klr initiation report - d. gacicia

Cyclical Wheel Is Turning If a Production Response Doesn’t Convince You, Then Multiple Expansion May

Darren Gacicia Managing Director

Senior Oilfield Services Analyst KLR Group, LLC 713-352-0887

[email protected]

For definitions and the distribution of analyst ratings, and other disclosures, please refer to pages 230 - 231 of this report

Bullish on Oil Services: Signs of Production Response Herald Turn in Cycle & Multiple Expansion for Shares Sector Outlook: Bullish Risk/Reward for Oil Services. We are launching coverage on the Oilfield Service sector with a positive outlook. Oilfield Service equities trading at bearish cyclical valuations represent an attractive risk/reward. In our view, the production response to lower upstream spending and the initial stages of the oil market recovery should provide a positive catalyst for the sector. Tighter commodity market balances over the course of 2016 may signal a positive turn in upstream activity, oil services capacity utilization, and positive operating leverage for the sector. Leaner oil services companies, fresh from cost cutting, internal re-alignments, and capacity attrition, may be poised to beat estimates and post outsized returns as the cycle turns. Against a backdrop of bearish sentiment and trough 2016 consensus estimates, we expect upward revisions to conservative consensus 2017 estimates and multiple expansion to reflect better oilfield service growth prospects.

Preferred Exposure: Premium Franchises & US Land. The market offers investors the opportunity to own premium franchises at meaningful discounts to our view of net present value (NPV). Our NPV methodology shifts focus from commodity forecast timing to intrinsic values, based on our forecast of average returns over the course of the upstream cycle (pg. 11). As outlined on the following page, we prefer oil services exposure to North America. In our view, US land activity likely recovers first, given short term availability of established services, equipment, midstream capacity, and infrastructure. We forecast US market fundamentals should bottom in 4Q15/1Q16 with a migration of E&Ps towards cash flow neutrality (limited funding gaps). We are buyers of US levered service & equipment stocks as activity levels bottom and downside estimate risks subside. Within North America, we favor the supply/demand outlook for land drillers ((HP, $51.37, B, $78.00PT), (PTEN, $14.80, B, $23.00PT), (NBR, $8.69, B, $13.00PT)) and pressure pumping companies (CJES, $4.81, B, $7.50PT) over those of proppant companies ((SLCA, $19.61, H, $20.00PT), (FMSA, $2.33, H, $2.30PT), (CRR, $16.32, H, $15.25PT)). Among services, equipment, and offshore drillers, company preferences become more stock specific. Smaller services companies, like SPN ($13.53, B, $21.00PT) and NR ($4.83, B, $7.25PT), slightly further out on the risk frontier, screen well to gain market share with industry consolidation. Equipment companies ((NOV, $33.29, B, $52.00PT), (FET, $12.22, B, $19.00PT)) screen better than diversified services, excluding SLB ($69.82, B, $105.00PT), due to merger concerns for HAL ($36.96, A, $46.00PT) and need for a more consistent returns track record to re-rate WFT ($8.85, A, $10.25PT). Rig oversupply, which hinders recovery of economics for offshore drillers, leads us to prefer equipment & services ((FI, $15.24, B, $23.00PT), (OIS, $28.06, B, $43.00PT), (FTI, $28.92, B, $43.00PT)) for exposure to the offshore market. As the turn in the cycle accelerates, we see potential upside to NPV valuations, as fundamentals improve and our estimates are de-risked (lower discount rates/WACC).

Catalyst: Under Investment Turns Commodity Markets. We want to own the oil services group, as the production response from lower oil prices becomes more apparent (negative IEA non-OPEC supply revisions pg. 28). Currently, oil prices reflect peak negative sentiment, due to concerns surrounding oversupply, incremental production from Iran, and high inventory levels. We expect the oil market to rebalance as lower crude prices, cash flow and capital spending has a negative impact on production. Negative IEA revisions to US production have begun. In our view, a lack of spending on larger, longer lead time international projects (~90% of world oil production) may add downside risk to international supply forecasts. Evidence of tighter oil markets should herald the need for more upstream spending, a positive turn in the outlook for oilfield services fundamentals and stocks.

Structural Theme: Digestion of Upstream Leap Up the Marginal Cost Curve Increases Importance of Oilfield Services Group. The dawn of unconventional plays in North America and transition to developing deepwater fields shapes the complexion of the oilfield services sector. As a function of trial, error, and cost overruns, the shift to unconventional & deepwater production was a leap up the marginal cost curve. The market is in the process of moving up the learning curve to lower project breakeven costs in the unconventional and deepwater frontiers. The transition may continue to push the structural change on oil service & equipment markets. Within the US unconventional market, we see continued themes of well optimization, equipment high-grading, logistics & efficiency, central procurement for E&Ps, bundled services offerings, and consolidation of oil service providers as the signs of adaptation. Within deepwater, we see more equipment/design standardization, greater efficiency, and employment of technology brought to bear to lower breakeven costs. The SLB/CAM merger and FTI/Technip JV suggest scale and R&D capabilities may reshape the deepwater supply chain. Further, the HAL/BHI merger represents a consolidation of market power, which benefits the oil service companies across markets. In our view, the importance of oil service and equipment providers should improve as upstream operators grow to rely on oil service companies’ scale, bank of knowledge of evolving “best practices” and ability to advance new technologies.

December 15, 2015 2

Coverage Breakdown & Preference Ranking

Sources: KLR Group, LLC Forecasts; Factset

Company Ticker Rating

B/S & Covenant

Risk

Market

Cap. (MM) Price

Price

Target Upside North America International Business Mix

Schlumberger SLB Buy No $ 88,050 $ 69.82 $105.00 50% Minority Majority Diversified Services & Equipment, Subsea Equipment (CAM)

Superior Energy SPN Buy No $ 2,039 $ 13.53 $ 21.00 55% Majority Minority Diversified Services

Core Labs CLB Buy No $ 4,751 $112.14 $155.00 38% Mixed Mixed Reservoir Analysis, Oilfield Consumables

National Oilwell Varco NOV Buy No $ 12,509 $ 33.29 $ 52.00 56% Mixed Mixed Rig Equipment, Diversified Equipment, Diversified Servies, Oilfield Consumables

Patterson-UTI PTEN Buy No $ 2,178 $ 14.80 $ 23.00 55% Majority -- Land Contract Driller

C&J Energy Services CJES Buy Yes $ 579 $ 4.81 $ 7.50 56% Majority -- Pressure Pumping, Oilfield Services

Forum Energy FET Buy No $ 1,105 $ 12.22 $ 19.00 55% Majority Minority Diversified Equipment

Oil States OIS Buy No $ 1,426 $ 28.06 $ 43.00 53% Mixed Mixed Offshore & Onshore Services & Equipment

Helmerich & Payne HP Buy No $ 5,537 $ 51.37 $ 78.00 52% Majority Minority Land Contract Driller

Frank's International FI Buy No $ 2,364 $ 15.24 $ 23.00 51% Mixed Mixed Offshore Services & Equipment

Nabors Industries NBR Buy No $ 2,873 $ 8.69 $ 13.00 50% Mixed Mixed Land Contract Driller

FMC Technologies FTI Buy No $ 6,593 $ 28.92 $ 43.00 49% Mixed Mixed Offshore & Onshore Equipment

Transocean RIG Buy Yes $ 4,616 $ 12.69 $ 19.00 50% Mixed Mixed Offshore Driller

Newpark Resources NR Buy Yes $ 406 $ 4.83 $ 7.25 50% Mixed Mixed Offshore & Onshore Services & Equipment

Ensco ESV Buy No $ 3,523 $ 14.96 $ 20.00 34% Mixed Mixed Offshore Driller

Noble Corp. NE Buy No $ 2,879 $ 11.90 $ 16.00 34% Mixed Mixed Offshore Driller

Rowan Companies RDC Buy No $ 2,184 $ 17.50 $ 25.00 43% Mixed Mixed Offshore Driller

Flotek Industries FTK Buy No $ 577 $ 10.76 $ 14.50 35% Majority Minority Oilfield Consumables

Dril-Quip DRQ Accumulate No $ 2,229 $ 58.11 $ 75.00 29% Mixed Mixed Subsea Equipment, Rig Equipment

Halliburton HAL Accumulate No $ 31,631 $ 36.96 $ 46.00 24% Majority Minority Diversified Services & Equipment

Oceaneering Intl OII Accumulate No $ 3,722 $ 38.04 $ 49.00 29% Mixed Mixed Offshore Services & Equipment

Diamond Offshore DO Accumulate No $ 2,764 $ 20.15 $ 24.00 19% Mixed Mixed Offshore Driller

Weatherford WFT Accumulate Yes $ 6,895 $ 8.85 $ 10.25 16% Mixed Mixed Diversified Services & Equipment

US Silica SLCA Hold No $ 1,047 $ 19.61 $ 20.00 2% Majority -- North American Proppant

Atwood Oceanics ATW Hold Yes $ 850 $ 13.15 $ 12.50 (5%) Mixed Mixed Offshore Driller

Carbo Ceramics CRR Hold Yes $ 380 $ 16.32 $ 15.25 (7%) Majority -- North American Proppant

Pacific Drilling PACD Hold Yes $ 204 $ 0.97 $ 3.00 209% Mixed Mixed Offshore Driller

Fairmount Santrol FMSA Hold Yes $ 376 $ 2.33 $ 2.30 (1%) Majority -- North American Proppant

Seadrill SDRL Reduce Yes $ 2,050 $ 4.16 $ 3.50 (16%) Mixed Mixed Offshore Driller

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December 15, 2015 3

Oil Service Shares in “Sweet Spot” of the Upstream Cycle – Production Response Starts Turn

Commodity Recovery

- Activity Increase Meets Lean OFS Cos. - Peak Returns to Incentivize Investment - OFS Stocks See Multiple Expansion - Price Targets De-Risked (lower WACCs) - Growth Trajectory Returns to Estimates

Expansion

- OFS Capacity Additions Pressure Returns - Borrowing Bases & Leverage Increase - Ests. Extrapolate Growth & Econ. Rents - Commodity Supply/Demand Balances - Risk/Reward Shifts Negative

Production Response

- Low Investment Curtails Supply - Commodity Prices Bottom - Earnings Estimates Bottom - Services Overcapacity Leads to Attrition

Commodity Collapse

- Upstream Investment Shrinks - Negative Operating Leverage - Negative Earnings Revisions - De-Leveraging Balance Sheets

Normalized Mid-Cycle Returns

BUY

BUY

Risk/Reward

SELL

WE ARE HERE

Risk/Rewar d

December 15, 2015 4

Key Proprietary Analytical Frameworks: Conclusions & Methodology Synopsis

US Land Rig Forecast Model

•Conclusion: Land Rig Market Bottoms in 4Q15/1Q16, Begins Recovery with Oil Prices

•Links Oil Prices, Operating Cash Flow, & CAPEX to Forecast Rig Count

•High Correlations Between Variables

•Detail Sensitivity Analysis

•Analysis of 60 North American E&P

•15 Years of Historical Data

•Pgs. 38-45

US Land Rig Fleet Breakdown

•Conclusion: Land Rig Market More Attractive in 2016/2017

•Segmentation of US active and total land rig fleet, between AC & SCR

•Breakdown of fleet by horsepower

•Comparisons between rig fleets

•Pgs. 46-49

Offshore Rig Supply/Demand Model

•Conclusion: Offshore rig market continues to decline in 2016, with recovery expected in 2017/2018

•Field Level Bottoms Up Analysis of Development Demand

•Comparison of Development Demand vs. Ordered Subsea Equipment

•Breakout of Exploration Demand & History

•Pgs. 61-76

Offshore Rig Attrition Analysis

•Conclusion: Retirement of 60-70 floaters and ~125 jackups over the next two years

•Ranks All Rigs on Multi-Factory Scoring System

•Forecast List for Floater Retirements

•Forecast List for Jackup Retirements

•Focus on Contract Conclusions & Required Surveys

•Pgs. 77-93

Offshore Equipment Market Analysis

•Conclusion: Modest near term recovery in subsea tree deliveries, new order recovery seen in 2016/2017

