Earnings Call Slide Deck March 2, 2017 March 2017 This presentation - - PowerPoint PPT Presentation

Earnings Call Slide Deck – March 2, 2017

March 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,

• fficers 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

• ther 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 2017 2



Introduction



Disclaimer



Table of Contents



Company Highlights



Capitalization Table



Core Properties



Company Leasehold Position



Haynesville Shale Opportunity



Haynesville Shale Geologic Characteristics



Haynesville Shale Completion Evolution



Recent Industry Activity



Development Plan – Spacing



Economics



Why Invest in Goodrich Petroleum March 2017 3 Page 1 2 3 4 5 6 7 8 9 14 17 21 22 25

March 2017 4

• CAP TABLE: (12/31/16)
• Cash ~ $37 Million
• Total Net Debt - $21 Million
• Basic Shares Outstanding – 8.6 Million (11.1 Million with Costless Warrants)
• TRADING PLATFORM:
• Current - OTC-QX Market (“GDDP”)
• Plan – Up-list to NYSE
• ASSETS:
• Haynesville, Eagle Ford and TMS
• CATALYST:
• New Haynesville Completion Methodology Transformational for the Play and the Company
• PRELIMINARY 2017 PLANS:
• $40 - 50 Million Haynesville Capex Program

(USD in thousands) Cash $37,000 Debt Senior Credit Facility 17,000 New 2L Notes (PIK) 41,000 Total Debt 58,000 Total Net Debt $21,000

March 2017 5

March 2017 6 Texas Mississippi Louisiana

TUSCALOOSA MARINE SHALE:

Gross (Net) Acres: 215,100 (155,700) Proved Reserves (YE’16 - SEC) 16.8 Bcfe Objectives: Tuscaloosa Marine Shale

EAGLE LE FORD SHALE: E:

Gros

• ss (Net)

t) Acres: 32,400 (14,100) Proved Reserves (YE’16 – SEC) Objecti tive ves: Eagle Ford d Shale, Pearsall Shale & Buda da Lime me

HAYNESVILLE / BOSSIER SHALE ANGELINA RIVER TREND (“ART”)

Gross (Net) Acres : 13,000 (8,000) Proved Reserves (YE'16 - SEC) 4.2 Bcfe Objective: Haynesville & Bossier Shale

HAYNESV ESVILL ILLE E SHALE E - CORE

Gros

• ss (Net)

t) Acres: 35,000 (16,000) Prove

• ved

d Reserves (YE'16 - SEC) 281.6 Bcfe Objecti tive ve: Haynesvi ville Shale (Core)

March 2017 7

North Louisiana (Haynesville)

• Total Gross/Net Acres:

38,000/15,700

• Average WI/NRI: 41%/30%
• Acreage HBP: 100%
• 85 total producing wells
• Approximately 235 potential

locations

• CHK Joint Venture on 60% of NLA

Core Acreage Angelina River Trend (ART) Haynesville and Bossier Shales:

• Total Gross/Net Acres: 13,000/

8,000

• Average WI/NRI: 61% / 48%
• Total HBP acreage: 4,300 net acres
• 5 producing wells
• 230 potential locations
• 115 Haynesville locations
• 115 Bossier locations

ART 8,000 0 Net Ac Ac HAYNESV ESVILL ILLE E SHALE ~24,000 net Ac Greenw enwood- Waskom / Metcalf/ alf/Lo Long ngwo wood 4,650 0 Net Ac Swan Lake/Tho horn rn Lake 750 Net Ac

March 2017

8 Key Points

• Large natural gas reserve

base on concentrated leasehold position with expected net resource potential of over 1.1 Tcf (approximately 900 BCF alone in NLA) at 2.5 Bcf/1,000 feet

• 235 Gross Potential Locations
• Average EUR for the 85 wells

drilled to date of ~5.4 Bcf (~1.2 Bcf/1,000’) from short laterals (4,600’) and low proppant (~1,100 lbs / foot) concentrations

• 2.0 – 2.5 Bcf per 1,000’ of

lateral expected from long lateral / high proppant wells

• Recent long lateral industry

wells have produced 3-4 Bcf in 120 days and expect to produce over 9 Bcf in 1 year

