EnerCom s London Oil & Gas Conference. June 16, 2011

Transcription

1 EnerCom s London Oil & Gas Conference June 16, 2011

2 2 Forward Looking Statements Certain statements in this presentation regarding future expectations and plans for future activities may be regarded as forward-looking statements within the meaning of the Private Securities Litigation Reform Act of They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company s Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. We have also included in this report internally generated risked estimates of probable and possible reserves and related well locations. Estimates and potential recovery of non-proved reserves is inherently more speculative than estimates of proved reserves and there is no assurance that we will drill for, or recover, these reserves. Our ultimate recovery will be dependent upon numerous factors including actual geological conditions, the impact of future oil and gas pricing and exploration costs, and our future drilling decisions and budgets based upon our future evaluation of risk returns and the availability of capital. The United States Securities and Exchange Commission (SEC) has generally permitted oil and gas companies in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under economic and operating conditions existing at the date of the report. Accordingly, the SEC guidelines may prohibit us from including these alternatively priced proved reserve estimates, and estimates of probable and possible reserves, in filings with the SEC.

3 3 Market Data Headquartered: Houston, Texas Market Data as of June 8, 2011 Price $18.20 Per Share (NYSE:) Shares Of Common Stock Outstanding (Basic) 36.1 Million Market Capitalization $ 660 Million Enterprise Value $ 1,200 Million Enterprise Value / 3P Reserves (all objectives) (1) $0.19 per Mcfe Current Insider Ownership 10 million shares (approximately 28%) Current Public Float 27.0 Million Shares 52 Week Price Range $10.54 $23.80 Average Daily Volume (3 months) 0.8 Million Shares (1) See drilling inventory slide.

4 Capitalization Table ($ in 000s) As of March 30, 2011 Cash, Restricted Cash & Equivalents $84,300 Current Debt: Senior Credit Facility (1) $0 Convertible Senior Notes due 2026 (2) 29,100 Long-term Debt: Convertible Senior Notes due 2029 (3) 218,500 Senior Notes due ,000 Total Debt $522,600 Total Net Debt $438,300 Stockholders Equity $153,000 Total Capitalization $675,600 Total Liquidity $309,300 (1) Current borrowing base of $225 million (2) Put / Call: December, Converts at $65.94 / share, 3.25% Coupon. Current financials reflect $ MM, which is notional amount less current debt discount of $0.958 MM (3) Put / Call: October, Converts at $34.66 / share, 5.00% Coupon. Current financials reflect $ MM, which is notional amount less current debt discount of $ MM 4

5 5 Company Profile & Strategy Proved Reserves Growth (Bcfe) Growth oriented low cost E&P company focused on unconventional resource plays in Louisiana and Texas. Multiple objectives with long life reserves and repeatability Proven track record for consistently growing reserve base (5 yr CAGR of 23%) and production volumes (5 yr CAGR of 21%) guidance of 10 20% growth, with 12 17% oil 206 Large core acreage position with 279,000 gross (157,000 net) acres in Texas and Louisiana: Production Growth (Mmcfe/d) Approximately 55,000 gross (40,000 net) acres in the oil window of the Eagle Ford Shale in La Salle and Frio counties Texas Over 88,000 net acres prospective in the Haynesville Shale (43,000 net acres in the core of North Louisiana and Angelina River Trend of Shelby Trough) Growing oil volumes and cash margin expansion from oil directed activity % cash flow growth in 2011 driven by 400% growth in oil volumes 2011 budget of $235 million with 70% of capex allocated to oil exposure (62% Eagle Ford Shale Trend). Operate 90% of 2011 capital expenditures 3P resource potential of over 6 Tcfe, 50 year drilling inventory at current rate

6 6 FYE 2010 Reserve Overview Proved Reserves by Area 3P Reserves by Area Shelby Trough / ART 2% CV - Vertical 18% Cotton Valley Taylor Sand 30% Eagle Ford 1% North Louisiana Haynesville (Core) 50% Cotton Valley Taylor Sand 15% North Louisiana Haynesville (Core) 18% Eagle Ford 7% (1) CV - Vertical 1% East Texas Haynesville 24% Shelby Trough / ART 36% Total = 464 Bcfe Total = 6,373 Bcfe (1) Eagle Ford Shale reserves risked at 50%.

