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Management PresentationTuohy Brothers 11th Annual “Drill, Chill, & Re-Fill” Conference
August, 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,
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.
August, 2020 2
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
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 of 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 BcfeObjectives: Tuscaloosa Marine Shale
EAGLE FORD SHALE:Net Acres (1Q20): 4,300Proved Reserves (YE19 – 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 (1Q20): 40,300 (22,300)Proved Reserves (YE19 - SEC) 510 BcfeObjective: Haynesville Shale
HAYNESVILLE PURE PLAY OPPORTUNITY
STRONG HAYNESVILLE RESULTS
COMPANY RETURNS AND BALANCE SHEET
Texas
Mississippi
August, 2020 4
* EBITDA Margin defined as EBITDA divided by Revenues adjusted for settled derivatives
5
55
303
428
480517
0
100
200
300
400
500
600
2015 2016 2017 2018* 2019
ETX TMS NLA - Haynesville Total
SEC PV10 of $297 Million
YE19 Proved Reserves by Area (Bcfe, %)
YE19 Proved Reserves by Category (Bcfe, %)
SEC Proved Reserves (Bcfe) YE19 Proved Reserves by Commodity
August, 2020
PUD-372 (72%)
PDP-145
(28%)
HS – 511 (99%)
TMS-6 (1%)
NaturalGas – 511
(99%)
Oil - 6(1%)
6
Net Debt to EBITDA of 1.3X based on TTM EBITDA of $80.3 million
Target of Less than 1.5X
Capitalization
$ in millions 3/31/20
Cash and Cash Equivalents $1.3
Senior Credit Facility (Borrowing Base) 92.9
2L Senior Secured Notes 13.4
Total Debt $106.3
Total Stockholders' Equity 88.5
Total Book Capitalization $194.8
Credit Statistics
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
August, 2020
- 20,000 40,000 60,000 80,000
100,000 120,000 140,000 160,000
2016 2017 2018 2019 2020*
Mcfe/Day
Mcfe/Day
7* Mid-Point of Guidance
8
Period Natural Gas Volumes (Mcf/d)
Swap Volumes(Mcf/d)
Collar Volumes(Mcf/d) Swap Price Collar Prices
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
2Q21 50,000 50,000 0 $2.47
3Q21 50,000 50,000 0 $2.48
4Q21 50,000 50,000 0 $2.45
1Q22 50,000 50,000 0 $2.45
Period Oil Volumes (Bo/d)
Swap Volumes(Bo/d)
Collar Volumes(Boe/d) Swap Price
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
August, 2020
9
Volumes and Cost Guidance 2020E
Production
Annual Net Production (Bcfe): 50 – 52
Avg. Daily Production – Midpoint (MMcfe/d): 140
Percent Natural Gas: 99%
Capital Expenditures (MM)
Total Capital Expenditures $40 - $50
Price Realization
Henry Hub Differential $0.15 – $0.25
Unit Cost (Per Mcfe)
LOE: $0.20 - $0.25
Taxes: $0.04 – $0.07
Transportation: $0.30 - $0.40
G&A (Cash): $0.24 - $0.30
Development Schedule 2020E
Activity
Gross (Net) Wells: 12 (5.0)
Avg. Net Lateral Length: ~8,500’
Percentage Operated (Net): 72%
Net Capital Allocation
Bethany-Longstreet 91%
Thorn Lake 9%
Quarterly Completion 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)
Total 12 Gross (5.0 Net)
August, 2020
-10
-5
0
5
10
15
20
GDP
August, 2020Peer 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: Bloomberg, Company (1Q20 Financials)
10
0
1
2
3
4
5
6
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: Bloomberg, Company (1Q20 Financials)
11
0
2
4
6
8
10
12
GDP
August, 2020Peer 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: Bloomberg, Company (1Q20 Financials)
12
GDP 22,300 Net Acres
Pay Zones
} 100 – 300 feet
August, 2020 13
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 HAYNESVILLE SHALE
~22,300 net Ac
ART3,000 Net
Ac
NORTH LOUISIANA CORE
AREA19,300 Net Ac
Rig Source: Ulterra Bits
Haynesville Completion Evolution
August, 2020 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
Haynesville – Recent Industry Activity
August, 2020 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
12
34
567
8
9
10-16
1718-20
21
22
(22) GDPMelody Jones 20H-1
4,600’ LateralIP: 22,000 Mcf/d
22
(23) CRKGates 26-35 #1 & #2
10,000’ LateralsIP: 24,600 Mcf/dIP: 23,700 Mcf/d
23
August, 202017
August, 2020 18
August, 2020 19
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 / MMBtuTransportation: $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) $7,047 (Post Capex)
Economic EUR’s vary depending on gas price assumptions.
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg
Dai
ly P
rodu
ctio
n (M
cfpd
)
Months
4,600' Lateral Type Curve
4,600' Lateral
EUR Capex(Mmcfe) ($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 PricingAFE: Two well pad.
IRR Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex) IRRs Incoporate Early Time Outperformance
Gas P
rice
Gas P
rice
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 / MMBtuTransportation - $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)
$13,453 (Post Capex)
Economic EUR’s vary depending on gas price assumptions.
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg
Dai
ly P
rodu
ctio
n (M
cfpd
)
Months
7,500' Lateral Type Curve
7,500' Lateral
EUR Capex(Mmcfe) ($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 PricingAFE: Two well pad.
IRR Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex) IRRs Incoporate Early Time Outperformance
Gas
Pric
e
Gas
Pric
e
22
Assumptions Louisiana
EUR 25 Bcf (2.5 Bcf/1,000’)
Sales Gas BTUPrice Adjustment 1.020
Pricing Differentials/Transportation
Average - NYMEX less $0.15 / MMBtuTransportation: $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) $15,226 (Post Capex)
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg
Dai
ly P
rodu
ctio
n (M
cfpd
)
Months
10,000' Lateral Type Curve
10,000' Lateral
EUR Capex(Mmcfe) ($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 PricingAFE: Two well pad.
IRR Sensitivity Analysis (IRR Sensitivity to EURs and Capex) IRRs Incoporate Early Time Outperformance
Gas
Pric
e
Gas
Pric
e
Economic EUR’s vary depending on gas price assumptions
August, 2020
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+ Tcfof 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