exceeding prior guidance on engineered 5.4 bcf type curve Offsets to under-performing wells seeing early time benefit from updated completion schemes Updated 7/29/10. Source: IHS Production Data on non-op wells 12

13 Big Reveal Longer Lateral Length Impact on Long Term Performance Oldest producing HB well with longer lateral shows material separation beyond reasonable change in rock character Well Lateral Length 5,075 2,305 Similar completion schemes 1000 offset Confirmed observations of numerous shale operators 2000 offset Enhanced production due to offset well completions Cumulative Note: Productivity Index: Daily Production divided by average of best 7 days of production 13

14 New Generation Completions: The Upgrade in Progress Analysis normalized to see non-lateral length performance enhancements Same unit or direct offset comparisons 100% confirmation to date on upgraded performance profiles Late 1 st quarter or 2 nd quarter completions 14

15 GMXR Move to Haynesville Story: Building Production with Fewer Rigs Total Net Proved Developed Producing Production and Forecast August Daily Data MCFED (Net) NET MCFED Net Rigs Drilling Oct-10 Sep-10 Aug-10 Jul-10 Jun-10 May-10 Apr-10 Mar-10 Feb-10 Jan-10 Dec-09 Nov-09 Oct-09 Sep-09 Aug-09 Jul-09 Jun-09 May-09 Apr-09 Mar-09 Feb-09 Jan-09 Dec-08 Nov-08 Oct-08 Sep-08 Aug-08 Jul-08 Jul-08 Jun-08 May-08 Apr-08 Mar-08 Feb-08 Jan-08 Dec-07 Note: August is estimate from daily data, updated through 8/14/10 15

16 Smartly Navigating a Challenging Business Environment CAPEX reduction driven by improved well results Two Rig Drilling Program Grows GMXR Production at a 3 Year CAGR of 34% Improved results allow production growth using 2 rigs Maintains adequate liquidity Available liquidity is $107 Million at June 30, 2010 $3 Million Cash at June 30, 2010 Undrawn borrowing base of $104 Million (October 2010 Next Re-Determination) Sub-Leased 2 rigs to manage CAPEX & Liquidity Operated JOA s with WI Partners Commodity Price Risk Management Protect 60-80% of estimated production based on market conditions Hedge to get through rig contracts that expire in 2012 & early

17 Lowering CAPEX, Increased Production, Greater Liquidity ($ ($ 000's) BCF $ $ 225,000 $ $ 200,000 $ $ 175,000 Cap Ex - Guidance Range Revenue - Guidance Midpoint Production - Guidance Midpoint $ $ 150, $ $ 125, $ $ 100, $ $ 75, $ $ 50, $ $ 25, $ $ Assumptions: Forward gas prices on July 29, 2010, Production per 5.4 EUR Curve, CWC of $8.2 Million

18 Driving Costs Out of New Wells $ 14,000 $ 13,000 $ 12,000 $ 11,000 $ 10,000 $ 9,000 $ 8,000 $ 7,000 $ 6,000 $ 5,000 $ 4,000 $ 3,000 $ 2,000 $ 1,000 $ 0 Completed Well Costs as Reported in 10Ks and 10Qs Audited by 3 rd Party Auditor Commodity Prices Drive Completed Well Costs Q Q Q Q Q Q Q Note 1: Grouped by quarter in which wells are completed Note 2 : NYMEX is the simple average of the first of month price for Henry Hub, per IFGMR NYMEX $ $ $ $ $ $ $ $ $

19 De-Mystifying the CAPEX Budget H/B CWC Costs ($8.2 MM) : 2 Rigs Since July 2010 $ 150,000 $ 131,200 $ 131,200 Shallow Oil Development $ 0,000 $ 10,000 $ 10,000 Sub-Total $ 155,000 $ 141,200 $ 141,200 Pipeline Infrastructure $ 2,000 $ 1,100 $ 1,100 Leasehold & Land $ 6,500 $ 16,363 $ 15,163 Capitalized G&A and Interest $ 10,600 $ 9,300 $ 10,500 Day Rate Fees on Subleased Rigs $ 3,560 $ 5,037 $ 5,037 Miscellaneous $ 3,000 $ 2,000 $ 2,000 Grand Total $ 175,660 $ 175,000 $ 175,000 19

20 Low Well Costs Generate Positive Returns in the Current Gas Price Environment Spud to TD Avg 31 Days for Q2 Spuds : Good Rock Drills Quickly 40.00% 35.00% $ 7.7 Million CWC $ 8.2 Million CWC $ 8.7 Million CWC 30.00% 25.00% 20.00% 15.00% 10.00% 5.00% Bentek Report $3.26 / MMBtu Haynesville Breakeven NYMEX Price (1) Morgan Stanley $3.50 / MMBTU Haynesville NYMEX Price for 10% IRR (1) IRR > 20%: Hedges are Gravy 0.00% -5.00% $ 3.00 Flat $ 3.26 Flat $ 3.50 Flat $ 4.00 Flat $ 5.00 Flat NYMEX Strip on Aug 5th $ 6.00 Flat NYMEX Strip + Hedges % (1) See Report in Appendix Assumptions: 10 Year IRRs, based on 4,500 Foot Lateral and Production per GMXR 5.4 EUR Curve, NYMEX on Aug 5 th. 20

