earnings call slides - 4q18 1 - goodrich...

Earnings Call Slides – 4Q18

March 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.

March 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

4Q18 Average Production of 99.2 MMcfe/d

4Q18 Adjusted EBITDA of $21.4 Million

4Q18 Net Income of $8.1 Million ($0.68/Share – Basic)

Preliminary 2019E guidance of 140 MMcfe/d on $90-$100 Million in capital spending

TUSCALOOSA MARINE SHALE:Gross (Net) Acres (4Q18): 50,500 (35,100)Proved Reserves (YE18 – SEC) 9 BcfeObjectives: Tuscaloosa Marine Shale

EAGLE FORD SHALE:Gross (Net) Acres (4Q18): 28,200 (12,300)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 (4Q18): 34,000 (20,000)Proved Reserves (YE18 - SEC) 471 BcfeObjective: Haynesville Shale

>1.0 Tcf of natural gas resource potential in North Louisiana . Fully de-risked

OPERATED OPPORTUNITY

STRONG FUNDAMENTALS

4Q18 HIGHLIGHTS & GUIDANCE

TexasLouisiana

Mississippi

March 2019 3

0

100

200

300

400

500

600

2015 2016 2017 2018*

ETX

TMS

NLA -Haynesville

Total

303

55

428

480

SEC PROVED RESERVES (Bcfe)

4March 2019

* Year-End 2018 PV10 of $418 Million

(USD in thousands)

Cash $4,068

Debt

Senior Credit Facility 27,000

2L Convertible Notes (PIK) 53,691

Total Debt 80,691

Total Net Debt $76,623

March 2019 5

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: 11 (9.8) Average Net Lateral Length: 7,000’ Percentage Operated (Net): 100%

Net Capital Allocation

Bethany-Longstreet 67% Thorn Lake 33%

Quarterly Completion Cadence

1Q19 2 Gross (2.0 Net) 2Q19 4 Gross (3.4 Net) 3Q19 3 Gross (2.7 Net) 4Q19 2 Gross (1.7 Net) Total 11 Gross (9.8 Net)

March 2019 6

March 2019

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

100,000 120,000 140,000 160,000

2017 1Q18 2Q18 3Q18 4Q18 2019*Est.

TMS

Haynesville

Total

7* Mid-Point of Guidance

0.00

2.00

4.00

6.00

8.00

10.00

GDP

EV/EBITDA

March 2019Peer Group Includes: APA,APC,AR,AREX,AXAS,BCEI,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DVN,ECA,ECR,EOGEPE,EQT,ESTE,FANG,GPOR,HK,HPR,JONE,LLEX,LONE,LPI,MCF,MPO,MTDR,MUR,NBL,NFX,OAS,PDCE,PE,QEP,PXD,REN,RRC,SBOW,SD,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company 8

-2.00

0.00

2.00

4.00

6.00

8.00

10.00

GDP

NET DEBT/EBITDA

March 2019

Peer Group Includes: APA,APC,AR,AREX,AXAS,BCEI,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DVN,ECA,ECR,EOGEPE,EQT,ESTE,FANG,GPOR,HK,HPR,JONE,LLEX,LONE,LPI,MCF,MPO,MTDR,MUR,NBL,NFX,OAS,PDCE,PE,QEP,PXD,REN,RRC,SBOW,SD,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company

9

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

GDP

Capital Efficiency

March 2019

10

Peer Group Includes: AXAS,BCEI,COG,CPE,CRK,CXO,ECA,ECR,ESTE,FANG,GDP,HK,HPR,LLEX,LONE,MTDR,MUR,OAS,PDCE,PXD,REN,SBOW,SM,SRCI,WPX

Source: Bloomberg, Company

March 2019 11

North Louisiana (Haynesville)

Total Gross/Net Acres: 34,000/20,000

Average WI/NRI: 59%/43%

Acreage HBP: 100%

102 total producing wells (25 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: 7,000/ 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 Recent Industry Activity

March 2019 12

(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) EXCORed Oak Timber 6-7HC

9,500’ LateralIP: 22,400 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 #1IP: 27,500 Mcf/d

6,100’ Lateral

(14) GDPLoftus 27&22 #1

Waiting on Completion

7,500’ Lateral

(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

1

2

3

4

56

7

8

9

10‐16

1718‐20

21

22

13

59 59 59 59 59 59 59 59 59 59 59 59 5951

4642 42 40 39 37 36

31 29 28

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

Well C

ount

Gas Produ

ction, M

cfpd

Months

Recent Haynesville 4,600' Wells

Company Type Curve: EUR: 11.5 Bcf (2.5 Bcf/1,000 ft)


GDP, 4 Well Average(Avg 4,100' LL; 4,200 #/ft Frac)

