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Copyright 2015 Goodrich Petroleum Corporation 1

Earnings Call Presentation

May 2015

Copyright 2015 Goodrich Petroleum Corporation 2 2

FORWARD LOOKING STATEMENTS

Headquartered: Houston, Texas

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 1995. 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.

Proved reserves described in this presentation meet definitions and guidelines of the U.S. Securities

and Exchange Commission (SEC) for such reserves. We have also included in this presentation

internally generated estimates of non-proved or 3P (proved+probable+possible) reserves, resources

and well locations, or potential non-proved or 3P reserves, resources and well locations. These

estimates are inherently more speculative than our estimates of proved reserves and there is no

assurance that we will drill these wells or recover these hydrocarbon quantities. Our probable and

possible resource potential included herein is based on internal estimates and 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 SEC has generally permitted oil and gas companies in their filings with the SEC to disclose only

reserves meeting SEC definitions and guidelines and only separately by reserve category.

( NYSE : GDP )


$1 $19

$158

$332 $373

$583

$147

$343

$294 $27

$99

$68

2009 2010 2011 2012 2013 2014

Oil & NGL Gas

COMPANY PROFILE

■ Large core acreage position with 562,500 gross (392,930 net) acres in Texas, Louisiana and Mississippi, with over 7.1 Tcfe of resource potential:

■ 325,000+ net acres in the Tuscaloosa Marine Shale (150,000 in delineated core)

■ Approximately 30,000 net acres in the oil window of the Eagle Ford Shale in La Salle and Frio counties Texas

■ 36,000 net acres prospective in the Haynesville Shale trend (14,300 net acres in the core of North Louisiana and 21,700 net acres in the Angelina River Trend of Shelby Trough)

$148

$362

$452

$359

$472

$651

1 At SEC pricing:

YE09: Gas $3.87/MMbtu, Oil $57.65/Bbl; YE10: Gas $4.38/MMbtu, Oil $75.96/Bbl; YE11: Gas $4.12/MMbtu, Oil $92.71/Bbl; YE12: Gas $2.78/MMbtu, Oil $91.21/Bbl

YE13: Gas $3.67/MMbtu, Oil $96.94/Bbl; YE14: Gas $4.35/MMbtu, Oil $94.99/Bbl

Proved Reserves PV10 Growth ($MM)1

$7 $82

$393

$148

$347 $294

$30 $99

$68

$15 $158

$322

$291

$190

2009 2010 2011 2012 2013 2014

TMS Haynesville Shale Eagle Ford Shale

$148

$362

$452

$359

$472

$651


CORE PROPERTIES

Acreage: 562,550 gross (392,900 net)

(1) Internal estimates as of 12/31/14. Actual reserves dependent upon pricing and cost assumptions. See assumptions on the Drilling Inventory slide.

Texas

Mississippi

Louisiana

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres: 459,000 (327,000)

Proved Reserves (YE’14): 19 MMBoe

Risked Resource Potential (1): 693 MMBoe

Objectives: Tuscaloosa Marine Shale

EAGLE FORD SHALE:

Gross (Net) Acres: 44,400 (30,000)

Proved Reserves (YE’14): 10 MMBoe

Risked Resource Potential (1): 75 MMBoe

Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime

HAYNESVILLE / BOSSIER SHALE

ANGELINA RIVER TREND (“ART”)

Gross (Net) Acres : 28,000 (21,700)

Proved Reserves (YE'14): 11 Bcfe

Probable/Possible Potential (1): 1,656 Bcfe

Objective: Haynesville & Bossier Shale

HAYNESVILLE SHALE - CORE

Gross (Net) Acres: 31,150 (14,300)

Proved Reserves (YE'14): 83 Bcfe

Probable/Possible Potential (1): 566 Bcfe

Objective: Haynesville Shale (Core)


TUSCALOOSA MARINE SHALE

■ Emerging shale oil play covering approximately 2.5 million acres

■ Low cost basis on 300,000+ net acres

■ Vintage wells define oil saturation and rock quality

■ Depths: 10,500’ – 14,500’ TVD

■ Thickness 100’ – 250’

■ High quality crude (38 – 45 deg. API)

■ 92 – 98% oil, High BTU gas


TUSCALOOSA MARINE SHALE

Legend

TMS Oil Shows (Vertical)