•Subsea Tree Probability Weighted Demand Forecast

•Subsea Tree Manufacturing Capacity & Utilization Outlook

•Industry Market Share Analysis

•Customer Preference Analysis

•Pgs. 99-106

Pressure Pumping Framework

•Conclusion: Market balance tightens in 2H16, starting new upcycle

•Simplified analysis of horsepower capacity

•Driven by US land rig count forecast

•Assumes fleet attrition through 2016

•Pgs. 50-51

Methodology

December 15, 2015 5

Key Takeaways from Proprietary Analytical Frameworks Proprietary US Rig Count Model Forecasts US Land Rig Count Bottom in 4Q15/1Q16, with Recovery into 2017. We have built a proprietary US land rig count forecast model to reflect the high correlations between commodity prices, cash flow, capital expenditures, funding gaps, rig efficiency, inflation/deflation, and service intensity per well. Given an oil price bottom in 4Q15/1Q16, we see the US land rig count finding a trough in the 600-700 rig range during 4Q15/1Q16. As oil prices recover towards $85 in 2017, we forecast the US land rig count exiting 2016 closer to ~1,000 rigs . At the bottom, the market may come closer to cash flow neutrality, with funding gaps (CFO-CAPEX) closer to 15%-20%, down from recent highs. In our view, E&Ps living within cash flow at low oil prices marks the bottom of the North American downturn. Our US land rig forecast provides the engine for pressure pumping and proppant market sub-sector forecasts:

• Pressure Pumping May Begin to Tighten in 2H16. A combination of activity recovery and capacity attrition may tighten the pressure pumping market in 2H16. We see potential for horsepower utilization levels to cross into the 80%-90% range in 2017. Roughly, 6-9 month lead times for new equipment orders slow the pace of potential capacity expansion to meet increased demand. Improvement in supply/demand balances may leave the pressure pumping market poised for a new upcycle. (pg. 50)

• Proppant Market Remains Challenged. Proppant demand should exit 2016 at 1H15 demand levels. As a result, proppant economics remain under pressure from high fixed costs and lower capacity absorption until further out into our forecast. (pg. 52)

Proprietary Floater Market Demand Model Sees ~26% Decline in 2016, Fuller Recovery by 2018. Our field-by-field analysis of floater demand sees significantly lower rig counts in 2016, driven by a precipitous ~40% Y/Y decline in exploration and ~17% fall in development drilling (methodology outlined in slides below pgs. 61-76). We see little chance for upward revisions to rig demand without a sustained turn in commodity sentiment before the end of year 2016 budgeting cycle, which may bring investment decisions for new projects for 2017. If operators look to replace reserves and maintain production profiles, the collapse in exploration spending in our opinion is not sustainable beyond 2016. We see a more accelerated recovery in 2017 and 2018.

Proprietary Rig Attrition Model Targets 67 Floater & 125 Jackup Retirements. As outlined below (pgs. 77-92), we created a multi-factor weighting for each rig in the offshore fleet. In our view, rigs with lower multi-factor scores, contract expirations, near term regulatory surveys, and/or those in need of significant capital expenditures may screen well for retirement. Ultimately, we believe an incremental ~60-70 floaters and ~125 jackups may need to retire or exit the market to bring floater and jackup market balances closer to more manageable 80%-90% utilization levels. We anticipate this process may accelerate in coming quarters, adding to the approximate 40 floaters already retired and limited jackup attrition to date.

Proprietary Subsea Tree Model Forecasts Slight Rebound in 2016 Deliveries, Meaningful Order Recovery Waits for 2017. Leveraging our field-by-field analysis applied to offshore rig demand, we forecast flat to lower subsea equipment deliveries. Equipment providers may continue to process backlog inventories, as anemic 2015 subsea tree orders appear to trend under low 2014 levels. A linear relationship, lower order flow from 2014-2016, must impact deliveries beyond 2016, and hamper the economics of the subsea tree business. More manifolds and other equipment elements from greater project complexity may leave subsea trees alone a conservative benchmarking tool (pg. 103). That said, our probability weighted subsea tree outlook leaves equipment players subject to a lower run rate of activity. As upstream operators work through project inventories to lower breakeven costs, we maintain a more bullish bias that our outlook may prove conservative. As investor sentiment towards growth turns positive, investors may expand offshore equipment stock multiples to discount the potential for a greater number of projects to materialize.

International Activity Declines Lagged North America, But Persist Into 2016. International projects are larger in scale, significant capital expenditures, that have long lead times. Once multi-year development plans pass through final investment decision (FID), the projects push forward. As a result, international activity has more consistency. Projects may be pushed to the right and delays may drag on activity when the commodity is under pressure, but approved projects generally move forward. Within the process, year end budgeting cycles, when IOCs decide to move forward with projects, set the tone for international project activity over the coming year. Demonstrated by more stable activity in the Middle East, NOC activity may not closely track the commodity, given varying priorities, policy issues at the national level, and strategic initiatives at OPEC. We continue to see the Middle East pulling up international activity averages. We remain watchful of persistent high Middle East rigs counts, drilling to support a quest for OPEC market share, as upstream spending may begin to conflict with budget constraints. With 2015 largely complete, 2015 international rig counts are down ~10% Y/Y. Looking forward, our international rig count forecast ties together historical relationships between production, rig counts, and exploration spending. Amid IOC’s bleak 2016 budget tones, we forecast international rig counts down another ~5% in 2016. (pgs. 55-60)

December 15, 2015 6

Digestion of Leap Up the Marginal Cost Curve Shapes the Oil Services Sector Battle to Lower Marginal Cost of Frontier Supply Shapes the Oil Services Industry. The quest to maintain and grow production led the industry up the marginal cost curve to exploit new supply in unconventional and deepwater plays. Greater technological hurdles, higher oil service intensity, and more required infrastructure defined the higher marginal cost resource. The industry continues to address the shift to a higher degree of project difficulty, through data analysis, technology, efficiency, and process refinements. Mistakenly, investors apply broad, stagnant generalizations regarding fixed cost structures, which may place tiers of unconventional plays and deepwater projects out of the money. In our view, the cost curve for these projects remains dynamic, not just due to pricing concessions, but due to the evolution of solutions and “best practices”. The digestion of the leap up the marginal cost curve equates to the battle to lower marginal project costs to allow E&Ps, OICs, and NOCs to monetize asset investments. The battle to move the production frontier drives the complexion of the oil service industry in the following ways:

• Focus on Well Optimization. Unconventional development may continue to call on more data and well design iterations to optimize the production per well and the lower per barrel costs. We continue to see an evolution of well designs, stage intensity, proppant volumes/preferences, pressure pumping horsepower demand, and emphasis on chemistry, in order to expand top tier acreage. Greater service intensity per well remains the trend, but a shift towards optimal well designs vs. raw service volumes may gain importance.

• Scale, Logistics, Efficiency. As made more apparent by the downturn, oil services companies may need to better leverage their footprints and efficiency of their assets. The trend favors larger companies with significant scale, who can refine processes and logistics. The heightened level of execution may make these companies the low cost providers of choice. Exiting the downturn, we believe leaner more cost efficient oil service companies should emerge. As a result, we see modest acceleration in activity driving greater operating leverage. As a function of this efficiency focus, oil service companies may compete on execution and technology, potentially seeking performance bonus opportunities for solutions versus discrete services as the upstream investment cycle improves.

• Centralized Procurement & Bundled Services. Cyclically upstream operators centralize and tighten spending controls. The current cycle remains the same. Centralized procurement at the E&Ps and IOCs shifts services demand toward bundled services, as planners find it easier to find price points and coordinate with fewer services providers. In our view, the trend should persist, with oil service companies consolidating and aligning their offerings (SPN, CJES/NBR) to match the industry trend.

• Oil Service Market Consolidation. The need for scale, efficiency, technology (new solutions), and bundled services may continue to drive consolidation of service and equipment providers. The trend is evident with the HAL/BHI ($47.80, NR), SLB/CAM ($63.07, NR), FTI/TEC (€46.16, NR) JV combinations. We see providers of commoditized offerings of discrete services as challenged. Capacity utilization attracts capital, but does not create viable long term franchises in a market competing on execution, not available capacity. We continue to see the exit of return-chasing, capacity investments in pressure pumping, proppant, and potential offshore rigs market through 2016. While second and third tier services companies struggle and drive equipment attrition, we do expect a few companies to be sponsored by upstream operators to maintain adequate competition. In our view, small/mid capitalization companies, like SPN, OIS, CJES, NR, and WFT as potential winners amid consolidation.

• Standardization to Lower Breakeven Costs. Standardization of processes to create efficiency in oil service companies and in project design (deepwater) for upstream operators may accelerate. Standardized solutions and lower break-even economics may trump design marvels from engineers that have driven deepwater project costs higher. As a rule, over engineering is the enemy of project profitability. Co-creation of production solutions with oilfield equipment providers may increase the importance of modular solutions. Equipment manufacturers may become more important and integrated into field development. Lowered development costs should promote higher project throughput, which may boost equipment sales and offshore rig demand.

• Well Cost/Authorization for Expenditures (AFE) vs. Estimated Ultimate Recovery (EUR). Currently, US E&Ps seek lower well cost solutions versus higher cost alternatives, which may offer higher ultimate recoveries. The trend may continue, as low oil prices drive E&P companies to fight for the title of “low cost producer”. On a longer term per unit basis, the better EUR solution may lower per barrel costs. We anticipate a migration back to a middle ground in the AFE vs. EUR debate, as potentially beneficial to oil services companies that look to push higher margin technology/products.

• Equipment High Grading to Persist. Modern, higher specification equipment tends to be more efficient and ultimately lower cost than nominally less expensive legacy equipment. Upstream companies realize the immediate cost/efficiency trade off. In our view, we continue to see the trade to better equipment, especially in the land and offshore drilling markets.

December 15, 2015 7

Coverage Universe, excluding Offshore Drillers: Product & Service Line Breakdown

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Diversified Oilfield Serivices

Schlumberger (SLB), w ith CAM X X X X X X X X X X X X X X X X X X X X X X X

Halliburton (HAL), w ith BHI X X X X X X X X X X X X X X X X X X X

Weatherford (WFT) X X X X X X X X X X X X X X X X

Mid/Small Cap Oilfield Serices

Core Laboratories (CLB) X X

Superior Energy Services (SPN) X X X X X X X X X X X X

Flotek Industries (FTK) X X X X

Franks International (FI) X

Oil States (OIS) X X X X X X X

Newpark (NR) X X

Pressure Pumpers

C&J Services (CJES) X X X X X X X X X X

Proppant

US Silica (SLCA) X

Carbo Ceramics (CRR) X

Fairmount (FMSA) X

Oilfield Equipment & Manufacturers

National Oilwell Varco (NOV) X X X X X X X X X X X X X

FMC Technologies (FTI) X X

Oceaneering (OII) X X X

Forum Energy (FET) X X X X X

Dril-Quip (DRQ) X

Onshore Drilling

Helmerich & Payne (HP) X

Nabors Industries (NBR) X X

Patterson-UTI Energy (PTEN) X X

Source: Factset; KLR Group, LLC Forecasts; Company Filings/Disclosures

December 15, 2015 8

Table of Contents Introduction 1 Segmented Market: Better Demand for AC 1,500+HP Rigs, Tougher Competition for the Rest 48

Bullish on Oil Services: Signs of Production Response Herald Turn in Cycle & Multiple Expansion 2 HP, NBR, PTEN May Be Winners, Representing >60% of AC Rig Fleet Composition 49

Coverage Breakdown & Preference Ranking 3 US Pressure Pumping Market Poised for 2016/2017 Rebound 50

Oil Service Shares in “Sweet Spot” of the Upstream Cycle – Production Response Starts Turn 4 Simplified Model Suggests A Recovery With Capacity Attrition & Horizontal Rig Count Recovery 51

Key Proprietary Analytical Frameworks: Conclusions & Methodology Synopsis 5 US Proppant Market Balances More Opaque 52

Key Takeaways from Proprietary Analytical Frameworks 6 Proppant Companies: Lagging Absorption of High Fixed Costs Translate Into Later Cycle Play 53

Digestion of Leap Up the Marginal Cost Curve Shapes the Oil Services Sector 7 Proppant Volume Recovery Does Not Boost Util ization Until Beyond 2016 54

Coverage Universe, excluding Offshore Dril lers: Product & Service Line Breakdown 8 International Markets 55

Table of Contents 9 Larger Projects, Less Infrastructure: Creates Lag in International Decline & Recovery 56

Mid-Cycle Valuation Methodology 11 KLR Rig Count Forecast Sees Further 2016 Downside, With Slow 1Q16 Start & Offshore Decline 57

Focus on Mid-Cycle Returns Within the Oil Services Valuation Cycle 12 International Production (ex FSU) Falls With Rig Decline, Rig Count Recovery May Lag Commodity Uptick 58

Coverage Universe Risk/Reward Map 13 Over 10+ Years, International Oil Production/Rig is Down ~50%, vs. North America Up ~20% 59

Mid-Cycle Valuations Track Average Returns 14 Middle East Rig Count Resilience Reflects OPEC Efforts to Gain Market Share 60

Risk Parameters Differentiate the Oil Services Group (WACC Comparisons) 15 Offshore Rig Markets 61

