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Earn rnin ings C Call S ll Slides 3Q19 November 2019 This presentation has been prepared by Goodrich Petroleum Corporation (the Company) solely for information purposes and may include "forward- looking statements"

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SLIDE 1

Earn rnin ings C Call S ll Slides – 3Q19

November 2019

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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.

November 2019

2

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SLIDE 3

>10 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

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

2.5 Bcf Per 1,000 Feet of Lateral

Low LOE on New Wells - $0.05/Mcf

Severance Tax Abatement For 2 Years or Payout

Return on Capital Employed (“ROCE”) – 17% (3Q19 Annualized EBIT)

3Q19 Adjusted EBITDA of $21.3 Million. EBITDA Margin

  • f Approximately 64%*

Top Tier Capital Efficiency (Both Volumes and Adjusted for Growth in EBITDA)

Low Leverage (3Q19 – Debt to EBITDA <1.5X)

Low Multiple (EV/EBITDA ~ 2.5X)

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres (3Q19): 48,000 (33,000) Proved Reserves (YE18 – SEC) 9 Bcfe Objectives: Tuscaloosa Marine Shale

EAG AGLE LE F FORD SHALE ALE:

Gross ( ss (Net) A Acres (3Q19 19): 18, 18,00 000 (12,000 000) Proved ed R Reser erves es ( (YE18 18 – SEC) ) Obj bjectiv ives: Eagle le F Ford S rd Shale le, P Pears rsall S l Shale le & & Buda da L Lim ime

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

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

HAY AYNESVILL LLE S SHALE ALE - COR ORE

Gross ( ss (Net) A Acres (3Q19) 9): 38,000 00 (22,000 000) Proved ed R Reser erves es ( (YE18 18 - SEC) C) 47 471 Bcf cfe2 Obj bjectiv ive: H Haynes esville e Shale e

HAYNESVILLE P PURE P PLAY OPPORTU RTUNITY TY STRONG NG H HAYNES NESVI VILLE E RETURNS NS COMPANY RETURN RNS AND BALANCE SHE HEET T

Texas Mississippi

November, 2019 3

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

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SLIDE 4

PD-127 (26%) PUD-353 (74%) Oil (2%) Natural Gas (98%) NLA HAY CORE-471 (98%) TMS-9 (2%)

4 55 303 428 480 100 200 300 400 500 600 2015 2016 2017 2018* ETX TMS NLA - Haynesville Total

* SEC P C PV10 10 o

  • f $418

$418 Million YE YE18 18 Proved Reserve ves by Area (Bcfe, % , %) YE18 Prov

  • ved Reserv

rves by Category

  • ry (Bcfe,

, %) %) SEC Proved Reserves (Bc Bcfe) e) YE YE18 18 Proved ed Reserve ves by Commodi dity

November, 2019

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SLIDE 5

(USD in thousands) Cash $ 1,160 Debt Senior Credit Facility 87,900 2L Convertible Notes (PIK) 12,546 Total Debt 100,446 Total Net Debt $99,286

November, 2019

5

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SLIDE 6

November, 2019

  • 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000

Mcf cfe/Day

Mcfe/Day

6

* Mid-Point of Guidance

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SLIDE 7

Perio riod Natu tural Gas Vol Volume mes Swap Vol Volume mes Col

  • llar Vol

Volume mes S Swap Price Col

  • llar Prices

(M (MCFPD) ) (M (MCFPD)

) (MCFPD)

3Q19 100,000 100,000 0 $2.89

4Q19 100,000 100,000 0 $2.89

1Q20 70,000 70,000 0 $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 Period

  • d

Oil il Volu lumes Sw Swap Volu lumes Colla llar Volu lumes Sw Swap Pric rice C Collar Pric rices (BO (BOPD) ) (BO (BOPD) (BO BOPD)

