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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
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
IP: 34,000 Mcf/d8,350’ Lateral
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
IP: 44,000 Mcf/d10,000’ Lateral
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)
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 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
Recent Haynesville 7,500' Wells
Company Type Curve: EUR: 18.75 Bcf (2.5 Bcf/1,000 ft)
Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft)
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
7,500' Laterals Cum Production (MCF)
Company Type Curve: EUR: 18.75 Bcf (2.5 Bcf/1,000 ft)
Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft)
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
Recent Haynesville 10,000' Wells
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
10,000' Laterals Cum Production (MCF)
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
March 2018 22
Type CurveAssumptions Louisiana
EUR 18.75 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 $10.2 MM
Facilities Capex $0.17 MM, included in D&C Capex
Spud to 1st Sale 60 Days
PV10 (M$)($3.00/Mcf Pricing)
$7,869
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg
Dai
ly P
rodu
ctio
n (M
cfpd
)
Months
7,500' Lateral Type Curve
Economic EUR’s vary depending on gas price assumptions.
7,500' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
EUR Capex(Mmcfe) ($M)
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
March 2018 23
Type CurveAssumptions Louisiana
EUR 25.0 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 $12.4 MM
Facilities Capex $0.17 MM, included in D&C Capex
Spud to 1st Sale 60 Days
PV10 (M$)($3.00/Mcf Pricing)
$11,731
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg
Dai
ly P
rodu
ctio
n (M
cfpd
)
Months
10,000' Lateral Type Curve
Economic EUR’s vary depending on gas price assumptions.
10,000' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
EUR Capex(Mmcfe) ($M)
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
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