Accelerating. Johnson Rice Energy Conference. New Orleans October Accelerating

Transcription

1 Johnson Rice Energy Conference New Orleans October We are purposefully driven to provide top quartile share price performance and exceptional rates of return for our shareholders as we help meet the world s growing energy demand through exploration and production of hydrocarbons.

2 Growing, Balanced, Diversified E&P Company Market Capitalization Enterprise Value EBITDA (Trailing 12 months) * Cash Undrawn Credit Facility ** Production Hedged ( ) $1.6 Billion $2.4 Billion $635 Million $226 Million $400 Million $1.1 Billion Morgantown Appalachia Debt 2017 Sr. Notes (8 5/8%) 2017 Sr. Convertible Notes (1 3/4%) 2022 Sr. Notes (7.5%) *** $375 Million $300 Million $300 Million Lafayette New Orleans Houston Deep Gas Conventional Shelf Deep Water Gulf of Mexico 2 *See reconciliations to US GAAP in appendix. ** Excludes letters of credit. *** Face Value. All financial figures as of 6/30/13.

3 Strategy and Results: Diversified, Growing Reserves Explore in areas with material impact to oil production Invest in price advantaged, condensate rich gas basins Limit reinvestment in Conventional Shelf to oil development Estimated Proved Reserves 2012 Estimated Proved Reserves 2009 Conventional Shelf 79% Deep Water 21% Marcellus 44% Conventional Shelf 18% Deep Water 34% 69 mmboe 129 mmboe 3 Oil/NGL - 48% Gas - 52% Oil/NGL - 49% Gas - 51%

4 YTD Return CAGR% Strategy Results: Stock Performance vs. Peer Group SGY SGY CAGR % SGY 100% First Quartile 1 Year Average September 27, 2013 Second Quartile Third Quartile Fourth Quartile 80% 60% 40% 20% 60% 50% 40% 3 Year Stock Performance September 27, 2013 First Quartile Second Quartile Third Quartile Fourth Quartile 0% 30% -20% 20% 10% -40% 0% 60% 50% 5 Year Stock Performance September 27, 2013 First Quartile Second Quartile Third Quartile Fourth Quartile -10% -20% -30% 40% -40% 30% 20% 10% 0% -10% -20% Peer Group: COG, CPE, CRK, CRZO, DNR, EPL, EXXI, MCF, NFX, PDCE, PQ, SFY, SD, SGY, SM, RRC, UPL, WLL, WTI, XCO, XEC -30% -40% 4

5 Updated 2013 Capital Program Allocation Considerations: Maximize projected stock price Maximize net present value Conventional Shelf 24% Deep Gas 3% Deep Water 39% Grow cash flow Liquids driven Low risk projects Appalachia 31% Onshore Oil 3% High potential exploration Geographic & product diversification $710 million 5

6 Financing Options and Statistics Exploration and Development Funding Status Cash $225 mm Done Credit Facility $400 mm Available Shelf Non Core Property Proceeds Data Room Open Dilute Working Interest After Discovery Upon Discovery Deep Water Exploration Joint Venture If Favorable Access Capital Markets Success & Market Driven $/boe $20.00 Debt Statistics $/boepd $25,000 $/boe 20x EBITDA Statistics $/boe $45 $15.00 $10.00 $5.00 $20,000 $15,000 $10,000 $5,000 15x 10x 5x $40 $35 $30 $25 $20 $15 $10 $5 $0.00 Debt/BOE Debt/Flowing BOE $0 0x EBITDA/ Interest Expense EBITDA Margin/ BOE $0 6

7 5 Year Plan: GOM Deep Water 7

8 GOM Deep Water: Drilling Program Ramping Up Planned Rig Schedule Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q SGY Operated Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec Amethyst Cardona Cardona South Derbio Pompano Platform (4-6 wells) Amberjack Platform (4-6 wells) Amethyst Amberjack Pompano Cardona Carrick Cardona South Derbio TwentyOne Non Operated Taggert (Llog) San Marcos (Apache) Mica Deep (Exxon) Guadalupe (Apache) Phinisi/Goodfellow (ENI) Twenty One (Conoco) Marauder San Marcos Sherwood Guadalupe Taggart Mica Deep Planned 2013 Drilling Planned 2014 Drilling Conoco JV Phinisi Parmer 127 Deep Water leases 20 High potential prospects 26 Tie back exploration prospects 14 Platform development wells 5 Tie back development prospects 8 * Future Capital Expenditure are preliminary and subject to Board approval, available funding, internal sanctioning, and drilling results. Please see the Disclosure Forward Looking Statements section.