7 Drilling Program Area ($ MM) % of total 2011 Capex Allocation Eagle Ford Shale Trend $145 62% Haynesville Core (NW La.) $28 12% Haynesville Shelby Trough / ART $24 10% Cotton Valley Taylor Sand $23 10% Leasehold & Infrastructure $15 6% Cotton Valley Taylor Sand 10% Shelby Trough / ART 10% North Louisiana Haynesville (Core) 12% Leasehold 6% Eagle Ford 62% Total capital budget $ % Total = $235 mm

8 MCFE Per Day Stock Price 8 Production Volumes (Average Net Daily Mcfe) 120, ,000 $32.24 $ , ,000 $40 $35 81,600 $30 80,000 66,100 $24.94 $25 60,000 $20 40,000 43,800 $15.80 $18.20 $15 $10 20,000 $ E (1) $0 Average Oil Production Average Gas Production Average Stock Price (1) Mid-point of 2011 production guidance. Divested 12,000 Mcfe/d on 12/30/2010.

9 9 Hedging Summary Daily Natural Gas & Crude Oil Hedged Volumes (NYMEX) Natural Gas Volume (MBtu/d) Floor Ceiling Natural Gas Volume (MBtu/d) Floor Ceiling Collar #1 10,000 $6.00 $ ,000 $6.00 $7.40 Collar #2 30,000 $6.00 $ ,000 $6.00 $6.98 Total Volume & Average Price 40,000 $6.00 $ ,000 $6.00 $7.09 Volume (Bbls/d) Crude Oil (a) Swap Price Volume (Bbls/d) Crude Oil (a) Swap Price Swap #1 (a) 1,000 $ (a) Counterparty has option to extend crude oil swap agreement for two successive one year terms under same terms and conditions

10 10 Core Properties NORTH LOUISIANA HAYNESVILLE CORE Gross (Net) Acres: 33,000 (16,000) Proved Reserves (YE 10): 230 Bcfe Proved Reserves % PD: 34% Proved Reserves PV-10: $155mm Probable/Possible Reserves: 892 Bcfe Objective: Haynesville Shale (Core) EAST TEXAS COTTON VALLEY / HAYNESVILLE TEXAS TEXAS LOUISIANA Gross (Net) Acres: 129,200 (76,000) Proved Reserves (YE 10): 223 Bcfe Proved Reserves % PD: 46% Proved Reserves PV-10: $176mm Probable/Possible Reserves: 2,301 Bcfe Objectives: Cotton Valley / Haynesville Shale SOUTH TEXAS: Gross (Net) Acres: 55,000 (40,000) Proved Reserves (YE 10): 476 Mboe Proved Reserves % PD: 100% Proved Reserves PV-10: $15mm Risked Resource Potential: 63 Mmboe Objectives: Eagle Ford Shale & Buda Lime ANGELINA RIVER TREND (SHELBY TROUGH) HAYNESVILLE / BOSSIER Gross (Net) Acres : 48,500 (27,000) Proved Reserves (YE 10): 9 Bcfe Proved Reserves % PD: 100% Proved Reserves PV-10: $17mm Probable/Possible Reserves: 2,284 Bcfe Objective: Haynesville & Bossier Shale

11 11 Eagle Ford Shale Trend Overview Pay Zones OLMOS ANACACHO TEXAS AUSTIN CHALK TEXAS EAGLE FORD } feet BUDA

12 12 Eagle Ford Shale Trend Oil Window La Salle and Frio Counties, Texas 62% of capex budget allocated to EFS Trend, which will drive rapid oil volume growth Eight Eagle Ford Shale wells (Avg. 675 BOE/day) and two Buda Lime wells (Avg. 520 BOE/day) completed. Two rigs running to drill gross (16 20 net) wells Acquisition Summary: Approximately 55,000 gross (40,000 net) acres with average working interest of 72.5% (56% NRI). 6,000 foot laterals with 100-acre spacing yields 550 gross (400 net) locations Total consideration $1,650 per acre. $23 million of cash ($575 per acre), and $43 million ($1,075 per acre) of drilling carry (20.8% WI)