Average Well Performance 59 Wells (3,400 #/ft Frac)

SI ‐ Offset Fracs

March 2019

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

0 5 10 15 20 25 30 35

Cum Produ

ction (M

CF)

Months

4,600' Laterals Cum Production (MCF)




GDP, 4 Well Average(4,100' LL; 4,200 #/ft Frac)

14March 2019

87 87 87 87 87 87 87 87 87 87 87 87 8474 72

55 54 51 4741 39

32 30 28 28 26 2422

1714 13

1

10

100

1000

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

Well Cou

nt

Gas Produ

ction, M

cfpd

Months



Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft)


GDP, 5 Well Average(Avg 7,600' LL, 4,500 #/ft Frac)

SI ‐ Offset Fracs

March 201915

16March 2019

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

0 5 10 15 20 25 30 35

Cum Produ

ction (M

CF)

Months



Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft)

Average Well Performance 87 Well (3,100 #/ft Frac)

GDP, 5 Well Average(Avg 7,600' LL, 4,500 #/ft Frac)

35 35 35 35 35 35 35 35 35 35 35 35 3529

22

17 1714

12 11 108 8

65 5

4 4 4

1

10

100

1000

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

Well Cou

nt

Gas Produ

ction, M

cfpd

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)

Average Well Performance35 Wells (3,200 #/ft Frac)

GDP, 8 Well Average(Avg 9,500' LL; 3,700 #/ft)

ROTC Clean out Lateral & Ran Tubing

17March 2019

0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

12,000,000

0 5 10 15 20 25 30 35

Cum Produ

ction (M

CF)

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)

Average Well Performance35 Wells (3,200 #/ft Frac)

GDP, 6 Well Average(Avg 9,500' LL; 3,700 #/ft)

March 201918

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

GDP

BCFE

March 2019Peer Group Includes: Aethon, BHP, Chesapeake, Comstock, Covey Park, Ensight, Exco, Geosouthern, Goodrich, Indigo, QEP, Vine

Source: RS Energy Group, Company ‐2/5/19 (Wells Completed After 1/1/16)19

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

GDP

BCFE

March 2019Peer Group Includes: Aethon, BHP, Chesapeake, Comstock, Covey Park, Exco, Geosouthern, Goodrich, Indigo, QEP, Vine

Source: RS Energy Group, Company ‐ 2/5/19 (Wells Completed After 1/1/16)20

0.0

1.0

2.0

3.0

4.0

5.0

6.0

GDP

BCFE

March 2019Peer Group Includes: Aethon, BHP, Chesapeake, Comstock, Covey Park, Exco, Geosouthern, Goodrich, Indigo, QEP, Vine

Source: RS Energy Group, Company ‐ 2/5/19 (Wells Completed After 1/1/16)21

March 2019 22

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.

4,600' LateralIRR Sensitivity Analysis (IRR sensitivity to EURs and Capex). IRRs

Incorporate Early Time Outperformance

EUR Capex(Mmcfe) ($M)

90% 100% 110% 90% 100% 110%

Gas Pric

e 2.50 14.7% 25.0% 37.3%

Gas Pric

e 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.

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

March 2019 23


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





90% 100% 110% 90% 100% 110%

Gas Pric

e 2.50 31.4% 44.7% 60.0%

Gas Pric

e 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%


100

1,000

10,000

100,000

0 20 40 60 80 100 120

Avg

Dai

ly P

rodu

ctio

n (M

cfpd

)

Months


March 2019 24


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





90% 100% 110% 90% 100% 110%

Gas Pric

e 2.50 40.1% 55.4% 72.9%

Gas Pric

e 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%


100

1,000

10,000

100,000

0 20 40 60 80 100 120

Avg

Dai

ly P

rodu

ctio

n (M

cfpd

)

Months


Strong EBITDA Growth to Continue in 2019 Driven By Margin Expansion from Substantial Increase in Production and Lower Unit Cost Structure

One Operated Rig Running Currently, Expect a 2nd Rig Later in the Year

Focus on Growth in Cash Flow and Return on Capital Employed With Manageable Outspend Through 2019 While Keeping Debt Metrics 1.0X to 1.5X EBITDA

Strategic Acquisitions That Add Inventory But Don’t Dilute Down Best in Class Quality of Inventory

March 2019 25

A-1March 2019

Period Natural Gas Volumes (Mcfpd) Natural Gas Price

1Q19 80,000 $2.93 2Q19 70,000 $2.86 3Q19 70,000 $2.86 4Q19 70,000 $2.86 1Q20 40,000 $2.81

Period Oil Volumes (Bopd) Oil Price

1Q19 325 $51.08 2Q19 325 $51.08 3Q19 300 $51.08 4Q19 300 $51.08

March 2019 A-2

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