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NYSE American: GDP Manag ageme ment Presen entati ation on Earnings Call 2Q20 This presentation has been prepared by Goodrich Petroleum Corporation (the Company) solely for information purposes and may include "forward-


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Manag ageme ment Presen entati ation

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Earnings Call – 2Q20 NYSE American: GDP

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This presentation has been prepared by Goodrich Petroleum Corporation (the “Company”) solely for information purposes and may include "forward- looking statements" within the meaning of the U.S. Private Litigation Securities Reform Act of 1995. The Company, its respective employees, directors,

  • fficers or advisors, does not make any representation or warranty as to the accuracy or completeness of the information contained in the presentation
  • materials. The Company shall have no liability for this presentation, information contained herein, or any representations (expressed or implied), whether

the communications were oral or written. The 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. These statements include, but are not limited to forward-looking statements about acquisitions, divestitures, trades, potential strategic alliances, the availability

  • f capital, the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the

Company's drilling program, production, hedging activities, capital expenditure levels and other guidance that may be included in this presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to the Company's financial performance and results, availability of sufficient cash flow to execute its business plan, prices and demand for oil, natural gas and natural gas liquids, the ability to replace reserves and efficiently develop current reserves, the ability to access the capital markets and finance operations, including capital expenditures, and other important factors that could cause actual results to differ materially from those projected as described in this presentation and the Company's reports filed with the Securities and Exchange

  • Commission. See "Risk Factors" in the Company's Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press

releases.

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 orotherwise.

August, 2020 2

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 Environmental:

  • Total Gas Flared: (% of Production)
  • Total GHG Emissions: (2019) (000 Mt) (EPA,LDEQ,MDEQ,TECQ Compliant)
  • Total Water Use (2019 - MMBls):
  • OSHA Compliant

 Social:

  • Number of Employees:
  • Percentage of Employees Unionized:
  • Percentage of Women in the Workforce:
  • Percentage of Minorities in the Workforce:

 Governance:

  • Size of Board:
  • Independent Directors:
  • Percentage of Independent Directors:
  • Board Duration:
  • Number of Board Meetings:
  • Board Meeting Attendance:

~0 27 5.1 48 0% 51% 20% 8 6 75% 1 Year 10 100%

August, 2020 3

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SLIDE 4

16+ Year Inventory of Core Locations (77% Operated)

Acreage is Held By Production and Fully De-Risked

>1.0 Tcf of Natural Gas Resource Potential in North Louisiana

Production: 138,000 Mcfe/day (2Q20)

Low Finding/Development and Lifting Cost Generating Strong Rates of Return

2.5 Bcf Per 1,000 Feet of Lateral

Low LOE (<$0.05/Mcf) and No Sev Tax on New Wells

2Q20Adjusted EBITDA of $15.4 Million. EBITDAMargin

  • f Approximately 56%*

Cash Opex: $1.01/Mcfe; Cash Opex Plus Cash Interest: $1.09/Mcfe

Low Leverage (Net Debt to EBITDA (TTM) – 1.45X)

Low Multiple (EV/EBITDA ~2.9X) and Top TierCapital Efficiency and Returns

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres (2Q20): 47,800(33,200) Proved Reserves (YE19 – SEC) 7Bcfe Objectives: Tuscaloosa Marine Shale

EAGLE E FORD SHALE: E:

Net Acres(2Q2 Q20): 4,300 Prov

  • ved

ed Reserves ves(YE19 19 – SE SEC) Objective ves: Eagle Ford Shale, Pearsall Shale & Buda Lime

HAYNESVILLE / BOSSIER SHALE ANGELINA RIVER TREND (“ART”)

Gross (Net) Acres (4Q18): 7,000(3,000) Proved Reserves (YE18 - SEC) Objective: Haynesville & Bossier Shale

HAYNESVILL ILLE E SHALE - CORE CORE

Gross (Net) Acres (2Q2 Q20): 42,000 (24,000) Proved Reserves (YE19- SEC) 510Bcfe Objective ve: Haynes nesvi villeShale

HAYNE NESV SVILLE PURE PLAY OPPO PORT RTUNIT ITY STRONG RONG HAYN YNESV SVILL ILLE RESUL ULTS TS COMPAN ANY Y RETURN RNS S AND BALANC ANCESHEET

Texas

4 August, 2020

Mississippi

* EBITDA Margin defined as EBITDA divided by Revenues adjusted for settled derivatives

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5 55 303 428 517 500 480 100 200 300 400 600 2015 2016 2017 2018*

SEC PV10 0 of $297 Mil illion

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2019 ETX TMS NLA - Haynesville Total