13 13 Eagle Ford Shale Trend Goodrich Acreage 55,000 gross (40,000 net) acres

14 HK Eagle Ford Shale Activity Petrohawk Mustang Ranch #1H IP: 350 BBL/day Petrohawk Mustang Ranch C #1H 1st 7-day Avg. (on pump): 570 BBL/day Chesapeake Traylor North #1H IP: 980 BOE/day Chesapeake Brownlow #1H IP: 1,220 BOE/day Chesapeake Lazy A Cotulla #1H IP: 980 BOE/day APC Blackbrush Pals Ranch #9H (Buda) IP: 530 BOE/day CHK El Paso TJ Pearsall #1H Completing Lancaster C 1H (Buda) IP: 512 BOE/day El Paso Frio Land & Cattle #1H Drilling Burns Ranch A 4H (EFS) IP: 600 BOE/day Drilling Plan: Gross EFS Wells Burns Ranch A 1H (EFS) IP: 1,010 BOE/day Pedro Morales 7H (EFS) IP: 460 BOE/day EP Burns Ranch A 15H (EFS) Completing (9,200 lateral) EP Burns Ranch A 3H, 19H & 20H Pad -9000Drilling / Completing Pan Am C 1H (EFS) IP: 250 BOE/day COG Burns Ranch A 5H (EFS) IP: 600 BOE/day Burns Ranch A 16H (EFS) Completing Burns Ranch A 9H (EFS) IP: 860 BOE/day Burns Ranch A 7H (EFS) IP: 940 BOE/day Pan Am B 1H (EFS) Formerly (Frances Shiner B-1) IP: 667 BOE/day Cabot O & G Patrick West #1H IP: 355 BOE/day Cabot O & G Shorp #1H (Loc) Cabot O & G Arminius Trust #1H & #2H IP: 925 & 550 BOE/day Cabot O & G Zella Cromwell Ranch #1H IP: 733 BOE/day Burns Ranch A 17H (EFS) Drilling EOG

15 Normalized Production (BOE/day) 15 Eagle Ford Shale Type Curve MBoe 475 MBoe 575 MBoe IP rate (Boe/d) ,025 IP rate (30 day avg. Boe/d) Pretax IRR ($90.00/ $5.00) 50% 75% 118% F&D ($/Boe) $28.44 $22.50 $18.55 PV10 ($MM) $4.4 $6.4 $9.4 Years to Payout PV 10 / 100 acre spacing $44,000 $64,000 $94, Production Month Low TC MBoe Mid TC MBoe High TC MBoe ANNUAL DECLINE RATES: Year 1 Year 2 Year 3 Year 4 Year 5 71% 41% 28% 22% 18%

16 IRR (%) 16 Eagle Ford Shale Well Economics IRR Sensitivity - $8.0 MM Capex 175% 150% 125% 100% 75% 50% 25% 0% $80.00 / $5.00 $90.00 / $5.00 $ / $5.00 Oil Price ($/BBL) / Gas Price ($/MMBtu) Low TC Mboe Base TC Mboe High TC Mboe Note: 20:1 natural gas to crude oil price conversion. NYMEX pricing shown. IRR calculation assumes NYMEX pricing less price differentials of $1.50/Mcf for natural gas and $4.50/Bbl for crude oil. Source: Goodrich Petroleum Corporation internal projections.

17 17 Haynesville Shale Overview Pay Zones 88,000 Net Acres TAYLOR SAND TEXAS } feet TEXAS LOUISIANA LOUISIANA

18 Haynesville / Bossier Shale Activity Harrison Co. Caddo Ph. Greenwood Waskom Field Bossier Ph. Core Haynesville horizontal Avg. EUR: 7.2 Bcfe CHK / wells Avg. EUR: 7.0 Bcfe Panola Co. N. LA. Core S. Henderson Field (H Nelson 1H) Haynesville Shale Horizontal IP: 12.4 MMcfe/day 11,500 psi, 14/64 choke (SW Henderson #1H) Haynesville Shale Horizontal IP: 21.0 MMcfe/day 10,250 psi, 22/64 choke A R T Rusk Co. Beckville / Minden Fields Nacogdoches Co. Angelina Co. Shelby Co. Shelby Trough San Augustine Co. Sabine Co. DeSoto Ph. Bethany-Longstreet Field EOG (Crane #1H) IP: 31.2 MMcfe/day 9,543 psi, 26/64 choke ECA (Blackstone A43 #1H) IP: 32.4 MMcfe/day 8,685 psi, 31/64 choke EOG (Pop-Pop GU #1) IP: 19.3 MMcfe/day EOG (Murray #1) IP: 30.0 MMcfe/day 8,700 psi, 25/64 choke EOG (Sutton GU #1) IP: 24.7 MMcfe/day EOG (Oglesbee GU #1) IP: 22.1 MMcfe/day Sabine Ph. Red River Ph. Acreage Natchitoches Ph. Haynesville Shale Penetrations Haynesville Rig Activity 18

