Management Presentation and Haynesville Shale Overview...

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


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


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




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




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


EUR 18.75 Bcf (2.5 Bcf/1,000’)

Sales Gas BTU

Price

Adjustment

1.022

Pricing

Differentials









D&C Capex $10.2 MM




$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 10,000' Lateral


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%


Gas

Pri

ce

Gas

Pri

ceNovember 2017

16


EUR 25.0 Bcf (2.5 Bcf/1,000’)

Sales Gas BTU

Price

Adjustment

1.022

Pricing

Differentials









D&C Capex $12.4 MM




$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


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%


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

Management Presentation and Haynesville Shale Overview...

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