• Excess throughput capacity in

desirable region

• The Haynesville Shale is a proven natural gas resource play experiencing a renaissance due to

longer laterals and improvements in completion design  Over 2,700 wells drilled by industry in North Louisiana with a well-defined core area  Consistent well results when utilizing similar completion recipes  Recent wells drilled by offset operators utilizing a predominantly slick water design and up to 5,000 lbs

• f proppant per foot (an increased proppant concentration of close to 400%) projected to yield more

than 2.5 Bcf per 1,000 feet of lateral, a 100+% improvement in EUR per foot versus short lateral/low proppant wells

• Shared and received technical data with numerous industry participants active in the basin which

further enhances our technical knowledge, in-house database and industry best practices

• Economic Advantages of the Play

 Henry Hub pricing less an average of ~ $0.63/Mcf ($0.37/Mcf Operated) at the wellhead, including transportation expense, provides for high realized price compared to other prolific natural gas basins  Dry gas production and high rates provide for low per unit operating expenses ($0.05/Mcf initially)  No severance tax until the earlier of Payout or 2 Years  Existing facilities and infrastructure provide for pad drilled wells with low incremental costs and rapid “spud-to-sales” cycle times to bring the wells to production

• Incremental production from offset wells as a result of the fracs offers additional upside

March 2017 9

Key Points

• Dark organic rich, brittle mudstone-shale with modest clay (<30%) content
• The Haynesville Shale is deposited in deep-basin setting with generally

south, basin-ward dip at depths ranging from 10,500’ - 14,000’

• Thick pay interval ranging from 150’ - 400’ with an average 250’ (gross)
• Consistent high porosity (~15%) log characteristics throughout the pay

section

• 3-D Seismic shows calm depositional environment with no faulting
• Core Lab consortium (65 wells with whole cores) demonstrate consistent

high quality rock across core of the play

• Over-pressured shale (> 0.9 psi/ft) provides for high production rates and

gas recovery factor

• Future staggered lateral placement in upper and lower targets may allow for

higher recovery factor from tighter spacing

Potential Upper Target Top HS Porosity

15% Porosity

Type Log

Goodrich Petroleum, James Cook #1 Caddo Parish, Louisiana

Potential Lower Target

March 2017 10

11 March 2017

March 2017 GDP 12

March 2017 13

March 2017 14

• 4,600‘ Laterals
• 1,000 lbs/ft Proppant
• Hybrid Fluid
• 300-450’ Frac Intervals
• Cluster Spacing 50-70’
• 4,600 – 10,000’ Laterals
• 3,000 lbs/ft Proppant
• Slick Water Fluid
• 150-250’ Frac Intervals
• Cluster Spacing 30-50’
• 10,000’ Laterals
• 5,000+ lbs/ft Proppant
• Slick Water Fluid
• 75-150’ Frac Intervals
• Cluster Spacing 10-20’

Original Design (2008 - 2014) Recent Design (2015 - Current) Testing (Currently)

Evolving completions maximize near-wellbore stimulation

March 2017

15 IP30 versus Total Proppant Well Name Operator LL (ft) Stage Length Stages IP30 (MMcfpd) Prop (#/ft) Total Proppant (#) Prod Date