9 GOM Deep Water: Pompano Amberjack Corridor Legend Producing or HBP Primary Term Carrick Current rate: 10,000 boepd net 16 Exploitation well portfolio 17 Exploration well portfolio 60,000 bopd Pompano platform capacity 9

10 GOM Deepwater: Pompano Tie Back Development (MC 28/29) Cardona Operator SGY 65% working interest Projected first well spud 1q 2014 Estimated rate 6,000 boepd per well 1 st production target 1q mmboe gross per well * $54 million net well DHC * * #-15 ST Loc #34 Loc Shale Out Cardona 13,575 TVD A Salt A A Cardona TB-9 Cardona South WD: 2,007 WD: 2,185 5 mmboe #TB-9 10 mmboe Shale Out Cum Prod 116 mmboe Cardona South A 12,075 TVD Shale Out 5 mmboe Legend Producing Prospective Shale Out 10 * Well rates and potential resources are internally estimated by Stone by calculating a P90-P10 range. The dry hole cost (DHC) is estimated by Stone or the operator.

11 GOM Deep Water: Pompano Tieback Development Pompano Cardona Long Term Operability Future capability and flexibility Multiple flow options Optimize access Cardona South Sand Detector Available Hub Subsea FEED Detailed Design ITT Prep & Mitigation Issue ITT LLI Long Leads Valves - LLI Umbilical - LLI Connectors LLI Flowline Fab LLI Flowline Spool LLI Topsides Activities Fab/Install Topsides Eqpt Interconnect/Commission J Tube Reclaim Cardona D/C Ensco 8502 Cardona S D/C Ensco 8502 Subsea Installation Template E-Umbilical/SUTA Cardona Umbilical/SUTA Cardona Flowline/PLET Interconnect/Commission Platform Rig Install First Production Range First Production Cardona Q 4Q Critical Path Schedule Delivery Milestones Front End Engineering Design Order Long Lead Equipment Topsides Modifications Execute EPIC Contract Drilling and Completion Progress Report and Status Completed 3Q2013 Completed 3Q2013 Began 3Q2013 Complete 2Q2014 Completed 3Q2013 Rig Contracted 1Q2014 Spud 11 * Future Capital Expenditure are preliminary and subject to Board approval, available funding, internal sanctioning, and drilling results. Please see the Disclosure Forward Looking Statements section.

12 GOM Deepwater: Pompano Platform Development (MC 28) Cardona Operator SGY 100% working interest Projected spud 1q 2015 Estimated well rates 4,600 boepd 1 st production target 2q mmboe gross per well * $45 million net well DHC * * A WD: 1,295 A A15 A15ST A34 TB-5 A #A-15 ST Loc #A34 Loc Shale Out Cardona 13,575 TVD #TB-9 A Salt 10 mmboe Shale Out Cum Prod 116 mmboe Cardona South A 12,075 TVD Shale Out 12 A15 Cum 8 mmboe TB-5 Cum 20 mmboe Legend Producing Prospective * Well rates and potential resources are internally estimated by Stone by calculating a P90-P10 range. The dry hole cost (DHC) is estimated by Stone or the operator. A Shale Out

13 GOM Deepwater: Exploration Drilling (2013) Taggart San Marcos SGY 22.92% Operator LLOG Discovery 90 Feet Net Pay Offsets Devils Tower DHC $45 mm net Salt SGY 25% Operator APA mmboe gross Currently drilling Offset Shell Vito DHC $31 mm net * * Amethyst Mica Deep Salt SGY 100% Operator SGY 8-56 mmboe gross Projected spud 4q 2013 Strong AVO response DHC $100 mm gross SGY 50% Operator XOM mmboe gross Possible spud late 2013 Offsets Marmalard DHC $41 mm net 13 * Potential resources for all prospects are internally estimated by Stone by calculating a P90-P10 range. The dry hole cost (DHC) is estimated by Stone or the operator.

14 GOM Deep Water: Exploration Drilling (2014) Phinisi Derbio Salt SGY 20% Operator ENI mmboe gross Between St. Malo, Jack DHC $32 mm net * * SGY 100% Operator SGY mmboe gross Awarded offset lease DHC $104 mm net Goodfellow Twenty-One Salt SGY 13% Operator ENI mmboe gross Significant field potential DHC $40 mm net Salt SGY 37% Operator Conoco mmboe gross Offsets $53 mm CVX block DHC $20 mm net 14 * Potential resources for all prospects are internally estimated by Stone by calculating a P90-P10 range. The dry hole cost (DHC) is estimated by Stone or the operator.