19 Gas Rate (Mcfpd) Haynesville Type Curve North Louisiana Core ,000 10,000 Low (6.5 Bcfe) Base (7.5 Bcfe) High (8.5 Bcfe) IP rate (MMcf/d) IP rate (30 day avg. MMcf/d) Gross EUR (Bcf) Pretax IRR 20% 30% 49% F&D ($/Mcfe) $1.87 $1.62 $1.43 PV10 ($MM) $2.0 $3.6 $5.6 Breakeven Price ($/Mcf) (1) $3.75 $3.25 $2.75 Acreage Value (PV10 / spacing) $25,553 $45,053 $70, Bcfe 7.5 Bcfe 6.5 Bcfe 1, Year 1 85% Year 2 40% Year 3 26% Producing Month Note: Chart includes statistics for 6.5, 7.5, and 8.5 Bcfe horizontal Haynesville Shale wells. Pretax IRR, F&D and PV10 figures assume $5.00/Mcf NYMEX natural gas price (less $0.50/Mcf price differential), $8.5 MM drilling & completion cost, and 100% / 70% working interest and net revenue interest, respectively. Acreage values calculated using 80-acre spacing for horizontal wells. LOE estimated at $0.36/Mcf over life of well. Severance tax abatement for first two years then $0.165/Mcfe thereafter. (1) Natural gas price required to generate a pre-tax 10% rate of return. Year 4 20% ANNUAL DECLINE RATES: Year 5 16% Year 6 13% Year 7 11% Year 8 10% Year 9 9%

20 Average Daily Production (Mcfpd) Haynesville Well Performance North Louisiana Core Well Count 20 Bethany Longstreet, Greenwood-Waskom & Metcalf Fields Haynesville Horizontal Well Performance 11,000 Well Count 10,000 Hay Hz Well Group 9, Bcf Type Curve 8, ,000 6, ,000 4, , ,000 1, Normalized Production Month 0

21 21 Haynesville Shale Well Economics North Louisiana Core 150% Haynesville Well Economics: $8.5 MM well cost 125% 100% 75% 50% 25% 0% $4.00 $5.00 $6.00 $ Bcfe 7.5 Bcfe 8.5 Bcfe Note: NYMEX pricing shown. IRR calculation assumes NYMEX pricing less $0.50/Mcf price differential. Source: Goodrich Petroleum Corporation internal projections

22 Shelby Trough Haynesville Shale Activity Minden / Beckville Panola Co. Haynesville Shale Penetrations Acreage Haynesville Shale Permits Bethany Longstreet Haynesville Rig Activity South Henderson DeSoto Ph. Nacogdoches Co. (H Nelson 1H) Haynesville Shale Horizontal IP: 12.4 MMcfe/day 11,500 psi, 14/64 choke Rusk Co. ART Shelby Co. Shelby Trough Haynesville Shale EOG (Pop-Pop GU #1) IP: 19.3 MMcfe/day EOG (Murray #1) IP: 30.0 MMcfe/day 8,700 psi, 25/64 choke EOG (Sutton GU #1) IP: 24.7 MMcfe/day EOG (Oglesbee GU #1) IP: 22.1 MMcfe/day EOG (Crane #1H) IP: 31.2 MMcfe/day 9,543 psi, 26/64 choke Angelina Co. (SW Henderson #1H) Haynesville Shale Horizontal IP: 21.0 MMcfe/day 10,250 psi, 22/64 choke San Augustine Co. Sabine Co. (Lowery 1H) 2H 11 Spud ECA (Blackstone A43 #1H) IP: 32.4 MMcfe/day 8,685 psi, 31/64 choke 22

23 Shelby Trough Bossier Shale Activity 23 Minden / Beckville Panola Co. Haynesville Shale Penetrations Acreage Haynesville Shale Permits Bethany Longstreet Haynesville Rig Activity South Henderson Rusk Co. Nacogdoches Co. ART Shelby Co. Shelby Trough Bossier Shale DeSoto Ph. (R. Dean #2H) Bossier Shale Horizontal IP: 8.6 MMcfe/day EnCana Bossier Shale Horizontal IP: 23.6 MMcfe/day EnCana Bossier Shale Horizontal IP: 20.0 MMcfe/day Forest Oil Bossier Shale Horizontal IP: 17.0 MMcfe/day Common Resources Bossier Shale Horizontal IP: 12.0 MMcfe/day Cabot Bossier Shale Horizontal IP: 19.0 MMcfe/day Angelina Co. San Augustine Co. Sabine Co. EOG Bossier Shale Horizontal IP: 21.0 MMcfe/day

