Management Presentation - Seaport Global, Chicago, IL

Transcription

1 NYSE American: GDP Management Presentation - Seaport Global, Chicago, IL

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 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 Year Inventory (1.2 Tcf of Resource Potential) of NLA Haynesville Core Locations at Current Capex Budget, with Significant Option Value on Oil TRADING PLATFORM: NYSE American: ( GDP ) PLAN & CATALYSTS Rapid Growth in Natural Gas Production and EBITDA, While Maintaining Low Debt Metrics 2Q18 Production Grew 66% Sequentially to 60,600 Mcfe. Year-End 2018 Guidance Up an Additional 65% to 100,000 Mcfe Per Day and Preliminary 2019 Guidance of an Average of 140,000 Mcfe Per Day Per Unit Operating Costs Dropping Creating Margin Expansion Increasing Activity in Haynesville - Two Rigs Running Currently and Two Wells Near Flowback 3

4 HAYNESVILLE SHALE - CORE Gross (Net) Acres (YE17): 38,000 (19,000) Proved Reserves (YE17 - SEC) Bcfe Objective: Haynesville Shale HAYNESVILLE / BOSSIER SHALE ANGELINA RIVER TREND ( ART ) Mississippi Gross (Net) Acres (Current): 8,000 (3,000) Proved Reserves (YE17 - SEC) 4.0 Bcfe Objective: Haynesville & Bossier Shale Texas Louisiana TUSCALOOSA MARINE SHALE: Gross (Net) Acres (YE17): 60,000 (43,000) Proved Reserves (YE17 - SEC) 12.7 Bcfe Objectives: Tuscaloosa Marine Shale EAGLE FORD SHALE: Gross (Net) Acres (YE17): 32,500 (14,000) Proved Reserves (YE17 SEC) 0 Objectives: Eagle Ford Shale, Pearsall Shale & Buda Lime 4

5 SEC PROVED RESERVES (Bcfe) ETX TMS NLA - Haynesville Total April

6 USD in thousands) Cash $1,729 Debt Senior Credit Facility 6,000 2L Convertible Notes (PIK) 50,224 Total Debt 56,224 Total Net Debt $54,495 6

7 160, , , ,000 80,000 60,000 40,000 20, Q18 2Q * 2018 Exit Rate 2019* Est. TMS Haynesville Total * Mid-Point of Guidance 7

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

10 GDP NET DEBT/EBITDA 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, QEP,PXD,REN,RRC,SBOW,SD,SM,SN,SWN,UPL,WLL,WPX,WTI Source: Bloomberg, Company 10

11 $35,000 Capital Efficiency $30,000 $25,000 $20,000 $15,000 $10,000 $5,000 $- GDP Source: Company Peer 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,N FX,OXY,PDCE,PE,QEP,RVAC,PXD,REXX,RRC,RSSP,SM,SN,SRCI,SWN,UPL,WLL,WRD,XEC 11

12 North Louisiana (Haynesville) Total Gross/Net Acres: 38,500/19,000 Average WI/NRI: 40%/29% Acreage HBP: 100% 91 total producing wells (17 Operated) Approximately 200 gross (90 net) potential locations on 880 spacing Operator for Approximately 55% of the NLA core position CHK Joint Venture on most of the remaining 45% 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: 38% / 30% Recent 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 14,000 Net Ac ART 3,000 Net Ac HAYNESVILLE SHALE ~22,000 net Ac Swan Lake/Thorn Lake 1,300 Net Ac Rig Source: Ulterra Bits 12

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

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

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

16 Core Lab Haynesville Shale Core Data A A A A Core Wells Locator A A 16

17 Core Lab Haynesville Shale Core Data (Average Core Total Porosity) Data from Core Lab Consortium; contours prepared by Goodrich 17

18 Haynesville Completion Evolution Evolving completions maximize near-wellbore stimulation Original Design ( ) Recent Design ( Current) Testing (Currently) 4,600 Laterals 1,000 lbs/ft Proppant Hybrid Fluid Frac Intervals Cluster Spacing ,600 10,000 Laterals 3,000 4,000 lbs/ft Proppant Slick Water Fluid Frac Intervals Cluster Spacing ,000 Laterals 4,000-5,000+ lbs/ft Proppant Slick Water Fluid Frac Intervals Cluster Spacing

19 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 16 Bcf in 14 months (9) EXCO Red Oak Timber 6-7HC 9,500 Lateral IP: 22,400 Mcf/d (20) GDP Cason-Dickson #3&4 Preparing to Spud 10,000 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 Drilling Completed 6,200 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 Drilling in Progress 7,500 Lateral (15) GDP Demmon 34H #1 Flowing 4,600 Lateral (16) GDP Wurtsbaugh 35H #1 Producing 4,600 Lateral 19

20 20

21 21

22 22

23 23

24 24

25 Cum Production (MCF) 10,000,000 10,000' Laterals Cum Production (MCF) 9,000,000 8,000,000 Company Type Curve: EUR: 25 Bcf (2.5 Bcf/1,000 ft) 7,000,000 6,000,000 ROTC 2-Well Average (4,000#/ft) Company Type Curve EUR: 20 Bcf (2.0 Bcf/1,000 ft) 5,000,000 4,000,000 3,000,000 Average Well Performance 35 Wells (3,251#/ft Frac) 2,000,000 1,000,000 GDP, 1 Well (9,265' LL, 3,943#/ft Frac) Months 25

