Earnings Call 2Q20goodrichpetroleumcorp.investorroom.com/download/Earnings...Cash Opex: $1.01/Mcfe;...

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


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


(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


(7) CRKCook 21-28 HC #2


3,798#/ft

(6) CRK Cook 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) GDP Melody Jones 20H-1


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


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



Severance TaxPayout or 24 month tax holiday;




D&C Capex $8.9 MM

Facilities/Tubing

Capex $0.408 MM, included in D&C Capex



$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


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


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



Severance TaxPayout or 24 month taxholiday;




D&C Capex $10.7 MM

Facilities/TubingCapex

$0.485 MM, included in D&C Capex



$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


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

Earnings Call 2Q20goodrichpetroleumcorp.investorroom.com/download/Earnings...Cash Opex: $1.01/Mcfe;...

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