Deutsche Bank 22nd Annual Leveraged Finance Conference

Transcription

1 Deutsche Bank 22nd Annual Leveraged Finance Conference October 1, 2014 Scottsdale, Arizona

2 Disclosure This material contains statements that are forward looking statements about Paragon s business and financial performance. These statements can be identified by the fact that they do relate strictly to current or historical facts. Each future projection is a forward looking statement that involves certain risks, uncertainties and assumptions. These include but are not limited to operational risks, actions by regulatory authorities or other third parties, costs and difficulties related to the separation, market conditions, financial results and performance, tax rates, ability to repay debt and timing thereof, actions by customers and other third parties, factors affecting the level of activity in the oil and gas industry, supply and demand of drilling rigs, factors affecting the duration of contracts, the actual amount of downtime, factors that reduce applicable dayrates, violations of anticorruption laws, the future price of oil and gas and other factors including those detailed in Paragon s filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. Paragon disclaims any duty to update the information presented here. 2

3 Agenda Introducing Paragon Offshore Key Challenges and Paragon s Strategy Conclusion Paragon C

4 Overview of Paragon Offshore Business Overview Worldwide Offshore Presence Offshore contract drilling services provider operating standard specification rigs Spin-off from Noble Corporation completed 1 August 2014 Headquartered in Houston, TX and incorporated in the United Kingdom NYSE: PGN 6/30/2014 Estimated EBITDA* by Region Mexico Jackups: 11 Canada Hibernia Platform Operations Brazil Drillships: 3 Semis: 1 West Africa Jackups: 4 North Sea Semis: 1 Jackups: 7 Middle East Jackups: 9 India/Asia Drillships: 1 Jackups: 2 West Africa 8% Brazil 18% Middle East 16% India / Asia 6% Mexico 19% North Sea 33% Operating* Fleet Composition Jackups: 33 Drillships: 4 Semisubmersibles: 2 Total: 39 * See Appendix for reconciliation to EBITDA. Map and Operating Fleet do not include cold stacked rigs, which includes two floaters, one jackup, and one FPSO. 4

5 Paragon s Strategy Deliver reliable, safe, cost-efficient operations Match our assets to customers in fitfor-purpose applications while maintaining industry-leading utilization Manage our costs to preserve flexibility in changing dayrate environments Practice disciplined capital allocation in terms of fleet maintenance, fleet growth and returns to shareholders Paragon DPDS2 5

6 Significant Contract Backlog with Global Customers $ in millions $ 750 $ 500 $ 561 $2.3 Bn of Backlog As of 6/30/2014 $ 508 $443 Backlog by Customer Other 28% Nexen 4% ADMA- OPCO 5% Total 7% as of 6/30/2014 Petrobras 42% Pemex 14% ~2/3 of Backlog with NOCs $ 250 $292 $255 $ 99 $111 $ E Remaining 2015E 2016E 2017E $ 2 Jackups: 52% Floaters: 48% Source: Company 6

7 Strong History of Utilization Speaks to Quality of Operations & Assets Marketed fleet utilization for non-us rigs 15 years old and older since January 1, 2011 Percentage 100 ILC Jackup Utilization Percentage 100 Floater Utilization Paragon Rest of Industry 70 Paragon Rest of Industry Source: IHS Petrodata ; company analysis 7

8 Industry-Leading Safety and Quality Performance Commitment to Safety and Quality Strong Safety Record FY2012 FY st Half 2014 Customers recognize our commitment to safety and performance ~50% lower TRIR 1 than International Association of Drilling Contractors (IADC) in Continued improvement and outperformance as compared to IADC Promotes strong relationships with key stakeholders such as employees, customers, and the local communities in which we operate We believe that our excellent safety record contributes to lower downtime and lower costs IADC Paragon 1. TRIR defined as the number of recordable injuries and illnesses incurred in the period multiplied by 200,000 and then divided by the total number of employee hours worked. A lower TRIR is better. 2. Includes both offshore and onshore contract drillers 8

