Earnings Call Slides - 3Q19 - Goodrich Petroleum

Earnings Call 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" 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.

November 2019 2

>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 of 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 BcfeObjectives: Tuscaloosa Marine Shale

EAGLE FORD SHALE:Gross (Net) Acres (3Q19): 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 - COREGross (Net) Acres (3Q19): 38,000 (22,000)Proved Reserves (YE18 - SEC) 471 Bcfe2Objective: Haynesville Shale

HAYNESVILLE PURE PLAY OPPORTUNITY

STRONG HAYNESVILLE RETURNS

COMPANY RETURNS AND BALANCE SHEET

Texas

Mississippi

November, 2019 3

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

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

November, 2019

(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

November, 2019

- 20,000 40,000 60,000 80,000

100,000 120,000 140,000 160,000 Mcfe/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 $2.54 $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 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

November, 2019 7

Production 2019E

Annual Net Production: 46.4 – 49.3 Bcfe Avg Daily Production (Mid-Point): 130,000 Mcfe/d

Natural Gas: 98%

Capex (MM) $90 - 95

Price Realization HH Less $0.20 – 0.30

Unit Costs (Per Mcfe)

LOE $0.20 – 0.30 Taxes $0.05 – 0.07 Transportation $0.40 – 0.48 G&A (Cash) $0.25 – 0.35

Activity (Turned In Line) Wells

Gross (Net) Wells: 8 (7.2) Average Net Lateral Length: ~7,500’ Percentage Operated (Net): 100%

Net Capital Allocation

Bethany-Longstreet 67% Thorn Lake 33%

Quarterly Completion (TIL) Cadence

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

-20%

-10%

0%

10%

20%

30%

40%

GDP

ROCE

November, 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,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 (October 30, 2019) 9

0.0010.0020.0030.0040.0050.0060.0070.0080.00

GDP

Capital Efficiency

November, 201910

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 (October 30, 2019)

0.00

1.00

2.00

3.00

4.00

5.00

GDP

NET DEBT/EBITDA

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

Source: Bloomberg, Company (October 30, 2019) 11

0.00

2.00

4.00

6.00

8.00

10.00

GDP

EV/EBITDA

November, 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 (October 30, 2019) 12

GDP 22,000 Net Acres

Pay Zones

} 100 – 300 feet

November, 2019 13

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

HAYNESVILLE SHALE~22,000 net Ac

Greenwood-Waskom /

Metcalf/Longwood2,700 Net Ac

Swan Lake/Thorn

Lake1,300 Net Ac

ART3,000 Net

Ac

BethanyLongstreet

15,000 Net Ac

Rig Source: Ulterra Bits

HAYNESVILLE – RECENT INDUSTRY ACTIVITY

November, 2019 15

(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 #1&2

IP: 27,500 Mcf/dIP: 26,000 Mcf/d

6,100’ & 9450’ Laterals

(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

12

34

567

8

9

10-16

1718-20

21

22

(22) GDPMelody Jones 20H-1


22

299 298 294 288 285 278 274 263 251 251 235 217 209 200 199 194 179163 159 153 145 136 131 121 116 108

99 93 88 84 7965 62 58

47 46

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

Wel

l Cou

nt

Gas

Pro

duct

ion,

Mcf

pd

Months

Recent Haynesville 4,600' Wells

Company Type Curve: EUR: 11.5 Bcf (2.5 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



November, 201916

206 202 201 201 197 191 188 184 178 178 174 162 158 152 144 138 137 131 124 117100 96

84 8267 67

57 5448

44 4136

33 33 31 29

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

Wel

l Cou

nt

Gas

Pro

duct

ion,

Mcf

pd

Months



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)




November, 2019 17

187 179 178 177 173 163 156 143 138 133 122 119 113 103 9586

7567 61

52 52 5043

36

27 2623 21

18 17

12 1210

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

Wel

l Cou

nt

Gas

Pro

duct

ion,

Mcf

pd

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 Performance187 Wells (2,950 #/ft Frac)

GDP, 9 Well Average(Avg 9,602' LL; 3,495 #/ft)



November, 2019 18

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 / MMBtuTransportation: $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

0 20 40 60 80 100 120

Avg

Dai

ly P

rodu

ctio

n (M

cfpd

)

Months

4,600' Lateral 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 PricingAFE: Two well pad.

Gas

Pric

e

Gas

Pric

e

November, 2019 20


EUR 18.75 Bcf (2.5 Bcf/1,000’)


1.020


Average - NYMEX less $0.15 / MMBtuTransportation - $0.35 / Mcf






D&C Capex $10.9 MM



PV10 (M$)($3.00/Mcf Pricing)

$10,198


100

1,000

10,000

100,000

0 20 40 60 80 100 120

Avg

Dai

ly P

rodu

ctio

n (M

cfpd

)

Months


7,500' Lateral



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%


Gas

Pric

e

Gas

Pric

e

November, 2019 21


EUR 25.0 Bcf (2.5 Bcf/1,000’)


1.020


Average - NYMEX less $0.15 / MMBtuTransportation - $0.35 / Mcf






D&C Capex $13.1 MM



PV10 (M$)($3.00/Mcf Pricing)

$14,376


100

1,000

10,000

100,000

0 20 40 60 80 100 120

Avg

Dai

ly P

rodu

ctio

n (M

cfpd

)

Months


10,000' Lateral



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%


Gas

Pric

e

Gas

Pric

e

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

Documents

Earnings Call Slides - 3Q19 - Goodrich Petroleum