management presentation and haynesville shale overview...
TRANSCRIPT
Management Presentation and Haynesville Shale Overview
– 3Q17 Earnings Call
November 2017
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.
November 2017 2
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
20+ Year Inventory (1.2 Tcf of Resource Potential) of Haynesville Core Locations at Current Capex
Budget, with Significant Option Value on Oil
TRADING PLATFORM:
NYSE American: (“GDP”)
PLAN & CATALYSTS
Increasing Activity in Haynesville - New Completion Methodology Transformational for the Play and the
Company. Two Recent ROTC Wells Have Produced Approximately 13.4 Bcf in 10 Months
Guidance to 55,000 – 60,000 Mcfe Per Day Dec17 – Jan18 Rate, Approximately 50% Growth From
~40,000 Mcfe Per Day Average for 3Q17
Low Finding and Lifting Costs Creating Substantial Growth in EBITDA and Attractive Full Cycle Returns.
Minimum Outspend as Volumes and Cash Flow Grow Through 2018
November 2017
4
Capital Expenditures:
Capital Expenditures of $5.4 Million in 3Q17 and $25.8 Million Through 3Q17 Spent on Drilling and
Completing Haynesville Wells. Full Year Capex Guidance Back to Original Guidance of $40-50 Million Due
to an Additional 4 Non-Operated Wells (Drilled 4Q17, Completed 1Q18)
Production:
Production Grew By 11% Sequentially With No Wells Added During the Quarter. Three Additional Long-
Lateral Haynesville Wells Commence Back-to-Back Fracking Operations Late Fourth Quarter
Cash Flow:
Margin Expansion From Rapidly Growing Volumes, Low Finding & Development Costs and Decreasing
Per Unit Lifting Costs.
3Q17 Operating Costs Per Unit Down Sequentially Versus 2Q17
Pro Forma Adjusted EBITDA of $8.8 Million Up Significantly Over 2Q17
Balance Sheet:
Quarter End Cash Balance - $31.7 Million
Total Debt - $62.1 Million
Net Debt - $30.4 Million
November 2017
5
Operations:
Franks 25&24 No. 1 (69% WI, 50% NRI) Completion Will Provide Material Cost Savings
Due to Lower Completion Costs from Fracking Three Wells Back-to-Back
Wurtsbaugh 25&24 Nos. 2 & 3 Wells (55% WI, 39% NRI) Currently Drilling, Both 7,500’
Laterals From 2-Well Pad, With Frac Dates Right After Franks
Two 10k Laterals on Cason – Dickson Unit in Thorn Lake (Red River Parish) Expected to
Spud in November
Bolt-On Acreage Acquisitions/Acreage Swaps
Acreage Swap:
Over 25 Bcf of Proved Undeveloped Reserves (YE16 Report) Picked Up During the
Quarter With Acreage Swap, Along with Expanding the Company’s Long Lateral and
Operated Inventory
Potential for Additional Swaps and Bolt-On Acquisitions
November 2017
6
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
2015 2016 2Q17 3Q17 Dec17 -
Jan18
Eagle Ford
TMS
Haynesville
Total
November 2017
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 $3.01
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
Dec18 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
7November 2017
8
Texas
Mississippi
Louisiana
TUSCALOOSA MARINE SHALE:
Gross (Net) Acres (YE16): 102,000 (71,000)Proved Reserves (YE16 - SEC) 16.8 BcfeObjectives: Tuscaloosa Marine Shale
EAGLE FORD SHALE:
Gross (Net) Acres (YE16): 32,000 (14,000)Proved Reserves (YE16 – SEC) 0Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime
HAYNESVILLE / BOSSIER SHALEANGELINA RIVER TREND (“ART”)
Gross (Net) Acres (Current): 12,500 (7,500)Proved Reserves (YE16 - SEC) 4.2 BcfeObjective: Haynesville & Bossier Shale
HAYNESVILLE SHALE - CORE
Gross (Net) Acres (Current): 37,500 (18,500)Proved Reserves (YE16 - SEC) 281.6 BcfeObjective: Haynesville Shale
November 2017
November 2017 9
North Louisiana (Haynesville)
Total Gross/Net Acres:
38,000/18,500
Average WI/NRI: 40%/29%
Acreage HBP: 100%
89 total producing wells (17
Operated)
Approximately 250 gross (100 net)
potential locations on 880’ spacing
Operator for Approximately 50% of
the NLA core position
CHK Joint Venture on most of the
remaining 50% 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: 12,500/
7,500
Average WI/NRI: 61% / 48%
5 producing wells (5 Operated)
Offset Activity Proving Up Potential
of Acreage with New Completion
Design
HAYNESVILLE SHALE~26,000 net Ac
Greenwood-Waskom /
