Earnings Call Slides – YE17goodrichpetroleumcorp.investorroom.com/download/YE17... · 2018. 4. 10. · other important factors that could cause actual results to differ materially

Earnings Call Slides – YE17

March 2018

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 2018 2

March 2018 3

Value and Growth Investment Opportunity with an Enhanced Balance Sheet, Very High Leverage to the Haynesville and the Ability to Rapidly Grow Volumes, Reserves and EBITDA

ASSETS:

Haynesville Shale, Eagle Ford Shale and TMS

15+ Year Inventory (1.2 Tcf of Resource Potential) of NLA Haynesville Core Locations at CurrentCapex Budget, with Significant Option Value on Oil

TRADING PLATFORM:

NYSE American: (“GDP”)

PLAN & 2018 CATALYSTS

Rapid Growth in Natural Gas Production and EBITDA, While Maintaining Low Debt Metrics

Increasing Activity in Haynesville - New Completion Methodology Transformational for the Play.Two additional 7,500 ft wells reported at a combined rate of 55,000 Mcfe/day

East Texas Asset Sale of $23 Million Provides Additional Liquidity and Acceleration of DevelopmentActivities in Core North Louisiana Haynesville in 2H18

Capex Budget of $65 - $75 Million Haynesville-Focused Capex Program to Drill an Estimated 16gross (6.5 net) wells, with an Average Lateral Length of Approximately 9,000 feet

Guidance to 77,000 – 83,000 Mcfe Per Day Average for the Year with Low Lifting Costs CreatingSubstantial Growth in EBITDA

March 2018 4

Capital Expenditures:

Capital Expenditures of $16.0 Million in 4Q17 and $41.8 Million for the Year, Versus Guidance of $40-50Million. Maintain 2018 Guidance of $65 – 75 Million, but likely acceleration in 2H18

Production:

No New Wells Were Added During the Quarter and Production Averaged 31.2 MMcfe/day, Affected ByDelays and Shut-Ins Due to Frac Operations

Three operated wells recently added have combined gross IP of 85 MMcfe/day Current Net Production Rate of Approximately 60 MMcfe/day 2 Additional 10,000’ (92% WI) Wells Scheduled to be Fracked Early MarchMaintain Yearly Guidance with Potential to Accelerate Development in 2H18

Cash Flow:

Adjusted EBITDA to Grow Dramatically in 2Q - 4Q18

Balance Sheet:

Quarter End Cash Balance - $26 Million Total Debt - $63.7 Million Net Debt - $37.7 Million

Pro Forma For Asset Sale – Net Debt of Approximately $15 Million

0

100

200

300

400

500

2015 2016 2017

ETX

TMS

NLA -Haynesville

Total

303

55

428

SEC PROVED RESERVES (Bcfe)

5March 2018

USD in thousands)

Cash $26,000

Debt

Senior Credit Facility 16,700

2L Convertible Notes (PIK) 47,000

Total Debt 63,700

Total Net Debt $37,700

March 2018 6

March 2018

- 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000

Eagle Ford

TMS

Haynesville

Total

7* Mid-Point of Guidance

0

2

4

6

8

10

12

14

GDP

EV/EBITDA

March 2018Peer Group Includes: APA,APC,AR,AREX,AXAS,BBG,BCEI,CHK,CLR,COG,CPE,CRC,CRK,CRZO,CXO,DVN,ECA,ECR,EOG,EPE,EQT,FANG,GPOR,HK,JONE,LNGG,LONE,LPI,MCF,MPO,MTDR,MUR,NBL,NFX,OAS,PDCE,PE,PQ,QEP,PXD,REN,REXX,RRC,SBOW,SD,SGY,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company

8

-5

0

5

10

15

20

GDP

NET DEBT/EBITDA

March 2018

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

9

$- $100,000 $200,000 $300,000 $400,000 $500,000 $600,000 $700,000 $800,000

GDP

Growth in EBITDA

March 2018Peer Group Includes: APA,APC,AR,AREX,AXAS,BBG,BCEI,CHK,CLR,COG,CPE,CRC,CRK,CRZO,CXO,DVN,ECA,ECR,EOG,EPE,EQT,FANG,GPOR,LONE,LPI,MCF,MPO,MTDR,MUR,NBL,NFX,OAS,PDCE,PE,PQ,QEP,PXD,REN,REXX,RRC,SBOW,SGY,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company

