Management Presentation

Transcription

1 NYSE American: GDP Management Presentation

2 This presentation has been prepared by Goodrich Petroleum Corporation (the Company ) solely for information purposes and may include "forwardlooking statements" within the meaning of the U.S. Private Litigation Securities Reform Act of 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. 2

3 OPERATED OPPORTUNITY >10 year inventory of high return core HS locations HAYNESVILLE SHALE - CORE High margin gas (HS), oil upside (TMS and EFS) Low capital intensity from low decline rate PDPs STRONG FUNDAMENTALS Cash margin expansion continuing in 2019 Low leverage on low reinvestment rate Top-tier full cycle returns on low leasehold costs Improving debt-adjusted growth for the multiple Texas Louisiana Mississippi Gross (Net) Acres (4Q18): 34,000 (20,000) Proved Reserves (YE18 - SEC) 471 Bcfe Objective: Haynesville Shale HAYNESVILLE / BOSSIER SHALE ANGELINA RIVER TREND ( ART ) Gross (Net) Acres (4Q18): 8,000 (3,000) Proved Reserves (YE18 - SEC) Objective: Haynesville & Bossier Shale TUSCALOOSA MARINE SHALE: Gross (Net) Acres (4Q18): 50,500 (35,100) Proved Reserves (YE18 SEC) 9 Bcfe Objectives: Tuscaloosa Marine Shale EAGLE FORD SHALE: 3Q18 HIGHLIGHTS & GUIDANCE Gross (Net) Acres (4Q18): 28,200 (12,300) Proved Reserves (YE18 SEC) 0 Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime 3Q18A 85 MMcfe/d (4Q18E 100 MMcfe/d) 3Q18A adjusted EBITDA $14MM Preliminary 2019E guidance of 140 Mmcfe/d on $90- $100MM in capital spending 70,000 high return, low cost basis net acres >1.0 Tcf of natural gas resource potential in North Louisiana. Fully de-risked 3

4 SEC PROVED RESERVES (Bcfe) * ETX TMS NLA - Haynesville Total * Year-End 2018 PV10 of $418 Million 4

5 USD in thousands) Cash $1,931 Debt Senior Credit Facility 15,000 2L Convertible Notes (PIK) 51,938 Total Debt 66,938 Total Net Debt $65,007 5

6 160, , , ,000 80,000 60,000 40,000 20, Q18 2Q18 3Q18 4Q18* Est. 2019* Est. TMS Haynesville Total * Mid-Point of Guidance 6

7 Production 2019E Annual Net Production: Bcfe Avg Daily Production (Mcfe/d): 135, ,000 Natural Gas: 98% Activity Wells Gross (Net) Wells: 11 (9.8) Average Net Lateral Length: 7,000 Percentage Operated (Net): 100% Capex (MM) $ Net Capital Allocation Price Realization HH Less $ Unit Costs (Per Mcfe) LOE $ Taxes $ Transportation $ G&A (Cash) $ Bethany-Longstreet 67% Thorn Lake 33% Quarterly Completion Cadence 1Q19 2 Gross (2.0 Net) 2Q19 4 Gross (3.4 Net) 3Q19 3 Gross (2.7 Net) 4Q19 2 Gross (1.7 Net) Total 11 Gross (9.8 Net) 7

8 EV/EBITDA GDP Peer Group Includes: APA,APC,AR,AREX,AXAS,BCEI,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DVN,ECA,ECR,EOG EPE,EQT,ESTE,FANG,GPOR,HK,HPR,JONE,LLEX,LONE,LPI,MCF,MPO,MTDR,MUR,NBL, NFX,OAS,PDCE,PE,QEP,PXD,REN,RRC,SBOW,SD,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company 8

9 10.00 NET DEBT/EBITDA GDP Peer Group Includes: APA,APC,AR,AREX,AXAS,BCEI,CHK,CLR,COG,CPE,CRK,CRZO,CXO,DVN,ECA,ECR,EOG EPE,EQT,ESTE,FANG,GPOR,HK,HPR,JONE,LLEX,LONE,LPI,MCF,MPO,MTDR,MUR,NBL, NFX,OAS,PDCE,PE,QEP,PXD,REN,RRC,SBOW,SD,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company 9

