Post on 20-Aug-2020
Management Presentation
Earnings Call – 2Q20
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 orotherwise.
August, 2020 2
Environmental:◦ Total Gas Flared: (% of Production)
◦ Total GHG Emissions: (2019) (000 Mt) (EPA,LDEQ,MDEQ,TECQ Compliant)
◦ Total Water Use (2019 - MMBls):
◦ OSHA Compliant
Social:◦ Number of Employees:
◦ Percentage of Employees Unionized:
◦ Percentage of Women in the Workforce:
◦ Percentage of Minorities in the Workforce:
Governance:◦ Size of Board:
◦ Independent Directors:
◦ Percentage of Independent Directors:
◦ Board Duration:
◦ Number of Board Meetings:
◦ Board Meeting Attendance:
~0
27
5.1
48
0%
51%
20%
8
6
75%
1 Year
10
100%
August, 2020 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
2Q20Adjusted EBITDA of $15.4 Million. EBITDA Margin
of 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) 7BcfeObjectives: Tuscaloosa Marine Shale
EAGLE FORD SHALE:
Net Acres (2Q20): 4,300Proved Reserves (YE19 – SEC) 0Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime
HAYNESVILLE / BOSSIER SHALE ANGELINA 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 (2Q20): 42,000 (24,000)Proved Reserves (YE19- SEC) 510Bcfe Objective: HaynesvilleShale
HAYNESVILLE PURE PLAY OPPORTUNITY
STRONG HAYNESVILLE RESULTS
COMPANY RETURNS AND BALANCESHEET
Texas
4August, 2020
Mississippi
* EBITDA Margin defined as EBITDA divided
by Revenues adjusted for settled derivatives
5
55
303
428
517
500 480
0
100
200
300
400
600
2015 2016 2017 2018*
SEC PV10 of $297 Million
2019
ETX TMS NLA - Haynesville Total
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%)
Natural
Gas – 511
(99%)
Oil - 6
(1%)
6
Capitalization
$ in millions 6/30/20
Cash and Cash Equivalents $1.6
Senior Credit Facility 95.4
2L Senior Secured Notes 13.9
Total Debt $109.3
Total Stockholders' Equity 74.4
Total Book Capitalization $183.7
Credit Statistics
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
August, 2020
August, 2020
-
2016 2017 2018 2019 2020*
140,000
120,000
100,000
80,000
60,000
40,000
20,000
160,000Mcfe/Day
Mcfe/Day
7
* Mid-Point of Guidance
PeriodNatural Gas Volumes
(Mcf/d)Swap Volumes
(Mcf/d)Collar Volumes
(Mcf/d)Swap Price Collar Prices
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 70,000 70,000 0 $2.54
3Q21 70,000 70,000 0 $2.55
4Q21 70,000 70,000 0 $2.53
1Q22 70,000 70,000 0 $2.53
PeriodOil Volumes
(Bo/d)Swap Volumes
(Bo/d)Collar Volumes
(Boe/d)Swap Price
2Q20 225 225 0 $59.41
3Q20 210 210 0 $58.36
4Q20 200 200 0 $57.51
1Q21 200 200 0 $56.58
8August, 2020
Development Schedule 2020E Volumes and Cost Guidance 2020E
Activity Production
Gross (Net) Wells: 12 (5.0)Annual Net Production (Bcfe): 50 – 52
Avg. Net Lateral Length: ~8,500’Avg. Daily Production – Midpoint (MMcfe/d): 140
Percentage Operated (Net): 72%Percent Natural Gas: 99%
Net Capital AllocationCapital Expenditures (MM)
Bethany-Longstreet 91%Total Capital Expenditures $40 - $50
Thorn Lake 9% Price Realization
Quarterly Completion Cadence Henry Hub Differential $0.15 – $0.25
1Q20 5 Gross (1.8 Net) Unit Cost (Per Mcfe)
2Q20 1 Gross (0.8 Net) LOE: $0.20 - $0.25
3Q20 6 Gross (2.4 Net) Taxes: $0.04 – $0.07
4Q20 0 Gross (0.0 Net) Transportation: $0.30 - $0.40
Total 12 Gross (5.0 Net) G&A (Cash): $0.24 - $0.30
9August, 2020
GDP 24,000 Net Acres
Pay Zones
} 100 – 300 feet
August, 2020 10
Haynesville - Core
▪ Total Gross/Net Acres:
~36,000/21,000
▪ 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 ForBolt-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
~24,000 net Ac
ART 3,000 Net
Ac
NORTH LOUISIANA CORE
AREA21,000 Net Ac
August, 2020 11
Rig Source: Ulterra Bits
Haynesville Completion Evolution
• 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
12August, 2020
Haynesville – Recent Industry Activity
(8) CHK ROTC 1 & 2
10,000’ LateralsIP: 72,000 Mcf/d
(Combined)
(11) GDP-Wurtsbaugh 25-24 #2&3
7,500’ LateralsIP: 25,000 Mcf/dIP: 29,000 Mcf/d
(10) GDP Wurtsbaugh 26 4,600’ Lateral IP: 22,000 Mcf/d
(9) GDP MSR - 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-ALT IP: 18,800 Mcf/d4,661’ Lateral
5. CHK GEPH Unit
IP: 47,988 Mcf/d15,000’ 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’ LateralIP: 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/dIP: 27,600 Mcf/d
(20) GDPCason-Dickson 23&24
#3&4IP: 62,000 Mcf/d9,300’ 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/d25,000 Mcfe/d7,500’ Laterals
(15) GDP Demmon 34H #1
22,500 Mcf/d4,600’ Lateral
(16) GDP Wurtsbaugh 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) CRK Cook 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) GDP Melody Jones 20H-1
4,600’ LateralIP: 22,000 Mcf/d
22
(23) CRK Gates 26-35 #1 & #2
10,000’ LateralsIP: 24,600 Mcf/dIP: 23,700 Mcf/d
23
13August, 2020
August, 202014
August, 2020 15
August, 2020 16
Assumptions Louisiana
EUR 12.6 Bcf (2.7 Bcf/1,000’)
Sales Gas BTU
Price
Adjustment1.020
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 TaxPayout 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)
$7,047 (Post Capex)
Economic EUR’s vary depending on gas price assumptions.
