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)
2Q19 3 Gross (2.6 Net)
3Q19 2 Gross (2.0 Net)
4Q19 5 Gross (2.7 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
IP: 47,988 Mcf/d15,000’ Lateral
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
8,800’ LateralIP: 31,000 Mcf/d
(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
IP: 22,500 Mcf/d4,600’ Lateral
(7) CRKCook 21-28 HC #2
10,000’ LateralIP: 26,800 Mcf/d
3,798#/ft
(6) CRKCook 21-28 HC #1
10,000’ LateralIP: 25,600 Mcf/d
3,803#/ft
(2) CRKNissen 28-21HC #2
10,000’ LateralIP: 25,000 Mcf/d
3,801#/ft
(1) CRKNissen 28-21HC #1
10,000’ LateralIP: 27,000 Mcf/d
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
4,600’ LateralIP: 22,000 Mcf/d
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)
Company Type Curve: EUR: 9.2 Bcf (2.0 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
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 178 Wells (3,026 #/ft Frac)
GDP, 9 Well Average(Avg 7,638' LL, 3,646 #/ft Frac)
Industry Average Proppant 2,511 #/ftIndustry Average Proppant 3,354 #/ft
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
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 Performance152 Wells (2,956 #/ft Frac)
GDP, 8 Well Average(Avg 9,656' LL; 3,462 #/ft)
Industry Average Proppant 2,198 #/ftIndustry Average Proppant 3,248 #/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
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 TaxPayout 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)
$10,198
Economic EUR’s vary depending on gas price assumptions.
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg D
aily P
roducti
on (M
cfp
d)
Months
7,500' Lateral Type Curve
7,500' Lateral 10,000' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
IRRs Incorporates Early Time Outperformance
EUR Capex
(Mmcfe) ($M)
90% 100% 110% 90% 100% 110%
2.25 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
Pri
ce
Gas
Pri
ce
September, 2019 22
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 TaxPayout 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)
$14,376
Economic EUR’s vary depending on gas price assumptions.
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg D
aily P
roducti
on (M
cfp
d)
Months
10,000' Lateral Type Curve
10,000' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
IRRs Incorporates Early Time Outperformance
EUR Capex
(Mmcfe) ($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
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