Well Number 1 Operator 1 10,000 90 107 WOC 5,000 50,000,000 12/15/16 Well Number 2 Operator 1 10,000 110 89 WOC 3,000 30,000,000 12/15/16 Well Number 3 Operator 1 10,000 114 86 WOC 5,000 50,000,000 11/01/16 Well Number 4 Operator 1 10,000 115 86 25.4 4,000 40,000,000 09/16/16 Well Number 5 Operator 1 8,366 125 67 29.8 2,860 23,926,760 09/16/16 Well Number 6 Operator 1 7,062 112 63 31.0 2,700 19,067,400 07/18/16 Well Number 7 Operator 1 7,042 252 28 18.1 1,600 11,267,200 07/18/16 Well Number 8 Operator 1 9,747 259 36 38.0 3,000 29,241,000 06/27/16 Well Number 9 Operator 1 9,306 259 36 18.3 1,600 14,889,600 06/27/16 Well Number 10 Operator 1 7,251 271 27 16.8 1,916 13,892,916 04/14/16 Well Number 11 Operator 1 8,601 269 32 26.0 1,490 12,816,000 01/01/16 Well Number 12 Operator 1 9,759 250 39 21.7 1,516 14,794,644 11/10/15 Well Number 13 Operator 1 6,426 358 18 16.7 2,277 14,632,002 11/09/15 Well Number 14 Operator 1 7,622 365 21 15.8 1,900 14,481,800 04/17/15 Well Number 15 Operator 1 5,145 370 14 15.0 1,527 7,856,415 01/19/15 Well Number 1 Operator 2 7,451 248 30 24.0 2,772 20,654,802 06/29/16 Well Number 2 Operator 2 8,063 235 30 24.0 2,742 22,110,570 05/19/16 Well Number 3 Operator 2 7,367 246 30 23.0 2,988 22,009,910 04/18/16 Well Number 4 Operator 2 7,430 196 38 22.0 2,762 20,519,077 01/04/16 Well Number 5 Operator 2 5,953 237 30 17.1 2,912 17,338,080 11/12/15 Well Number 6 Operator 2 7,547 243 31 20.6 2,878 21,724,670 10/22/15 Well Number 7 Operator 2 7,102 237 30 15.0 2,810 19,957,420 09/16/15 Well Number 8 Operator 2 7,124 237 30 23.0 2,792 19,890,200 08/16/15 Well Number 9 Operator 2 7,063 248 30 17.8 2,730 20,311,486 07/08/15 Well Number 10 Operator 2 7,401 247 30 13.5 2,680 19,809,886 06/03/15 Well Number 11 Operator 2 7,430 248 30 17.2 2,626 19,514,186 05/21/15 Well Number 12 Operator 2 6,880 229 30 17.5 2,855 19,639,260 04/20/15 Well Number 13 Operator 2 7,578 253 30 20.1 2,589 19,616,420 04/19/15

March 2017

16

Improving Results From Haynesville Completion Evolution

IP30 versus Total Proppant Well Name Operator LL (ft) Stage Length Stages IP30 (MMcfpd) Prop (#/ft) Total Proppant (#) Prod Date

Well Number 1 Operator 3 6,870 215 32 21.9 3,683 25,302,210 10/22/15 Well Number 2 Operator 3 7,442 219 34 22.5 3,585 26,679,570 10/01/15 Well Number 3 Operator 3 4,536 216 21 11.7 2,793 12,669,048 07/01/15 Well Number 4 Operator 3 4,536 216 21 11.7 2,720 12,337,920 07/01/15 Well Number 1 Operator 4 4,570 218 21 15.1 3,376 15,428,320 01/22/16 Well Number 2 Operator 4 4,537 216 21 20.6 3,575 16,219,775 01/11/16 Well Number 3 Operator 4 4,473 213 21 21.3 3,617 16,178,841 01/10/16 Well Number 4 Operator 4 4,574 213 21 21.1 3,556 16,265,144 01/09/16 Well Number 5 Operator 4 4,661 212 22 18.8 4,749 22,135,089 11/26/15 Well Number 6 Operator 4 4,562 217 21 16.3 3,107 14,174,134 10/23/15 Well Number 7 Operator 4 4,625 220 21 16.7 3,794 17,547,250 10/14/15 Well Number 8 Operator 4 4,819 219 22 15.1 3,152 15,189,488 09/09/15 Well Number 9 Operator 4 4,565 177 26 12.9 2,656 12,124,640 02/25/14 Well Number 10 Operator 4 3,997 171 24 14.3 2,672 10,679,984 02/25/14 Well Number 11 Operator 4 4,395 174 26 10.8 2,720 11,954,400 02/23/14 Well Number 12 Operator 4 4,725 205 23 12.3 1,820 8,599,500 11/12/11

March 2017 17

CHK PCK 13&24&25-15- 15HC - 001-ALT IP30: 31,000 Mcf/d 7,052’ lateral COVEY PARK ODEN 35-26 H1 IP30 – 21,900 Mcf/d 6,870’ lateral 3,683#/ft COVEY PARK TUCKER 31-6C H1 DRILLING 10/21/2016 ~ 7500’ lateral CHK ROTC 1 & 2 10,000’ Laterals (IP:72,000 Mcf/d)