9 Key Challenges Jackup market capacity additions and potential impact on the market Some customers focusing on more challenging wells (e.g., wells requiring higher specification rigs) Petrobras rollover of current floater contracts Capital structure and capital allocation strategy Paragon DPDS3 9

10 Newbuild Jackup Orders According to IHS 22 September Total Newbuilds Contracted Rigs 141 Anticipated Jackup Deliveries 25 Rigs on Order- No Contract Rigs Under Construction-No Contract China Singapore Other (USA, UAE, India, Indonesia, Qatar) Rig by Design Forecasted Deliveries by Year * Preferred designs for established drilling contractors 23 JU2000E* Gusto CJ-46 Keppel B Class LeT Super 116E PPL Pacific 400 Gusto CJ-50* Keppel Super B* Gusto CJ-70* Other Other UAE Singapore China Contracted Source: IHS Petrodata

11 Considerations for the Jackup Markets Large jackup orderbook may be cause for concern, but more nuanced analysis of the market is required. Consider: Newbuilds Will all newbuilds actually be delivered? If so, will they be on time? Are some designs targeted at noncompetitive markets (China, Iran, etc.) or less interesting for potential buyers? Will there be quality issues with some yards? How will speculators market, crew and operate these rigs? What break-even cash (operating + financing costs) dayrate is required? Customer Behavior Do all customers need and want newbuild jackups to execute their programs? What true efficiencies do newbuilds offer customers? What is the price elasticity of different customers? Will Paragon s customers maintain spending and activity levels? Standard Fleet Are all standard assets of the same quality? At what pace will we see retirements/stacking? Whose assets are likely to be stacked/retired first? 11

12 Differences Between Floater and Jackup Markets Fixtures for UDW Rigs > 7,500 Ultradeepwater Floater Markets Few fixtures over last 12 months and downward trend Demand governed by relatively few customers (supermajors, Petrobras) who have alternative uses for capital (e.g., Lower 48 onshore) Supply of 93 units scheduled for delivery between now and 2020; built largely by established drilling contractors (50) or for Petrobras (29) Fixtures for International ILC Jackups International Jackup Markets Many fixtures over last 12 months at flat rates Many more jackup customers vs. floater customers; not nearly as many opportunities to redeploy capital away from offshore; additional demand projected Supply of 141 units scheduled for delivery between now and 2017 Built largely by financial speculators (more than 50%) looking to sell Source: IHS Petrodata

13 People A Key Ingredient for Success and an Advantage for Paragon With 141 jackups and 93 floaters under construction, the industry needs to add a significant number of people to crew these units At an average of 100 people per rig, we will need more than 20,000 new employees to crew these rigs Although rig stacking and retirements will likely make crews available for some newbuilds, a large proportion of the workforce is past the age of 50, which means that the great crew change is coming Many safety and downtime incidents can be traced to human error those contractors with the most experienced crews and best training programs, like Paragon, will be best positioned for success 13

14 Paragon s Contract Coverage 15 September 2014 Fleet Status Jackup Floater Rig Name Region DPDS3 (NRE) Brazil DPDS2 (NLS) Brazil M1162 (NRR) Arabian Gulf B301 (NJH) Mexico B391 (NJR) North Sea M825 (NEN) West Africa L1113 (NJS) Mexico M842 (NEP) Mexico L1115 (NHD) Arabian Gulf C462 (NPvE) North Sea C20051 (NAW) North Sea B152 (NDF) Arabian Gulf MDS1 (NDU) India C461 (NLB) North Sea MSS2 (NTM) Brazil Dhabi II Arabian Gulf HZ1 (NGS) North Sea MSS1 (NTvL) North Sea DPDS1 (NPH) Brazil M824 (NTJ) Mexico L785 (NGM) Malaysia M531 (NLJ) Mexico L1112 (NEH) India L782 (NPJ) West Africa L781 (NRB) Mexico M841 (NBJ) Mexico C20052 (NBW) North Sea C463 (NRH) North Sea L783 (NTC) West Africa L784 (NJP) Arabian Gulf M826 (NLN) West Africa L1114 (NSN) Mexico M823 (NEF) Mexico M821 (NCN) Mexico L1116 (NGR) Mexico L1111 (NGA) Arabian Gulf M1161 (NCY) Arabian Gulf L786 (NKD) Arabian Gulf M822 (NCS) Arabian Gulf Source: Company data J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F 2015 Committed Days ~39% of jackup ~66% of floater 2017 M A M J J A S O N D 14