YE19 Prove

  • ved

d Res eser erves by Area ea (Bcfe fe,%) %) YE19 Prov

  • ved Res

eser erves by Categ egory

  • ry (Bcf

cfe, e,%) %) SEC Prov

  • ved

ed Rese eserv rves (Bc Bcfe fe) YE19 Prov

  • ved Res

eser erves by by Commod

  • dity

ty

August, 2020

PUD-372 (72%) PDP- 145 (28%)

HS – 511 (99%)

TMS-6 (1%) Natural Gas – 511 (99%) Oil - 6 (1%)

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6

Capi pitali liza zatio ion $ $ in in millio ions 6/30 30/20 Cash and Cash Equivalents $1.6 Senior Credit Facility 95.4 2L Senior Secured Notes 13.9 Total Debt $109. $109.3 Total Stockholders' Equity 74.4 Total Book Capit pitali liza zatio ion $183. $183.7 Credit Statist istic ics TTM 6/30/20 Adjusted EBITDA $74.1 Net Debt / Adjusted TTM EBITDA 1.45X Net Debt to Total Capitalization 59% Borrowing Base $120.0

August, 2020

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SLIDE 7

August, 2020

  • 2016

2017 2018 2019 2020* 140,000 120,000 100,000 80,000 60,000 40,000 20,000 160,000

Mcfe/Day /Day

Mcfe/Day

7

* Mid-Point of Guidance

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Peri riod

  • d

Natural Gas Volumes mes (Mcf/d) d) Swap Volumes mes (Mcf/d) d) Collar Volumes (Mcf/d) d) Swap Price Collar Prices 2Q20 70,000 47,000 23,000 $2.54 $2.40 - $2.62 3Q20 70,000 45,000 25,000 $2.56 $2.40 - $2.62 4Q20 70,000 45,000 25,000 $2.59 $2.40 - $2.62 1Q21 70,000 43,000 27,000 $2.64 $2.40 - $2.62 2Q21 70,000 70,000 $2.54 3Q21 70,000 70,000 $2.55 4Q21 70,000 70,000 $2.53 1Q22 70,000 70,000 $2.53 Peri riod

  • d

Oil Volume mes (Bo/ Bo/d) d) Swap Volumes mes (Bo/ Bo/d) d) Collar Volumes (Boe Boe/d) d) Swap Price 2Q20 225 225 $59.41 3Q20 210 210 $58.36 4Q20 200 200 $57.51 1Q21 200 200 $56.58

8 August, 2020

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Devel evelopme

  • pment

nt Schedu chedule 2020E 2020E Volu lume mes and Cost Gui uidanc nce 2020E 2020E

Activity Product uction

Gross (Net) Wells: 12 (5.0) Annual Net Production (Bcfe): 50 – 52

  • Avg. Net Lateral Length:

~8,500’

  • Avg. Daily Production – Midpoint (MMcfe/d):

140 Percentage Operated (Net): 72% Percent Natural Gas: 99%

Net Capi pital al Alloca cation Capi pital al Expe pend nditur ures (MM)

Bethany-Longstreet 91% Total Capital Expenditures $40 - $50 Thorn Lake 9%

Price Real alization Quarterl erly y Complet etion Cadenc dence

Henry Hub Differential $0.15 – $0.25 1Q20 5 Gross (1.8 Net)

Unit Cost (Per Mcfe) fe)

2Q20 1 Gross (0.8 Net) LOE: $0.20 - $0.25 3Q20 6 Gross (2.4 Net) Taxes: $0.04 – $0.07 4Q20 0 Gross (0.0 Net) Transportation: $0.30 - $0.40 Total 12 12 Gross (5.0 Net) G&A (Cash): $0.24 - $0.30

9 August, 2020

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GDP 24,000 ,000 Net Acres cres

Pay Zones

} 100 – 300 feet

August, 2020 10

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Haynesville - Core ▪ Total Gross/Net Acres: ~36,000/21,000 ▪ Average WI/NRI: ~59%/43% ▪ Acreage HBP: 100% ▪ 117 total producing wells (32 Operated) ▪ 1/1/20 – Inventory of 208 gross (91 net) potential locations on 880’ spacing providing 15+ year inventory ▪ Operator for Approximately 73% of the NLA core position ▪ CHK Joint Venture on most ofthe remaining 27% of NLA Core Acreage ▪ Recent Acreage Swaps Adding to Operated and Long Lateral Acreage ▪ Continuing to Look ForBolt-On Opportunities Shelby Trough/Angelina River Trend (ART) Haynesville and Bossier Shales: ▪ Total Gross/Net Acres: ~6,000/ 3,000 ▪ Average WI/NRI: ~40% / 30%

TOTAL HAYNESV SVILL ILLE E SHALE ~24,00 000 0 net Ac Ac ART 3,000 Net Ac Ac

NORTH TH LOUIS ISIA IANA CORE AREA 21,000 ,000 Net Ac Ac

August, 2020 11

Rig Source: Ulterra Bits

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Haynes ynesville ville Comple pletio tion Evo volu lution tion