21 GMXR : Positive Results in a Challenging Environment Contiguous position in Capital Core area Haynesville/Bossier Shale and Cotton Valley Sands; shallow oil Lower costs = more favorable economics Reduction in drilling days and costs Spud to TD Days down to CWC Approx $8.2 Million Completion improvement and higher production Allows company to move to 2 rig program Strong current liquidity position $107 Million currently at June 30, 2010 Ability to manage CAPEX Operated JOAs with working interest partners Drilling schedule matches service commitment Low-risk production and reserve growth allows for years of running room 3 yr PDP Growth 200% Proactively protecting revenues 7.2 Bcfe at $6.37 in 2H Bcfe at $6.14 in Bcfe at $6.08 in 2012 GMXR A Well Managed Company With Great Assets 21

22 Appendix

23 Operating Efficiencies Drive Improved Metrics 2 nd Quarter 2010 Natural gas and oil production volumes increased by 35% from 1Q10 to 4.3 billion cubic feet of natural gas equivalent (Bcfe) in the second quarter, a new Company record. Natural gas and oil production volumes increased 15% to 7.5 Bcfe in the first half of 2010 as compared to the first half of % lower total capital expenditures as compared to the first half of Both lease operating expenses of $0.52/MCFE and G&A of $1.44/MCFE are significantly lower than 1Q10 on a per MCFE basis. Oil & gas production of 4.3 BCFE Increased 35% from 3.2 BCFE in 1Q10 Oil & gas sales of $23.2 million Oil and gas sales up 20% from 1Q10 excluding non-cash ineffectiveness of cash flow hedges Lease Operating Expenses of $0.52/MCFE LOE is $2.2 million for 2Q10 vs. $3.1 million for 1Q10 General & Administrative Expenses of $1.44/MCFE Down $0.33/MCFE from Adjusted 1Q10 of $1.77/MCFE Non-GAAP Discretionary Cash Flow of $13.2 million Up 50% from $8.8 million in 1Q10 Adjusted non-gaap diluted earnings per share of $0.10 (1) Exceeded street guidance Average realized gas price down 11% to $5.57/Mcfe in 2Q10 vs. $6.23/Mcfe in 1Q10 Fighting a bad tape (1) Adjusted non-gaap diluted earnings per share excludes non-cash interest charges related to recent changes in accounting principles for convertible notes, share lending agreements, and fair value; unrealized losses on derivatives; change in deferred income tax valuation allowance for unrealized gains on hedges; and one-time resignation costs. 23

24 Hedging Ensures IRR of 25 30% With our hedges, we generate operating cash flow if NYMEX is $3.00. Completed well cost range of $1.92/MCF (1) are not included. Assumptions: 1. Gas prices as of July 29, Excludes potential processing upgrade 3. Bought Puts & Sold Puts impacts included $ 6.50 $ 6.00 $ 5.50 $ 5.00 $ 4.50 $ 4.00 $ 3.50 $ 3.00 $ 2.50 $ 2.00 $ 1.50 $ 1.00 $ 0.50 $ 0.00 Gas Price Options & Cash Costs Metrics Futures NYMEX + Hedges $ Hedges $3.00 NYMEX + Hedges Cash Operating Costs Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 (1) CWC $8.2 Million with Gross 5.4 EUR and NRI of 80% 24

25 Excellent Cash Flow Protection Due to Revenue Floors Strategy Actively manage to reduce price risk Maintain target of 60% - 80% of 3 year natural gas production protected Reduce price risk in borrowing base redetermination Does not consume borrowing base capacity Weighted Average Floor Price $6.37 $6.14 $6.08 Use deferred finance puts to match operating income and cash flow 25 Gas protection in future years includes: 2010: 13.3 Bcf at $6.37/Mmbtu 2011: 14.9 Bcf at $6.14/Mmbtu : 16.7 Bcf at $6.08/Mmbtu Sold Puts help offset cost of Bought Puts. As PUDs become PDP, GMXR will sell calls to recover 10 75% of Natural Gas Production Protected 52% of Natural Gas Production Protected 51% of Natural Gas Production Protected any puts spread cost & create 3-way collars 5 Cost of 2010 Bought Puts already fully recovered. Counterparties: BNP Paribas (members of our bank group) Protected Natural Gas Unprotected Natural Gas Crude Note: Weighted average floors do not include the effect of sold puts associated with three way collars or put spreads. In addition, sold calls have been excluded from volumes due to no downside protection provided by instruments. 25