3Q19 300 300 0 $51.08

4Q19 300 300 0 $51.08

1Q20 250 250 0 $60.44

2Q20 225 225 0 $59.41

3Q20 210 210 0 $58.36

4Q20 200 200 0 $57.51

1Q21 200 200 0 $56.58 November, 2019 7

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SLIDE 8

Produ ductio ion

2019E 2019E

Annual Net Production: 46.4 – 49.3 Bcfe

Avg Daily Production (Mid-Point): : 130,000 Mcfe/d

Natural Gas:

98%

Capex ex (MM MM) ) $90 - 95

Pric ice R Reali lizatio ion HH Less $0.20 – 0.30

Unit t Costs ts (Per Mcfe)

LOE $0.20 – 0.30

Taxes $0.05 – 0.07

Transportation $0.40 – 0.48

G&A (Cash) $0.25 – 0.35

Activi ivity (Turned In Line) Wells ls

Gross (Net) Wells: 8 (7.2)

Average Net Lateral Length: ~7,500’

Percentage Operated (Net): 100%

Net Capit ital l Allocatio ion

Bethany-Longstreet 67%

Thorn Lake 33%

Quarterly Completion n (TIL) Cadence nce

1Q19 2 Gross (2.0 Net)

2Q19 3 Gross (2.6 Net)

3Q19 1 Gross (0.9 Net)

4Q19 2 Gross (1.7 Net)

Total 8 Gross (7.2 Net)

November, 2019 8

Estimated YE19 Haynesville DUCs – 5 Gross (2.5 Net) Wells

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SLIDE 9
  • 20%
  • 10%

0% 10% 20% 30% 40% GD GDP

RO ROCE

November, 2019

Peer Group Includes: AMPY.APA,AR,AXAS,BCEI,BRY,CDEV,CHAP,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DNR,DVN,ECA,EOG, EQT,ESTE,FANG,GDP,GPOR,HPR,JAG,KOS,LONE,LPI,MCF,MGY,MR,MTDR,MUR,NBL,NOG,OAS, PDCE,PE,PVAC,PXD,QEP,REI,RRC,SBOW,SD,SM,SRCI,SWN,TALO,WLL,WPX,WTI,XOG Sourc rce: Bloomberg rg, Company (October er 30, 30, 2019) 2019)

9

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SLIDE 10

0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 GD GDP

Capital E l Effic icie iency

November, 2019 10

Peer Group Includes: AXAS,BCEI,BRY,CHAP,CHK,COG,CPE,CRK,CRZO,CXO,DNR,DVN,ECA,EOG,ESTE,FANG, GDP,HPR,JAG,KOS,LLEX,LONE,MGY,MR,MTDR,MUR,OAS,PDCE,PE,PVAC,PXD,REI,SBOW, SRCI,TALO,WPX Sourc rce: : Bloomberg, , Company (Oct ctober 30, 30, 2019) 2019)

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SLIDE 11

0.00 1.00 2.00 3.00 4.00 5.00 GD GDP

NET D DEBT/ T/EBITD ITDA

November, 2019

Peer Group Includes: APA,AR,AREX,AXAS,BCEI,BRY,CDEV,CHAP,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DNR,DVN,ECA, EOG,EQT,ESTE,FANG,GDP,GPOR,HPR,JAG,KOS,LONE,LPI,MCF,MGY,MPO,MR,MTDR,MUR,NBL, OAS,PDCE,PE,PVAC,PXD,QEP,REI,RRC,SBOW,SD,SM,SNEC,SRCI,SWN,TALO,UPL,WLL,WPX,WTI, XOG Sourc rce: : Bloomberg, , Company (Oct ctober 30, 30, 2019) 2019)

11

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SLIDE 12

0.00 2.00 4.00 6.00 8.00 10.00 GD GDP

EV/EBITDA ITDA

November, 2019

Peer Group Includes: AMPY,APA,AR,AREX,AXAS,BCEI,BRY,CDEV,CHAP,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DNR,DVN,ECA ,EOG,EQT,ESTE,FANG,GDP,GPOR,HPR,JAG,KOS,LONE,LPI,MCF,MGY,MR,MTDR,MUR,NBL,OAS,PDCE, PE,PVAC,PXD,QEP,REI,RRC,SBOW,SD,SM,SRCI,SWN,TALO,UPL,WLL,WPX,WTI,XOG Sourc rce: Bloomberg rg, Company (Oct ctober 30, 30, 2019) 2019)