Drilled/Completed TMS Wells

Permitted TMS Wells

GDP Legacy Acreage

TMS Acquisition Acreage

Wells Drilling

Wells Completing

9

11

6

10

5

GDP Kent 41H-1

(Completing)

12

4

14

GDP T. Lewis 7-38H-1

(Completing)

8

15 GDP

B-Nez 43H-2 (Completing)

GDP Painter 5H1 (Completing)

GDP Kinchen 58H-1 (Completing)

16

GDP B-Nez 43H-1 (Completing)

GDP W Alford 10H1 (Completing)

1. Non-Operated (0% WI), IP: 1,915 Boe/d (24-hr), ~7,000 ft, 19 stgs

2. Non-Operated (0% WI), IP: 1,600 Boe/d (24-hr), ~9,800 ft, 29 stgs

3. ECA Mathis 29-17H-1 (0% WI), IP: 1,570 Boe/d (24-hr), ~9,100 ft, 26 stgs

4. ECA Lyons 35H-2 (0% WI), IP: 1,535 Boe/d (24-hr), ~5,200 ft, 19 stgs

5. ECA Lewis 7-18H-1 (17% WI), IP: 1,500 Boe/d (24-hr), ~8,100 ft, 29 stgs

6. GDP C.H. Lewis 30-19H-1 (81.4% WI), IP: 1,450 Boe/d (24-hr), ~6,600 ft, 26 stgs

7. GDP Verberne 5H-1 (66.7% WI), IP: 1,375 Boe/d (24-hr), ~6,600 ft, 21 stgs

8. GDP Spears 31-6H-1 (77.0% WI), IP: 1,360 Boe/d (24-hr), ~6,200 ft, 23 stgs

9. GDP Crosby 12H-1 (50% WI), IP: 1,300 Boe/d (24-hr), ~6,700 ft, 24 stgs

10. ECA Mathis 29-32H-1 (0% WI), IP: 1,300 Boe/d (24-hr), ~6,400 ft, 17 stgs

11. GDP Blades 33H-1 (66.7% WI), IP: 1,270 Boe/d (24-hr), ~5,100 ft, 20 stgs

12. GDP Denkmann 33-28H-2 (75% WI), IP: 1,250 Boe/d (24-hr), ~6,000 ft, 22 stgs

13. GDP Williams 46H-1 (68.2% WI), IP: 1,240 Boe/d (24-hr), ~6,400 ft, 20 stgs

14. GDP CMR 24-13H-1 (97% WI), IP: 1,215 Boe/d (24-hr), ~6,500 ft, 24 stgs

15. GDP CMR 31-22H-1 (90% WI), IP: 1,140 Boe/d (24-hr), ~6,700 ft, 24 stgs

16. SN St. Davis 1H (0% WI), IP: 1,140 Boe/d (24-hr.), ~5,600 ft, 25 stgs

1

3

7 13

2


Well Control & Structure Map 500’ Contour

TMS OPTIMIZED WELLS (30)

■ Red well markings represent approximately 1,350 vertical penetrations through the TMS

■ 90% of acreage at -14,000’ TVD or shallower, where most wells have been completed to date

■ Green dots represent GDP wells waiting on completion

■ Nunnery is the most up-dip (-10,825’ Subsea TVD; 17,550’ MD; 5,450’ horizontal)

■ SLC is the deepest optimally completed well drilled to date (-13,809’ SS TVD; 21,450’ MD; 7,000’ horizontal)

■ Active Rigs

GDP SLC, Inc.

81H-1

WILKINSON

AMITE

PIKE WALTHALL

WEST

FELICIANA EAST

FELICIANA

ST.