26 Regional Rig Count 300 US Horizontal Rig Count US Horizontal Rig Count by Region Total Rig Count Current Total (All Regions) 923 Hz Rigs Q3 08 Total (All Regions) 655 Hz Rigs Haynesville Bossier Q3 09 Total (All Regions) 424 Hz Rigs Barnett Q2 07 Q3 07 Q4 07 Q1 08 Q2 08 Q3 08 Q4 08 Q1 09 Q2 09 Q3 09 Q4 09 Q1 10 Q2 10 Q3 10 Current 8/13/2010 US Horizontal Rig Count Regions include: Arkoma, Haynesville Bossier, Mid-Continent, Barnett, Northeast, Rockies. Other regions include: Alaska, Non-TX Gulf Coast, West TX/New Mexico, South TX, and Western Source: RigData, Tudor Pickering Holt, TPH Weekly Rig Roundup 08/16/

27 2010 Estimated Natural Gas Production Hedged Hedging in this Natural Gas Price Environment GMXR 77% Matters Bigger is not always better; GMXR is in great position compared to other producers, most of whom are substantially larger April 16,

28 Breakeven Levels Current 2010 NYMEX Strip = $4.79 on July 29,

29 Costs are Lower in Haynesville/Bossier Source: BENTEK Energy, LLC Presentation from June 3,

30 Attractive Well Economics Despite Current Gas Prices Single Well Illustrative Gross EUR $ 4.00 Flat + Hedges $ 5.00 Flat + Hedges $ 6.00 Flat + Hedges 10 Year Strip + Hedges 10 Year Strip Henry Hub Price : 10 Year Avg $ $ $ $ $ Less : Downstream Transport & Fuel ($ 0.550) ($ 0.574) ($ 0.599) ($ 0.592) ($ 0.592) Less : Basis ($ 0.020) ($ 0.025) ($ 0.030) ($ 0.029) ($ 0.029) Equals : Realized Price $ $ $ $ $ Less Operating Exp ($ 0.139) ($ 0.139) ($ 0.139) ($ 0.139) ($ 0.139) Less : Prod & Ad Valorem Taxes ($ 0.147) ($ 0.168) ($ 0.189) ($ 0.157) ($ 0.147) Equals : Gross Margin $ $ $ $ $ Completed Well Cost ($ 000's) $ 8,200 $ 8,200 $ 8,200 $ 8,200 $ 8,200 CWC ($ / Net MCF) $ 1.92 $ 1.92 $ 1.92 $ 1.92 $ Year IRR 19.03% 26.46% 33.04% 31.02% 23.82% 10 Year 10% ($ 000's) $ 1,226 $ 2,404 $ 3,541 $ 3,268 $ 2, Year NPV / Acre (Based on 80 Acre) $ 15,329 $ 30,044 $ 44,264 $ 40,850 $ 29,138 $ 4.00 Flat + Hedges $ 5.00 Flat + Hedges $ 6.00 Flat + Hedges 10 Year Strip + Hedges 10 Year Strip IRR at $7.8 Million Complete Well Cost 22.48% 30.26% 37.15% 34.97% 26.97% IRR at $8.0 Million Complete Well Cost 20.70% 28.30% 35.03% 32.93% 25.35% IRR at $8.2 Million Complete Well Cost 19.03% 26.46% 33.04% 31.02% 23.82% Note: NRI = 80.0%. Gas prices are as of July 29,

31 Analysis of Net Income Applicable to Common Shareholders Analysis of Net Income Applicable to Common Shareholders For the Three Months ended June 30, 2010 Earnings per Adjustments to Share Note Income/(Expense) Reconciliation Net loss applicable to common shareholders (GAAP) (2,977,000) $ (0.11) Add back non-operating charges: Non-cash Expenses Deferred income tax provision 1 2,369,000 $ 0.08 Ineffectiveness of cash flow hedges 2 1,786,000 $ 0.06 Mark to market on non-hedge derivatives 3 (107,000) $ - Amortization of fair value of share-lending agreement 4 172,000 $ 0.01 Amortization of deferred premiums on derivative instruments 5 223,000 $ 0.01 Amortization of 5.00% Convertible Bonds ,000 $ 0.03 Amortization of 4.50% Convertible Bonds ,000 $ 0.02 Net income applicable to common shareholders after non-operating charges (Non-GAAP) 2,745,000 $ 0.10 Weighted average diluted common shares for the three months ended June 30, ,181,587 Notes: 1 Increase in deferred tax valuation allowance due to reduction in deferred tax liabilities associated with a decrease in unrealized gains on the Company s hedges 2 Unrealized loss on cash flow hedges recognized in oil and gas sales which is the result of a difference in the fair value of the Company s hedges and the fair value of the projected cash flows of a hypothetical derivative based on the Company s expected sales point. 3 Unrealized gains from changes in market values for non-hedge derivative contracts. 4 Amortization of the value of the share-lending agreement which was required to be valued and recorded under new accounting guidance (FASB ASU ) beginning in 1Q Accretion expense related to the liability for deferred premiums on derivative instruments. 6 Accretion expense related to the Company s convertible bonds as required by accounting guidance (FASB ASC ). Amount is additional interest above the cash interest paid to the bond holders. 31