15 Mexico Reform Likely to Continue to Provide Opportunities Mexican Energy Reform Underway Round 0: Pemex received 100% of 2P and 67% of Prospective Reserve requests including current shallow water areas Round 0.5 expected: Tandem with Round 1, allows Pemex to partner with foreign firms to develop areas from Round 0 Round 1: 169 blocks across deepwater, shallow water, and onshore to be placed on offer for a total of 3.9 Bn barrels of 2P reserves. Assignment of contracts planned for May- September 2015 * Average dayrates for rigs where dayrate is known Sources: IHS Petrodata, PEMEX PEMEX to retain: 93% (8 bn boe) PEMEX to retain: 15% (8.9 bn boe) PEMEX to retain: 59% (9.5 bn boe) PEMEX to retain: 29% (8.1 bn boe) 46 jackups currently drilling 22 < 15 years old; Avg. Dayrate*: $147k 24 > 15 years old; Avg. Dayrate*: $ 94k Paragon is the international contractor who currently provides the greatest number of rigs to PEMEX 15

16 Paragon s Position in Brazil Four of Paragon s floaters operate in the postsalt Campos Basin where decline rates are estimated to exceed 10% per year Capex budget for Petrobras has increased by ~4.6% Rigs under construction in Brazil likely to be delayed and over budget (potentially >$ 1 Bn per unit) Brazil is one of Paragon s centers of Subsea Excellence Paragon also provides operational and shorebase support for Noble Corporation s floaters in Brazil DPDS3 DPDS1 DPDS2 MSS2 Two of Paragon s floaters come off contract in

17 Capital Structure Overview In Millions $73 $800 $ June 2014 Pro-forma Cash Balance Revolving Credit Facility, Matures 2019 Undrawn LIBOR % Secured Term Loan, Matures 2021 LIBOR %, 1% Floor 1% annual repayment $1,730 Million $500 $ % Senior Unsecured Notes due 2022 Non-call for 4 years 7.25% Senior Unsecured Notes due 2024 Non-call for 5 years 17

18 Debt Maturity Profile In Millions $800 $700 $600 Revolver $500 $400 Term Loan (including required amortization) $800 $300 $200 Senior Notes $609 $500 $580 $100 $0 $2 $7 $7 $7 $7 $

19 $800MM Revolving Credit Facility $800MM Revolving Credit Facility, with $80MM swing line and $300MM accordion Ratings: BBB- (S&P), Baa3 (Moody s) Pricing: LIBOR %, plus annual commitment fee of 0.375%, both based on Leverage Ratio Collateral: All rigs except the FPSO1 (Seillean), the DPDS4 (Muravlenko), and the B153 (Don Walker). Collateral is shared equally with the Term Loan lenders Cross guarantees: All rig owning companies and rig contracting companies Financial Covenants: Leverage Ratio: Maximum Net Debt 1 to EBITDA of 4 to 1 Interest Coverage: Minimum EBITDA to Interest Expense of 3 to 1 Letters of Credit full amount of facility available for letters of credit. LC s priced at 2.00%. Incremental Non-Revolver Debt: Allowed if Leverage less than 3.5 to 1 Restricted Payments -- No limits on Restricted Payments if Leverage Ratio is below 2.5 to 1 Restricted Payments Baskets not limited by Leverage Ratio: Annual dividends up to $93M, growing by 10% per year Grower basket = Cumulative 50% of Consolidated Net Income and 100% of Net Loss Currently at $0 General basket of $50MM Stock buybacks of $20MM in the aggregate Asset Sales Limited when Leverage Ratio is greater than 3 to 1 $150MM in annual asset sales allowed if Collateral Coverage Ratio is greater than 1.5 to 1. 1 Debt less balance sheet cash 19