CRK Wells

CHK Western D Unit Wells (Planned) 10,000’ laterals COVEY PARK LOWERY 27H1 IP30 - 11,700 Mcf/d 4,536’ lateral 2,720#/ft COVEY PARK LOWERY 27H2 IP30 - 11,700 Mcf/d 4,536’ lateral 2,793#/ft CHK NGUYEN 5&8-15-14HC 002-ALT IP30: 15,800 Mcf/d 7,668’ lateral CHK CA 12&13-15 -15 HC 002-ALT IP30: 18,300 Mcf/d 9,373’ lateral CHK NGUYEN 5&8-15-14HC 001-ALT IP30: 16,896 Mcf/d 7,659’ lateral CHK CA 12&13-15 -15 HC 001-ALT IP: 38,000 Mcf/d 9,814’ lateral CRK 14 Planned Wells 10,000’ Laterals GOODRICH W FRANKS 10000’ LATERAL LOCATION GOODRICH WURTSBAUGH 5000’ LATERAL LOCATION CHK WILL 22&27&34- 15-15HC - 001-ALT IP30: 34,000 Mcf/d 8,350’ lateral CHK Sentel 002 & 003-ALT Planned 10,000’ laterals COVEY PARK ODEN 35-2 H1 IP30 - 22,500 Mcf/d 7,442’ lateral 3,585#/ft VINE HA RC SUJ;CLAY ROBERTSON 14 002-ALT IP30: 16,700 Mcf/d 4,625’ lateral CHK PKY35&26&23-14- 15HC - 002-ALT IP: 18,192 Mcf/d 5,981’ lateral CHK Muse 13&12-14-15 HC

• 001-ALT

IP: 19,296 Mcf/d 8,601’ lateral CHK PCK 13&24&25-15- 15HC - 002-ALT IP30: 18,100 Mcf/d 7,042’ lateral CHK, Black 1H WOC Test 10,000’ lateral 5,000#/ft VINE HA RA SU74;L L GOLSON 3 - 003-ALT IP30: 18,800 Mcf/d 4,661’ lateral CHK PE 36&25-15-15 HC 001ALT IP30: 21,700 Mcf/d 9,759’ lateral CHK 28&21-14-15 HC 001, 002 & 003-ALT Planned 10,000’ laterals

0.1 1.0 10.0 100.0

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00

Gas production, MMcf/day Time (Years)

Recent Haynesville 4600' Wells

Operator 4, Well No 5 Prod Data Operator 4 Well Data Average Operator 4 Well Average Type Curve Operator 3 Well 3 Well Data Operator 3 Well 4 Well Data Base Case Type Curve (3,000#/ft Frac, 9.2 BCF) High Case Type Curve (4000#/ft Frac) 11 BCF

Operator 4, Well Number 5 (4,749#/ft Frac) Operator 4 Well Type Curve (Avg 3600#/ft Frac) - EUR: 13.7 Bcf GDP High Case Type Curve (4000#/ft Frac) - EUR: 11.5 Bcf Operator 4, Average Well Performance from 8 Wells (Avg. 3600#/ft Frac) Operator 3 Well 3 (2763#/ft Frac) Operator 3 Well 4 (2720#/ft Frac) GDPP Base Case Type Curve (3000#/ft Frac) - EUR: 9.2 BCF March 2017 18

January 2017 19

0.1 1.0 10.0 100.0

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00

Gas production, MMcf/day Time (Years)

Recent Haynesville 7500' Wells

Operator 3, Well 1 (3,683#/ft Frac) Operator 1, Well 15 (1,900#/ft Frac) Operator 1, Well 14, (1,900#/ft Frac) Operator 3, Well 2 (3,585#/ft Frac) Operator 2, Average Well Performance from 12 Wells (2,800#/ft Frac) Operator 1, Well 11 (1,490#/ft Frac) Base Case (3,000#/ft Frac) Type Curve EUR: 15 Bcf (2.0 Bcf/1,000 ft) Increased Proppant Design (4,000#/ft Frac) Type Curve EUR: 19 Bcf (2.5 Bcf/1,000 ft) March 2017 19

0.1 1.0 10.0 100.0

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00

Gas production, MMcf/day Time (Years)