12

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SLIDE 13

GDP DP 22,000 ,000 Net Acre cres

Pay Zones

} 100 – 300 feet

November, 2019 13

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SLIDE 14

November, 2019 14

North Louisiana (Haynesville)

  • Total Gross/Net Acres:

~34,000/20,000

  • Average WI/NRI: ~59%/43%
  • Acreage HBP: 100%
  • 113 total producing wells (31

Operated)

  • 1/1/19 – Inventory of 214 gross (99

net) potential locations on 880’ spacing

  • 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: ~8,000/

3,000

  • Average WI/NRI: ~40% / 30%
  • Sale of Producing Wells and a

Portion of the Company’s Acreage for $23 Million

HAYN YNESVILLE LE S SHALE LE ~22, 22,000 00 net A t Ac Greenwood

  • od-

Waskom kom / / Metcalf/L /Longwood

  • od

2, 2,700 700 Net A t Ac Swan an Lake/T /Thor

  • rn

Lake ke 1, 1,300 300 Net A t Ac ART RT 3, 3,000 000 Net t Ac Ac

Betha hany ny Longstreet et 15,000 ,000 Net t Ac

Rig Source: Ulterra Bits

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SLIDE 15

HAYNESVILLE – RECENT INDUSTRY ACTIVITY

November, 2019 15

(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&2 IP: 27,500 Mcf/d IP: 26,000 Mcf/d 6,100’ & 9450’ Laterals (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

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SLIDE 16

299 298 294 288 285 278 274 263 251 251 235 217 209 200 199 194 179 163 159 153 145 136 131 121 116 108 99 93 88 84 79 65 62 58 47 46

10 100 1,000 10,000

100 1,000 10,000 100,000 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Well Count

Gas Production, Mcfpd Months

Recent Haynesville 4,600' Wells

Company Type Curve: EUR: 11.5 Bcf (2.5 Bcf/1,000 ft) Company Type Curve: EUR: 9.2 Bcf (2.0 Bcf/1,000 ft) GDP, 6 Well Average (Avg 4,097' LL; 4,127 #/ft Frac) Industry Average Well Performance 299 Wells (3,057 #/ft Frac) Industry Average 3,453 #/ft Industry Average 3,242 #/ft Industry Average 2,352 #/ft

November, 2019 16

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SLIDE 17

206 202 201 201 197 191 188 184 178 178 174 162 158 152 144 138 137 131 124 117 100 96 84 82 67 67 57 54 48 44 41 36 33 33 31 29

10 100 1,000 10,000

100 1,000 10,000 100,000 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Well Count

Gas Production, Mcfpd Months

Recent Haynesville 7,500' Wells

Company Type Curve: EUR: 18.75 Bcf (2.5 Bcf/1,000 ft) Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft) Industry Average Well Performance 206 Wells (2,962 #/ft Frac) GDP, 9 Well Average (Avg 7,780' LL, 3,692 #/ft Frac) Industry Average 3,401 #/ft Industry Average 3,283 #/ft Industry Average 2,394 #/ft

November, 2019 17

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SLIDE 18

187 179 178 177 173 163 156 143 138 133 122 119 113 103 95 86 75 67 61 52 52 50 43 36 27 26 23 21 18 17 12 12 10 10 100 1,000 10,000 100 1,000 10,000 100,000 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Well Count

Gas Production, Mcfpd Months

Recent Haynesville 10,000' Wells

Company Type Curve: EUR: 25 Bcf (2.5 Bcf/1,000 ft) Company Type Curve EUR: 20 Bcf (2.0 Bcf/1,000 ft) Industry Average Well Performance 187 Wells (2,950 #/ft Frac) GDP, 9 Well Average (Avg 9,602' LL; 3,495 #/ft) Industry Average 3,340 #/ft Industry Average 2,222 #/ft