100
1,000
10,000
100,000
0 20 40 80 100 120
Avg
Daily P
roducti
on
(Mcfp
d)
60Months
4,600' Lateral TypeCurve
EUR
(Mmcfe)
90% 100% 110%
Capex
($M)
90% 100% 110%
2.00 25.0%
2.25 43.3%
2.50 65.0%
2.75 90.5%
3.00 120.0%
37.8%
61.3%
89.2%
122.1%
160.6%
52.6%
81.9%
117.1%
158.9%
208.4%
2.00 53.0%
2.25 82.8%
2.50 118.5%
2.75 161.0%
3.00 211.4%
37.8%
61.3%
89.2%
122.1%
160.6%
27.0%
45.9%
68.3%
94.6%
125.1%
4,600' Lateral
IRR Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex)
IRRs Incoporate Early Time Outperformance
Ownership: WI 100% - NRI 73%
Pricing:
AFE:
Flat Pricing
Two well pad.
Gas
Pric
e
Gas
Pric
e
August, 2020 17
Assumptions Louisiana
EUR 21 Bcf (2.8 Bcf/1,000’)
Sales Gas BTU
Price
Adjustment1.020
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 TaxPayout 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)
$13,453 (Post Capex)
Economic EUR’s vary depending on gas price assumptions.
100
1,000
10,000
100,000
0 20 40 80 100 120
Avg
Daily P
roducti
on
(Mcfp
d)
60
Months
7,500' Lateral TypeCurve
EUR
(Mmcfe)
90% 100% 110%
Capex
($M)
90% 100% 110%
2.00 47.8%
2.25 72.8%
2.50 102.6%
2.75 137.8%
3.00 179.0%
65.5%
97.5%
135.9%
181.9%
236.3%
85.7%
125.9%
174.8%
233.9%
304.9%
2.00 86.8%
2.25 127.7%
2.50 177.5%
2.75 237.7%
3.00 310.1%
65.5%
97.5%
135.9%
181.9%
236.3%
49.6%
75.0%
105.4%
141.3%
183.3%
7,500' Lateral
IRR Sensitivity Analysis Estimates (IRR Sensitivity to EURs and Capex) IRRs Incoporate Early Time Outperformance
Ownership: WI 100% - NRI73%
Pricing:
AFE:
Flat Pricing
Two well pad.
Gas
Pri
ce
Gas
Pri
ceAugust, 2020 18
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 TaxPayout or 24 month taxholiday;
thereafter $0.12 / Mcf
Ad Val Tax $0.03 / Mcf
Royalty Burden 27.0%
D&C Capex $10.7 MM
Facilities/TubingCapex
$0.485 MM, included in D&C Capex
Spud to 1st Sale 60 Days
PV10 (M$)($2.75/Mcf Pricing)
$15,226 (Post Capex)
100
1,000
10,000
100,000
0 20 40 80 100 120
Avg
Daily P
roducti
on
(Mcfp
d)
60
Months
10,000' Lateral TypeCurve
EUR
(Mmcfe)
90% 100% 110%
Capex
($M)
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.
10,000' Lateral
IRR Sensitivity Analysis (IRR Sensitivity to EURs andCapex) IRRs Incoporate Early Time Outperformance
Ga
sP
rice
Ga
sP
rice
Economic EUR’s vary depending on gas price assumptions
August, 2020 19
Cash Flow Generation With Strong Balance Sheet and LowTrading Multiple Creates an Attractive Entry Point for the Stock
16+ Year Inventory on Core Haynesville Position Provides 1+ Tcf of Resource Potential on Acreage Held By Production
A Continued Reduction in Per Unit Cash Costs Driven By HighVolume Low Lifting Costs Wells
Improving Natural Gas Price Environment Setting Company Up for Top Tier Free Cash Flow Potential for 2021
August, 2020 20