Leverage Ratios Reflect Reasonable Debt Levels Across Majority of Group 16 Distressed Offshore Dril l ing Sector Offers Values, But Faces Headwinds 62

OFS Cost of Debt Widens on Rating Scale, Prohibitive at Lower Grades 17 Offshore Equipment & Services Outperform Offshore Dril lers, Until Rig Oversupply Abates 63

TBVs Suggest Sentiment, Company Health, Trading Floors, & Potential Write-Downs 18 Offshore Dril ler Liquidation Values (NAV) Il lustrate Investor Bias Toward Stronger Balance Sheets 64

Short Interest Positions & Days to Cover May Lead to “Short Squeeze” Rallies 19 Company Value Composition – Older Assets Drive Little Value in Our Models 65

Industry & Company Comparable Valuation Analysis 20 Dayrate Forecast: Floater Dayrates Inflect in 2017, Jackup Downturn Prolonged Until 2018 66

KLR EPS Estimates vs. Consensus 22 Floater Market Balances Improve With Rig Attrition & Cold Stacking (-67 Floaters) 67

Commodities Factors Start to Turn for Oilfield Services 26 KLR Well Count Forecast Narrows Project Opportunity Set by Probability Weighted Analysis 68

Negative IEA Supply Revisions & Low OPEC Spare Capacity Work in Oil’s Favor 27 Floater Demand Forecast Methodology 69

Mkt Share Quest Leaves OPEC Spare Capacity Low, Potentially Heading Lower 28 Floating Rig & Subsea Equipment Model: Probability Weighting Methodology 70

Negative IEA Non-OPEC Supply Revision Suggest Markets Move Toward Balance 29 Percentage of Equipment Ordered Il lustrates Risk to Development Forecast 71

US EIA Weekly Crude Production Data Beginning to Rollover, But Pace & Trajectory Question Marks 30 Recovery of Exploration Demand For Floaters Drives Recovery 72

KLR US Liquids Production Forecast 31 Forecasted Supply of Floaters & Jackups Remains Very Dependent on Attrition 73

IEA Global Demand Forecast Stable, But Economic Growth Concerns May Leave Negative Bias 32 Determination of the Marketed Supply of Offshore Rigs 74

Oil Inventory – OECD and US Inventories Historically High, But Production Response May Reverse Trends 33 Risk/Reward 6G Floater Purchases May Only Support Distressed Asset Deals 75

Natural Gas Markets Remain Enigmatic, But Bright Spots in the Data 34 Jackup Market Needs Attrition & Cold Stacking (-125 Jackups), Fragmented, It May be Sloppy 76

Gas Well Productivity Improvements Challenge Legacy Inventory/Natural Gas Price Paradigms 35 Offshore Rig Supply & Attrition 77

KLR US Natural Gas Production Forecast 36 Historical Addition/Attrition Column Chart - Floaters 78

Natural Gas Productivity Improvements Slow, Potentially Shifting Natural Gas Price Paradigms 37 Historical Addition/Attrition Column Chart - Jackups 79

US Land Market Bottoms 4Q15/1Q16 38 Floater Attrition Methodology: Multi-Factor Scores for Offshore Rigs 80

Positive Backdrop for North American Services Outlook 39 Older Floaters Rank Poorly on Our Spec Factor Scale 81

Investors Favor Leverage to Perceived Lower Marginal Cost Onshore vs. Higher Cost Offshore 40 Floater Retirement Focus List 82

US Land Rig Forecast Finds Bottom in 4Q15/1Q16 41 Jackup Attrition Methodology: Multi-Factor Scores for Offshore Rigs 83

US Land Rig Count Bottoms as E&P CAPEX Nears Cash Flow From Operations & Funding Gaps Erode 42 Similar to Floaters, Older Jackups Rank Poorly on Our Spec Factor Scale 84

Proprietary Model Captures Relationships Between WTI, CFO, CAPEX, Funding Gaps, & Rig Counts 43 Jackup Retirement Focus List 85

High Yield Energy Market Has Choked-Off E&P’s Capacity To Run Funding Gaps 44 Jackup Newbuilds: Risks For the ~85% of Fleet Ordered by Non-Established Offshore Dril lers 87

US Land Activity Hinges on Oil Prices & Leverage in the Rig Count Sensitivity Analysis 45 Jackup Newbuilds 88

US Land Drilling Market 46 Floater Newbuilds: Most Delivery Risk From PBR Sponsored New Construction 91

AC Rig Util ization May Tighten Through 2016 With Horizontal Land Rig Count Recovery 47 Floater Newbuilds 92

December 15, 2015 9

Table of Contents (cont.) Key Offshore Rig Market Metrics 94 Newpark Resources (NR): Buy, $7.25PT 146

Floater Fleet Snapshot 95 Proppant Companies 150

Jackup Fleet Snapshot 96 US Sil ica (SLCA): Hold, $20.00PT 151

Regional View of Floater Fleet 97 Fairmount (FMSA): Hold, $2.30PT 155

Regional View of Jackup Fleet 98 Carbo Ceramics (CRR): Hold, $15.25PT 159

Subsea Equipment Market: Favorable Offshore Exposure 99 Oilfield Equipment 163

Subsea Equip. Screens Well, As Sentiment & 2016/2017 Orders Return to Chase Project Opportunity Set 100 National Oilwell Varco (NOV): Buy, $52.00PT 164

Forecast Subsea Tree Deliveries Sees Flattish Offshore Activity Given Project Delays 101 FMC Technologies (FTI): Buy, $43.00PT 168

Trees Ordered vs. Forecast Leaves 4Q15 Manageable, but Offers Sluggish Order Recovery Until 2017 102 Oceaneering (OII): Accumulate, $49.00PT 172

Greater Field Complexity Creates the Need for Economies of Learning To Lower Project Costs 103 Forum Energy (FET): Buy, $19.00PT 176

Subsea Equip. Manufacturing Util. Declines May Hurt Fixed Costs Absorption, Pricing, & Economics 104 Dril-Quip (DRQ): Accumulate, $75.00PT 180

Concentration of Deliveries/Demand with Large Customers 105 Land Contract Drillers 184

Top 30 Subsea Tree Orders Customers: One Subsea & FMC Dominate Market Share 106 Helmerich & Payne (HP): Buy, $78.00PT 185

Companies 107 Nabors Industries (NBR): Buy, $13.00PT 189

Large Cap Integrated Oilfield Services 108 Patterson-UTI Energy (PTEN): Buy, $23.00PT 193

Schlumberger (SLB): Buy, $105.00PT 109 Offshore Contract Drillers 197

Halliburton (HAL): Accumulate, $46.00PT 113 Seadrill (SDRL): Reduce, $3.50PT 198

Weatherford (WFT): Accumulate, $10.25PT 117 Transocean (RIG): Buy, $19.00PT 202

Small/Mid Cap Oil Services 121 ENSCO (ESV): Buy, $20.00PT 206

Core Laboratories (CLB): Buy, $155.00PT 122 Diamond Offshore (DO): Accumulate, $24.00PT 210

Superior Energy Services (SPN): Buy, $21.00PT 126 Atwood Oceanics (ATW): Hold, $12.50PT 214

Franks International (FI): Buy, $23.00PT 130 Noble (NE): Buy, $16.00PT 218

Oil States International (OIS): Buy, $43.00PT 134 Rowan (RDC): Buy, $25.00PT 222

C&J Services (CJES): Buy, $7.50PT 138 Pacific Dril l ing (PACD): Hold, $3.00PT 226

Flotek Industries (FTK): Buy, $14.50PT 142

December 15, 2015 10

Mid-Cycle Valuation Methodology Reveals Value & Removes Commodity Forecasting Timing Risk


Focus on Mid-Cycle Returns Within the Oil Services Valuation Cycle Key Valuation Conclusions • Oil Services in “sweet spot” of valuation cycle • Focus on long term returns, shifts focus from timing of

commodity recovery, centers our view on risk/reward • At trough valuations, most of our coverage has

significant upside to mid-cycle valuations • De-risking of the group, reflected in lower discount

rates, provides the opportunities for price targets to re-rate higher as balance sheet and credit issues abate

• Attention to company specific risks & issues vs. broad brush strokes of multiples illustrates company differentiation

Valuation Methodology • We mean revert the “normal year” that drives our NPV

to reflect our estimates of average mid-cycle returns • Mid cycle returns reflect our view of the mid-point or

average return structure for a company over the cycle • We want to pick stocks with best risk/rewards • We look to factor risk/reward through adjustments to

the cost of capital, via an analysis of the total capital structure and risk messaging from credit markets

• WACCs are adjusted to reflect discounts/risk represented in the yields of corporate bonds. (Yield to Worst)

• Leverage & covenant issues create a larger spread of risks calculated in WACCs

• We triangulate our NPV value against Gordon-Growth Model & Tangible Book Value valuation metrics as a sanity check

Commodity Recovery

Expansion

Production Response

Commodity Collapse

Normalized

Mid-Cycle

Returns

Potential for Upward Revisions to Mid-Cycle

Values as WACC’s De- Risk

DCF Valuations Catches Up with Company Specific Downside Risk

Linear Extrapolation of Growth & Economic Rents

Outrun Mid-Cycle Valuations

Mid-Cycle Valuation “Sweet Spot” – Risks Factored, Upside Bias

WE ARE HERE


ESV

SLB

CLB

FI NROIS

FTK

CJESNOV

FTI

FET

RIG

NE

RDC

HPNBR

PTEN SPN

HAL

WFT

OIIDRQ

DO

SLCA

FMSA

CRRATW

SDRL

REDUCE

HOLD

HOLD

ACCUMULATE

ACCUMULATE

BUY

(20%)

(15%)

(10%)

(5%)

-

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

3% 4% 5% 6% 7% 8% 9% 10% 11% 12% 13% 14% 15% 16% 17% 18% 19% 20% 21% 22% 23% 24% 25% 26% 27% 28% 29% 30% 31%

Up

sid

e v

s. P

rice

(%

)

WACC (%)

Coverage Universe Risk/Reward Map

Note: PACD not listed on graph with 209% upside Source: Factset; KLR Group, LLC Forecasts

Buy

Accumulate

Hold

Reduce

Low Return, High Risk with Balance Sheet & Covenant Overhangs screen poorly on risk/reward

Best company in a tough Proppant sub-sector

Looking for counter-cyclical investment to renew fleet

BHI merger digestion risk may create entry points

“Show me” story that re-rates higher , with execution on better returns

High Return, Further Out on Risk Frontier, high probability of upward price target revisions with turn in sentiment

High Return, High Risk North American play, with chance to re-rate significantly higher as balance sheet de-risks

Great ROV franchise, estimate revision risk overhangs shares Good offshore equip. story, screening better

Quality franchise, high cash flow, high payout, high leverage outlier

Solid Franchises, trading at trough valuations, with less credit / balance sheet risk


Mid-Cycle Valuations Track Average Returns on Assets in a Cyclical Business & Variable Returns

Source: KLR Group, LLC Forecasts; Factset

Return on Assets 10 Year Range vs. KLR “Normal Year” Forecasts

38%

16%

22% 23%

12%

19%20%

16%

11%12%

8%

27%

10%

13%

22%

15%

30%

20%

11%12%

14%

9%11%

31%

20%

3%

22%

12%

27%

3% 4%

9%

1%

8%6%

0% 5% 5%2% 3%

8%

4%2%

0%

(28%)

(6%)(5%)

(4%)(2%)

(24%)

(16%)

(4%) (3%)(6%)

(1%)(0%)

(1%)(0%)

30%

15%13% 12% 12% 11% 10% 10% 10% 9%

8% 8% 7% 7%6%

6% 5% 5% 4% 4% 4% 4% 4% 3% 3% 3% 2% 2%1%

-30%

-20%

-10%

0%

10%

20%

30%

40%

CLB

DR

Q FI

FTK

SLC

A

SLB

CR

R

HP

FTI

OII

FET

HA

L

NR

OIS

FMSA

SDR

L

CJE

S

ESV

NO

V

RIG

SPN

WFT

NB

R

PTE

N

AT

W

PA

CD

NE

RD

C

DO

RO

A (%

)

10yr Range KLR "Normal Period" Returns


24%

17% 17%17%

16%15% 15%

14% 13%13% 13%

12% 12% 11%11% 10%

10%

4%

16%

12% 12% 11%10%

32%

25%

21%

19%

13%

30%

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

22%

24%

26%

28%

30%

32%

PA

CD

SDR

L

FMSA

CJE

S

CR

R

AT

W

RIG NR

SPN

WFT

NB

R

FET

FTK

NE

RD

C

SLC

A

PTE

N

ESV

HP

FTI

DO

HA

L

OIS OII

NO

V

SLB

DR

Q FI

CLB

WA

CC

(%)

Risk Parameters Differentiate the Oil Services Group (WACC Comparisons)

Source: KLR Group, LLC Forecasts

High Risk – High Reward. Higher balance sheet risks, likely represented larger yields on bonds, also translates into higher WACCs. As credit concerns are allayed, less discounted risk could vault these shares higher. We see these stocks as potential upgrade candidates as conditions turn and shares are de-risked.

