Timing the Return to Normalization for Offshore Drilling

Transcription

1 Timing the Return to Normalization for Offshore Drilling Marine Money Offshore Finance Forum Michael Acuff, SVP Sales and Business Development, Pacific Drilling April 7, 216

2 Forward Looking Statements Certain statements and information contained in this presentation constitute forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, and are generally identifiable by the use of words such as estimate, expect, forecast, plan, potential, projected, target, or other similar words, which are generally not historical in nature. The forward-looking statements speak only as of the date hereof, and we undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. Our forward-looking statements express our current expectations or forecasts of possible future results or events, including: market outlook; forecasts of trends; future client contract opportunities; and our business strategies and plans and objectives of management. Although we believe that the assumptions and expectations reflected in our forward-looking statements are reasonable and made in good faith, these statements are not guarantees and actual future results may differ materially due to a variety of factors. These statements are subject to a number of risks and uncertainties, many of which are beyond our control. Important factors that could cause actual results to differ materially from our expectations include: the global oil and gas market and its impact on demand for our services; the offshore drilling market, including reduced capital expenditures by our clients; changes in worldwide oil and gas supply and demand; rig availability and supply and demand for high-specification drillships and other drilling rigs competing with our fleet; costs related to stacking of rigs; our ability to enter into and negotiate favorable terms for new drilling contracts or extensions; possible cancellation, renegotiation, termination or suspension of drilling contracts as a result of market changes or other reasons. 2

3 Summary Two part solution to fixing the offshore rig market -Stacking/scrapping/delaying newbuild rigs -Demand recovery (stabilization/marginal growth) -Floating rig market will be smaller than the 215 peak floater fleet (~35 down to ~225 rigs) -But the fleet will be more technologically capable -Recovery timeframe is likely to begin in late 217 as rig contracting restarts -Dayrates will likely increase in as the market begins to tighten 3

4 Scale of Recent 6 th /7 th Gen Newbuild Cycle is Relatively in Line with 3 rd /4 th Gen Cycle Floater Fleet by Delivery Year # of Rigs Delivered # of UDW Rigs in Fleet Removed From Fleet UDW Floater Fleet (RHS) Source: IHS-Petrodata 4

5 Aging Floater Fleet Replaced By Newer, More Efficient Rigs 45 Floater Fleet Composition No growth since 1985 with a fleet total of ~ Under Construction Less than 1 years 1-2 years 2-3 years More than 3 years Source: IHS-Petrodata 5

6 ~115 Rigs Have Left the Market Since 214 and See Potential for Additional ~5 to Leave Through Actual and Forecasted Rig Removal through Cold Stacking and Scrapping Q1 214 Q2 214 Q3 214 Q4 214 Q1 215 Q2 215 Q3 215 Q4 215 Q1 216 Overdue Q2 216 Q3 216 Q4 216 Q1 217 Q2 217 Q3 217 Q4 217 Post 217 Cold Stacked/Scrapped 6th gen+ 5th gen 4th gen 3rd gen- Expected C. Stacked/Scrapped 6th gen+ 5th gen 4th gen 3rd gen- Cumulative Out of Market (RHS) Estimated Out of Market (RHS) Source: IHS-Petrodata, PACD estimates 6

7 Floater Fleet Profile vs Projected 218 Floater Fleet Profile Shows a Net Fleet Decline of ~13 Rigs (-37%) 215 Peak Fleet 3 Projected Floater Fleet Changes Prior Scrapped Prior Cold Stacked End of 218 (355) (224) Additions Removals Abs. Growth % Change 6th Gen % 5th Gen -24-3% 4th Gen -17-5% 3rd Gen % -7 Additions include 4 newbuilds (7 Sete) to be delivered through 218, though we believe all are at risk for delays and some for cancellation Source: IHS-Petrodata, Cold stacking is assumed after a rig is stacked for more than six months or after announced, PACD estimates 7

8 But More Capable Remaining Fleet Translates to Effective Fleet Decline of 33% 393 Effective Floater Fleet (fleet x Gen drilling efficiency) -33% Decline Progression from 3rd through 5th gen was predominately focused on drilling deeper wells and carrying heavier loads Peak Fleet End 215 End 216 End 217 End 218 Move from 5th to 6th gen and especially to 7th is focused on increasing operational efficiencies This increased efficiency is reflected in the greater weighting given to 6th Gen + rigs Technology used to improve efficiency include: Offline handling Dual mud systems Dual BOPs Increase tripping speeds Longer joints More deck load / storage Condition based maintenance 6th gen+ 5th gen 4th gen 3rd gen- Est. Drilling Efficiency 1.33x 1.1x 1.x 1.x Source: IHS-Petrodata, Cold stacking is assumed after a rig is stacked for more than six months or after announced, PACD estimates 8