10 $14.00 Capital Efficiency $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $- GDP Peer Group Includes: AXAS,BCEI,COG,CPE,CRK,CXO,ECA,ECR, ESTE,FANG,GDP,HK,HPR,LLEX,LONE,MTDR,MUR,OAS,PDCE,PXD,REN, SBOW,SM,SRCI,WPX Source: Bloomberg, Company 10

11 North Louisiana (Haynesville) Total Gross/Net Acres: 34,000/20,000 Average WI/NRI: 59%/43% Acreage HBP: 100% 102 total producing wells (25 Operated) 1/1/19 Inventory of 214 gross (99 net) potential locations on 880 spacing Operator for Approximately 73% of the NLA core position CHK Joint Venture on most of the remaining 27% 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: 8,000/ 3,000 Average WI/NRI: 40% / 30% Sale of Producing Wells and a Portion of the Company s Acreage for $23 Million Greenwood- Waskom / Metcalf/Longwood 3,700 Net Ac Bethany Longstreet 15,000 Net Ac ART 3,000 Net Ac HAYNESVILLE SHALE ~23,000 net Ac Swan Lake/Thorn Lake 1,300 Net Ac Rig Source: Ulterra Bits 12

12 Regional Structure Map (Top of the Haynesville Shale) 13

13 Haynesville Shale Regional Cross - Section (West - East) 14

14 Haynesville Shale Regional Cross - Section (South - North) 15

15 Core Lab Haynesville Shale Core Data (Average Core Total Porosity) Data from Core Lab Consortium; contours prepared by Goodrich 16

16 Haynesville Completion Evolution Evolving completions maximize near-wellbore stimulation Original Design Tested Current Design 4,600 Laterals 1,000 lbs/ft Proppant Hybrid Fluid Frac Intervals Cluster Spacing ,000 Laterals 5,000+ lbs/ft Proppant Slick Water & Hybrid Fluid <100 Frac Intervals Cluster Spacing ,600-10,000 Laterals 3,000 4,000 lbs/ft Proppant Slick Water Fluid Frac Intervals Cluster Spacing

17 Haynesville Recent Industry Activity (1) CRK Nissen 28-21HC #1 10,000 Lateral IP: 27,000 Mcf/d 3,796#/ft (2) CRK Nissen 28-21HC #2 10,000 Lateral IP: 25,000 Mcf/d 3,801#/ft 3. CRK FLORSHEIM 9-16 HC #1&2 10,000 Laterals IP: 26,500 Mcf/d IP: 27,600 Mcf/d 4. CRK HUNTER 28-21HC 1&2 IP: 27,000 Mcf/d each 9,200 Laterals 5. CHK GEPH Unit IP: 47,988 Mcf/d 15,000 Lateral (22) CHK Black 1H IP: 44,000 Mcf/d 10,000 Lateral (6) CRK Cook HC #1 10,000 Lateral IP: 25,600 Mcf/d 3,803#/ft (21) Vine HA RA SU74;L L Golson ALT IP: 18,800 Mcf/d 4,661 Lateral (7) CRK Cook HC #2 10,000 Lateral IP: 26,800 Mcf/d 3,798#/ft (8) CHK ROTC 1 & 2 10,000 Laterals IP: 72,000 Mcf/d 19 Bcf in 19 months (9) EXCO Red Oak Timber 6-7HC 9,500 Lateral IP: 22,400 Mcf/d (20) GDP Cason-Dickson 23&24 #3&4 Flowback 9,000 Laterals (19) GDP Cason-Dickson #1&2 IP: 31 MMcf/d, IP: 23 MMcf/d 8,000 & 3,000 Laterals (18) GDP Harris 14&23 #1 IP: 27,500 Mcf/d 6,100 Lateral (17) Covey Park Tucker 31-6C H1 IP 18,045 Mcf/d 7,466 Lateral (10) GDP Wurtsbaugh 26 4,600 Lateral IP: 22,000 Mcf/d (11) GDP-Wurtsbaugh #2&3 7,500 Laterals IP: 25,000 Mcf/d IP: 29,000 Mcf/d (12) GDP Wurtsbaugh #1 8,800 Lateral IP: 31,000 Mcf/d (13) GDP Franks 25&24 #1 IP: 30,000 Mcf/d 9,600 Lateral (14) GDP Loftus 27&22 #1 Waiting on Completion 7,500 Lateral (15) GDP Demmon 34H #1 22,500 Mcf/d 4,600 Lateral (16) GDP Wurtsbaugh 35H #1 IP: 22,500 Mcf/d 4,600 Lateral 17