HELENA TANGIPAHOA

WASHINGTON

Area #4

GDP Crosby 12H-1

GDP C.H. Lewis 30-19H-1

GDP Nunnery 12-1H-1

GDP Blades 33H-1

GDP Beech Grove

94H-1

GDP Denkmann 33-28H-2

GDP CMR Foster Creek

31-22H-1

GDP Spears 31-6H-1


24-13H-1

GDP CMR

8-5H-1

GDP Verberne

5H-1

GDP Williams

46H-1

Currently delineated core (GDP: 150,000 net acres)


8H -2

Area #1 Area #2

Area #3


OPTIMIZED TMS WELLS (30)

Optimized Criteria:

■ Lower TMS landing target

■ 5,000’+ lateral length

■ >450,000 lbs. proppant per stage (>1,500 lbs. per foot)

■ Optimum hybrid slick water frac design

Optimized TMS Wells: ■ GDP Crosby 12 H1

■ GDP CMR 8-5 H1

■ GDP Blades 33 H1

■ GDP CH Lewis 30 H1

■ GDP Spears 31-6 H1

■ GDP Nunnery 12 H1

■ GDP Beech Grove 94

■ GDP SLC 81 H1

■ GDP Denkmann H2

■ GDP CMR FC 31-22 H1

■ GDP CMR FC 24-13 H1

■ GDP Verberne 5 H1

■ GDP Williams 46 H1

■ GDP CMR FC 8 H2

■ ECA Mathis 29-32 H1

■ ECA Lewis 7-18 H1

■ Non-Operated #1

■ Non-Operated #2

■ Non-Operated #3

■ Non-Operated #4

■ Non-Operated #5

■ Non-Operated #6

■ Non-Operated #7

■ Non-Operated #8

■ Non-Operated #9

■ Non-Operated #10






OPTIMIZED WELL PERFORMANCE

Area #1 (Core)



Area #2 (Core)



Area #3 (Core)



Area #4 (Non-Core)


Optimized Wells (30)

TMS TYPE CURVE (600 & 800 MBOE)


30 Wells

TMS OPTIMIZED COMPOSITE WELL DECLINE CURVE

Note: with +$5/bbl uplift

Gross Reserves 700 Mboe 600 Mboe

Net Reserves 578 Mboe 496 Mboe

F&D Cost ($/BOE) $17.30 $20.16

IRR 32% 22%

NPV ($MM) $5.38 $3.31

Core locations 1,500 - 2,000

82.6% NRI, $10.0MM, $65/bbl

GDP Type Curves

Gross Reserves 700 Mboe 600 Mboe

Net Reserves 578 Mboe 496 Mboe

F&D Cost ($/BOE) $17.30 $20.16

IRR 48% 33%

NPV ($MM) $7.82 $5.48

Core locations

GDP Type Curves

1,500 - 2,000

82.6% NRI, $10.0MM, $75/bbl


TMS AVERAGE DRILL TIME BY QUARTER


COST BREAKDOWN

(USD in millions)

2014

6,000’ Single-Well Pad

2015

5,000’ Single-Well Pad

(High-Proppant)

2015

5,000’ Two-Well Pad

(High-Proppant)

Drilling 40 Days 24 Days 24 Days

Intangible $4.7 $3.6 $3.2

Tangible 0.9 0.8 0.8

Run Casing 1.4 1.2 1.2

Total Drill $7.0 $5.6 $5.2

Completion

Intangible $5.7 $4.1 $3.8

Tangible 0.3 0.3 0.3

Total Completion $6.0 $4.4 $4.1

Well Total $13.0 $10.0 $9.3


Well Cost: $10.0 MM

Lateral Length: 6,000’

Frac Stages: 20

Royalty Burden: 17.4%

Severance Tax: 0% until Payout

12.5% after Payout

Reserves (Gross): 700 MBOE

Reserves (Net): 578 MBOE

F&D Cost ($/BOE): $17.30

IRR: 48%

NPV ($MM): $7.82 MM

TMS WELL ECONOMIC SUMMARY

Note: Economics assumes $75/Bbl NYMEX crude oil pricing.

■ Current single-well pad AFE is approximately $10.0 MM.

■ Additional cost savings from two-well pad drilling: rig MOB, location, mud system, zipper / simultaneous fracs, and sharing of production equipment and facilities.


TMS WELL ECONOMICS

Note: Internally estimated type curve. IRR assumes an 82.6% NRI, 2-year tax abatement and a premium to NYMEX of $5/Bbl. Breakeven

economics assumes WTI oil price to generate a 10% internal rate of return.

Breakeven

Economics

$10 MM

EU

R 600 MBoe $50/Bbl

700 MBoe $44/Bbl

800 MBoe $37/Bbl

$10.0 MM Capex


NYSE: GDP

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