20 $650MM Term Loan $650MM, 7 year Term Loan Ratings: BBB- (S&P), Baa3 (Moody s) Pricing: LIBOR %, 1% LIBOR Floor Amortization: $1.6MM quarterly ($6.5MM per year). Pre-payable at any time at par Collateral: All rigs except the FPSO1 (Seillean), the DPDS4 (Muravlenko), and the B153 (Don Walker). Collateral is shared equally with the Revolver lenders Cross guarantees: All rig owning companies and rig contracting companies Financial Covenants: None Change of Control put at 101% Incremental Debt not subject to Incurrence Test: Greater of $1.65B or ($500M + 25% of Consolidated Tangible Assets) Debt incurrence test: Fixed charge coverage greater than 2.0 to 1 Restricted Payment Limitations: Restricted payments not limited if Leverage ratio is below 2.5 to 1 Certain payments possible, subject to passing debt incurrence test Excess Cash Flow Sweep: Sweep of 25% of excess annual cash flow if leverage is between 3.0x and 3.25x Sweep of 50% of excess annual cash flow if leverage is above 3.25x. Excess Cash Flow = EBITDA less (capex, principal reductions, cash payments for tax and interest) 20

21 Senior Unsecured Notes $500MM, 6.75% notes maturing July 2022 (8 years) Non-call 4 years $580MM, 7.25% notes maturing August 2024 (10 years) Non-call 5 years Ratings: B+ (S&P), Ba3 (Moody s) Financial Covenants: None Change of Control put at 101% Incremental debt not subject to incurrence test: Greater of $1.65B or ($500M + 25% of Consolidated Tangible Assets) Allows for use of revolver plus accordion, and also allowed initial term loan funding Debt incurrence test: Fixed charge coverage greater than 2.0 to 1 Restricted Payment Limitations: Restricted payments not limited if Leverage ratio is below 2.5 to 1 If Leverage is above 2.5 to 1, then certain payments possible, subject to passing debt incurrence test Asset Sales: Proceeds from asset sales to be used for Capital Expenditures, repayment of Term Loan or other pari passu debt, acquisitions, or otherwise to redeem Senior Notes 21

22 Disciplined Capital Allocation The Focus for Paragon Offshore Secure contract renewals Focus on Existing Fleet Make disciplined investments to maintain fleet, improve competitiveness, extend life $180 MM Maintenance (base budget + survey-related expenditures) $ MM Discretionary Capability Upgrades, Customer Requirements, Capital Spares Explore sales of stacked rigs; potentially others Examine Options for Fleet Renewal Lower average fleet age over time Be opportunistic, patient and disciplined Refrain from spec building Focus on quality designs and yards; primarily jackups Steward Our Resources Announced plan to initiate $0.50/share dividend; first quarterly installment anticipated to be payable in 4Q14; expect to be sustainable and growable Explore and act as appropriate on opportunities to reduce debt and/or repurchase shares Seek to remain leverage-neutral when considering opportunities Invest through lens of ROCE 22

23 Paragon s Model Intact Under Stress Case Assume no contribution from floating rigs; jackups operating at 98% ILLUSTRATIVE Assume Cash Requirements: Cash operating costs: Interest expense: Cash taxes: Capital expenditures: SG&A: Dividend: Total cash requirements: $600 MM ($50k per day after inflation) 100 MM 50 MM 150 MM (maintenance capex only) 55 MM 45 MM $1,000 MM Breakeven jackup dayate: ~$85,000 per day Paragon still breaks even on a cash basis at ~30% below our current average dayrate of ~$120,000 per day 23