18 Gas Production, Mcfpd Well Count 100,000 Recent Haynesville 4,600' Wells 1,000 GDP, 4 Well Average (Avg 4,100' LL; 4,200 #/ft Frac) 10,000 SI - Offset Fracs Average Well Performance 59 Wells (3,400 #/ft Frac) 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) Months 18 1

19 Cum Production (MCF) 6,000,000 4,600' Laterals Cum Production (MCF) GDP, 4 Well Average (4,100' LL; 4,200 #/ft Frac) 5,000,000 Company Type Curve: EUR: 11.5 Bcf (2.5 Bcf/1,000 ft) 4,000,000 3,000,000 Average Well Performance 59 Wells (3,400 #/ft Frac) Company Type Curve: EUR: 9.2 Bcf (2.0 Bcf/1,000 ft) 2,000,000 1,000, Months 19

20 Gas Production, Mcfpd Well Count 100,000 GDP, 5 Well Average (Avg 7,600' LL, 4,500 #/ft Frac) Recent Haynesville 7,500' Wells 1000 SI - Offset Fracs Average Well Performance 87 Wells (3,100 #/ft Frac) 10,000 Company Type Curve: EUR: Bcf (2.5 Bcf/1,000 ft) ,000 Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft) Months 20 1

21 Cum Production (MCF) 8,000,000 7,000,000 7,500' Laterals Cum Production (MCF) GDP, 5 Well Average (Avg 7,600' LL, 4,500 #/ft Frac) 6,000,000 5,000,000 Company Type Curve: EUR: Bcf (2.5 Bcf/1,000 ft) Company Type Curve EUR: 15.0 Bcf (2.0 Bcf/1,000 ft) 4,000,000 3,000,000 Average Well Performance 87 Well (3,100 #/ft Frac) 2,000,000 1,000, Months 21

22 Gas Production, Mcfpd Well Count 100,000 GDP, 8 Well Average (Avg 9,500' LL; 3,700 #/ft) Recent Haynesville 10,000' Wells 1000 Average Well Performance 35 Wells (3,200 #/ft Frac) 10,000 Company Type Curve: EUR: 25 Bcf (2.5 Bcf/1,000 ft) ROTC Clean out Lateral & Ran Tubing 1, Company Type Curve EUR: 20 Bcf (2.0 Bcf/1,000 ft) Months 22

23 Cum Production (MCF) 12,000,000 10,000' Laterals Cum Production (MCF) Company Type Curve: EUR: 25 Bcf (2.5 Bcf/1,000 ft) 10,000,000 8,000,000 6,000,000 Company Type Curve EUR: 20 Bcf (2.0 Bcf/1,000 ft) GDP, 6 Well Average (Avg 9,500' LL; 3,700 #/ft) 4,000,000 2,000,000 Average Well Performance 35 Wells (3,200 #/ft Frac) Months 23

24 BCFE GDP Peer Group Includes: Aethon, BHP, Chesapeake, Comstock, Covey Park, Ensight, Exco, Geosouthern, Goodrich, Indigo, QEP, Vine Source: RS Energy Group, Company -2/5/19 (Wells Completed After 1/1/16) 24

25 BCFE GDP January 2019 Peer Group Includes: Aethon, BHP, Chesapeake, Comstock, Covey Park, Exco, Geosouthern, Goodrich, Indigo, QEP, Vine Source: RS Energy Group, Company - 2/5/19 (Wells Completed After 1/1/16) 25

26 BCFE GDP Peer Group Includes: Aethon, BHP, Chesapeake, Comstock, Covey Park, Exco, Geosouthern, Goodrich, Indigo, QEP, Vine Source: RS Energy Group, Company - 2/5/19 (Wells Completed After 1/1/16) 22

