Management Presentation Johnson Rice...

Management PresentationJohnson Rice Conference, New Orleans, Louisiana

September, 2019

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,

officers 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

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 or otherwise.

September, 2019 2

>10 year inventory of high return core HS locations

High margin gas (HS), oil upside (TMS and EFS)

Low capital intensity from low decline rate PDPs

Cash margin expansion continuing in 2019

Low leverage on low reinvestment rate

Top-tier full cycle returns on low leasehold costs

Improving debt-adjusted growth for the multiple

2Q19 Average Production of 138 MMcfe/d

2Q19 Adjusted EBITDA of $21.5 Million

2Q19 Net Income of $11.8 Million (Includes MTM of

Derivatives)

Return on Capital Employed (“ROCE”) of 18% on 2Q19

Annualized EBIT

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres (2Q19): 49,000 (34,000)Proved Reserves (YE18 – SEC) 9 BcfeObjectives: Tuscaloosa Marine Shale

EAGLE FORD SHALE:

Gross (Net) Acres (2Q19): 18,000 (12,000)Proved Reserves (YE18 – SEC) 0Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime

HAYNESVILLE / BOSSIER SHALEANGELINA RIVER TREND (“ART”)

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

HAYNESVILLE SHALE - CORE

Gross (Net) Acres (2Q19): 39,000 (22,000)Proved Reserves (YE18 - SEC) 471 Bcfe2Objective: Haynesville Shale

>1.0 Tcf of natural gas resource potential in North Louisiana . Fully de-risked

OPERATED OPPORTUNITY

STRONG FUNDAMENTALS

2Q19 HIGHLIGHTS

Texas

Louisiana

Mississippi

September, 2019 3

PD-127

(26%)

PUD-353

(74%)

Oil (2%)

Natural

Gas (98%)

NLA HAY

CORE-471

(98%)

TMS-9 (2%)

4

55

303

428

480

0

100

200

300

400

500

600

2015 2016 2017 2018*

ETX TMS NLA - Haynesville Total

* SEC PV10 of $418 Million

YE18 Proved Reserves by Area (Bcfe, %)

YE18 Proved Reserves by Category (Bcfe, %)

SEC Proved Reserves (Bcfe) YE18 Proved Reserves by Commodity

September, 2019

(USD in thousands)

Cash $ 1,669

Debt

Senior Credit Facility 84,400

2L Convertible Notes (PIK) 12,135

Total Debt 96,535

Total Net Debt $94,866

September, 2019 5

September, 2019

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000Mcfe/Day

Mcfe/Day

6

* Mid-Point of Guidance

Period Natural Gas Volumes Swap Volumes Collar Volumes Swap Price Collar Prices

(MCFPD) (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 $2.58 $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 Oil Volumes Swap Volumes Collar Volumes Swap Price Collar Prices

(BOPD) (BOPD) (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

September, 2019 7

Production 2019E

Annual Net Production: 49.3 – 52.9 Bcfe

Avg Daily Production (Mcfe/d): 135,000-145,000

Natural Gas: 98%

Capex (MM) $90 - 100

Price Realization HH Less $0.12 – 0.15

Unit Costs (Per Mcfe)

LOE $0.20 – 0.30

Taxes $0.05 – 0.09

Transportation $0.40 – 0.48

G&A (Cash) $0.25 – 0.35

Activity Wells

Gross (Net) Wells: 12 (9.3)

Average Net Lateral Length: 8,000’

Percentage Operated (Net): 92%

Net Capital Allocation

Bethany-Longstreet 67%

Thorn Lake 33%

Quarterly Completion Cadence

1Q19 2 Gross (2.0 Net)




Total 12 Gross (9.3 Net)

September, 2019 8

-20%

-10%

0%

10%

20%

30%

40%

GDP

ROCE

September, 2019Peer 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,LLEX,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 Source: Bloomberg, Company (JSeptember 3, 2019) 9

$-

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

GDP

Capital Efficiency

September, 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

Source: Bloomberg, Company (September 3, 2019)

0

1

2

3

4

5

GDP

NET DEBT/EBITDA

September 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,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

Source: Bloomberg, Company (September 3, 2019) 11

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

GDP

EV/EBITDA

September, 2019Peer 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 Source: Bloomberg, Company (September 3, 2019) 12