10

$-

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

GDP

Capital Efficiency

Source: Company and RS Energy Group (9/17)

March 2018Peer Group Includes: APA,AR,AREX,BBG,BCEI,CHK,CLR,CNX,COG,CPE,CRC,CRK,CRZO,CXO,DVN,ECA,ECR,EGN,EOG,EPE,EQT,ESTE,FANG,GPOR,GST,HES,HK,JONE,LPI,MTDR,MUR,NFX,OXY,PDCE,PE,QEP,RVAC,PXD,REXX,RRC,RSSP,SM,SN,SRCI,SWN,UPL,WLL,WRD,XEC

11

March 2018

Texas

Mississippi

Louisiana

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres (YE17): 87,600 (64,900)Proved Reserves (YE17 - SEC) 12.7 BcfeObjectives: Tuscaloosa Marine Shale

EAGLE FORD SHALE:

Gross (Net) Acres (YE17): 32,400 (14,100)Proved Reserves (YE17 – SEC) 0Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime

HAYNESVILLE / BOSSIER SHALEANGELINA RIVER TREND (“ART”)

Gross (Net) Acres (Current): 8,400 (3,200)Proved Reserves (YE17 - SEC) 4.0 BcfeObjective: Haynesville & Bossier Shale

HAYNESVILLE SHALE - CORE

Gross (Net) Acres (YE17): 38,600 (18,900)Proved Reserves (YE16 - SEC) 411.3 BcfeObjective: Haynesville Shale

12

Presenter

Presentation Notes

3/17/16 – YE15 Reserves updated.

March 2018 13

North Louisiana (Haynesville)

Total Gross/Net Acres:38,600/18,900

Average WI/NRI: 40%/29%

Acreage HBP: 100%

92 total producing wells (20Operated)

Approximately 250 gross (100 net)potential locations on 880’ spacing

Operator for Approximately 50% ofthe NLA core position

CHK Joint Venture on most of theremaining 50% of NLA CoreAcreage

Continuing to Look For Bolt-OnOpportunities

Shelby Trough/Angelina River Trend (ART)

Haynesville and Bossier Shales:

Total Gross/Net Acres: 8,400/3,200

Average WI/NRI: 38% / 30%

Recent Sale of a Producing Wellsand a Portion of the Company’sAcreage

HAYNESVILLE SHALE~22,100 net Ac

Greenwood-Waskom /

Metcalf/Longwood4,700 Net Ac

Swan Lake/Thorn

Lake1,300 Net Ac

ART3,200 Net

Ac

BethanyLongstreet

12,900 Net Ac

Rig Source: Ulterra Bits

Haynesville Recent Industry Activity

March 2018 14

Covey ParkOden 35-26 H1IP: 21,900 Mcf/d

6,870’ Lateral3,683#/ft

CHKROTC 1 & 2

10,000’ LateralsIP: 72,000 Mcf/d

16 Bcf in 14 months

CHK3 Units

2 Drilling7 Permitted 10,000’3 Permitted 7500’

Covey ParkLowery 27H1

IP3: 11,700 Mcf/d4,536’ Lateral

2,720#/ft

Covey ParkLowery 27H2

IP: 11,700 Mcf/d4,536’ Lateral

2,793#/ft

CHKNguyen 5&8-15-14HC

002-ALTIP: 15,800 Mcf/d

7,668’ Lateral

CHKCA 12&13-15 -15 HC

002-ALTIP: 18,300 Mcf/d

9,373’ Lateral

CHKNguyen 5&8-15-14HC

001-ALTIP: 16,896 Mcf/d

7,659’ Lateral

CHKCA 12&13-15 -15 HC

001-ALTIP: 38,000 Mcf/d

9,814’ Lateral

CRK3 Permitted

6 Drilled / Waiting on Completion Wells10,000’ Laterals

GDP-Wurtsbaugh 25-24 #2&3

7,500’ LateralsIP: 25,000 Mcf/dIP: 29,000 Mcf/d

GDP Wurtsbaugh 264,600’ Lateral

IP: 22,000 Mcf/d

CHK WILL 22&27&34-15-15HC - 001-ALT


EXCORed Oak Timber 6-7HC

9,500’ LateralIP: 22,400 Mcf/d

Covey ParkOden 35-2 H1

IP : 22,500 Mcf/d7,442’ Lateral

3,585#/ft

CHK Black 1H


VineHA RA SU74;L L

Golson 3 - 003-ALTIP: 18,800 Mcf/d

4,661’ Lateral

CHKGEPH Unit

Two 15,000’ LateralsDrilling

Covey ParkTucker 31-6C H1IP 18,045 Mcf/d

7,466’ Lateral

Covey Park4 Permitted Wells5 Potential Wells

8x ~ 7,500’ Laterals1x ~ 10,000’ Lateral

CHKSIX J 1&12-14-15 HC

001-ALTIP: 35,000 Mcf/d~10,000’ Lateral

CHKGLD 36&1&12-15-15

HC 001-ALTIP: 42,000 Mcf/d

8,002’ Lateral

EXCO3 Waiting on Comp

5,000’ Laterals

CRKHUNTER 28-21HC 1&2 IP: 27,000 Mcf/d each

9,200’ Laterals

GDPFranks 25&24 #1IP: 30,000 Mcf/d

9,600’ Lateral

GDPWurtsbaugh 25-24 #1

8,800’ LateralIP: 31,000 Mcf/d

GDPCason-Dickson 14-23

#1&210,000’ Laterals

Completing Mar’ 18

CRKFLORSHEIM 9-16 HC

#1&2 Drilled10,000’ Laterals

Waiting on completion

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

Gas

Pro

duct

ion,

Mcf

pd

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, Wurtsbaugh 26H 1-ALT(5,000#/ft Frac)

Average Well Performance 56 Well (3,556#/ft Frac)

March 201815

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

0 5 10 15 20

Cum

Pro

duct

ion

(MCF

)

Months

4,600' Laterals Cum Production (MCF)



GDP, Wurtsbaugh 26H 1-ALT(5,000#/ft Frac)

Average Well Performance 56 Wells (3,556#/ft Frac)

March 201816

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

Gas

Pro

duct

ion,

Mcf

pd

Months




ART Average Well Performance2 Wells (2,700#/ft Frac)

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

GDP, Wurtsbaugh 25&24 1(8,800' LL, 4,000#/ft Frac)

March 2018 17

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

Cum

Pro

duct

ion

(MCF

)

Months




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

GDP, Wurtsbaugh 25&24 1(8,800' LL, 4,000#/ft Frac)

ART Average Well Performance2 Wells (2,700#/ft Frac)

March 2018 18

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

Gas

Pro

duct

ion,

Mcf

pd

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 (3,100#/ft Frac)

GDP, Wurtsbaugh 25&24 1 (8,800' LL, 4,000#/ft Frac)

ROTC 2 Well Average (4,000#/ft)

March 201819

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

9,000,000

10,000,000

0 5 10 15 20

Cum

Pro

duct

ion

(MCF

)

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)

ROTC 2 Well Average (4,000#/ft)

Average Well Performance35 Wells (3,100#/ft Frac)

March 2018 20

March 2018 21

Type CurveAssumptions Louisiana

EUR 11.5 Bcf (2.5 Bcf/1,000’)

Sales Gas BTU Price Adjustment

1.022

Pricing Differentials

Average - NYMEX less $0.60 / MMBtu(includes transportation)

Fixed Opex Fixed Opex: $3,676 / month

Variable Opex $0.05 / Mcf

Severance Tax 24 month tax holiday;thereafter, $0.16 / Mcf

Ad Val Tax $0.03 / Mcf

Royalty Burden 27.0%

D&C Capex $8.3 MM

Facilities Capex $0.17 MM, included in D&C Capex

Spud to 1st Sale 60 Days

PV10 (M$)($3.00/Mcf Pricing) $5,002

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

Economic EUR’s vary depending on gas price assumptions.

4,600' Lateral

IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)

EUR Capex(Mmcfe) ($M)

90% 100% 110% 90% 100% 110%2.50 15.2% 22.9% 33.9% 2.50 31.7% 22.9% 16.0%2.75 25.4% 36.3% 49.2% 2.75 49.0% 36.3% 26.5%3.00 37.8% 52.7% 70.4% 3.00 70.2% 52.7% 39.2%3.50 70.3% 96.2% 127.5% 3.50 127.3% 96.2% 72.6%

Ownership:WI 100% - NRI 73%Pricing: Flat Pricing

Gas

Pric

e

Gas

Pric

e

Presenter

Presentation Notes

V:\2. Projects\LA Haynesville\_Economic Analysis\2017.02.20 - Hville 4,600_7,500_10,000_TC\2016.02.20 Economic Sensitivity Summary.xlsx

