Managem gemen ent P Presen entation September, 2020 2020 This - - PowerPoint PPT Presentation

Managem gemen ent P Presen entation

September, 2020 2020 NYSE American: GDP



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.

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 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:

48

• 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%

3



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



2Q20 Adjusted EBITDA of $15.4 Million. EBITDA Margin

• 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 Tier Capital Efficiency and Returns

TUSCALOOSA MARINE SHALE:

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

EAG AGLE LE F FORD SHALE ALE:

Net t Acres s (2Q20 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 (2Q20) 0): 42,000 00 (24,000 000) 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

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

4

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

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

HS – 511 (99%)

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

6

Capita talizati tion $ $ in in milli illions 6/30/ 30/20 20 Cash and Cash Equivalents $1.6 Senior Credit Facility 95.4 2L Senior Secured Notes 13.9 Tota

• tal D

Debt $109. $109.3 Total Stockholders' Equity 74.4 Tota

• tal B

Book

• ok Capitalization
• n

$183. $183.7 Credit S t Sta tati tistics cs 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

• 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

* Mid-Point of Guidance

7

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 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 100,000 70,000 30,000 $2.54 $2.50 - $3.50 3Q21 100,000 70,000 30,000 $2.55 $2.50 - $3.50 4Q21 100,000 70,000 30,000 $2.53 $2.50 - $3.50 1Q22 100,000 70,000 30,000 $2.53 $2.50 - $3.50 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 3Q20 210 210 $58.36 4Q20 200 200 $57.51 1Q21 200 200 $56.58

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)

$0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 GDP Per Unit Cash Costs Cash Interest Expense

$0. $0.94 $1. $1.05 $1. $1.69 $1. $1.79 $2. $2.74

Peers include: AR,COG,CRK,EQT,GDP, GPOR,MR,RRC,SWN

$1. $1.09 $1. $1.34 $1. $1.59 $2. $2.30

10

• 40%
• 20%

0% 20% 40% 60%

Cash Margin

3 3

2% 2%

GDP DP

51 51% 38 38% 33 33% 21 21% 11 11% 6% 6%

2% 2%

Peer Companies Include: AR,COG,CRK,EQT,GDP,GP OR,MR,RRC,SWN

47 47%

• 27

27% 11

GDP DP 24,000 ,000 Net Acre cres

Pay Zones

} 100 – 300 feet

12

13

Haynesville - Core

• Total Gross/Net Acres:

~36,000/21,000

• Average WI/NRI: ~59%/43%
• Acreage HBP: 100%
• 120+ total producing wells (`40

Operated)

• 1/1/20 – Inventory of 216 gross (96

net) potential locations on 880’ spacing providing 19+ year inventory

• Operator for Approximately 75% of

the NLA core position

• CHK Joint Venture on most of the

remaining 25% of NLA Core Acreage

• Recent Acquisitions Adding to

Inventory with No Upfront Capital

• 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 ~24, 24,000 00 net A t Ac ART RT 3, 3,000 000 Net t Ac Ac

NORTH LOUISIAN ANA A CORE AREA 21,000 ,000 Net t Ac

Rig Source: Ulterra Bits

Core Haynesville Inventory

GROSS NET PROVED YE19 SEC POTENTIAL TOTAL 3P PARISH/ GROSS NET REMAINING REMAINING RESERVES PV10 NET RESERVES NET RESOURCE COUNTY AREA ACRES ACRES LOCATIONS LOCATIONS (BCFE) * (MM) (BCFE) ** POTENTIAL Caddo/DeSoto/ Panola Bethany- Longstreet 30,300 16,000 137 63 411 $224 740 1,151 Caddo Greenwood- Waskom 4,100 3,600 54 31 40 2 445 485 Bienville Swan Lake/Thorn Lake 1,600 1,400 25 2 59 55 35 94 Other Angelina River, Other 6,000 3,000 1 1 1 Total Haynesville 42,000 24,000 216 96 511 282 1,220 1,731 TMS LA, MS 47,800 33,200 6 15 6 Totals 89,800 57,200 216 96 517 $297 1,220 1,737 * YE19 Proved Reserves - Netherland Sewell & Ryder Scott ** 2.5 Bcfe/1k ft of Lateral Applied to Potential Reserves. Angelina River Potential Not Quantified

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

(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

15

298298295297297297298298298298297296292287279273270256252243228213199198191190178163154149139138129122114103 92 88 80 77 71 62 60 56 42 43 40 36

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 38 40 42 44 46 48

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, 8 Well Average (Avg 4,352' LL; 3,972 #/ft Frac) Industry Average Well Performance 298 Wells (2,578 #/ft Frac) Industry Average 2,786 #/ft Industry Average 2,657 #/ft Industry Average 2,177 #/ft

16

207205207207206207206206206203206203203200198191186180177176173162157156141138132123123 110103 91 82 72 67 63 56 49 43 39 38 34 33 30 31 28 28 23

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 38 40 42 44 46 48

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 207 Wells (2,497 #/ft Frac) GDP, 10 Well Average (Avg 7,689' LL, 3,731 #/ft Frac) Industry Average 2,714 #/ft Industry Average 2,682 #/ft Industry Average 1,997 #/ft

17

187 186 180 186 185 185 187 186 187 186 186 185 185 183 170 160 154 142 138 127 122 117 11299 91 82 74 64 60 52 52 49 41 32 27 25 23 19 18 15 12 12 10 10 100 1,000 10,000 100 1,000 10,000 100,000 6 12 18 24 30 36 42 48

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 (2,889 #/ft Frac) GDP, 9 Well Average (Avg 9,602' LL; 3,495 #/ft) Industry Average 3,155 #/ft Industry Average 2,275 #/ft

18

19

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

20

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 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

21

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

 Cash Flow Generation With Strong Balance Sheet and Low

Trading Multiple Creates an Attractive Entry Point for the Stock

 20 Year Inventory on Core Haynesville Position Provides ~1.7

Tcf of Resource Potential on Acreage Predominately Held By Production

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

Volume, Low Lifting Cost Wells

 Improving Natural Gas Price Environment Setting Company Up

for Top Tier Growth and Free Cash Flow Potential for 2021

22