Recent Haynesville 10,000' Wells

Operator 1, Well 8 (3,000#/ft Frac) Operator 1, Well 12 (1,516#/ft Frac) Increased Proppant Design Type Curve (4,000#/ft Frac) - EUR: 25 Bcf (2.5 Bcf/1,000 ft) Operator 1, Well 9 (1,600#/ft Frac) Base Case Type Curve (3,000#/ft Frac) EUR: 20 Bcf (2.0 Bcf/1,000 ft)

March 2017 20

ROTC 1 (5,200#/ft Frac) ROTC 2 (3,000#/ft Frac)

March 2017 21



Typical Development Case (10,000’ Lateral Wells)

 6 Wells / 1280-Acre

Unit

• 880’ between wells
• 2.0 Bcf per 1,000’
• 20.0 Bcf per well
• 120 Bcf / 1280 acre unit
• 32.6% recovery factor



6 Wells / 1280-Acre Unit

• 880’ between wells
• 2.5 Bcf per 1,000’
• 25.0 Bcf per well
• 150 Bcf / 1280 acre unit
• 40.7% recovery factor



5 Wells / 1280-Acre Unit

• 1,056’ between wells
• 2.5 Bcf per 1,000’
• 25.0 Bcf per well
• 125 Bcf / 1280 acre unit
• 33.9% recovery factor



OOIP (Bcf / 1280 A

• Ac. Unit)

t) Wells / Unit it EUR / Well (MBoe) e) Recove very Factor tor Base Case 368 6 20 32.6%

Typical Development Unit (1280 acres) es)

6 Well Spacing Lateral

Note: Not drawn to scale.

10,560’ 5,280’ 440’ 880’ 9,900’ 1056’ 528’ 5 Well Spacing Lateral

March 2017 22 4,600’ Lateral Length, 4,000# Per Foot Frac Design Type Curve

Assumptions Louisiana EUR 11.5 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.022 Pricing Differentials NYMEX less $0.63 / 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 20 40 60 80 100 120 Avg g Daily y Produ ducti tion

• n (Mcfpd

pd) Month ths

4,600' Lateral ral Type Curve ve

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 AFE: Two well pad.

Gas Price Gas Price

March 2017 23 7,500’ Lateral Length, 4,000# Per Foot Frac Design Type Curve

Assumptions Louisiana EUR 18.75 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.022 Pricing Differentials NYMEX less $0.63 / 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 20 40 60 80 100 120 Avg g Daily y Produ ducti tion

• n (Mcfpd

pd) Month ths

7,500' Lateral ral Type Curve ve

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 AFE: Two well pad.

Gas Price Gas Price

March 2017 24 10,000’ Lateral Length, 4,000# Per Foot Frac Design Type Curve

Assumptions Louisiana EUR 25.0 Bcf (2.5 Bcf/1,000’) Sales Gas BTU Price Adjustment 1.022 Pricing Differentials NYMEX less $0.63 / 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 20 40 60 80 100 120 Avg g Daily y Produ ducti tion

• n (Mcfpd

pd) Month ths

10,000' Lateral ral 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 AFE: Two well pad.

Gas Price Gas Price



Value and Growth Investment Opportunity Due to a Restructured Balance Sheet and the Ability to Rapidly Grow Volumes and Reserves



The Haynesville Shale Economics Will Compete with the Best Basins, Regardless of the Commodity Due to the Following:

• Substantial Changes in Completion Techniques Yielding Step-Change in Well Productivity;
• Low Lease Operating Expenses (less than $0.05/Mcf initially);
• Minimum Infrastructure Expense due to Existing Facilities with Ample Takeaway Capacity;
• Favorable Revised Transportation Agreements ($0.25 - $0.52/Mcf Operated and $0.75/Mcf

Non-Operated)

• Severance Tax Abatement Until Earlier of Payout or 2 Years



Near 100% of Capital Expenditure Budget Allocated to the Haynesville (Leverage to the Basin):

• Over 1.1 Tcf of Reserve Exposure (900 Bcf Resource Potential from ~235 Locations in NLA

Core);

• Reserve Expansion Due to High Volume Wells and the Ability to Replace Previously Booked

PUDs with New PUDs Utilizing Improved Completion Methodology



Option Value in the Eagle Ford and TMS, Pending Oil Price Recovery

March 2017 25