  • 4,600‘ Laterals
  • 1,000 lbs/ft Proppant
  • Hybrid Fluid
  • 300-450’ Frac Intervals
  • Cluster Spacing 50-70’
  • 10,000’Laterals
  • 5,000+ lbs/ft Proppant
  • Slick Water & Hybrid Fluid
  • <100’ Frac Intervals
  • Cluster Spacing 20 - 50’
  • 4,600 - 10,000’Laterals
  • 3,000 – 4,000 lbs/ft Proppant
  • Slick Water Fluid
  • 100 - 150’ FracIntervals
  • Cluster Spacing 20 - 30’

Original Design T ested Current Design

Evolving completions maximize near-wellbore stimulation

12 August, 2020

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Hayn ynes esvill ille e – Rece cent t Indus dustry try Act ctivi ivity ty

(8) CHK ROTC 1 & 2 10,000’ Laterals IP: 72,000 Mcf/d (Combined) (11) GDP-Wurtsbaugh 25-24 #2&3 7,500’ Laterals IP: 25,000 Mcf/d IP: 29,000 Mcf/d (10) GDP Wurtsbaugh 26 4,600’ Lateral IP: 22,000 Mcf/d (9) GDP MSR - Hunt 5H-1 4,600’ Lateral IP: 17,000 Mcf/d (22) CHK Black 1H IP: 44,000 Mcf/d 10,000’ Lateral (21) Vine HA RA SU74;L L Golson 3 - 003-ALT IP: 18,800 Mcf/d 4,661’ Lateral

  • 5. CHK

GEPHUnit IP: 47,988 Mcf/d 15,000’ Lateral

  • 4. CRK

HUNTER 28-21HC 1&2 IP: 27,000 Mcf/d each 9,200’ Laterals (13) GDP Franks 25&24 #1 IP: 30,000 Mcf/d 9,600’ Lateral (12) GDP Wurtsbaugh 25-24 #1 8,800’ Lateral IP: 31,000 Mcf/d (19) GDP Cason-Dickson #1&2 IP: 31 MMcf/d, IP: 23 MMcf/d 8,000 & 3,000’ Laterals

  • 3. CRK

FLORSHEIM 9-16 HC #1&2 10,000’ Laterals IP: 26,500 Mcf/d IP: 27,600 Mcf/d (20) GDP Cason-Dickson 23&24 #3&4 IP: 62,000 Mcf/d 9,300’ Laterals (18) GDP Harris 14&23 #1 IP: 27,500 Mcf/d 6,100’ Lateral (14) GDP Loftus 27&22 #1 & 2 26,000 Mcfe/d 25,000 Mcfe/d 7,500’ Laterals (15) GDP Demmon 34H #1 22,500 Mcf/d 4,600’ Lateral (16) GDP Wurtsbaugh 35H #1 IP: 22,500 Mcf/d 4,600’ Lateral (7) CRK Cook 21-28 HC #2 10,000’ Lateral IP: 26,800 Mcf/d 3,798#/ft (6) CRK Cook 21-28 HC #1 10,000’ Lateral IP: 25,600 Mcf/d 3,803#/ft (2) CRK Nissen 28-21HC #2 10,000’ Lateral IP: 25,000 Mcf/d 3,801#/ft (1) CRK Nissen 28-21HC #1 10,000’ Lateral IP: 27,000 Mcf/d 3,796#/ft (17) Covey Park Tucker 31-6C H1 IP 18,045 Mcf/d 7,466’ Lateral

1 2 3 4 5 6 7 8 9 10-16 17 18-20 21 22

(22) GDP Melody Jones 20H-1 4,600’ Lateral IP: 22,000 Mcf/d

22

(23) CRK Gates 26-35 #1 & #2 10,000’ Laterals IP: 24,600 Mcf/d IP: 23,700 Mcf/d

23

13 August, 2020

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Assumptions Louisiana EUR 12.6 Bcf (2.7 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.020 Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation: $0.30 / Mcf Fixed Opex Fixed Opex: $3,290 / month Variable Opex $0.07 / Mcf Severance Tax Payout or 24 month tax holiday; thereafter $0.12 / Mcf Ad Val Tax $0.03 / Mcf Royalty Burden 27.0% D&C Capex $7.0 MM Facilities/Tubing Capex $0.381 MM, included in D&C Capex Spud to 1st Sale 60 Days PV10 (M$)

($2.75/Mcf Pricing)

$7,047 (Post Capex) Economic EUR’s vary depending on gas price assumptions. 100 1,000 10,000 100,000 20 40 80 100 120 Avg Daily Prod