Most Enticing Risk/Reward. Middle of the risk frontier may offer less credit risk, with greater potential for company transformations, leverage to recovery, and small/midcap beta for the group. High Quality Franchises, Trough Valuations. The ranks

of lower risks companies offer some of the highest quality oilfield franchises trading at “trough” valuations.

Buy

Accumulate

Hold

Reduce


40%37%

34%31%

26% 25% 24%

11%7% 6% 5%

-3%

84%

60%

52%

43%

33% 32% 32%

6% 5%

-5%

106%

48%

20%

4%1%

2.5X

11.7X

5.7X

6.6X

7.1X

4.7X

3.6X 3.5X4.0X

5.2X

6.1X

4.2X

3.5X

4.5X

3.2X2.7X

1.5X

2.4X

1.2X

4.9X

1.5X 1.4X

0.9X 0.9X

10.2X

- 0.0X -

1.0X

2.0X

3.0X

4.0X

5.0X

6.0X

7.0X

8.0X

9.0X

10.0X

11.0X

12.0X

(10%)

-

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

CLB

FMSA

CJE

S

WFT

SDR

L

PA

CD

NB

R

NE

DO

AT

W

RIG

SLC

A

ESV

SPN

HA

L

RD

C

PTE

N

FTI

NO

V

SLB

FET

OII

OIS

FTK

CR

R

HP

NR

DR

Q FI

Tota

l De

bt/

EBIT

DA

Ne

t D

eb

t /

Cap

italNet Debt / Capital (2016) Total Debt/EBITDA (2016)

Leverage Ratio Comparisons Reflect Reasonable Debt Levels Across Majority of Group

Source: KLR Group, LLC Forecast

Debt covenants tend to center on maximum Debt/EBITDA ratios at a maximum of 4.0x

Net debt to capital ratio in the 40%+ range are considered high and may trip debt covenants that tend to call for Debt/Capital ratios below 50%-60%.

Investment Grade

Non-Investment Grade

Unrated


OFS Cost of Debt Widens on Rating Scale, Prohibitive at Lower Grades Down the Risk Spectrum

133

307

644

780725

1,312

1,399

5734

346

132193

456

736

95

173

458

582526

849

1,067

0

200

400

600

800

1,000

1,200

1,400

1,600

AA- A BBB+ BBB BBB- BB+ BB

Spre

ad O

ver

T-Yi

eld

(b

ps)

Range Avg

0

200

400

600

800

1,000

1,200

1,400

1,600

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Yie

ld T

o W

ors

t (b

ps)

Years To Maturity

AA- A BBB+ BBB BBB- BB+ BB B+ T-yield

Source: Factset Source: Factset

OFS Debt Spreads by Rating OFS Debt Spreads by Maturity


TBVs Suggest Investor Sentiment Company Health, Trading Floors, & Potential Write-Downs

5.0X

3.9

X

3.9X

3.2X

3.2X

3.0

X

2.8X

2.7

X

2.4X

2.2X

2.1X

1.7

X

1.5

X

1.2

X

1.1

X

0.8X

0.8X

0.6X

0.6X

0.6X

0.5X

0.4X

0.4X

0.3X

0.3X

0.2X

0.1X

(2.5

X)

(3.0X)

(2.0X)

(1.0X)

-

1.0X

2.0X

3.0X

4.0X

5.0X

6.0X

SLB

FTK

FTI

SLC

A

OII

FET

WFT FI

HA

L

NO

V

SPN

DR

Q

OIS

CJE

S

HP

PTE

N

NR

DO

NB

R

CR

R

RD

C

NE

ESV

RIG

AT

W

SDR

L

PA

CD

FMSA CLB

Pri

ce /

Tan

gib

le B

V p

er

Shar

e

FMSA’s lack of tangible book value is a concern

CLB has immense cash flow, low debt levels, and high payout, which eases concerns as an outlier.

Stocks trading below tangible book value, either imply asset write-downs, solvency issues, or that stocks screen as attractive values.

Price to Tangible Book Value Company Comparisons

As expected shares of companies with stable businesses and balance sheets trade above tangible book value.

Source: Factset, 3Q 2015 Company Earnings Releases


Short Interest Positions & Days to Cover May Lead to “Short Squeeze” Rallies

15.4

8.5

9.7

7.4

6.1

4.2 4.4

10.7

6.0 5.8 6.1

7.3

3.8

6.8

4.4 3.6

4.2

5.1

2.8

3.9

2.2 2.3

3.2

7.9

3.1 3.0

5.2

6.5

3.0

0

2

4

6

8

10

12

14

16

18

0%

5%

10%

15%

20%

25%

30%

35%

40%

CR

R

SLC

A

RIG

FTK

NE

AT

W

PTE

N

CLB HP

SDR

L

CJE

S

NO

V

ESV

FET

DO

RD

C

WFT OII

SPN

HA

L

NB

R

OIS FT

I

FMSA N

R

DR

Q

SLB FI

PA

CD

Day

s C

ove

rage

(3 M

on

th A

vg. D

aily

Tra

din

g V

ol.

)

Sho

rt In

tere

st %

of S

har

es

Ou

tsta

nd

ing

Short Interest Days Coverage

Source: Factset


Note: Curreny in ($ US), unless otherwise indicated

Company Ticker

12/11

Price Rating

KLR

Target Upside

Shares Out

(MM)

Mkt Cap

(MM) EV (MM)2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017

Diversified Oilfield Serivices

Schlumberger SLB-US 69.82 Buy $105.00 50% 1,261 $88,050 $93,441 $3.36 $2.81 $4.35 20.8X 24.9X 16.1X 9.4X 9.4X 7.2X 1.2X 1.2X 0.9X 19% 15% 14%

Halliburton HAL-US 36.96 Accumulate $46.00 24% 856 $31,631 $44,066 $1.45 $0.87 $2.16 25.5X 42.7X 17.1X 10.9X 9.4X 6.0X 2.0X 4.5X 2.8X 26% 33% 31%

Baker Hughes BHI-US 47.80 NR -- -- 436 $20,845 $22,945 ($0.36) ($0.03) $1.13 -- -- 42.4X 12.0X 11.8X 8.4X 2.1X 2.1X 1.5X 16% 16% 16%

Weatherford WFT-US 8.85 Accumulate $10.25 16% 779 $6,895 $13,578 ($0.29) ($0.34) $0.23 (30.8X) (26.3X) 38.5X 9.8X 10.5X 6.9X 5.6X 5.7X 3.6X 47% 45% 42%

5.1X 13.7X 28.5X 10.5X 10.3X 7.1X 2.7X 3.4X 2.2X 27% 27% 26%

Mid/Small Cap Oilfield Serices

Core Laboratories CLB-US 112.14 Buy $155.00 38% 42 $4,751 $5,237 $3.19 $2.92 $3.89 35.2X 38.4X 28.8X 24.1X 25.8X 20.5X 2.0X 2.5X 2.1X 72% 82% 83%

Superior Energy Services SPN-US 13.53 Buy $21.00 55% 151 $2,039 $3,004 ($1.23) ($1.26) $0.16 (11.0X) (10.8X) 82.7X 6.8X 7.1X 4.0X 3.6X 3.5X 1.8X 31% 31% 29%

Franks International FI-US 15.24 Buy $23.00 51% 155 $2,364 $2,038 $0.61 $0.38 $0.79 24.9X 40.2X 19.4X 6.4X 7.9X 5.3X 0.0X 0.0X 0.0X 0% 0% 0%

Newpark Resources NR-US 4.83 Buy $7.25 50% 84 $406 $372 ($0.18) ($0.29) $0.21 (26.3X) (16.5X) 22.8X 12.2X 21.2X 4.6X 5.9X 10.2X 2.2X 20% 20% 19%

Oil States International OIS-US 28.06 Buy $43.00 53% 51 $1,426 $1,490 $0.70 ($0.20) $1.08 40.3X -- 25.9X 8.2X 13.2X 7.4X 0.9X 1.4X 1.3X 10% 10% 14%

Flotek Industries FTK-US 10.76 Buy $14.50 35% 54 $577 $594 $0.09 $0.50 $1.06 -- 21.7X 10.2X 31.6X 11.5X 5.9X 2.5X 0.9X 0.5X 12% 10% 8%

Tetra Technologies TTI-US 8.22 NR -- -- 80 $659 $1,913 $0.28 $0.16 $0.37 29.9X 51.1X 22.3X 8.0X 8.1X 7.2X 4.1X 3.9X 3.5X 49% 48% 46%

Tesco Corp. TESO-US 7.01 NR -- -- 39 $273 $216 ($0.93) ($0.81) ($0.16) (7.5X) (8.7X) (44.6X) 26.1X 35.1X 6.0X -- -- -- -- -- --

Basic Energy Services BAS-US 2.84 NR -- -- 43 $121 $954 ($4.53) ($4.67) ($3.20) (0.6X) (0.6X) (0.9X) 39.9X 86.4X 9.5X 36.5X 78.3X 8.7X 72% 83% 89%

Key Energy Services KEG-US 0.50 NR -- -- 158 $79 $845 ($1.07) ($0.93) ($0.60) (0.5X) (0.5X) (0.8X) (78.7X) 30.8X 8.8X (89.6X) 35.1X -- 51% 56% --

RPC RES-US 12.37 NR -- -- 217 $2,684 $2,696 ($0.45) ($0.47) $0.05 (27.2X) (26.5X) -- 22.2X 24.1X 9.7X 0.3X 0.4X 0.2X 3% 4% 4%

C&J Services CJES-US 4.81 Buy $7.50 56% 120 $579 $1,717 ($1.96) ($1.54) $0.60 (2.5X) (3.1X) 8.0X 40.3X 17.2X 3.8X 27.4X 11.7X 2.5X 45% 47% 43%

Calfrac Well Services CFW-CA 1.47 NR -- -- 95 $140 $958 ($1.28) ($1.25) ($0.77) (1.2X) (1.2X) (1.9X) 33.4X 15.3X 6.9X 31.3X 15.4X 6.9X 48% 52% 53%

Trican Well Service TCW-CA 0.63 NR -- -- 149 $94 $581 ($3.29) ($0.71) ($0.49) (0.2X) (0.9X) (1.3X) (23.9X) 8.4X 4.9X (19.1X) 7.1X 3.7X 29% 32% 32%

4.1X 6.4X 13.1X 11.2X 22.3X 7.5X 0.4X 12.2X 2.6X 31% 34% 32%

Proppant

US Silica SLCA-US 19.61 Hold $20.00 2% 53 $1,047 $1,364 $0.27 ($0.09) $0.87 73.5X -- 22.5X 13.5X 16.8X 8.9X 4.9X 6.1X 3.2X 44% 47% 47%

Fairmount FMSA-US 2.33 Hold $2.30 (1%) 161 $376 $1,426 $0.10 ($0.19) $0.16 23.9X (12.5X) 14.5X 11.1X 25.3X 8.3X 9.6X 22.0X 7.2X 86% 86% 83%

Carbo Ceramics CRR-US 16.32 Hold $15.25 (7%) 23 $380 $386 ($1.71) ($2.37) ($1.08) (9.6X) (6.9X) (15.0X) -- (27.6X) 14.0X -- (6.3X) 3.3X 10% 10% 11%

Emerge Energy EMES-US 5.42 NR -- -- 24 $131 $398 ($0.03) ($0.78) $0.32 -- (7.0X) 17.0X 8.0X 12.6X 7.7X 5.4X 8.8X 5.7X 66% 69% 74%

Hi-Crush Partners HCLP-US 6.19 NR -- -- 37 $229 $478 $1.04 $0.20 $0.73 6.0X 30.4X 8.5X 7.0X 13.2X 7.9X 3.6X 6.5X -- 61% 57% --

23.4X 1.0X 9.5X 9.9X 8.0X 9.4X 5.9X 7.4X 4.8X 53% 54% 54%


National Oilwell Varco NOV-US 33.29 Buy $52.00 56% 376 $12,509 $13,882 $2.93 $1.41 $1.87 11.4X 23.6X 17.8X 5.6X 8.4X 6.9X 1.6X 2.4X 2.0X 13% 13% 13%

Cheneire LNG-US 41.29 NR -- -- 236 $9,746 $26,094 ($2.70) ($0.99) $1.46 (15.3X) (41.5X) 28.3X -- 50.2X 22.1X -- -- -- -- -- --