March 2018 22


EUR 18.75 Bcf (2.5 Bcf/1,000’)


1.022








D&C Capex $10.2 MM



PV10 (M$)($3.00/Mcf Pricing)

$7,869

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



90% 100% 110% 90% 100% 110%2.50 20.6% 28.9% 38.5% 2.50 38.3% 28.9% 21.4%2.75 31.6% 43.1% 56.5% 2.75 56.3% 43.1% 32.7%3.00 44.7% 60.1% 78.2% 3.00 78.0% 60.1% 46.1%3.50 78.1% 104.0% 134.9% 3.50 134.7% 104.0% 80.4%

Ownership: WI 100% - NRI 73%Pricing: Flat Pricing

Gas

Pric

e

Gas

Pric

e

Presenter

Presentation Notes


March 2018 23


EUR 25.0 Bcf (2.5 Bcf/1,000’)


1.022








D&C Capex $12.4 MM



PV10 (M$)($3.00/Mcf Pricing)

$11,731

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



90% 100% 110% 90% 100% 110%2.50 27.4% 37.6% 49.5% 2.50 49.4% 37.6% 28.4%2.75 40.8% 55.0% 71.4% 2.75 71.3% 55.0% 42.1%3.00 56.9% 75.9% 98.2% 3.00 98.1% 75.9% 58.6%3.50 98.1% 130.4% 169.3% 3.50 169.1% 130.4% 100.9%

Ownership: WI 100% - NRI 73%Pricing: Flat Pricing

Gas

Pric

e

Gas

Pric

e

Presenter

Presentation Notes


Strong EBITDA Growth in 2018 Driven By Substantial Increase inProduction On A Much Lower Unit Cost Structure

One Operated Rig Running Currently, With 2 Additional 10,000’Wells Completed in March. Two Non-Operated Rigs RunningCurrently to Drill 6 Gross (0.5 Net) Wells

Growth in Liquidity From the Asset Sale and Higher FutureBorrowing Base Driven From Proved Reserve Adds

Focus on Growth in Cash Flow and Return on Capital Employed WithMinimum Outspend

Strategic Acquisitions That Add Inventory While Keeping DebtMetrics Less Than 1.5X. Net Debt Currently Less Than 1XAnnualized 3Q17 Adjusted EBITDA

March 2018 24

A-1March 2018

Period Natural Gas Volumes (Mcfpd) Natural Gas Price

4Q17 6,000 $3.20 12,000 $3.00 – 3.60 Collar 1Q18 20,000 $3.00 2Q18 25,275 $3.03 3Q18 38,000 $3.02 4Q18 39,000 $3.02 1Q19 34,000 $3.03 2Q19 7,500 $3.03 3Q19 7,500 $3.03 4Q19 7,500 $3.03

Period Oil Volumes (Bopd) Oil Price

Dec17 400 $51.08 1Q18 400 $51.08 2Q18 400 $51.08 3Q18 350 $51.08 4Q18 350 $51.08 1Q19 325 $51.08 2Q19 325 $51.08 3Q19 300 $51.08 4Q19 300 $51.08

March 2018 A-2

Production 2018E

Annual Net Production: 28.25 - 30.25 Bcfe Avg Daily Production: 77,000-83,000 Mcfe/d Natural Gas: 95%

Capex (MM) $65 - 75

Unit Costs (Per Mcfe)

Basis Henry Hub Less: $0.12 – 0.15 LLS Less: $2.00 – 2.25

LOE $0.30 – 0.40 Taxes $0.07 – 0.11 Transportation $0.30 – 0.40 G&A (Cash) $0.40 – 0.50

Activity Wells

Gross (Net) Wells: 16 (6.5) Average Net Lateral Length: 9,000’ Percentage Operated (Net): 84%

Net Capital Allocation

Bethany-Longstreet 70% Thorn Lake 30%

Quarterly Completion Cadence

1Q18 7 Gross (3.9 Net) 2Q18 4 Gross (0.3 Net) 3Q18 2 Gross (1.7 Net) 4Q18 3 Gross (0.6 Net)

March 2018 A-3

Earnings Call Slides – YE17goodrichpetroleumcorp.investorroom.com/download/YE17... · 2018. 4. 10. · other important factors that could cause actual results to differ materially

Documents