24 Conclusion 24

25 Why Paragon Offshore? Significant Scale, Size and Expertise Low-cost Driller with Proven Record of Excellence Strong Backlog and Established Diverse Customer Base Well-Maintained Workhorse Fleet of Rigs Opportunistic Acquirer Total Return Investment Vehicle Paragon C

26 NYSE Listed: PGN 3151 Briarpark Drive Houston, TX For additional information, contact: Lee M. Ahlstrom SVP-Investor Relations, Strategy & Planning

27 Appendix 27

28 Management Team with More Than 180 Years of Experience in the Industry Randy Stilley President and CEO 38 years experience Charlie Yester Senior VP - Operations 40 years experience Steve Manz Senior VP and CFO 25 years experience Todd Strickler Vice President and General Counsel 12 years experience Lee Ahlstrom Senior VP Investor Relations, Strategy and Planning 23 years experience Luis Jimenez Vice President Human Resources 25 years experience Andrew Tietz Senior VP Marketing and Contracts 23 years experience 28

29 Reconciliation to EBITDA Predecessor Historical Paragon Offshore Pro Forma Year Ended December 31, Year Ended December 31, Six Months /30/2014 Net Income $104,823 $126,237 $360,305 $172,387 $135,172 Add: Depreciation and amortization expense $348,834 $367,837 $413,305 $367,304 $200,838 Interest expense, net of amount capitalized 1,986 3,746 5, ,641 54,044 Interest income and other, net 59 (1,959) 1,897 2,306 (525) Income tax provision 30,079 48,688 85,605 71,243 38,871 EBITDA 1 $485,781 $544,549 $867,050 $546,494 $428,400 Loss on impairment $12,719 $0 $43,688 $40,103 $0 Gain on disposal of assets, net - - (35,646) - - Gain on contract settlements/extinguishments, net (19,846) (4,869) (24,373) (16,182) - Operating Income $136,947 $176,712 $453,745 $351,577 $227,562 Add: Depreciation and amortization expense 348, , , , ,838 EBITDA 1 $485,781 $544,549 $867,050 $718,881 $428,400 Loss on impairment $12,719 $0 $43,688 $40,103 - Gain on disposal of assets, net - - (35,646) - - Gain on contract settlements/extinguishments, net (19,846) (4,869) (24,373) (16,182) - Source: Company s Form 10 filed 14 July 2014, Company s Quarterly Report on Form 10-Q for the three and six months ended 30 June

30 30 June 2014 Pro-forma Summary Balance Sheet Assets Cash $72,688 Total Current Assets $505,488 PPE, Net $2,883,729 Total Assets $3,484,679 Liabilities and Equity Total Current Liabilities $281,350 Long-term Debt $1,726,750 Other Liabilities $185,574 Total Liabilities $2,193,674 Total Equity $1,291,005 Total Liabilities and Equity $3,484,679 Source: Company s Quarterly Report on Form 10-Q for the three and six months ended 30 June

31 Jackup Overview: Rigs 15 Years and Older Number of Units Key Owners of Standard ILC Jackups Total Standard Specification Jackups Mat and IC Slot Rigs ILC jackups Cold stacked/out of Service Regional Breakdown of Operating Units Other, 71 UAE, 32 Saudia Arabia, Operating Company Number of ILC Jackups 15 Years and Older Shelf Drilling 37 Paragon Offshore 34 Ensco 30 Rowan 10 National Drilling 10 Hercules Offshore 8 COSL 7 Nabors 6 ONGC 6 GSP 6 Diamond Offshore 5 Noble 5 Transocean 5 Other (50 companies with 5 rigs or less incl. 41 with 1 or 2 rigs) 88 Total 257 Iran, 8 Qatar, 9 UK, 11 Mexico, 27 India, 21 Egypt, 12 China, 12 USA, 17 Source: IHS Petrodata as of