9 By 217 Drilling Contracts Spend Reduces By 5%, Allowing Operators to Reset New Project Costs $7 Historic and Contracted Floater Spend by Generation 3 $6 6th gen+ 4th gen Committed Rig Count (RHS) 5th gen 3rd gen- 216 Capex Level Rig Count (RHS)* 25 $5 Capex on Floating Rigs, $B $4 $3 $2 $1-1% % % % Floating Rig Count $ Committed 217 Committed 218 Committed Note: excludes owner-operated rigs, assumes all non-published dayrates are based on the average other contracted rigs dayrates: 3 rd gen-$34k/d, 4 th gen-4k/d, 5 th gen-475k/d, 6 th gen-52k/d *The rig count if 216 capex levels are maintained and rigs are signed at $25k/d to reach this level 9

10 Analysts Predict Demand Recovery in Analyst Projected Active Floating Rig Count Historic Analyst 1 Analyst 2 Analyst 3 Base Analyst 3 Bull Analyst 4 Flat 216 Spend Analysts include: Evercore ISI, Fearnley s, Morgan Stanley, Wells Fargo, PACD 1

11 Recovery Dependent on Pace of Demand and Removal of Excess Capacity 8 Contracted vs Available Rigs by Generation Cold Stacked/Scrapped Expected Cold Stacking/Scrapping Undelivered Newbuilds Uncontracted Below 5 th gen Contracted Below 5 th gen Uncontracted 5 th gen Contracted 5 th gen Uncontracted 6 th gen Contracted 6 th gen Demand, ranged (source: Analyst Range) High Demand Range -19% -5% 12% 13% 1% Mid Demand -21% -8% 1% 1% 9% Low Demand Range -24% -12% 7% 7% 8% Source: IHS-Petrodata, PACD estimates, stylized analyst range 11

12 Pace of Fixtures Projected to Pick Up from Late 217 to Mid Contracted vs Available Rigs by Generation Recovery Timeframe late 217 Mid 219 Expected Cold Stacking/Scrapping Undelivered Newbuilds Contracted Below 5 th gen Contracted 5 th gen Uncontracted Below 5 th gen Uncontracted 5 th gen Uncontracted 6 th gen Contracted 6 th gen Demand, ranged (source: Analyst Range) Source: IHS-Petrodata, PACD estimates, stylized analyst range 12

13 Normal High Spec Utilization is Between 9%-1%, Current Utilization is Unprecedented 1% Floater Fleet Utilization 9% 8% 7% 6% 5% 4% Utilization -1 years Utilization 1-2 years Utilization 2-3 years Utilization >3 years Source: IHS-Petrodata 13

14 Historic Data Shows, When Marketed Utilization is 88%+, Dayrates Begin Increasing Floater Utilization vs 4th Gen Dayrates Q $ k/day 25 2 Q Q1 94 Q1 3 7% 8% 9% 1% Utilization Source: RS Platou, PACD estimates 14

15 Positive Pricing Pressure Could Occur as Early as Late 217 in a High Demand Scenario 8 Contracted vs Available Rigs by Generation Recovery Timeframe late 217 Mid 219 High Demand Mid Demand Low Demand Contracted Below 5 th gen Undelivered Newbuilds Uncontracted Below 5 th gen Uncontracted 5 th gen Contracted 5 th gen Uncontracted 6 th gen Contracted 6 th gen Demand, ranged (source: Analyst Range) # 88% marketed utilization Source: IHS-Petrodata, PACD estimates, stylized analyst range; Marketed utilization of 88% excludes undelivered newbuilds 15

16 Because We See a Recovery Within the Next 3 Years for 6 th /7 th Gens, Smart Stacking is More Economic than Cold Stacking Smart Stack Cold Stack 3k/d Opex (crew, fuel, insurance, fees, port dues ) No upfront costs Avoids significant reactivation costs and risks Approx. 9 days to reactivate rig More marketable rig makes it more likely to go back to work sooner than cold stacked rigs Option to raft rigs could significantly decrease opex 12k/d Opex (crew, fuel, insurance, fees, port dues ) Significant upfront costs Substantial unknown reactivation costs (market estimates range from $5m- $1m) For each $1m in reactivation cost indifference point is pushed out 2 months Approx. 15 days to reactivate rig DDDDDDDDDDDDDDDDDDDD iiii UUUUUUUUUUUUUU aaaaaa RRRRRRRRRRRRRRRRRRRRRRRR CCCCCCCC oooo eeeeeee oooooooooooo DDDDDDDDDDDDDDDDDDDD iiii RRRRRRRRRRRRRRRRRRRR OOOOOOOOOOOOOOOOOO DDDDDDDDDD CCCCCCCC oooo eeeeeee oooooooooooo = Number of Days off contract prefer tosmart stack Source: PACD estimates 16