Aker Solutions AKSO-NO 34.36 NR -- -- 272 $9,347 $8,990 $3.33 $2.69 $2.39 10.3X 12.8X 14.4X 4.0X 4.5X 4.8X 4.4X 5.0X -- 36% 37% --

Cameron International CAM-US 63.07 NR -- -- 191 $12,054 $13,756 $3.62 $2.51 $2.82 17.4X 25.1X 22.4X 9.3X 11.9X 11.1X 1.9X 2.4X 2.2X 25% 24% 22%

FMC Technologies FTI-US 28.92 Buy $43.00 49% 228 $6,593 $7,071 $2.26 $1.69 $1.85 12.8X 17.1X 15.6X 6.7X 8.2X 7.9X 1.2X 1.5X 1.5X 19% 20% 19%

Oceaneering OII-US 38.04 Accumulate $49.00 29% 98 $3,722 $3,841 $2.86 $1.87 $1.98 13.3X 20.3X 19.2X 5.6X 7.1X 6.8X 1.2X 1.5X 1.4X 23% 23% 22%

Dril-Quip DRQ-US 58.11 Accumulate $75.00 29% 38 $2,229 $1,619 $4.90 $3.02 $3.22 11.9X 19.2X 18.0X 5.8X 8.9X 8.7X -- -- -- -- -- --

Exterran Holdings AROC-US 7.56 NR -- -- 69 $525 $2,651 $0.06 $0.21 $0.38 -- 36.4X 19.9X 7.0X 7.5X 6.8X 0.5X -- -- 6% -- --

Forum Energy FET-US 12.22 Buy $19.00 55% 90 $1,105 $1,208 $0.48 ($0.08) $0.56 25.4X -- 21.8X 7.8X 14.7X 7.9X 2.6X 4.9X 2.6X 19% 19% 18%

Schoeller-Bleckmann Oilfield SBO-AT 49.54 NR -- -- 16 $793 $780 $0.59 $0.99 $2.39 83.8X 50.0X 20.8X 11.1X 10.5X 7.5X -- -- -- -- -- --

Gulf Island Fabrication GIFI-US 8.95 NR -- -- 15 $130 $85 $0.27 $0.20 $0.30 33.1X 44.8X 29.8X 2.6X 2.9X 2.9X -- -- -- -- -- --

Willbros Group WG-US 2.35 NR -- -- 62 $146 $314 ($1.24) $0.04 $0.13 (1.9X) 53.4X 18.8X (41.9X) 10.8X 9.9X -- -- -- -- -- --

18.4X 23.7X 20.6X 2.2X 12.1X 8.6X 1.7X 2.2X 1.4X 18% 17% 14%

KLR / Consensus EPS P/E EV/EBITDA Total Debt/EBITDA Total Debt/Assets

Industry & Company Comparable Valuation Analysis

Source: Factset, KLR Group, LLC Estimates; Company Filings/Disclosures


Industry & Company Comparable Valuation Analysis (Cont.) Note: Curreny in ($ US), unless otherwise indicated

Company Ticker

12/11

Price Rating

KLR

Target Upside

Shares Out

(MM)

Mkt Cap

(MM) EV (MM)2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017 2015 2016 2017

Offshore Contract Drillers

Seadrill SDRL-US 4.16 Reduce $3.50 (16%) 493 $2,050 $13,548 $1.85 $1.08 $0.73 2.2X 3.8X 5.7X 5.8X 7.6X 8.0X 4.8X 6.6X 7.0X 48% 47% 45%

Transocean RIG-US 12.69 Buy $19.00 50% 364 $4,616 $11,972 $3.70 $0.47 $0.78 3.4X 26.8X 16.2X 3.9X 8.0X 7.3X 2.9X 5.2X 4.3X 34% 32% 29%

ENSCO ESV-US 14.96 Buy $20.00 34% 235 $3,523 $9,248 $4.37 $2.22 $2.29 3.4X 6.7X 6.5X 4.6X 6.6X 6.5X 2.9X 4.2X 4.3X 36% 36% 37%

Diamond Offshore DO-US 20.15 Accumulate $24.00 19% 137 $2,764 $5,204 $2.66 $0.65 $0.29 7.6X 30.8X 70.1X 5.2X 6.9X 7.4X 2.5X 3.5X 3.8X 32% 33% 33%

Noble NE-US 11.90 Buy $16.00 34% 242 $2,879 $7,942 $2.62 $1.15 $0.70 4.5X 10.4X 17.0X 4.7X 6.3X 6.7X 2.7X 3.6X 3.8X 34% 34% 34%

Rowan RDC-US 17.50 Buy $25.00 43% 125 $2,184 $4,017 $3.29 $2.42 $0.58 5.3X 7.2X 29.9X 4.0X 4.6X 6.3X 2.8X 3.2X 4.4X 33% 32% 32%

Atwood Oceanics ATW-US 13.15 Hold $12.50 (5%) 65 $850 $2,471 $7.74 $2.64 ($0.07) 1.7X 5.0X -- 3.2X 5.3X 8.0X 2.2X 4.0X 6.1X 35% 36% 36%

Seadrill Partners SDLP-US 4.31 NR -- -- 75 $324 $5,171 $3.11 $3.29 $2.06 1.4X 1.3X 2.1X 4.8X 4.8X 6.5X -- -- -- -- -- --

Pacific Drilling PACD-US 0.97 Hold $3.00 209% 211 $204 $2,509 $0.75 ($0.54) ($0.33) 1.3X (1.8X) (2.9X) 4.2X 6.9X 6.6X 4.8X 7.1X 6.7X 48% 45% 45%

Ocean Rig ORIG-US 1.57 NR -- -- 161 $253 $4,029 $2.24 $1.19 ($0.49) 0.7X 1.3X (3.2X) 3.9X 4.8X 6.9X 4.3X 5.3X 7.4X 52% 52% 52%

Transocean Partners RIGP-US 8.98 NR -- -- 41 $372 $1,350 $1.79 $1.85 $1.27 5.0X 4.9X 7.1X 4.5X 4.1X 5.3X -- -- -- -- -- --

Hercules Offshore HERO-US 2.80 NR -- -- 20 $56 $0 ($2.39) ($6.26) ($5.81) (1.2X) (0.4X) (0.5X) -- -- -- -- (22.9X) -- -- 9% --

Vantage VTGDF-US 0.00 NR -- -- 311 $1 $2,469 ($0.01) ($0.70) ($0.95) (0.5X) (0.0X) (0.0X) 6.5X 13.6X 29.9X -- -- -- -- -- --

2.7X 7.4X 12.3X 4.2X 6.1X 8.1X 3.0X 2.0X 5.3X 35% 36% 38%

Onshore Drilling

Helmerich & Payne HP-US 51.37 Buy $78.00 52% 108 $5,537 $5,406 $2.99 ($0.26) $1.60 17.2X -- 32.1X 4.9X 9.6X 6.3X 0.5X 0.9X 0.6X 7% 8% 8%

Nabors Industries NBR-US 8.69 Buy $13.00 50% 331 $2,873 $5,974 ($0.40) ($1.32) $0.46 (21.6X) (6.6X) 19.0X 5.3X 7.5X 5.1X 3.3X 4.7X 3.2X 38% 40% 38%

Patterson-UTI Energy PTEN-US 14.80 Buy $23.00 55% 147 $2,178 $2,811 ($0.71) ($1.71) ($0.24) (20.9X) (8.7X) (61.3X) 4.9X 8.8X 4.9X 1.5X 2.7X 1.5X 19% 20% 19%

Unit UNT-US 12.43 NR -- -- 50 $627 $1,546 ($0.19) ($0.51) $1.15 (66.4X) (24.3X) 10.9X 4.2X 4.8X 3.0X 2.6X 3.3X -- 28% 30% --

Seventy Seven Energy SSE-US 1.03 NR -- -- 57 $58 $1,497 ($3.30) ($3.54) ($2.29) (0.3X) (0.3X) (0.5X) 8.4X 11.3X 6.9X 9.0X 12.0X 6.7X 82% 90% 89%

(18.4X) (9.9X) 0.0X 5.6X 8.4X 5.2X 3.4X 4.7X 3.0X 35% 38% 38%

OCTG

Tenaris TS-US 23.78 NR -- -- 590 $14,037 $12,354 $0.85 $0.93 $1.40 27.8X 25.6X 16.9X 9.1X 9.0X 6.7X 0.8X 0.8X 0.6X 7% 7% 7%

Vallourec VK-FR 8.33 NR -- -- 134 $1,114 $3,114 ($3.81) ($2.28) $0.08 (2.2X) (3.7X) -- (46.6X) 43.3X 6.8X -- -- -- -- -- --

12.8X 11.0X 16.9X (18.7X) 26.1X 6.7X 0.8X 0.8X 0.6X 7% 7% 7%

Offshore Supply Chain

Bristow Group BRS-US 25.55 NR -- -- 35 $893 $1,795 $1.98 $2.67 $3.30 12.9X 9.6X 7.7X 5.9X 4.9X 3.4X 3.5X 3.3X -- 31% 35% --

Rignet RNET-US 19.36 NR -- -- 18 $344 $358 ($0.23) $0.59 $0.84 (85.4X) 32.8X 23.0X 5.3X 7.0X 6.6X -- -- -- -- -- --

Tidewater TDW-US 7.36 NR -- -- 47 $346 $1,762 ($0.78) ($1.91) ($1.36) (9.5X) (3.8X) (5.4X) 8.2X 12.4X 10.9X 6.9X 10.4X 8.9X 33% 34% 35%

Seacor Holdings CKH-US 54.53 NR -- -- 17 $946 $1,533 $1.60 $2.71 $3.25 34.0X 20.1X 16.8X 9.6X 7.7X 7.3X -- -- -- -- -- --

Hornbeck Offshore Services HOS-US 9.58 NR -- -- 36 $343 $1,122 $1.15 ($0.29) ($0.02) 8.3X (33.4X) -- 5.1X 7.2X 6.6X 4.9X 6.9X 6.3X 36% 36% 36%

Gulfmark Offshore GLF-US 5.43 NR -- -- 26 $140 $632 ($1.61) ($2.13) ($1.72) (3.4X) (2.6X) (3.2X) 13.6X 25.1X 14.8X 11.2X 20.8X -- 36% 36% --

(7.2X) 3.8X 7.8X 8.0X 10.7X 8.3X 6.6X 10.4X 7.6X 34% 35% 35%

Engineering & Construction

Petrofac PFC-GB 7.60 NR -- -- 346 $2,627 $3,831 $0.34 $0.94 $1.00 22.3X 8.1X 7.6X 9.4X 6.1X 5.7X 3.0X 1.5X 1.4X 21% 15% 14%

Wood Group WG-GB 5.77 NR -- -- 379 $2,184 $2,370 $0.51 $0.43 $0.47 11.4X 13.3X 12.2X 7.3X 8.2X 7.9X 1.0X 1.2X 1.1X 12% 12% 11%

Technip TEC-FR 46.16 NR -- -- 117 $5,405 $4,082 $4.91 $4.44 $3.78 9.4X 10.4X 12.2X 3.3X 3.6X 4.2X 1.9X 1.8X 1.9X 16% 14% 13%

Saipem SPM-IT 7.47 NR -- -- 441 $3,297 $7,447 ($1.68) $0.44 $0.52 (4.5X) 17.1X 14.3X 15.7X 5.8X 5.5X 14.1X 2.6X 2.4X 40% 19% 19%

Worley Parsons WOR-AU 4.62 NR -- -- 245 $1,132 $1,986 $0.80 $0.74 $0.75 5.8X 6.2X 6.2X 4.4X 4.6X 4.6X 2.7X -- -- 23% -- --

Tecnicas Reunidas TRE-ES 33.90 NR -- -- 56 $1,895 $1,540 $2.77 $2.96 $3.15 12.2X 11.5X 10.8X 7.3X 6.9X 6.5X -- -- -- -- -- --

Helix Energy Solutions HLX-US 5.01 NR -- -- 106 $532 $839 $0.18 ($0.04) $0.28 27.5X -- 17.7X 5.0X 5.3X 3.8X 4.8X 5.0X 3.5X 28% 27% 25%

Mcdermott MDR-US 3.62 NR -- -- 239 $865 $1,008 ($0.14) ($0.08) $0.12 (26.1X) (47.3X) 29.9X 5.3X 4.3X 3.4X 4.5X 3.6X 2.9X 24% 25% 24%

7.3X 2.8X 13.9X 7.2X 5.6X 5.2X 4.6X 2.6X 2.2X 23% 19% 18%

KLR / Consensus EPS P/E EV/EBITDA Total Debt/EBITDA Total Debt/Assets



KLR EPS Estimates vs. Consensus Company Category 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17EDiversified Oilfield SerivicesSchlumberger EPS $4.80 $5.56 $3.36 $2.81 $4.35 $1.06 $0.88 $0.78 $0.65 $0.66 $0.64 $0.71 $0.80 $0.88 $0.99 $1.17 $1.31