November, 2019 18

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SLIDE 19

November, 2019 19

Assumptions Louisiana EUR 11.5 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.020 Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation: $0.35 / 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 $0.04 / Mcf Royalty Burden 27.0% D&C Capex $8.5 MM Facilities Capex $0.185 MM, included in D&C Capex Spud to 1st Sale 60 Days PV10 (M$)

($3.00/Mcf Pricing)

$4,875 Economic EUR’s vary depending on gas price assumptions. 100 1,000 10,000 100,000 20 40 60 80 100 120 Avg Daily Produ duction

  • n (Mcfpd)

pd) Months hs

4, 4,60 600' 0' L Lateral T Type Curve 4,600' Lateral

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

EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% 2.25 4.5% 11.8% 20.3% 2.25 19.1% 11.8% 6.5% 2.50 14.7% 25.0% 37.3% 2.50 35.8% 25.0% 17.2% 2.75 27.0% 41.3% 58.3% 2.75 56.5% 41.3% 30.3% 3.00 41.9% 61.0% 83.6% 3.00 81.4% 61.0% 46.2% 3.50 80.0% 111.5% 148.8% 3.50 145.5% 111.5% 86.8%

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

Gas Price Gas Price

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SLIDE 20

November, 2019 20

Assumptions Louisiana EUR 18.75 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.020 Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation - $0.35 / 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 $0.04 / Mcf Royalty Burden 27.0% D&C Capex $10.9 MM Facilities Capex $0.185 MM, included in D&C Capex Spud to 1st Sale 60 Days

PV10 (M$)

($3.00/Mcf Pricing)

$10,198 Economic EUR’s vary depending on gas price assumptions. 100 1,000 10,000 100,000 20 40 60 80 100 120 Avg Daily Produ duction

  • n (Mcfpd)

pd) Months hs

7, 7,50 500' 0' L Lateral T Type Curve 7,500' Lateral

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

EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% 2.25 18.3% 27.7% 38.7% 2.25 37.8% 27.7% 20.4% 2.50 31.4% 44.7% 60.0% 2.50 58.9% 44.7% 34.2% 2.75 47.1% 65.0% 85.7% 2.75 84.2% 65.0% 50.8% 3.00 44.7% 88.9% 115.9% 3.00 114.1% 88.9% 70.4% 3.50 65.7% 148.7% 192.1% 3.50 189.3% 148.7% 119.0%

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

Gas Price Gas Price

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SLIDE 21

November, 2019 21

Assumptions Louisiana EUR 25.0 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.020 Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation - $0.35 / 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 $13.1 MM Facilities Capex $0.185 MM, included in D&C Capex Spud to 1st Sale 60 Days

PV10 (M$)

($3.00/Mcf Pricing)

$14,376 Economic EUR’s vary depending on gas price assumptions. 100 1,000 10,000 100,000 20 40 60 80 100 120 Avg Daily Produ duction

  • n (Mcfpd)

pd) Months hs

10 10,000 00' L Lateral Ty Type C Curve 10,000' Lateral

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

EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% 2.25 24.8% 35.9% 48.5% 2.25 47.6% 35.9% 27.1% 2.50 40.1% 55.4% 72.9% 2.50 71.8% 55.4% 43.1% 2.75 58.2% 78.5% 101.9% 2.75 100.5% 78.5% 62.2% 3.00 79.3% 105.6% 135.8% 3.00 134.1% 105.6% 84.4% 3.50 131.0% 172.3% 220.3% 3.50 217.6% 172.3% 138.9%

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

Gas Price Gas Price

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SLIDE 22

 Haynesville Generating Good Returns on High Volume Wells,

Favorable Hedging and Low Cost Structure

 Strong EBITDA Growth in 2019 Driven by Substantial Increase in

Production on a Much Lower Unit Cost Structure

 Eagle Ford and TMS Positions Provide Leverage to Oil Prices and

Strategic Optionality

 Optionality on 2020 Capital Plans Expected to Deliver Growth

and Free Cash

November, 2019 22