15 5 Year Plan: Gulf Coast Liquids Rich Gas 15

16 Gulf Coast Liquids Rich Gas: Exploration South Erath Moss #1 Thunder Bayou Prospect Tom Cat A A Tom Cat A Shallow Field 1.2 TCF, 20 mmbo M-2 La Montana Prospect La Cantera Broussard #1ST Broussard #2 BHL Loc Thibodeaux #1 A La Cantera Discovery SGY 35% working interest Tom Cat Prospect 300 pay zone 200 bcfe gross 3P reserves* 120 mmcfed gross La Montana Prospect Houston Tom Cat La Cantera Lafayette Weeks Bay 4 way closure below 1 TCF field Deeper Operc A target Working Interest 100% bcfe gross SGY 100% working interest Miocene target DHC $38 million gross bcf gross ** DHC $26 million gross ** * 3P reserves = Proved (60%), Probable (15%), Possible (25%) 16 ** Potential resources are internally estimated by Stone by calculating a P90-P10 range. The dry hole cost (DHC) is estimated by Stone or the operator.

17 5 Year Plan: Appalachia Liquids Rich Gas 17

18 5 Year Plan: Appalachia Upside and Valuation Enterprise Value($MM) Ohio West Virginia Sea Level Moundsville Plant Upper Devonian Marcellus Utica Ft. Beeler Plant Christine 31,000 net acres Katie/Andie 11,000 net acres Basement 4 Condensate 12 Gas Mary/Heather 39,000 net acres Buddy 6,000 net acres Upper Devonian 2013 test at Mary Utica 2014/2015 test Christine potential Mary Field Resource Company Valuations* 3000 Total Appalachia 3P net reserves 1.4 tcfe* Gross 3P reserves per Mary well: 5.1 bcfe 24 Gas SGY Initial Condensate Yield 70 bpmm NGL Yield 55 bpmm Over 250 remaining locations (gross) Drilling costs trending down Commodity price improving 12 Gas Heather Field Mobley Plant Production Bcfe/year Implied Market Value of Stone Marcellus * 3P reserves = Proved (26%), Probable (14%), Possible (60%) * AXAS, CXPO, GST, TPLM, CRK, GDP, PDCE, PVA, SFY, CRZO, RRC, ROSE, UPL, COG, REXX (As of August 2013) 18 Potential resources are internally estimated by Stone by calculating a P90-P10 range.

19 19

20 5 Year Plan: Potential Project Investment List * Conventional Shelf SS113 Coracle 1 SS113 Well 2 Well Program 2 Well Program 2 Well Program SS 113 Tail Dancer ST 100 Hammerlock 2-4 Well Drill Program Clovelly Hyena Weeks Island Deep Gas Deep Water La Cantera No. 3 El Jaguar La Cantera Extension Pumpkin Ridge Extension Aardvark South Erath Extension Pumpkin Ridge Onshore Surrogates Onshore Surrogates Tom Cat La Montana Cote Blanche Onshore Surrogates Onshore Surrogate Cardona Lamprey Apple Ruby San Marco Parmer Oil Carrick Almadine Rainbow Bridge Guadelupe Cardona South Parmer Gas Beryl Bayan 2 Pompano Pud Wells Sherwood Aries Jaguarundi Malachite 1 Amberjack Well Amberjack Wells Mica Deep Extension Taggart Phinisi Moore Rialto Amethyst Goodfellow 2 Pompano Pud Wells Miocene Surrogate Mica Deep 4 Well Amberjack Program Tieback Surrogates Twenty One Vernaccia Derbio Mallard Pompano TB-9 Workover Appalachia 1 Rig Drill Program 1 Rig Drill Program 1 Rig Drill Program 1 Rig Drill Program 1 Rig Drill Program Business Development 20 * Future Capital Expenditure are preliminary and subject to timing estimates, chance of occurrence and Board approval, available funding, internal sanctioning and drilling results. Please see the Disclosure Forward Looking Statements section.