Consensus EPS $3.37 $2.70 $3.62 $0.65 $0.61 $0.63 $0.69 $0.77 $0.76 $0.84 $0.93 $1.03

Consensus EPS-High $3.43 $3.26 $4.45 $0.72 $0.70 $0.77 $0.82 $0.95 $0.90 $1.05 $1.18 $1.32

Consensus EPS-Low $3.28 $2.15 $2.65 $0.57 $0.53 $0.50 $0.51 $0.58 $0.61 $0.60 $0.68 $0.76

Halliburton EPS $2.45 $4.01 $1.45 $0.87 $2.16 $0.49 $0.44 $0.31 $0.20 $0.19 $0.19 $0.27 $0.35 $0.44 $0.53 $0.64 $0.70

Consensus EPS $1.49 $1.11 $2.09 $0.24 $0.18 $0.22 $0.31 $0.40 $0.40 $0.48 $0.59 $0.70


Consensus EPS-Low $1.44 $0.65 $1.60 $0.19 ($0.04) $0.07 $0.14 $0.21 $0.29 $0.32 $0.45 $0.58

Weatherford EPS $0.60 $1.01 ($0.29) ($0.34) $0.23 ($0.04) ($0.10) ($0.05) ($0.09) ($0.11) ($0.10) ($0.08) ($0.05) ($0.02) $0.03 $0.08 $0.14

Consensus EPS ($0.32) ($0.33) $0.19 ($0.12) ($0.12) ($0.11) ($0.07) ($0.03) ($0.03) ($0.01) $0.05 $0.10

Consensus EPS-High ($0.26) $0.01 $0.83 ($0.06) ($0.09) ($0.03) $0.04 $0.10 $0.06 $0.04 $0.09 $0.15

Consensus EPS-Low ($0.37) ($0.65) ($0.38) ($0.17) ($0.18) ($0.20) ($0.16) ($0.13) ($0.08) ($0.07) ($0.02) $0.04


National Oilwell Varco EPS $5.52 $6.48 $2.90 $1.41 $1.87 $1.14 $0.77 $0.61 $0.38 $0.36 $0.34 $0.35 $0.36 $0.37 $0.42 $0.49 $0.58

Consensus EPS $2.98 $1.45 $1.90 $0.46 $0.38 $0.35 $0.37 $0.40 $0.41 $0.45 $0.49 $0.52



FMC Technologies EPS $2.17 $2.94 $2.26 $1.69 $1.85 $0.63 $0.52 $0.61 $0.50 $0.45 $0.42 $0.40 $0.41 $0.39 $0.41 $0.47 $0.58

Consensus EPS $2.26 $1.57 $1.64 $0.50 $0.41 $0.41 $0.38 $0.38 $0.36 $0.38 $0.42 $0.47



Oceaneering EPS $3.44 $4.00 $2.86 $1.87 $1.98 $0.70 $0.76 $0.82 $0.59 $0.48 $0.48 $0.51 $0.40 $0.41 $0.46 $0.59 $0.52

Consensus EPS $2.86 $2.14 $2.31 $0.59 $0.50 $0.56 $0.58 $0.54 $0.54 $0.58 $0.60 $0.58



Forum Energy EPS $1.46 $1.84 $0.48 ($0.08) $0.56 $0.30 $0.16 $0.08 ($0.05) ($0.05) ($0.04) ($0.01) $0.02 $0.06 $0.11 $0.16 $0.23

Consensus EPS $0.50 $0.10 $0.56 ($0.03) ($0.02) $0.00 $0.04 $0.08 $0.08 $0.11 $0.14 $0.19


Consensus EPS-Low $0.41 ($0.35) $0.06 ($0.13) ($0.13) ($0.12) ($0.08) ($0.02) $0.02 $0.03 $0.07 $0.14

Dril-Quip EPS $4.23 $5.09 $4.90 $3.02 $3.22 $1.25 $1.24 $1.32 $1.09 $0.88 $0.75 $0.71 $0.68 $0.67 $0.75 $0.83 $0.96

Consensus EPS $4.87 $2.98 $2.61 $1.06 $0.91 $0.76 $0.70 $0.65 $0.67 $0.70 $0.70 $0.73


Consensus EPS-Low $4.81 $2.35 $1.84 $1.00 $0.80 $0.62 $0.45 $0.43 $0.63 $0.61 $0.62 $0.63Source: Factset, KLR Group, LLC Estimates; Company Filings/Disclosures


Company Category 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17EMid/Small Cap Oilfield Serices

Core Laboratories EPS $5.32 $5.79 $3.19 $2.92 $3.89 $0.86 $0.82 $0.83 $0.67 $0.65 $0.68 $0.75 $0.83 $0.88 $0.94 $1.00 $1.07

Consensus EPS $3.17 $2.94 $3.77 $0.65 $0.64 $0.69 $0.77 $0.81 $0.77 $0.83 $0.91 $0.99



Superior Energy Services EPS $1.56 $1.79 ($1.22) ($1.26) $0.16 ($0.01) ($0.31) ($0.46) ($0.44) ($0.43) ($0.38) ($0.28) ($0.17) ($0.10) $0.01 $0.10 $0.15

Consensus EPS ($1.29) ($1.61) ($0.49) ($0.51) ($0.48) ($0.43) ($0.37) ($0.31) ($0.28) ($0.20) ($0.14) ($0.09)

Consensus EPS-High ($1.20) ($1.00) $0.62 ($0.42) ($0.36) ($0.29) ($0.20) ($0.08) ($0.05) $0.06 $0.15 $0.24

Consensus EPS-Low ($1.36) ($2.01) ($1.98) ($0.58) ($0.62) ($0.58) ($0.51) ($0.50) ($0.50) ($0.50) ($0.50) ($0.50)

Flotek Industries EPS $0.67 $0.97 $0.09 $0.50 $1.06 ($0.04) $0.01 $0.04 $0.08 $0.08 $0.11 $0.14 $0.17 $0.21 $0.25 $0.29 $0.31

Consensus EPS ($0.00) $0.18 $0.79 ($0.01) ($0.00) $0.02 $0.04 $0.05 $0.16 $0.21 $0.28 $0.29


Consensus EPS-Low ($0.02) ($0.03) $0.47 ($0.03) ($0.04) ($0.02) $0.00 ($0.01) $0.13 $0.17 $0.22 $0.24

Franks International EPS $1.99 $1.09 $0.61 $0.38 $0.79 $0.25 $0.15 $0.12 $0.10 $0.09 $0.08 $0.09 $0.11 $0.14 $0.18 $0.21 $0.25

Consensus EPS $0.62 $0.45 $0.58 $0.10 $0.10 $0.10 $0.11 $0.11 $0.12 $0.12 $0.14 $0.15



Oil States International EPS $0.71 $3.74 $0.69 ($0.20) $1.08 $0.45 $0.15 $0.11 ($0.02) ($0.06) ($0.07) ($0.07) ($0.01) $0.09 $0.21 $0.33 $0.45

Consensus EPS $0.70 ($0.14) $0.43 ($0.01) ($0.06) ($0.07) ($0.05) ($0.00) $0.02 $0.05 $0.13 $0.24


Consensus EPS-Low $0.66 ($0.50) $0.03 ($0.05) ($0.12) ($0.15) ($0.15) ($0.12) ($0.03) ($0.03) $0.02 $0.09

Newpark Resources EPS $0.50 $0.78 ($0.18) ($0.29) $0.21 $0.01 ($0.03) ($0.06) ($0.11) ($0.11) ($0.07) ($0.06) ($0.05) ($0.02) $0.02 $0.07 $0.14

Consensus EPS ($0.16) ($0.19) $0.20 ($0.08) ($0.08) ($0.08) ($0.05) ($0.03) ($0.07) ($0.07) ($0.05) ($0.04)

Consensus EPS-High ($0.15) ($0.07) $0.50 ($0.07) ($0.05) ($0.03) $0.00 $0.01 ($0.07) ($0.07) ($0.05) ($0.04)


C&J Services EPS $1.21 $1.51 ($1.78) ($1.54) $0.60 ($0.12) ($0.46) ($0.65) ($0.54) ($0.52) ($0.44) ($0.35) ($0.22) ($0.03) $0.10 $0.21 $0.32

Consensus EPS ($1.95) ($2.13) ($1.15) ($0.71) ($0.64) ($0.58) ($0.49) ($0.45) ($0.45) ($0.39) ($0.34) ($0.29)

Consensus EPS-High ($1.81) ($1.75) ($0.31) ($0.57) ($0.54) ($0.50) ($0.40) ($0.32) ($0.32) ($0.23) ($0.14) ($0.04)


KLR EPS Estimates vs. Consensus (cont.)





Company Category 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17EOffshore Contract Drillers

Seadrill EPS $3.03 $2.69 $1.85 $1.08 $0.73 $0.48 $0.77 $0.21 $0.39 $0.34 $0.34 $0.23 $0.17 $0.07 $0.06 $0.19 $0.40

Consensus EPS $1.90 $1.48 $0.63 $0.44 $0.40 $0.43 $0.31 $0.25 $0.18 $0.15 $0.23 $0.19


Consensus EPS-Low $1.73 $0.20 ($0.23) $0.27 $0.30 $0.29 $0.15 $0.09 $0.09 $0.12 $0.15 $0.10

Transocean EPS $3.73 $5.03 $3.70 $0.47 $0.78 $1.10 $1.12 $0.85 $0.62 $0.44 $0.04 $0.02 ($0.04) $0.11 $0.17 $0.19 $0.32

Consensus EPS $3.71 $0.62 ($0.56) $0.64 $0.45 $0.11 $0.06 $0.00 $0.03 ($0.03) ($0.23) ($0.24)


Consensus EPS-Low $3.49 ($0.57) ($1.84) $0.42 $0.15 ($0.22) ($0.33) ($0.42) ($0.24) ($0.34) ($0.60) ($0.66)

ENSCO EPS $6.16 $6.21 $4.37 $2.22 $2.29 $1.38 $1.16 $1.09 $0.73 $0.66 $0.62 $0.51 $0.43 $0.36 $0.58 $0.67 $0.69

Consensus EPS $4.38 $2.39 $1.13 $0.74 $0.76 $0.69 $0.45 $0.40 $0.28 $0.30 $0.28 $0.25


Consensus EPS-Low $4.12 $1.58 ($0.40) $0.48 $0.43 $0.44 $0.19 $0.23 $0.10 $0.10 ($0.02) $0.00

Diamond Offshore EPS $4.77 $3.17 $2.66 $0.65 $0.29 $0.49 $0.66 $1.05 $0.45 $0.03 $0.20 $0.28 $0.14 $0.06 $0.05 $0.10 $0.08

Consensus EPS $2.69 $0.70 $0.71 $0.48 $0.20 $0.13 $0.22 $0.21 $0.21 $0.11 $0.05 $0.05


Consensus EPS-Low $2.47 $0.06 ($0.27) $0.26 ($0.07) ($0.16) ($0.00) $0.03 $0.08 ($0.06) ($0.20) ($0.18)

Noble EPS $2.92 $3.04 $2.62 $1.15 $0.70 $0.72 $0.66 $0.72 $0.52 $0.38 $0.27 $0.27 $0.23 $0.19 $0.18 $0.17 $0.16

Consensus EPS $2.66 $1.26 $0.19 $0.56 $0.35 $0.33 $0.28 $0.28 $0.14 $0.06 $0.03 ($0.00)


Consensus EPS-Low $2.45 $0.50 ($0.92) $0.35 $0.19 $0.20 $0.10 $0.04 $0.08 ($0.13) ($0.10) ($0.11)

Rowan EPS $1.96 $2.11 $3.29 $2.42 $0.58 $0.99 $0.70 $0.89 $0.71 $0.68 $0.62 $0.56 $0.56 $0.41 $0.11 $0.06 $0.00

Consensus EPS $3.30 $2.36 $0.66 $0.72 $0.65 $0.64 $0.55 $0.53 $0.50 $0.29 $0.15 $0.09


Consensus EPS-Low $3.09 $1.57 ($0.45) $0.51 $0.46 $0.44 $0.18 $0.12 $0.25 ($0.14) ($0.21) ($0.10)

Atwood Oceanics EPS $5.32 $4.89 $7.74 $2.64 ($0.07) $1.71 $1.97 $1.73 $2.32 $0.85 $1.07 $0.68 $0.04 ($0.11) ($0.15) ($0.02) $0.21