24 Mcfd 24 Angelina River Haynesville Type Curves (Restricted Choke Program) 12,000 10,000 8,000 6,000 4,000 2, Production Month Low TC Bcf Mid TC Bcf High TC Bcf ANNUAL DECLINE RATES: Year 1 60% Year 2 35% Year 3 24% Year 4 19% Year 5 15%

25 25 Angelina River Haynesville Well Economics 80% IRR Sensitivity - $12.0 MM Capex 60% 40% 20% 0% $4.00 $5.00 $6.00 $7.00 $ Bcf 10.0 Bcf 12.0 Bcf Note: NYMEX pricing shown. IRR calculation assumes NYMEX pricing less $0.50/Mcf price differential. Source: Goodrich Petroleum Corporation internal projections

26 26 Potential Impact of the Haynesville Shale Area Bethany Longstreet Greenwood Waskom / Metcalf Net Proved Reserves (Bcfe) Gross Probable & Possible Wells (1) Net Probable & Possible Wells (1) Per Well Gross Reserve Estimates: 4.5 Bcfe 6.5 Bcfe 8.5 Bcfe Potential Net Impact on Reserves (Bcfe) Total Core ,122 Angelina River Trend / Shelby Trough ,212 1,751 2,284 Total Core + ART ,810 2,615 3,406 N. Minden ,109 1,602 2,094 Beckville Total 251 1, ,381 4,885 6,373 (1) All gross and net probable & possible well locations calculated using 80-acre spacing on 88,000 net acres.

27 27 Cotton Valley (Taylor Sand) Beckville, Minden & South Henderson Fields / Rusk & Panola Counties, Texas Beckville & Minden: Shallow Deep Gross Acres: 45,400 acres 45,200 acres Net Acres: 40,200 acres 37,200 acres Proved Reserves (YE 10) Beckville: 129 Bcfe Minden: 55 Bcfe Probable/Possible Reserve Exposure (1) Beckville: 259 Bcfe (CVTS); 462 Bcfe (Haynesville) = 721 Bcfe Minden: 262 Bcfe (CVTS); 1,109 Bcfe (Haynesville) = 1,371 Bcfe Objectives: Cotton Valley & Haynesville Shale WI: 100% NR: 76% South Henderson: Shallow Deep Gross Acres: 9,800 acres 9,800 acres Net Acres: 8,100 acres 8,100 acres Producing Wells (Cotton Valley) BP (Kangerga #3H) IP: 6.0 MMcf/day AB Taylor #3H IP: 7.0 MMcf/day KF WH Carter A2 GU B2H IP: 4.0 MMcf/day Minden Beckville Acreage Cotton Valley (Taylor Sand) Horizontal Well D. Ross #3H IP: 1.0 MMcf/day Travis Crow GU 1H IP: 12.2 MMcfe/day (9.9 MMcf/d, 380 Bopd) Approx. EUR: 9.0 Bcfe Craig #3H IP: 11.1 MMcfe/day (9.0 MMcf/d, 360 Bopd) South Henderson Craig #4H Completing Pone G.U. #6H IP: 2.7 MMcf/day Mechanical Issues GT Waldrop #3H IP: 4.8 MMcf/day Cabot (Birdwell #11H) IP: 11.1 MMcf/day John Brooks #6H IP: 4.1 MMcf/day GT Waldrop #5H IP: 4.1 MMcf/day Crow-Holland #1H Drilling Cabot (TXU GU #11H) IP: 9.5 MMcf/day COG Cabot (Tufco #11H) IP: 8.6 MMcf/day Brachfield

28 Normalized Production (Mcf/day) 28 Cotton Valley Taylor Sand Type Curve 12,000 10,000 8,000 6,000 4,000 2, Production Month Low TC Bcfe Mid TC Bcfe High TC Bcfe ANNUAL DECLINE RATES: Year 1 67% Year 2 33% Year 3 22% Year 4 16% Year 5 13%

29 IRR (%) 29 Cotton Valley Taylor Sand Well Economics IRR Sensitivity - $7.5 MM Capex 200% 160% 120% 80% 40% 0% $80.00 / $4.00 $90.00 / $5.00 $ / $6.00 Oil Price ($/BBL) / Gas Price ($/MMBtu) Low TC Bcfe Base TC Bcfe High TC Bcfe Note: NYMEX pricing shown. IRR calculation assumes NYMEX pricing less price differentials of $0.50/Mcf for natural gas and $4.50/Bbl for crude oil. Source: Goodrich Petroleum Corporation internal projections.

