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NYSE American: GDP Managem gemen ent P Presen entation th Annual Tuo uohy hy Br Brothers 1 11 th al Dril ill, l, Chill, ill, & Re-Fil ill l Confer eren ence ce August, 2020 2020 This presentation has been prepared


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SLIDE 1

Managem gemen ent P Presen entation

Tuo uohy hy Br Brothers 1 11th

th Annual

al “Dril ill, l, Chill, ill, & Re-Fil ill” l” Confer eren ence ce

August, 2020 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.

August, 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%

August, 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

EAG AGLE LE F FORD SHALE ALE:

Net t Acres s (1Q20 20): 4, 4,30 300 Proved ed R Reser erves es ( (YE19 19 – 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 (1Q20) 0): 40,300 00 (22,300 300) Proved ed R Reser erves es ( (YE19 19 - SEC) C) 51 510 Bcfe fe Obj bjectiv ive: H Haynes esville e Shale e

HAYNESVILLE P PURE P PLAY OPPORTU RTUNITY TY STRONG H HAYNESVILL LLE RESULT LTS COMPANY RETURN RNS AND BALANCE SHE HEET T

Texas Mississippi

August, 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 C PV10 of $297 $297 Million YE YE19 19 Proved ed Reserve ves by Area (Bcfe, % , %) YE19 Prov

  • ved Reserv

rves by Category

  • ry (Bcfe,

, %) %) SEC Proved Reserves (Bc Bcfe) e) YE YE19 19 Proved Re Reserves by Co Commodity

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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SLIDE 6

6

Net Debt to EBITDA of 1.3X based

  • n TTM EBITDA of $80.3 million

Target of Less than 1.5X

Capita talizati tion $ $ in in milli illions 3/ 3/31/ 31/20 20 Cash and Cash Equivalents $1.3 Senior Credit Facility (Borrowing Base) 92.9 2L Senior Secured Notes 13.4 Tota

  • tal D

Debt $106. $106.3 Total Stockholders' Equity 88.5 Tota

  • tal B

Book

  • ok Capitalization
  • n

$194. $194.8 Credit S t Sta tati tistics cs 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

August, 2020

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SLIDE 7

August, 2020

  • 20,000

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

Mcf cfe/Day

Mcfe/Day

7

* Mid-Point of Guidance

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SLIDE 8

8

Perio riod Nat Natural al G Gas as Volumes (M (Mcf cf/d) Sw Swap ap V Volumes (M (Mcf cf/d) Colla lar r Volumes (M (Mcf cf/d) Sw Swap ap P Price Coll llar Pric rices 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 Perio riod Oil V il Volu lumes (Bo/d) Sw Swap ap V Volumes (Bo/d) Colla lar r Volumes (Boe/d) Sw Swap ap P 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

August, 2020

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SLIDE 9

9

Volume mes and d Cost st Gui uida danc nce 2020 2020E

Product uction

Annual Net Production (Bcfe): 50 – 52

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

140 Percent Natural Gas: 99%

Capi pital Expe pendi ditures s (MM)

Total Capital Expenditures $40 - $50

Pric ice R Reali lizatio ion

Henry Hub Differential $0.15 – $0.25

Unit t Cost ( t (Per M Mcfe)

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

Dev evelopme ment Sche hedul dule 2020 2020E

Activi ivity

Gross (Net) Wells: 12 (5.0)

  • Avg. Net Lateral Length:

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

Net Capit ital l Allocatio ion

Bethany-Longstreet 91% Thorn Lake 9%

Quarterly ly Comple letion Cadence

1Q20 5 Gross (1.8 Net) 2Q20 1 Gross (0.8 Net) 3Q20 6 Gross (2.4 Net) 4Q20 0 Gross (0.0 Net) Tot

  • tal

12 12 Gross ( (5. 5.0 N 0 Net)

August, 2020

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SLIDE 10
  • 10
  • 5

5 10 15 20 GD GDP

August, 2020

Peer Group Includes: AMPY,APA,AR,BCEI,BRY,CDEV,CHK,CLR,COG,CPE,CRK,CXO,DNR,DVN,EOG, EQT,ESTE,FANG,GDP,GPOR,HPR,KOS,LONE,LPI,MGY,MR,MTDR,MUR,NBL,OAS,OVV,PDCE,PE,PVAC, PXD,QEP,REI,RRC,SBOW,SD,SM,SWN,TALO,WLL,WPX,XEC,XOG Sourc rce: Bloomberg rg, Company (1Q20 20 Financia cials)

10

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SLIDE 11

1 2 3 4 5 6 GD GDP

August, 2020

Peer Group Includes: AMPY,APA,AR,BCEI,BRY,CDEV,CHK,CLR,COG,CPE,CRK,CXO,DNR,DVN,EOG,EQT,ESTE,FANG, GDP,GPOR,HPR,KOS,LONE,LPI,MGY,MR,MTDR,MUR,NBL,OAS,OVV,PDCE,PE,PVAC,PXD,QEP,REI, RRC,SBOW,SD,SM,SWN,TALO,WLL,WPX,XEC,XOG Source: e: Bloomber erg, Company (1Q 1Q20 0 Financials)

11

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SLIDE 12

2 4 6 8 10 12 GD GDP

August, 2020

Peer Group Includes: AMPY,APA,AR,BCEI,BRY,CDEV,CHK,CLR,COG,CPE,CRK,CXO,DNR,DVN,EOG, EQT,ESTE,FANG,GDP,GPOR,HPR,KOS,LONE,LPI,MGY,MR,MTDR,MUR,NBL,OAS,OVV,PDCE,PE,PVAC, PXD,QEP,REI,RRC,SBOW,SD,SM,SWN,TALO,WLL,WPX,XEC,XOG Source: e: Bloomber erg, Company (1Q 1Q20 0 Financials)

12

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SLIDE 13

GDP DP 22,300 ,300 Net Acre cres

Pay Zones

} 100 – 300 feet

August, 2020 13

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SLIDE 14

August, 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 H L HAYNESVILLE LLE SHA HALE ~22, 22,300 00 net A t Ac ART RT 3, 3,000 000 Net t Ac Ac

NORTH LOUISIAN ANA A CORE AREA 19,300 ,300 Net t Ac

Rig Source: Ulterra Bits

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SLIDE 15

Haynesvil ille le C Comple pletion tion Evolu

  • luti

tion

  • n

August, 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

Hayn aynes esville e – Recent I t Indu dustry try Activ ivity ity

August, 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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SLIDE 17

August, 2020 17

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SLIDE 18

August, 2020 18

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SLIDE 19

August, 2020 19

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SLIDE 20

August, 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 Daily Produ duction

  • n (Mcfpd)

pd) Months hs

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

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

August, 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 Daily Produ duction

  • n (Mcfpd)

pd) Months hs

7, 7,50 500' 0' L Lateral T Type Curve 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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SLIDE 22

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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 Daily Produ duction

  • n (Mcfpd)

pd) Months hs

10 10,000 00' L Lateral Ty Type C 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

August, 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

August, 2020 23