Consensus EPS $3.69 ($0.22) $0.96 $1.35 $0.86 $0.53 ($0.04) $0.01 $0.07 $0.01

Consensus EPS-High $5.58 $2.03 $1.40 $1.73 $1.20 $1.20 $0.50 $0.27 $0.70 $0.55

Consensus EPS-Low $2.45 ($2.50) $0.76 $1.00 $0.35 ($0.13) ($0.29) ($0.37) ($0.43) ($0.49)

Pacific Drilling EPS $0.42 $0.86 $0.75 ($0.54) ($0.33) $0.24 $0.22 $0.19 $0.09 ($0.11) ($0.11) ($0.15) ($0.17) ($0.17) ($0.14) ($0.05) $0.03

Consensus EPS $0.79 ($0.37) ($0.88) $0.13 ($0.06) ($0.06) ($0.07) ($0.17) ($0.14) ($0.19) ($0.22) ($0.27)

Consensus EPS-High $0.91 $0.12 ($0.11) $0.25 ($0.03) ($0.01) $0.06 $0.01 ($0.10) ($0.17) ($0.21) ($0.23)

Consensus EPS-Low $0.69 ($0.78) ($1.76) $0.03 ($0.16) ($0.15) ($0.24) ($0.29) ($0.18) ($0.22) ($0.24) ($0.32)


Company Category 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17EOnshore Drilling

Helmerich & Payne EPS $5.67 $6.25 $2.98 ($0.26) $1.60 $1.70 $0.97 $0.27 $0.04 ($0.13) ($0.13) ($0.06) $0.06 $0.20 $0.32 $0.48 $0.61

Consensus EPS ($0.30) $0.21 ($0.07) ($0.10) ($0.08) ($0.06) ($0.02) $0.00 $0.07 $0.15

Consensus EPS-High $0.32 $1.14 $0.01 ($0.01) $0.02 $0.17 $0.21 $0.18 $0.29 $0.46

Consensus EPS-Low ($0.72) ($1.18) ($0.13) ($0.20) ($0.20) ($0.21) ($0.20) ($0.27) ($0.32) ($0.39)

Nabors Industries EPS $1.35 $1.14 ($0.40) ($1.32) $0.46 $0.20 ($0.15) ($0.07) ($0.40) ($0.41) ($0.38) ($0.31) ($0.22) ($0.11) $0.05 $0.22 $0.29

Consensus EPS ($0.28) ($1.30) ($0.69) ($0.27) ($0.32) ($0.36) ($0.31) ($0.28) ($0.21) ($0.19) ($0.09) ($0.06)

Consensus EPS-High ($0.09) ($0.34) $0.45 ($0.08) ($0.13) ($0.13) ($0.07) ($0.01) ($0.05) ($0.01) $0.24 $0.21


Patterson-UTI Energy EPS $1.46 $1.26 ($0.71) ($1.71) ($0.24) $0.06 ($0.13) ($0.27) ($0.37) ($0.46) ($0.47) ($0.42) ($0.35) ($0.25) ($0.11) $0.00 $0.12

Consensus EPS ($0.82) ($1.97) ($1.21) ($0.49) ($0.51) ($0.52) ($0.48) ($0.44) ($0.39) ($0.36) ($0.28) ($0.24)

Consensus EPS-High ($0.76) ($1.40) $0.05 ($0.42) ($0.37) ($0.38) ($0.27) ($0.16) ($0.11) ($0.04) $0.07 $0.13


Proppant

US Silica EPS $1.45 $2.41 $0.27 ($0.09) $0.87 $0.27 $0.08 ($0.03) ($0.07) ($0.08) ($0.05) ($0.01) $0.05 $0.11 $0.16 $0.25 $0.35

Consensus EPS $0.14 ($0.19) $0.68 ($0.19) ($0.14) ($0.05) $0.00 $0.01 $0.08 $0.14 $0.16 $0.15

Consensus EPS-High $0.25 $0.10 $2.05 ($0.08) ($0.03) $0.03 $0.11 $0.17 $0.08 $0.19 $0.20 $0.18

Consensus EPS-Low ($0.05) ($0.64) $0.08 ($0.38) ($0.29) ($0.16) ($0.11) ($0.11) $0.08 $0.09 $0.11 $0.12

Carbo Ceramics EPS $3.70 $3.39 ($1.71) ($2.37) ($1.08) ($0.28) ($0.41) ($0.35) ($0.67) ($0.63) ($0.60) ($0.57) ($0.57) ($0.47) ($0.35) ($0.21) ($0.05)

Consensus EPS ($1.93) ($2.21) ($0.82) ($0.89) ($0.69) ($0.55) ($0.50) ($0.46) $0.01 $0.01 $0.01 $0.01

Consensus EPS-High ($1.77) ($1.50) $0.04 ($0.73) ($0.51) ($0.40) ($0.31) ($0.26) $0.01 $0.01 $0.01 $0.01

Consensus EPS-Low ($2.04) ($2.86) ($1.65) ($1.00) ($0.87) ($0.69) ($0.77) ($0.74) $0.01 $0.01 $0.01 $0.01

Fairmount EPS $0.63 $1.05 $0.09 ($0.19) $0.16 $0.18 $0.02 ($0.05) ($0.06) ($0.07) ($0.06) ($0.04) ($0.02) $0.00 $0.02 $0.05 $0.09

Consensus EPS $0.06 ($0.24) $0.08 ($0.10) ($0.09) ($0.06) ($0.05) ($0.04) ($0.04) ($0.01) $0.01 $0.02

Consensus EPS-High $0.11 $0.00 $0.56 ($0.05) ($0.02) $0.02 $0.02 $0.00 ($0.02) $0.02 $0.05 $0.06

Consensus EPS-Low $0.01 ($0.40) ($0.15) ($0.15) ($0.15) ($0.12) ($0.09) ($0.08) ($0.05) ($0.04) ($0.03) ($0.03)




Commodities Factors Start to Turn for Oilfield Services


Negative IEA Supply Revisions & Low OPEC Spare Capacity Work in Oil’s Favor

BULLISH ON OIL MARKET. The oil market remains out of balance, but we see the second derivative of supply/demand dynamics moving in the right direction. We track four variables as a measure of the health of the oil market as an indicator for oilfield service activity. In our view, evidence of a production response to low oil prices and reduced upstream spending remains the most important. FOUR OILMARKET VARIABLES KEY TO TRAJECTORY OF COMMODITY BULLISH: OPEC Spare Capacity Remains Near Multi-Year Lows. As a percentage of total supply, OPEC spare capacity sits at historically low levels. Given OPEC’s quest to regain market shares, we anticipate that spare capacity should remain low. Reduced cushion in the market supports a shift to risk premiums in oil prices if non-OPEC supply revisions continue to trend lower, global demand numbers revise higher, or geopolitical issues pose a risk to supply estimates. (pg. 27) BULLISH: Negative Non-OPEC Supply Revisions. The IEA has begun negative supply revisions for 2016 non-OPEC supply estimates. Rapid upstream spending cuts in the North America and accelerating spending reductions in international markets, likely continues the negative estimate revision trend and potentially accelerate. Lowered supply estimates in combination with low OPEC spare capacity may prove bullish for oil prices. (pg. 28) NEUTRAL/BEARISH: Global Demand Growth Appears Stable for Now. The trajectory of global oil demand remains positive. Recent market concerns regarding global economic growth, particularly in China, may overhang global demand estimates. We view that variable as neutral to negative for oil prices in the near term. (pg. 31) BEARISH: Inventories Remain High. Global oil inventories remain high, but appear to have leveled off above recent averages. Continued builds in inventories may remain bearish for oil prices. The oil market needs global inventory numbers to begin to draw, as a signal of better supply/demand balances. We do note, that inventory level surpluses are small on a “days demand” basis. Even in the US, we are only carrying inventories approximately seven days of demand above the typical 55-60 days in stock. If demand remains healthy and supply revisions remain negative, inventories may begin to draw. (pg. 31)

2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 2017 2018 2019 2020

KLR Group $99.55A $55.38A $63.39A $51.37A $54.00 $56.03 $59.00 $66.50 $72.50 $80.00 $69.50 $90.00 $90.00 $90.00 $90.00

Futures Market $99.55A $55.38A $63.39A $51.37A $46.64 $54.19 $45.75 $47.87 $49.70 $51.41 $48.68 $54.58 $57.81 $59.90 $61.24

Consensus Forecast $99.55A $55.38A $63.39A $51.37A $50.40 $55.13 $56.00 $56.00 $56.00 $56.00 $56.00 $65.00 $70.00 $70.00 $70.00

Brent Crude Oil ($/bbl)1

2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 2017 2018 2019 2020

KLR Group $93.00A $48.80A $57.80A $46.70A $50.00 $50.83 $55.00 $62.50 $67.50 $75.00 $65.00 $85.00 $85.00 $85.00 $85.00

Futures Market $93.00A $48.80A $57.80A $46.70A $43.61 $49.23 $43.80 $45.95 $47.31 $48.57 $46.41 $50.74 $53.37 $55.52 $57.02

Consensus Forecast $93.00A $48.80A $57.80A $46.70A $47.40 $50.18 $50.29 $50.29 $50.29 $50.29 $53.50 $61.00 $67.25 $67.50 $69.00

NYMEX WTI Crude Oil ($/bbl)1

1Based on daily average price Sources: Bloomberg; KLR Group, LLC Forecasts


Mkt Share Quest Leaves OPEC Spare Capacity Low, Potentially Headed Lower as Iran Ramps

$15

$35

$55

$75

$95

$115

$135

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

11%

Jan

-01

Jan

-02

Jan

-03

Jan

-04

Jan

-05

Jan

-06

Jan

-07

Jan

-08

Jan

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

Jan

-15

Bre

nt

Cru

de

Oil

Pri

ce (

$/b

bl)

OP

EC S

par

e C

apac

ity

% o

f G

lob

al S

up

ply

OPEC Spare Capacity Brent Crude Price

Source: IEA

Non-OPEC Supply Revisions Boost Call Spare Capacity: Bullish


Negative IEA Non-OPEC Supply Revision Suggest Markets Move Toward Balance

$40

$50

$60

$70

$80

$90

$100

$110

$120

$130

$140

50

51

52

53

54

55

56

57

58

59

Jul-

08

Oct

-08

Jan

-09

Ap

r-0

9

Jul-

09

Oct

-09

Jan

-10

Ap

r-1

0

Jul-

10

Oct

-10

Jan

-11

Ap

r-1

1

Jul-

11

Oct

-11

Jan

-12

Ap

r-1

2

Jul-

12

Oct

-12

Jan

-13

Ap

r-1

3

Jul-

13

Oct

-13

Jan

-14

Ap

r-1

4

Jul-

14

Oct

-14

Jan

-15

Ap

r-1

5

Jul-

15

Oct

-15

Act

ual

Bre

nt

Cru

de

Oil

Pri

ce (

$/b

bl)

An

nu

al N

on

-OP

EC S

up

ply

Fo

reca

st (

mm

b/d

)

Vintage of Forecast

2009 IEA Supply 2010 IEA Supply 2011 IEA Supply 2012 IEA Supply 2013 IEA Supply

2014 IEA Supply 2015 IEA Supply 2016 IEA Supply Brent Crude

Source: IEA

Negative Non-OPEC Supply Revisions: Bullish for Oil

Note: We maintain an extensive catalogue of the IEA’s monthly changes to its supply and demand forecasts. Annual estimates are typically initiated the summer before the year tracked and end the summer after the tracking year has ended.

Recent history sees negative revisions for non-OPEC oil supply as a leading indicator of oil price recovery.


US EIA Weekly Crude Production Data Beginning to Rollover, But Pace & Trajectory Question Marks

Source: EIA as of 11/20/15

9.2

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

8.5

9.0

9.5

10.0

Jan-05

Jun-05

Nov-05

Apr-06

Sep-06

Feb-07

Jul-07

Dec-07

May-08

Oct-08

Mar-09

Aug-09

Jan-10

Jun-10

Nov-10

Apr-11

Sep-11

Feb-12

Jul-12

Dec-12

May-13

Oct-13

Mar-14

Aug-14

Jan-15

Jun-15

Nov-15

MMB/d

Weekly US Crude Production


KLR US Liquids Production Forecast

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

Jan

-11

Jul-

11

Jan

-12

Jul-

12

Jan

-13

Jul-

13

Jan

-14

Jul-

14

Jan

-15

Jul-

15

Jan

-16

Jul-

16

Jan

-17

Jul-

17

Jan

-18

Jul-

18

Jan

-19

Jul-

19

Jan

-20

Jul-

20

U.S

. Liq

uid

s Su

pp

ly (M

mb

pd

)

Other Alaska GOM NGLs Permian Williston Eagle Ford Top-Down ForecastSource: Baker Hughes, HPDI, EIA, KLR Group LLC.