GDP 23,000 Net Acres

Pay Zones

} 100 – 300 feet

September, 2019 13

September, 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

HAYNESVILLE SHALE~23,000 net Ac

Greenwood-Waskom /

Metcalf/Longwood3,700 Net Ac

Swan Lake/Thorn

Lake1,300 Net Ac

ART3,000 Net

Ac

BethanyLongstreet

15,000 Net Ac

Rig Source: Ulterra Bits

HAYNESVILLE COMPLETION EVOLUTION

September, 201915

• 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

HAYNESVILLE – RECENT INDUSTRY ACTIVITY

September, 2019 16

(8) CHKROTC 1 & 2

10,000’ LateralsIP: 72,000 Mcf/d

19 Bcf in 19 months

(11) GDP-Wurtsbaugh25-24 #2&3

7,500’ LateralsIP: 25,000 Mcf/dIP: 29,000 Mcf/d

(10) GDP Wurtsbaugh 264,600’ Lateral

IP: 22,000 Mcf/d

(9) GDPMSR - Hunt 5H-1

4,600’ LateralIP: 17,000 Mcf/d

(22) CHK Black 1H

IP: 44,000 Mcf/d10,000’ Lateral

(21) VineHA RA SU74;L L

Golson 3 - 003-ALTIP: 18,800 Mcf/d

4,661’ Lateral

5. CHKGEPH Unit


4. CRKHUNTER 28-21HC 1&2 IP: 27,000 Mcf/d each

9,200’ Laterals

(13) GDPFranks 25&24 #1IP: 30,000 Mcf/d

9,600’ Lateral

(12) GDPWurtsbaugh 25-24 #1


(19) GDPCason-Dickson #1&2

IP: 31 MMcf/d, IP: 23 MMcf/d

8,000 & 3,000’ Laterals

3. CRKFLORSHEIM 9-16 HC #1&2 10,000’ Laterals

IP: 26,500 Mcf/dIP: 27,600 Mcf/d

(20) GDPCason-Dickson 23&24

#3&4IP: 62,000 Mcf/d9,300’ Laterals

(18) GDPHarris 14&23 #1IP: 27,500 Mcf/d

6,100’ Lateral

(14) GDPLoftus 27&22 #1 & 2

26,000 Mcfe/d25,000 Mcfe/d 7,500’ Laterals

(15) GDPDemmon 34H #1

22,500 Mcf/d4,600’ Lateral

(16) GDPWurtsbaugh 35H #1


(7) CRKCook 21-28 HC #2


3,798#/ft

(6) CRKCook 21-28 HC #1


3,803#/ft

(2) CRKNissen 28-21HC #2


3,801#/ft

(1) CRKNissen 28-21HC #1


3,796#/ft

(17) Covey ParkTucker 31-6C H1IP 18,045 Mcf/d

7,466’ Lateral

1

2

3

4

56

7

8

9

10-16

17

18-20

21

22

(22) GDPMelody Jones 20H-1


22

265 263 260 256 250 245 235 223 209 201 200 193 191178

164 154 152142 138

126 120 114106

92 89 84 82

67 65 6256

4743 43

39

31

10

100

1,000

10,000

100

1,000

10,000

100,000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

We

ll C

ou

nt

Gas

Pro

du

ctio

n, M

cfp

d

Months

Recent Haynesville 4,600' Wells

Company Type Curve: EUR: 11.5 Bcf (2.5 Bcf/1,000 ft)


GDP, 5 Well Average(Avg 3,995' LL; 4,156 #/ft Frac)

Industry Average Well Performance 265 Wells (3,125 #/ft Frac)

SI - Offset Fracs

Industry Average Proppant 2,775 #/ftIndustry Average Proppant 3,365 #/ft

September, 201917

178 176 177 178 177 175 171 167156 155 151

140 139 132 127117

107 103

86 83

67 68 6457

49 4642

3834 32 31 31 29

2623

1410

100

1,000

10,000

100

1,000

10,000

100,000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

We

ll C

ou

nt

Gas

Pro

du

ctio

n, M

cfp

d

Months



Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft)

Industry Average Well Performance 178 Wells (3,026 #/ft Frac)

GDP, 9 Well Average(Avg 7,638' LL, 3,646 #/ft Frac)


September, 2019 18

152 141 143 139 135 129 123 118 112103 96 89

7768 67

6053 51

44

36

28 27 2521

1917

12 1210 10

87

6 6

4 4

1

10

100

1,000

100

1,000

10,000

100,000

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

We

ll C

ou

nt

Gas

Pro

du

ctio

n, M

cfp

d

Months


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 Performance152 Wells (2,956 #/ft Frac)

GDP, 8 Well Average(Avg 9,656' LL; 3,462 #/ft)


September, 2019 19

September, 2019 20

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 TaxPayout 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

0 20 40 60 80 100 120

Avg D

aily P

roducti

on (M

cfp

d)

Months

4,600' Lateral Type Curve

4,600' Lateral 7,500' Lateral

IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)

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

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

Pri

ce

Gas

Pri

ce

September, 2019 21


EUR 18.75 Bcf (2.5 Bcf/1,000’)

Sales Gas BTU

Price

Adjustment

1.020

Pricing

Differentials/

Transportation


Transportation - $0.35 / Mcf







D&C Capex $10.9 MM




$10,198


100

1,000

10,000

100,000

0 20 40 60 80 100 120

Avg D

aily P

roducti

on (M

cfp

d)

Months


7,500' Lateral 10,000' Lateral


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%



AFE: Two well pad.

Gas

Pri

ce

Gas

Pri

ce

September, 2019 22


EUR 25.0 Bcf (2.5 Bcf/1,000’)

Sales Gas BTU

Price

Adjustment

1.020

Pricing

Differentials/

Transportation


Transportation - $0.35 / Mcf







D&C Capex $13.1 MM




$14,376


100

1,000

10,000

100,000

0 20 40 60 80 100 120

Avg D

aily P

roducti

on (M

cfp

d)

Months


10,000' Lateral


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%



AFE: Two well pad.

Gas

Pri

ce

Gas

Pri

ce

Haynesville Generating Superior Returns Regardless of Commodity

◦ Incorporating Company Hedges and Blended Average Lateral Length for 2019 Generates 45% - 89% IRR from $2.50 - $3.00 per Mcf

Continued Strong EBITDA Growth in 2019 Driven by Substantial Increase in Production on a Lower Unit Cost Structure

◦ Production and EBITDA Projected to Double with Similar Capex and EBITDA

Eagle Ford and TMS Positions Provide Leverage to Oil Prices and Strategic Optionality

◦ Encouraging Recent Offset Activity

Focusing on Strategic Acquisitions That Add Inventory While Keeping Debt Metrics 1.5X or Less

◦ Completed Several Small Bolt-On Deals in 2018 Which More Than Replaced Inventory. Expect to do More in 2019

September, 2019 23

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