32 Jackup Overview: Newer Standard Rigs Less Than 15 Years Old JU-2000, 2 CJ-50, 4 L-780 Mod II, 6 CJ-46, 7 KFLES Mod V B types, 10 Other, 37 Breakdown by Design: 123 Total Mod V A, 2 Other, 8 LeTourneau 116, 26 KFELS B Class, 31 Mexico, 16 BMC 375, 27 Regional Breakdown of Operating Units Iran, 10 Key Owners of Newer Standard Jackups Company Number of ILC Jackups 14 Years and Older Seadrill 16 COSL 16 Ensco 8 CPOE 6 Maersk Drilling 6 Aban Offshore 5 National Drilling 5 Perforadora Central 4 UMW Standard Drilling 4 Rowan 4 Egyptian Drilling 4 Vantage Drilling 4 Other (21 companies with 3 rigs or less incl. 6 with 1 rig) 41 Total 257 China, 10 Gabon, 5 Saudi Arabia, 9 UAE, 6 Indonesia, 7 India, 7 Vietnam, 7 Malaysia, 9 Source: IHS Petrodata as of

33 Floater Overview Drillships and Semisubmersibles 15 Years and Older Number of Units 15 Years or Older Key Owners of Standard Floaters Total Standard Specification Floaters Other, 46 Drillships Semisubs Cold stacked/out of Service Regional Breakdown of Operating Units Brazil, Operating Company Drillships 15 Years and Older Semisubs 15 Years and Older Total Floaters 15 Years and Older Transocean Diamond Offshore Noble Ensco Paragon Offshore COSL 6 6 Dolphin 6 6 Saipem 5 5 SOCAR 5 5 Other (26 companies with 4 rigs or less incl. 22 with 1 or 2 rigs) Total Azerbaijan, 5 China, 6 India, 9 Singapore, 9 Malaysia, 10 UK, 21 USA, 14 Norway, 12 Australia, 10 Source: IHS Petrodata as of

34 Why Our Old Jackups Are Not Going Away Assertion: Response: Rigs that are 35 years old must be retired! Our 35 year-old rigs have very little on them that is actually 35 years old. Our continual maintenance replaces steel, renews drilling equipment, and refurbishes quarters. Someone s old jackups may be retired, but we believe ours generally have 10+ years of life left in them Assertion : Response : Maintenance capex on those old rigs when you do a survey is prohibitive! We budget ~$2.5 MM/year per jackup for regular maintenance capex. Survey costs typically run $8-15 MM. Our philosophy is to spend a little each year so that when we get to the yard for a survey, there are no surprises. If there are, we ll be disciplined about the investment decision. Someone s old jackups may very well have this issue and those are the rigs that may be retired when they need a survey Assertion : Response : New rigs are so much more efficient! New floaters are much more efficient, but we estimate a new jackup is only 10-20% more efficient. But new jackup dayrates are generally $50,000+ higher than our dayrates and new rigs have downtime of 6-8% vs. our 2%. So dollar for dollar, you get more out of our rigs Assertion : Response : But every customer wants a new rig! Oil companies aren t that different from retail consumers. Of course, some customers want the latest and greatest and are willing to pay for it. But more need a rig that gets the job done at a competitive price in a safe, reliable, consistent manner. Of the 300 possible, potential or actual tenders ODS is currently tracking for jackups, less than 10% appear to specifically call for a new or high specification rig Assertion : You guys should just stack your rigs to improve the market Response : IHS reports over 100 drilling contractors operating jackups, so no one contractor can influence the jackup market. More than 65 companies only have one or two rigs in service or under construction. With our scale, our geographic reach, and our crews, we ve got a competitive advantage over most others in the marketplace Assertion : Response : New rig owners will just lower rates to compete with you Perhaps. But our opex is about $45,000 per day vs. a newbuild at $60,000 - $80,000 per day. And unlike the pure speculators, we don t have debt financing to pay which could add another $50,000 - $60,000 per day. So they can drop rates, but before they get to our current average dayrate of about $120,000, they could go cash-flow negative. We have a lot of room to maneuver Source: IHS Petrodata as of