Metcalf/Longwood4,700 Net Ac
Swan Lake/Thorn
Lake1,300 Net Ac
ART7,500 Net
Ac
BethanyLongstreet
12,500 Net Ac
Rig Source: Ulterra Bits
Haynesville Recent Industry Activity
November 2017 10
Covey ParkOden 35-26 H1IP: 21,900 Mcf/d
6,870’ Lateral3,683#/ft
CHKROTC 1 & 2
10,000’ LateralsIP: 72,000 Mcf/d
13.4 Bcf in 10 months
CHK3 Units
5 Potential 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
CRK14 Permitted or Potential Wells10,000’ Laterals
GDPWurtsbaugh 25-24
#2&3 Drilling
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
Waiting on Completion
~10,000’ Lateral
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
2 Permitted Wells15,000’ Laterals
Covey ParkTucker 31-6C H1IP 18,045 Mcf/d
7,466’ Lateral
Covey Park9 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
EXCO1 Drilling
2 Waiting on Comp5,000’ Laterals
CRKHUNTER 28-21HC 1&2
Drilling /WOC10,000’ Laterals
GDPFranks 25&24 #1
Waiting on Completion
10,000’ Lateral
GDPWurtsbaugh 25-24 #1
8,800’ LateralIP: 31,000 Mcf/d
GDPCason-Dickson 14-23
#1&2Spud 11/17
10,000’ Laterals
CRKFLORSHEIM 9-16 HC
#1&2Permitted
10,000’ Laterals
100
1,000
10,000
100,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36
Gas
Pro
du
ctio
n, M
cfp
d
Months
Recent Haynesville 4,600' 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)
GDP, Wurtsbaugh 26H 1-ALT(5,000#/ft Frac)
Average Well Performance 1 Well (4,749#/ft Frac)
Average Well Performance 7 Wells (3,357#/ft Frac)
11
100
1,000
10,000
100,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36
Gas
Pro
du
ctio
n, M
cfp
d
Months
Recent Haynesville 7,500' 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)
ART Average Well Performance2 Wells (2,700#/ft Frac)
Average Well Performance 21 Wells (2,800#/ft Frac)
GDP, Wurtsbaugh 25&24 1 (8,800' LL, 4,000#/ft Frac)
21 Wells 20 Wells 15 Wells
12
100
1,000
10,000
100,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36
Gas
Pro
du
ctio
n, M
cfp
d
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 Performance3 Wells (3,200#/ft Frac)
GDP, Wurtsbaugh 25&24 1 (8,800' LL, 4,000#/ft Frac)
ROTC 2-Well Average (4,000#/ft)
13
14
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 Tax24 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)
$5,002
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg D
aily P
roducti
on (M
cfp
d)
Months
4,600' Lateral Type Curve
Economic EUR’s vary depending on gas price assumptions.
4,600' Lateral 7,500' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
EUR Capex
(Mmcfe) ($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
Pri
ce
Gas
Pri
ceNovember 2017
15
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 Tax24 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)
$7,869
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg D
aily P
roducti
on (M
cfp
d)
Months
7,500' Lateral Type Curve
Economic EUR’s vary depending on gas price assumptions.
7,500' Lateral 10,000' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
EUR Capex
(Mmcfe) ($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
Pri
ce
Gas
Pri
ceNovember 2017
16
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 Tax24 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)
$11,731
100
1,000
10,000
100,000
0 20 40 60 80 100 120
Avg D
aily P
roducti
on (M
cfp
d)
Months
10,000' Lateral Type Curve
Economic EUR’s vary depending on gas price assumptions.
10,000' Lateral
IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex)
EUR Capex
(Mmcfe) ($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
Pri
ce
Gas
Pri
ceNovember 2017
Strong 3Q17 Growth in Adjusted EBITDAX - Increased Production On A Much Lower Unit Cost Structure. This Will Continue, Which Will Drive Our Margin Expansion
One Operated Rig Running, With 3 Long-Lateral Wells Completed By End of the Year and 4 Additional Long-Lateral Wells Completed in 1Q18
Liquidity Increasing From Growing Cash Flow and an Expanding Borrowing Base
Focus on Growth in Cash Flow and Return on Capital Employed With Minimum Outspend
Maintain Low Debt Metrics. Net Debt is Currently Less Than 1X Annualized 3Q17 Pro forma Adjusted EBITDA
17November 2017