21 21

22 Disclosure Forward-Looking Statements. This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of Certain statements in this presentation are forward-looking and are based upon the current belief of Stone Energy Corporation ("Stone") as to the outcome and timing of future events. All statements, other than statements of historical facts, that address activities that Stone plans, expects, believes, projects, estimates or anticipates will, should or may occur in the future, including future production of oil and gas, future capital expenditures and drilling of wells and future financial or operating results are forward-looking statements. No assurance can be given that any of such plans, expectations, estimates or projections will prove to have been correct, and the same can be affected by inaccurate assumptions or by known or unknown risks or uncertainties. Important factors that could cause actual results or other expectations expressed in this presentation to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks, liquidity risks, political and regulatory developments and legislation, including developments and legislation relating to our operations in the Gulf of Mexico and Appalachia, and other risk factors as described in Stone's Annual Report on Form 10-K and Quarterly Reports on Form 10-Q as filed with the Securities and Exchange Commission ("SEC"). Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Stone's actual results and plans could differ materially from those expressed in the forward-looking statements. Given these risks and uncertainties, you are cautioned not to place undue reliance on forwardlooking statements, which speak only as of the date of this presentation or as of the report document in which they are contained. Absent legal requirement, we assume no duty to update these statements as of any future date. You should review carefully reports and documents that Stone files periodically with the SEC. Reserves The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions of such terms. Stone discloses only estimated proved reserves in its filings with the SEC. Stone's estimated proved, probable and possible reserves as of December 31, 2012 contained in this presentation were prepared by Netherland, Sewell & Associates, Inc., a nationally recognized engineering firm, and comply with definitions promulgated by the SEC. Additional information on Stone's estimated proved reserves is contained in Stone's Annual Report on Form 10-K. In this presentation, Stone may also use internal estimates of prospective or potential resources or other descriptions of volumes of resources potentially recoverable through additional exploratory drilling or recovery techniques, which volumes the SEC's guidelines strictly prohibit Stone from including in filings with the SEC. These estimates, as well as estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by Stone. Prospective resources refers to Stone's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. Prospective resources does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System. Actual quantities that may be ultimately recovered from Stone's interests might differ substantially. Factors affecting ultimate recovery include the scope of Stone s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, changes in law and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of prospective resources may change significantly as development of our resource plays provides additional data. Investors are urged to consider closely the disclosures in Stone's Annual Report on Form 10-K and Stone s Quarterly Reports on Form 10-Q, available free of charge on our internet site ( You can also obtain this form from the SEC on the SEC's internet site ( or by calling SEC

23 Appendix EBITDA Reconciliation 12 Months Ending 6/30/13 Net Income Interest expense Income taxes DD&A Accretion EBITDA $ $635 (In Millions) 23 * EBITDA is defined as net earnings plus interest expense, income taxes, DD&A, property write-down and accretion.

24 Revenue: Hedging Transactions Daily Volume (Bbl/d) Oil Price Daily Volume (Mmbtu/d) Natural Gas Price ,000 $92.35* Swap Contract ,000 $92.80 Swap Contract 10,000 $4.00 Swap Contract ,000 $94.45 Swap Contract ,000** $4.05 Swap Contract ,000 $94.60 Swap Contract ,000* $4.45 Swap Contract ,000 $97.15 Swap Contract ,000 $5.27 Swap Contract ,000 $ Swap Contract ,000 $5.32 Swap Contract ,000 $ Swap Contract 60,000 $ ,000 $ Swap Contract ,000 $ Swap Contract ,000 $4.00 Swap Contract ,000 $ Swap Contract ,000 $4.04 Swap Contract ,000 $ Swap Contract ,000 $4.10 Swap Contract ,000 $ Swap Contract ,000 $4.19 Swap Contract 13,000 $ ,000 $4.25 Swap Contract ,000 $4.35 Swap Contract ,000 $90.06 Swap Contract ,000 $92.25 Swap Contract 60,000 $ ,000 $93.55 Swap Contract ,000 $4.00 Swap Contract ,000 $94.00 Swap Contract ,000 $4.22 Swap Contract ,000 $98.00 Swap Contract ,000 $4.25 Swap Contract ,000 $98.30 Swap Contract 30,000 $ ,000 $98.85*** Swap Contract ,000 $99.65 Swap Contract ,000 $ Swap Contract Oil Gas Total 10,000 $ ,000 $90.00 Swap Contract Approximate % 39% 48% 1,000 $90.00 Percentage Hedged % 54% 46% % 23% 12% 24 Brent oil contract * July December **April - December ***Jan-June

25 Contacts Kenneth H. Beer Chief Financial Officer Phone: (337) Fax: (337) Tom Messonnier Director of Strategic Planning Phone: (337) Fax: (337)

26 26