26 Avg Daily Production (Mcfpd) Assumptions Louisiana Type Curve 100,000 4,600' Lateral Type Curve EUR 11.5 Bcf (2.5 Bcf/1,000 ) Sales Gas BTU Price Adjustment ,000 1,000 Pricing Differentials Average - NYMEX less $0.60 / MMBtu (includes transportation) Fixed Opex Fixed Opex: $3,676 / month Months Variable Opex Severance Tax Ad Val Tax $0.05 / Mcf 24 month tax holiday; thereafter, $0.11 / Mcf $0.03 / Mcf Royalty Burden 27.0% D&C Capex Facilities Capex $8.3 MM $0.17 MM, included in D&C Capex 4,600' Lateral IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex) Gas Price EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% % 22.9% 33.9% % 22.9% 16.0% % 36.3% 49.2% % 36.3% 26.5% % 52.7% 70.4% % 52.7% 39.2% % 96.2% 127.5% % 96.2% 72.6% Gas Price Spud to 1 st Sale PV10 (M$) ($3.00/Mcf Pricing) 60 Days $5,002 Ownership:WI 100% - NRI 73% Pricing: Flat Pricing Economic EUR s vary depending on gas price assumptions. 26

27 Avg Daily Production (Mcfpd) Assumptions Louisiana Type Curve 100,000 7,500' Lateral Type Curve EUR Bcf (2.5 Bcf/1,000 ) 10,000 Sales Gas BTU Price Adjustment ,000 Pricing Differentials Average - NYMEX less $0.60 / MMBtu (includes transportation) Fixed Opex Fixed Opex: $3,676 / month Months Variable Opex $0.05 / Mcf 7,500' Lateral IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex) Severance Tax Ad Val Tax 24 month tax holiday; thereafter, $0.11 / Mcf $0.03 / Mcf Royalty Burden 27.0% D&C Capex Facilities Capex Spud to 1 st Sale PV10 (M$) ($3.00/Mcf Pricing) $10.2 MM $0.17 MM, included in D&C Capex 60 Days $7,869 Gas Price EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% % 28.9% 38.5% % 28.9% 21.4% % 43.1% 56.5% % 43.1% 32.7% % 60.1% 78.2% % 60.1% 46.1% % 104.0% 134.9% % 104.0% 80.4% Ownership: WI 100% - NRI 73% Pricing: Flat Pricing Gas Price Economic EUR s vary depending on gas price assumptions. 27

28 Avg Daily Production (Mcfpd) Assumptions Louisiana Type Curve 100,000 10,000' Lateral Type Curve EUR 25.0 Bcf (2.5 Bcf/1,000 ) 10,000 Sales Gas BTU Price Adjustment ,000 Pricing Differentials Average - NYMEX less $0.60 / MMBtu (includes transportation) Fixed Opex Fixed Opex: $3,676 / month Months Variable Opex Severance Tax Ad Val Tax $0.05 / Mcf 24 month tax holiday; thereafter, $0.11 / Mcf $0.03 / Mcf Royalty Burden 27.0% D&C Capex Facilities Capex Spud to 1 st Sale PV10 (M$) ($3.00/Mcf Pricing) $12.4 MM $0.17 MM, included in D&C Capex 60 Days $11,731 10,000' Lateral IRR Sensitivity Analysis (IRR sensitivity to EURs and Capex) Gas Price EUR Capex (Mmcfe) ($M) 90% 100% 110% 90% 100% 110% % 37.6% 49.5% % 37.6% 28.4% % 55.0% 71.4% % 55.0% 42.1% % 75.9% 98.2% % 75.9% 58.6% % 130.4% 169.3% % 130.4% 100.9% Ownership: WI 100% - NRI 73% Pricing: Flat Pricing Gas Price Economic EUR s vary depending on gas price assumptions. 28

29 Strong EBITDA Growth in 2018 Driven By Substantial Increase in Production On A Much Lower Unit Cost Structure Two Operated Rigs Running Currently, Which Will Drive Operated Volume Growth Which Carries a Lower Lifting Cost Due to Favorable Gathering Contracts Focus on Growth in Cash Flow and Return on Capital Employed With Manageable Outspend Strategic Acquisitions That Add Inventory While Keeping Debt Metrics Less Than 1.5X 29

30 A-1

31 Period Natural Gas Volumes (Mcfpd) Natural Gas Price 3Q18 38,000 $3.02 4Q18 39,000 $3.02 1Q19 50,000 $2.96 2Q19 40,000 $2.85 3Q19 40,000 $2.85 4Q19 40,000 $2.85 1Q20 40,000 $2.81 Period Oil Volumes (Bopd) Oil Price 3Q $ Q $ Q $ Q $ Q $ Q $51.08 A-2

32 Production 2018E Annual Net Production: Bcfe Avg Daily Production: 65,000-75,000 Mcfe/d Natural Gas: 95% Activity Wells Gross (Net) Wells: 17 (8.2) Average Net Lateral Length: 8,000 Percentage Operated (Net): 84% Capex (MM) $85-95 Net Capital Allocation Unit Costs (Per Mcfe) Bethany-Longstreet 70% Thorn Lake 30% Basis Henry Hub Less: $ LLS Less: $ LOE $ Taxes $ Transportation $ G&A (Cash) $ Quarterly Completion Cadence 1Q18 3 Gross (1.8 Net) 2Q18 5 Gross (2.7 Net) 3Q18 6 Gross (2.3 Net) 4Q18 3 Gross (1.4 Net) Total 17 Gross (8.2 Net) A-3