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NYSE American: GDP Manage agemen ment Presentat entation ion May, 2020 This presentation has been prepared by Goodrich Petroleum Corporation (the Company) solely for information purposes and may include "forward- looking

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Manage agemen ment Presentat entation ion

May, 2020 NYSE American: GDP

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SLIDE 2

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 of 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

  • ther 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 or otherwise.

May, 2020 2

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SLIDE 3

 Environmental:

  • Total Gas Flared: (% of Production)

~0

  • Total GHG Emissions: (2019) (000 Mt) (EPA,LDEQ,MDEQ,TECQ Compliant) 27
  • Total Water Use (2019 - MMBls):

5.1

  • OSHA Compliant

 Social:

  • Number of Employees:

51

  • Percentage of Employees Unionized:

0%

  • Percentage of Women in the Workforce:

51%

  • Percentage of Minorities in the Workforce:

20%

 Governance:

  • Size of Board:

8

  • Independent Directors:

6

  • Percentage of Independent Directors:

75%

  • Board Duration:

1 Year

  • Number of Board Meetings:

10

  • Board Meeting Attendance:

100%

May, 2020 3

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SLIDE 4

18 Year Inventory of Core Locations (77% Operated) at Current Pace

Acreage is Held By Production and Fully De-Risked

>1.0 Tcf of Natural Gas Resource Potential in North Louisiana

Production: 137,000 Mcfe/day (1Q20), 32% YOY Growth

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

2.5 Bcf Per 1,000 Feet of Lateral

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

Return on Capital Employed (“ROCE”) – 12.5% (TTM EBIT/(Assets – Current Liabilities)

1Q20 Adjusted EBITDA of $16.6 Million. EBITDA Margin

  • f Approximately 58%*

Top Tier Capital Efficiency

Low Leverage (Net Debt to EBITDA (TTM) – 1.3X)

Low Multiple (EV/EBITDA ~ 2.50X)

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres (1Q20): 47,700 (33,200) Proved Reserves (YE19 – SEC) 7 Bcfe Objectives: Tuscaloosa Marine Shale

EAGLE E FORD SHALE: E:

Net Acres (1Q2 Q20): 4,300 Proved Reserve ves (YE19 – SEC) 0 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

HAYNES ESVIL ILLE LE SHALE - CORE CORE

Gross (Net) Acres (1Q2 Q20): 40,300 (22,300) Proved Reserve ves (YE19 - SEC) 510 Bcfe Objective ve: Haynes nesvi ville Shale

HAYN YNESV SVILLE PURE PLAY AY OPPO PORTU RTUNITY ITY STRONG RONG HAYN YNESV SVILL ILLE RESUL ULTS TS COMP MPANY ANY RETURN URNS S AND BALANC ANCE SHE HEET T

Texas Mississippi

May, 2020 4

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

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SLIDE 5

5 55 303 428 480 517 100 200 300 400 500 600 2015 2016 2017 2018* 2019 ETX TMS NLA - Haynesville Total

SEC PV10 10 of $297 7 Mill llion

  • n

YE19 9 Prov

  • ved Rese

serv rves es by Area rea (Bcfe Bcfe, , %) YE19 9 Prov

  • ved Rese

serv rves es by Categor tegory y (Bcfe Bcfe, , %) %) SEC Prove

  • ved

d Reserv eserves es (Bcfe cfe) YE19 9 Prove

  • ved

d Rese serv rves es by Commod

  • dity

ity

May, 2020

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

HS – 511 (99%)

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

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SLIDE 6

6

Net Debt to EBITDA of 1.3X based

  • n TTM EBITDA of $80.3 million

Target of Less than 1.5X

Capit italizati ization

  • n

$ i in millio ions 3/31/20 Cash and Cash Equivalents $1.3 Senior Credit Facility (Borrowing Base) 92.9 2L Senior Secured Notes 13.4 Total Debt $106.3 Total Stockholders' Equity 88.5 Total Book Capit itali liza zatio ion $194.8 Credit Statis istic ics TTM 3/31/20 Adjusted EBITDA $80.3 Net Debt / Adjusted TTM EBITDA 1.3x Net Debt to Total Capitalization 53.9% Borrowing Base $120.0

May, 2020

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SLIDE 7

May, 2020

  • 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000 2016 2017 2018 2019 2020*

Mcfe/Day /Day

Mcfe/Day

7

* Mid-Point of Guidance

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SLIDE 8

8

Period

  • d

Natural Gas Volumes mes (Mcf/d) d) Swap Volume mes (Mcf/d) d) Collar Volume mes (Mcf/d) d) Swap Price Collar Prices 1Q20 70,000 70,000 $2.87 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 50,000 50,000 $2.47 3Q21 50,000 50,000 $2.48 4Q21 50,000 50,000 $2.45 1Q22 50,000 50,000 $2.45 Period

  • d

Oil Volumes (Bo/

  • /d)

d) Swap Volume mes (Bo/

  • /d)

d) Collar Volume mes (Boe/

  • e/d)

d) Swap Price 1Q20 250 250 $60.44 2Q20 225 225 $59.41 3Q20 210 210 $58.36 4Q20 200 200 $57.51 1Q21 200 200 $56.58

May, 2020

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SLIDE 9

9

Volu lume mes and Cost st Gui uidanc nce 2020E 0E

Product uction

Annual Net Production (Bcfe): 50 – 52

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

140 Percent Natural Gas: 99%

Capi pital al Expendi penditures ures (MM)

Total Capital Expenditures $40 - $50

Price e Real alization ation

Henry Hub Differential $0.15 – $0.25

Unit Cost st (Per er Mcfe) fe)