30 30 TUSCALOOSA MARINE SHALE Emerging Shale Oil Play 72,000 Net Acres Leased Net Cost ~ $13 Million or $180/Acre Vintage Wells Define Oil Saturation and Rock Quality Average Depth 11,000-13,000 TVD Thickness High Quality Crude (38-40 Degrees API)

31 31 TMS Activity Map ECA & DNR Horizontal Re-Entry/Frac Prospective Area >100 TMS Thickness DVN Permitted DVN Drilling

32 32 Drilling Inventory 2011 Capital Program Total Inventory Area Gross # of Wells Net # of Wells 2011 Net Unrisked Capital Expenditures (MM) YE10 Proved Reserves (Bcfe) Gross Probable and Possible Wells (2) Net Probable and Possible Wells (2) Net Probable / Possible Reserve Exposure (Bcfe) (1) (3) Net Proved, Probable, Possible Reserve Exposure (Bcfe) (1) (3) Louisiana: Bethany Longstreet Haynesville Shale (3) $ Greenwood Waskom / Metcalf / Johnson Branch Haynesville Shale (3) $ Total Core Louisiana Haynesville Shale: $ ,122 Texas: Beckville CV Vertical Cotton Valley (Horizontal) Haynesville Shale (3) $0.0 $0.0 $ Minden CV Vertical Cotton Valley (Horizontal) Haynesville Shale (3) $0.0 $0.0 $ , ,115 South Henderson CV Vertical Cotton Valley (Horizontal) $0.0 $ Angelina River Trend / Shelby Trough Haynesville Shale / Bossier (3) $ ,284 2,293 Leasehold, Other $ Total Cotton Valley $ Eagle Ford Shale Trend $ Haynesville Shale / Bossier (3) $ , ,747 4,998 Total $ ,781 1,379 5,909 6,373 (1) Internal estimate. (2) Total inventory based on the following: 160-acre spacing on Cotton Valley (Taylor) Sand horizontal wells at Beckville, South Henderson and 50% of Minden. Haynesville Shale spacing at 80 acres. Eagle Ford Shale Trend acreage risked 50% and assumes 100-acre spacing and 6:1 conversion (432 Bcfe or 72 MMBoe). (3) Haynesville Shale economic reserves estimated at 6.7 Bcf at Bethany Longstreet and 6.9 Bcf at Greenwood-Waskom/Metcalf. Shelby Trough and Angelina River Trend estimated at 8.5 Bcf. Haynesville reserves of 4.5 Bcf at Beckville and Minden. No estimated reserves for Bossier Shale.

33 33 Estimated Sum of the Parts Asset Amount (1) Metric Valuation Range ($ in millions) Low High Low High Flowing Production Multiple 101,000 Mcfe/day $8,000 / Mcfe $12,000 / Mcfe $808 $1,212 Proved Undeveloped Reserves 272 Bcfe $1.50 / Mcfe $2.00 / Mcfe $408 $544 Shelby Trough Acreage 27,000 Net Acres $10,000 / Acre $12,000 / Acre $270 $324 Eagle Ford Shale Acreage 40,000 Net Acres $5,000 / Acre $10,000 / Acre $200 $400 (1) Pro Forma 12/31/2010. Production 1Q 11. (2) Basic share count of 36.0 million shares. Total $1,686 $2,480 Less: Net Debt $438 $438 Less: Preferred $113 $113 Total Valuation Range $1,135 $1,929 Valuation per Share (2) $32 $54

34 Why Invest in Goodrich Petroleum? Quality of reserves and inventory has never been this good Excellent exposure to Eagle Ford Shale oil play and core Haynesville Shale Attractive Margins: Approximately 45% of forecasted natural gas production in 2011 hedged with $6.00/MMBtu floor. 40% of oil production in 2011 hedged at $102.40/Bbl Per unit costs dropping due to cost reduction efforts and increasing percentage of volumes coming from the Haynesville Shale with significantly lower per unit LOE Cash flow per share expected to grow significantly in 2011 Superior liquidity position: Undrawn bank revolver borrowing base of $225 million and $83 million of cash and restricted cash provides over $300 million of liquidity Supportive shareholder base 28% inside ownership 34

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