27 Gas Price Gas Price Avg Daily Production (Mcfpd) Assumptions Louisiana 100,000 4,600' Lateral Type Curve EUR 11.5 Bcf (2.5 Bcf/1,000 ) Sales Gas BTU Price Adjustment Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation: $0.35 / Mcf Fixed Opex Fixed Opex: $3,290 / month 10,000 1, Months Variable Opex Severance Tax $0.07 / Mcf Payout or 24 month tax holiday; thereafter $0.12 / Mcf 4,600' Lateral IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex). IRRs Incorporate Early Time Outperformance Ad Val Tax $0.04 / Mcf Royalty Burden 27.0% D&C Capex $8.5 MM Facilities Capex $0.185 MM, included in D&C Capex Spud to 1 st Sale 60 Days EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% % 25.0% 37.3% % 25.0% 17.2% % 41.3% 58.3% % 41.3% 30.3% % 61.0% 83.6% % 61.0% 46.2% % 111.5% 148.8% % 111.5% 86.8% PV10 (M$) ($3.00/Mcf Pricing) $4,875 Economic EUR s vary depending on gas price assumptions. Ownership: WI 100% - NRI 73% Pricing: Flat Pricing AFE: Two well pad. 27

28 Gas Price Gas Price Avg Daily Production (Mcfpd) Assumptions Louisiana 100,000 7,500' Lateral Type Curve EUR Bcf (2.5 Bcf/1,000 ) Sales Gas BTU Price Adjustment Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation - $0.35 / Mcf Fixed Opex Fixed Opex: $3,290 / month 10,000 1, Months Variable Opex Severance Tax $0.07 / Mcf Payout or 24 month tax holiday; thereafter $0.12 / Mcf 7,500' Lateral IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex). IRRs Incorporate Early Time Outperformance Ad Val Tax $0.04 / Mcf Royalty Burden 27.0% D&C Capex $10.9 MM Facilities Capex $0.185 MM, included in D&C Capex Spud to 1 st Sale 60 Days EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% % 44.7% 60.0% % 44.7% 34.2% % 65.0% 85.7% % 65.0% 50.8% % 88.9% 115.9% % 88.9% 70.4% % 148.7% 192.1% % 148.7% 119.0% PV10 (M$) ($3.00/Mcf Pricing) $10,198 Economic EUR s vary depending on gas price assumptions. Ownership: WI 100% - NRI 73% Pricing: Flat Pricing AFE: Two well pad. 28

29 Gas Price Gas Price Avg Daily Production (Mcfpd) Assumptions Louisiana 100,000 10,000' Lateral Type Curve EUR 25.0 Bcf (2.5 Bcf/1,000 ) Sales Gas BTU Price Adjustment Pricing Differentials/ Transportation Average - NYMEX less $0.15 / MMBtu Transportation - $0.35 / Mcf Fixed Opex Fixed Opex: $3,290 / month 10,000 1, Months Variable Opex Severance Tax $0.07 / Mcf Payout or 24 month tax holiday; thereafter $0.12 / Mcf 10,000' Lateral IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex). IRRs Incorporate Early Time Outperformance Ad Val Tax $0.03 / Mcf Royalty Burden 27.0% D&C Capex $13.1 MM Facilities Capex $0.185 MM, included in D&C Capex Spud to 1 st Sale 60 Days EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% % 55.4% 72.9% % 55.4% 43.1% % 78.5% 101.9% % 78.5% 62.2% % 105.6% 135.8% % 105.6% 84.4% % 172.3% 220.3% % 172.3% 138.9% PV10 (M$) ($3.00/Mcf Pricing) $14,376 Economic EUR s vary depending on gas price assumptions. Ownership: WI 100% - NRI 73% Pricing: Flat Pricing AFE: Two well pad. 29

30 Haynesville Generating Superior Returns Regardless of Commodity Blended Average Lateral Length for 2019 Generates 45% - 89% IRR from $ $3.00 per Mcf Continued Strong EBITDA Growth in 2019 Driven By Substantial Increase in Production On A Lower Unit Cost Structure Production and EBITDA Projected to Double with Capex and EBITDA Aligned Eagle Ford and TMS Positions Provide Leverage to Oil Prices and Strategic Optionality Encouraging Recent Offset Activity Implying Higher Valuations Focusing on Strategic Acquisitions That Add Inventory While Keeping Debt Metrics Less Than 1.5X Completed Several Small Bolt-On Deals in 2018 Which More Than Replaced Inventory. Expect to do More in

31 January 2019 A-1

32 Period Natural Gas Volumes (Mcfpd) Natural Gas Price 4Q18 39,000 $3.02 1Q19 80,000 $2.93 2Q19 70,000 $2.86 3Q19 70,000 $2.86 4Q19 70,000 $2.86 1Q20 40,000 $2.81 Period Oil Volumes (Bopd) Oil Price 4Q $ Q $ Q $ Q $ Q $51.08 A-2