  • ducti

tion

  • n(Mcfpd

pd) 60 Mont nths

4,600' ' Latera eral Type Curve

EUR (Mmcfe) 90% 100% 110% Capex ($M) 90% 100% 110% 2.00 25.0% 2.25 43.3% 2.50 65.0% 2.75 90.5% 3.00 120.0% 37.8% 61.3% 89.2% 122.1% 160.6% 52.6% 81.9% 117.1% 158.9% 208.4% 2.00 53.0% 2.25 82.8% 2.50 118.5% 2.75 161.0% 3.00 211.4% 37.8% 61.3% 89.2% 122.1% 160.6% 27.0% 45.9% 68.3% 94.6% 125.1% 4,600' Lateral

IRR Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex) IRRs Incoporate Early Time Outperformance

Ownership: WI 100%- NRI 73% Pricing: AFE: Flat Pricing Two well pad.

GasPrice GasPrice

August, 2020 17

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SLIDE 18

Assumptions Louisiana EUR 21 Bcf (2.8 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.020 Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation - $0.30 / Mcf Fixed Opex Fixed Opex: $3,290 / month Variable Opex $0.07 / Mcf Severance Tax Payout or 24 month tax holiday; thereafter $0.12 / Mcf Ad Val Tax $0.03 / Mcf Royalty Burden 27.0% D&C Capex $8.9 MM Facilities/Tubing Capex $0.408 MM, included in D&C Capex Spud to 1st Sale 60 Days

PV10 (M$)

($2.75/Mcf Pricing)

$13,453 (Post Capex) Economic EUR’s vary depending on gas price assumptions. 100 1,000 10,000 100,000 20 40 80 100 120 Avg Daily Prod

  • ducti

tion

  • n(Mcfpd

pd) 60 Mont nths

7,500' ' Latera eral Type Curve EUR (Mmcfe) 90% 100% 110% Capex ($M) 90% 100% 110% 2.00 47.8% 2.25 72.8% 2.50 102.6% 2.75 137.8% 3.00 179.0% 65.5% 97.5% 135.9% 181.9% 236.3% 85.7% 125.9% 174.8% 233.9% 304.9% 2.00 86.8% 2.25 127.7% 2.50 177.5% 2.75 237.7% 3.00 310.1% 65.5% 97.5% 135.9% 181.9% 236.3% 49.6% 75.0% 105.4% 141.3% 183.3% 7,500' Lateral

IRR Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex) IRRs Incoporate Early Time Outperformance

Ownership: WI 100% - NRI73% Pricing: AFE: Flat Pricing Two well pad.

GasPrice GasPrice

August, 2020 18

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Assumptions Louisiana EUR 25 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.020 Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation: $0.30 / Mcf Fixed Opex Fixed Opex: $3,290 / month Variable Opex $0.07 / Mcf Severance Tax Payout or 24 month taxholiday; thereafter $0.12 / Mcf Ad Val Tax $0.03 / Mcf Royalty Burden 27.0% D&C Capex $10.7 MM Facilities/Tubing Capex $0.485 MM, included in D&C Capex Spud to 1st Sale 60 Days PV10 (M$)

($2.75/Mcf Pricing)

$15,226 (Post Capex) 100 1,000 10,000 100,000 20 40 80 100 120 Avg Daily Prod

  • ducti

tion

  • n(Mcfpd

pd) 60 Mont nths

10,000' ' Latera eral TypeCurve

EUR (Mmcfe) 90% 100% 110% Capex ($M) 90% 100% 110% 2.00 27.7% 39.9% 53.9% 2.00 54.5% 39.9% 29.4% 2.25 47.8% 65.7% 86.1% 2.25 87.3% 65.7% 50.1% 2.50 72.3% 97.1% 125.6% 2.50 127.4% 97.1% 75.4% 2.75 101.6% 134.7% 173.2% 2.75 175.8% 134.7% 105.5% 3.00 135.8% 179.2% 179.2% 3.00 233.5% 179.2% 140.9%

Ownership: WI 100% - NRI73% Pricing: Flat Pricing AFE: Two well pad.

10,000' Lateral

IRR Sensitivity Analysis (IRR Sensitivity to EURs andCapex) IRRs Incoporate Early Time Outperformance

GasPrice GasPrice Economic EUR’s vary depending on gas price assumptions

August, 2020 19

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 Cash Flow Generation With Strong Balance Sheet and Low

Trading Multiple Creates an Attractive Entry Point for the Stock

 16+ Year Inventory on Core Haynesville Position Provides 1+

Tcf of Resource Potential on Acreage Held By Production

 A Continued Reduction in Per Unit Cash Costs Driven By High

Volume Low Lifting Costs Wells

 Improving Natural Gas Price Environment Setting Company Up

for Top Tier Free Cash Flow Potential for 2021

August, 2020 20