LOE: $0.20 - $0.25 Taxes: $0.04 – $0.07 Transportation: $0.30 - $0.40 G&A (Cash): $0.24 - $0.30

Devel evelop

  • pme

ment nt Sched hedul ule 2020E 0E

Activi vity

Gross (Net) Wells: 12 (5.0)

  • Avg. Net Lateral Length:

~8,500’ Percentage Operated (Net): 72%

Net Capi pital al Allocat cation

Bethany-Longstreet 91% Thorn Lake 9%

Quarterly y Comp mpletion n Cade dence ce

1Q20 5 Gross (1.8 Net) 2Q20 1 Gross (0.8 Net) 3Q20 6 Gross (2.4 Net) 4Q20 0 Gross (0.0 Net) Total 12 G Gross (5.0 Net)

May, 2020

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SLIDE 10
  • 10
  • 5

5 10 15 20 25 GDP

May, 2020

Peer Group Includes: AMPY,APA,AR,AXAS,BCEI,BRY,CDEV,CHAP,CHK,CLR,COG,CPE,CRC,CRK,CXO,DNR,DVN,EOG, EQT,ESTE,FANG,GDP,GPOR,HPR,KOS,LONE,LPI,MCF,MGY,MR,MTDR,MUR,NOG,NBL,OAS,OVV, PDCE,PE,PVAC,PXD,QEP,REI,RRC,SBOW,SD,SM,SWN,TALO,WLL,WPX,XEC,XOG Source: : Bloom

  • mbe

berg, , Compa pany (4Q19 Finan ancial als for Peers, , 1Q20 Finan ancial als s for GDP) P)

10

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1 2 3 4 5 6 GDP GDP

May, 2020

Peer Group Includes: AMPY,APA,AR,AXAS,BCEI,BRY,CDEV,CHAP,CHK,CLR,COG,CPE,CRC,CRK,CXO,DNR,DVN,EOG, EQT,ESTE,FANG,GDP,GPOR,HPR,KOS,LONE,LPI,MCF,MGY,MR,MTDR,MUR,NOG,NBL,OAS,OVV, PDCE,PE,PVAC,PXD,QEP,REI,RRC,SBOW,SD,SM,SWN,TALO,WLL,WPX,XEC,XOG Source: : Bloom

  • mbe

berg, , Compa pany (4Q19 Finan ancial als for Peers, s, 1Q20 Finan ancial als for GDP) P)

11

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SLIDE 12

1 2 3 4 5 6 7 8 9 GDP GDP

May, 2020

Peer Group Includes: AMPY,APA,AR,AXAS,BCEI,BRY,CDEV,CHAP,CHK,CLR,COG,CPE,CRC,CRK,CXO,DNR,DVN,EOG, EQT,ESTE,FANG,GDP,GPOR,HPR,KOS,LONE,LPI,MCF,MGY,MR,MTDR,MUR,NOG,NBL,OAS,OVV, PDCE,PE,PVAC,PXD,QEP,REI,RRC,SBOW,SD,SM,SWN,TALO,WLL,WPX,XEC,XOG Source: : Bloom

  • mbe

berg, , Compa pany (4Q19 Finan ancial als for Peers, , 1Q20 Finan ancial als s for GDP) P)

12

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SLIDE 13

GDP P 22,300 ,300 Net t Acres cres

Pay Zones

} 100 – 300 feet

May, 2020 13

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May, 2020 14

Haynesville - Core

  • Total Gross/Net Acres:

~34,300/19,300

  • 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 of the

remaining 27% of NLA Core Acreage

  • Recent Acreage Swaps Adding to

Operated and Long Lateral Acreage

  • Continuing to Look For Bolt-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 L HAYNESVI SVILL LLE E SHALE ~22,30 300 0 net Ac ART 3,000 0 Net Ac Ac

NORTH TH LOUIS ISIA IANA CORE AREA 19,300 ,300 Net t Ac

Rig Source: Ulterra Bits

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SLIDE 15

Haynesvil nesville le Comple pletio tion n Evoluti

  • lution
  • n

May, 2020 15 15

  • 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’ Frac Intervals
  • Cluster Spacing 20 - 30’

Original Design Tested Current Design

Evolving completions maximize near-wellbore stimulation

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SLIDE 16

Haynesvil nesville le – Re Rece cent t Indus dustry try Act ctivi ivity ty

May, 2020 16

(8) CHK ROTC 1 & 2 10,000’ Laterals IP: 72,000 Mcf/d 19 Bcf in 19 months (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

GEPH Unit 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

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May, 2020 17

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May, 2020 18

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May, 2020 19

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May, 2020 20

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 60 80 100 120 Avg g Daily y Produ ducti tion

  • n (Mcfpd

pd) Month ths

4,600' Lateral ral Type Curve ve

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

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

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

Gas Price Gas Price

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SLIDE 21

May, 2020 21

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 $8.7 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 60 80 100 120 Avg g Daily y Produ ducti tion

  • n (Mcfpd

pd) Month ths

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

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

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

Gas Price Gas Price

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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 tax holiday; 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 60 80 100 120 Avg g Daily y Produ ducti tion

  • n (Mcfpd

pd) Month ths

10,000' Lateral ral Type Curve

10,000' Lateral EUR Capex (Mmcfe) ($M) 90% 100% 110% 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% - NRI 73% Pricing: Flat Pricing AFE: Two well pad.

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

Gas Price Gas Price

Economic EUR’s vary depending on gas price assumptions

May, 2020

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SLIDE 23

 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

  • f Resource Potential on Acreage Held By Production

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

Volume Low Lifting Costs Wells

 Optionality on 2020 Capital Plans Expected to Deliver

Additional Growth and Free Cash

May, 2020 23