32 Non-GAAP Reconciliations Discretionary Cash Flow Discretionary cash flow represents cash provided by operating activities before changes in assets and liabilities less preferred dividends. Discretionary cash flow is presented because we believe it is a useful additional consideration along with net cash provided by operating activities under accounting principles generally accepted in the United States ("GAAP"). Discretionary cash flow is widely accepted as a financial indicator of a natural gas and oil company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies within the natural gas and oil exploration and production industry. Discretionary cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. The manner in which we calculate discretionary cash flow may differ from that utilized by other companies. Discretionary cash flow is reconciled to each of net income and net cash provided by operating activities as follows: Three Months Ended June 30, Six Months Ended June 30, (as adjusted) (1) (as adjusted) (1) (In thousands) Net Income (Loss) $ (216) $ (1,202) $ (132,218) $ 4,082 Non cash charges: Depreciation, depletion, and amortization 6,641 8,731 15,501 15,101 Impairment of oil and natural gas properties and property and equipment ,078 - Deferred income taxes 2,953 2, (3,389) Non cash compensation expense 1,236 1,110 2,282 3,545 Other 2,515 3,993 3,328 5,916 Preferred stock dividends (1,157) (1,157) (2,313) (2,313) Net income attributable to noncontrolling interest - (618) - (931) Non-GAAP discretionary cash flow $ 11,972 $ 13,226 $ 25,183 $ 22,011 Reconciliation of GAAP "Net cash provided by operating activities" to Non-GAAP "discretionary cash flow" Net cash provided by operating activities $ 12,737 $ 12,010 $ 20,578 $ 22,470 Adjustments: Changes in operating assets and liabilities 392 2,991 6,918 2,785 Preferred stock dividends (1,157) (1,157) (2,313) (2,313) Net income attributable to noncontrolling interest - (618) - (931) Non-GAAP discretionary cash flow $ 11,972 $ 13,226 $ 25,183 $ 22,011 (1) Adjusted for retrospective application of FASB ASU Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, now codified under FASB ASC Topic 470 Debt. 32

33 Non-GAAP Reconciliations EBITDA EBITDA represents earnings before interest, taxes, depletion, depreciation & amortization. EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors in the valuation, comparison and investment recommendations of companies. EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our revolving bank credit facility and is used in the financial covenants in our revolving bank credit facility and our senior secured note agreement. EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Reconciliation of GAAP "Net Income Three Months Ended June 30, Trailing Twelve Months Ended June 30, to Non-GAAP EBITDA (Dollars in Thousands) Net Income (Loss) $ (216) $ (1,202) $ (275,693) $ (44,789) Adjustments Depreciation, depletion, and amortization 6,641 8,731 32,790 30,606 Certain non-cash expenses (1) 2,565 2,049 4,064 6,868 Impairment and other writedowns ,728 50,072 Income taxes (2,953) 2,369 (33,046) (3,978) Interest expense 4,095 4,654 15,298 17,480 Loss on extinguishment of debt ,976 EBITDA $ 16,038 $ 16,601 $ 74,141 $ 61,235 (1) Amount above includes non-cash compensation, hedging and derivative activity and other expenses per the Company s credit agreement. 33

34 Forward-Looking Statements & Disclaimer This presentation includes certain statements that may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. They include statements regarding the Company s financing plans and objectives, drilling plans and objectives, related exploration and development costs, number and location of planned wells, reserve estimates and values, statements regarding the quality of the Company s properties and potential reserve and production levels. These statements are based on certain assumptions and analysis made by the Company in light of its experience and perception of historical trends, current conditions, expected future developments, and other factors it believes appropriate in the circumstances, including the assumption that there will be no material change in the operating environment for the Company s properties. Such statements are subject to a number of risks, including but not limited to commodity price risks, drilling and production risks, risks relating to the Company s ability to obtain financing for its planned activities, risks related to weather and unforeseen events, governmental regulatory risks and other risks, many of which are beyond the control of the Company. Reference is made to the Company s reports filed with the Securities and Exchange Commission for a more detailed disclosure of these risks. For all these reasons, actual results or developments may differ materially from those projected in the forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. This presentation includes certain non-gaap financial measures that are different from financial measures calculated in accordance with GAAP and may be different from similar measures used by other companies. For a reconciliation of these financial measures, see the appendix. 34