$40

$50

$60

$70

$80

$90

$100

$110

$120

$130

$140

83

84

85

86

87

88

89

90

91

92

93

94

95

96

Jul-

08

Oct

-08

Jan

-09

Ap

r-0

9

Jul-

09

Oct

-09

Jan

-10

Ap

r-1

0

Jul-

10

Oct

-10

Jan

-11

Ap

r-1

1

Jul-

11

Oct

-11

Jan

-12

Ap

r-1

2

Jul-

12

Oct

-12

Jan

-13

Ap

r-1

3

Jul-

13

Oct

-13

Jan

-14

Ap

r-1

4

Jul-

14

Oct

-14

Jan

-15

Ap

r-1

5

Jul-

15

Oct

-15

Act

ual

Bre

nt

Cru

de

Oil

Pri

ce (

$/b

bl)

Glo

bal

De

man

d F

ore

cast

(m

mb

/d)

Vintage of Forecast

2009 IEA Demand 2010 IEA Demand 2011 IEA Demand 2012 IEA Demand 2013 IEA Demand

2014 IEA Demand 2015 IEA Demand 2016 IEA Demand Brent Crude

IEA Global Demand Forecast Stable, But Economic Growth Concerns May Leave Negative Bias

Source: IEA

Negative Global Demand Revisions : Bearish for Oil


51

56

61

66

71

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Day

s o

f In

ven

tory

5yr Range 2013 2014 2015

Oil Inventory – OECD and US Inventories Historically High, But Production Response May Reverse Trends

54

56

58

60

62

64

66


Day

s o

f In

ven

tory

'10-'14 Range 2013 2014 2015

OECD Inventory / OECD Daily Demand

Source: IEA

US Inventory / US Daily Demand

Source: EIA, as of 11/20/15


Natural Gas Markets Remain Enigmatic, But Bright Spots in the Data

NATURAL GAS MARKET REMAINS UNECONOMIC, YET ENIGMATIC. Productivity growth per well/rig continues to keep a lid on natural gas prices, despite our view that production is not economic at current levels. In the longer term, we see a correction in this relationship. From the oil services perspective, gas represent ~20% of the rig count, so a meaningful shift in activity may be required to move the needle in our forecasts. BEARISH: Storage Levels Remain High. High storage levels and healthy production continue to make it difficult for natural gas prices to rally. KLR continues to see current spending and ultimately production unsustainable at current economics. BULLISH: Productivity Per Well & RIG Slowing. The bearish natural gas argument hinges in part on continued productivity growth per rig/well driving down the marginal cost of gas. Recent EIA data suggests the upwards productivity trend is ending. Whether it is less associated gas volumes from reduced spending at oil plays or something more material in natural gas spending/drilling, the turn in the data may prove bullish.

2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 2017 2018 2019 2020

KLR Group $4.41A $2.99A $2.64A $2.77A $2.28A $2.67A $3.00 $3.25 $3.50 $3.75 $3.38 $4.25 $4.25 $4.25 $4.25

Futures Market $4.41A $2.99A $2.64A $2.77A $2.28A $2.67A $2.28 $2.39 $2.49 $2.62 $2.45 $2.78 $2.89 $2.96 $3.07

Consensus Forecast $4.41A $2.99A $2.64A $2.77A $2.28A $2.67A $3.25 $3.25 $3.25 $3.25 $3.25 $3.43 $3.50 $3.39 $3.52

NYMEX Natural Gas ($/mmbtu)2

1Based on settlement price on last trading day each month Sources: Bloomberg; KLR Group, LLC Forecasts


Gas Well Productivity Improvements Challenge Legacy Inventory/Natural Gas Price Paradigms

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0


Tril

lio

ns

of C

ub

ic F

ee

t

5yr Range 2015 2013 2014

Natural Gas Storage (% of 5yr Avg) vs. Henry Hub Price USA Natural Gas In Storage

40%

60%

80%

100%

120%

140%

160%

$2

$4

$6

$8

$10

$12

$14

Jan-0

7

Jul-07

Jan-0

8

Jul-08

Jan-0

9

Jul-09

Jan-1

0

Jul-10

Jan-1

1

Jul-11

Jan-1

2

Jul-12

Jan-1

3

Jul-13

Jan-1

4

Jul-14

Jan-1

5

Jul-15

Sto

rage

% o

f 5

yr A

vera

ge

Nat

ura

l Gas

Pri

ce

Gas Price Storage % of 5 Year Rolling Average

Source: EIA as of 11/20/15 Source: EIA as of 11/20/15


KLR US Natural Gas Production Forecast

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

Jan

-09

Jul-

09

Jan

-10

Jul-

10

Jan

-11

Jul-

11

Jan

-12

Jul-

12

Jan

-13

Jul-

13

Jan

-14

Jul-

14

Jan

-15

Jul-

15

Jan

-16

Jul-

16

Jan

-17

Jul-

17

Jan

-18

Jul-

18

Jan

-19

Jul-

19

Jan

-20

Jul-

20

U.S

. Gas

Su

pp

ly (B

cfp

d)

Other/GOM Associated Gas Barnett Haynesville Marcellus/Utica Total Top-Down Forecast

Source: Baker Hughes, HPDI, EIA, KLR Group LLC.


Natural Gas Productivity Improvements Slow, Potentially Shifting Natural Gas Price Paradigms

Natural Gas Production Per Rig Natural Gas Production Per Well

Source: EIA Source: EIA

100

120

140

160

180

200

220

19

89

19

91

19

93

19

95

19

97

19

99

20

01

20

03

20

05

20

07

20

09

20

11

20

13

mcf

d/w

ell

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

2,300

2,500

Mar-0

7

Sep

-07

Mar-0

8

Sep

-08

Mar-0

9

Sep

-09

Mar-1

0

Sep

-10

Mar-1

1

Sep

-11

Mar-1

2

Sep

-12

Mar-1

3

Sep

-13

Mar-1

4

Sep

-14

Mar-1

5

Sep

-15

mcf

d/r

ig

Note: Based on EIA monthly estimates for drilling productivity within Haynesville, Eagle Ford, Permian, Niobrara, Bakken, Utica, and Marcellus geographical regions. These seven regions accounted for 100% of the natural gas production growth during 2011 – 2014.


US Land Market Bottoms 4Q15/1Q16


Positive Backdrop for North American Services Outlook Proprietary US Rig Count Model See US Land Rig Count Bottom in 4Q15/1Q16. We have built a proprietary US land rig count forecast model to reflect the high correlations between commodity prices, cash flow, capital expenditures, funding gaps, rig efficiency, inflation/deflation, and service intensity per well. Given an oil price bottom in 4Q15/1Q16, we see the US land rig count finding a trough in the 600-700 rig range during 4Q15/1Q16. As oil prices recover towards $85 in 2017, we see the US land rig count exiting 2016 closer to ~1,000 rigs . As activities’ bottom, the market may come closer to cash flow neutrality, with funding gaps (CFO less CAPEX) closer to 15-20%, down from recent highs. The value of borrowing bases potentially revised down as a function of current lower oil and natural gas outlooks, banks and debt markets may continue to close the lending spigot. Meanwhile, equity markets may not give E&Ps credit for growth achieved through funding gaps. Narrowed funding gaps and lowered cash flow from depressed commodity prices may mark the bottom of rig and oil services activity. We are buyers of US levered oil service stocks at the nadir of activity, especially as negative global oil supply revisions begin to appear. From a bottom activity from financially deleveraged producers with more anemic cash flows, may only improve with a recovery of oil prices and more receptive capital markets. North American Activity Responds First to Market Inflection. A well established infrastructure in the US, created by years of “spot” market conditions and a plethora of E&Ps, allows for both a more rapid decline and rapid increase in activity. As a result, the North American market is more volatile than international and offshore markets, with larger scale projects and greater supply chain lead times. As oil prices rise and fall, US land rig counts can increased ~60% (2009/2010) or fall ~60% (2014/2015) year over year. As the commodity and activity find a bottom in 1H16, we see the potential for an accelerated recovery in land rig counts and completions activity (DUC inventory) in 2017/2016. Oil Services Companies Poised for Rapid Improvement in Returns. After over four quarters of cost cutting, process realignment, and other streamlining exercises, North American oil services providers are poised for tremendous operating leverage with the inflection of activity. Since we predict the inflection of activity in 2016, we want to own the group in front of the turn. Natural equipment attrition, stacking, and exit of weaker, often smaller competitors, in addition to the consolidation of larger competitors creates a strong tail wind for improvement in North American service and equipment market balances. Thus, the highest returns may come at the beginning of a cyclical turn, in part to incentivize incremental investment in front of more significant activity growth. In our view, more spot-oriented infrastructure, related to US activity creates an opportunity for faster capacity absorption relative to international and offshore markets. Winners • Oil Service/Equipment Companies Tied to North American Service & Consumables Demand. Several diversified and niche oil services providers may benefit from an uptick of US land activity. HAL

remains the biggest beneficiary amongst the diversified, large cap names, but risks around the digestion of BHI may create more attractive entry points. SPN, CLB, OIS, and FTK ($10.76, B, $14.50PT) stand out amongst small/mid caps. NOV and FET are the largest beneficiaries within the large and mid cap equipment group, respectively.

• Land Contract Drillers. HP, PTEN, and to a lesser extent NBR, may all have leverage to the high end of the land contract drilling market, positioned to improve with a modest recovery in US land rig counts. The pricing of higher tier rigs has shown resilience in that segment of the market, but higher utilizations may greatly improve economics.

• Pressure Pumping Companies (pg. 50). Equipment attrition matched with demand recovery for horsepower may rapidly improve pressure pumping economics. Pressure pumping companies may also benefit from an accelerated completion of DUCs, driving a faster demand recovery relative to land rigs. HAL benefits the most amongst large cap diversified service companies (others: SLB, WFT), while SPN is a safe way to play the small/mid cap group. Further out on the risk frontier, we like CJES among small cap names.

More Challenged • Proppant Companies. The proppant companies may clearly benefit from a US land recovery. An abundance of excess capacity and high fixed costs structures may lead the recovery in proppant

economics to lag the other sub-sectors. We view SLCA, FMSA, and CRR as later cycle plays to be revisited as their risk/reward improves. In the interim, we look to SLCA as a potential consolidator of capacity. We are more cautious on FMSA and CRR in light of balance sheet risks.


-64%

-55%

(65%) (60%) (55%) (50%) (45%) (40%) (35%) (30%) (25%) (20%) (15%) (10%)

(5%)-

5%10%15%20%25%30%35%40%45%50%55%

Jan

-14

Feb

-14

Ma

r-14

Ap

r-14

Ma

y-1

4

Jun

-14

Jul-

14

Au

g-14

Sep

-14

Oct

-14

No

v-14

Dec

-14

Jan

-15

Feb

-15

Ma

r-15

Ap

r-15

Ma

y-1

5

Jun

-15

Jul-

15

Au

g-15

Sep

-15

Oct

-15

No

v-15

Dec

-15

Ind

exe

d S

har

e P

erf

orm

ance

(%)Offshore Onshore

Investors Favor Leverage to Perceived Lower Marginal Cost Onshore vs. Higher Cost Offshore

Note: Offshore index includes FI, OIS, FTI, OII, DRQ, SDRL, RIG, ESV, DO, NE, RDC, ATW, and PACD equally weighted performance from 1/1/14 to 12/9/15 Onshore index includes SLCA, CRR, HP, NBR, and PTEN equally weighted performance from 1/1/14 to 12/9/15

Belief in a structural shift towards lower cost onshore projects from higher cost deepwater plays, combined with the offshore rig oversupply drove stock performance variance between onshore and offshore levered shares in 2014

The bounce in oil prices in mid-2015 illustrate that the bias towards oil services companies with greater onshore exposure persists. We believe investor sub-sector preferences may shift as the offshore rig market comes into balance and investors see evidence of lower break-even levels for large scale offshore projects. Thus, we believe onshore levered stocks may lead the initial stages of recovery in the group.

Source: Factset

Indexed Return For Onshore vs. Offshore Levered Stocks Drillers


US Land Rig Forecast Finds Bottom in 4Q15/1Q16

1,68

9 1,77

5 1,88

6 1,

828

1,28

3 87

9 930

1,09

9 1,

286

1,45

1 1,58

7 1,

648

1,67

4 1,77

8 1,89

3 1,

954

1,94

7 1,

924

1,85

5 1,

759

1,70

6 1,

710

1,69

1 1,

682

1,70

5 1,79

6 1,

828

1,84

3 1,

346

873

832

630 69

9 82

5 93

0 1,02

4 1,

230

1,30

5 1,

306

1,30

8 1,

310

1,31

2 1,

314

1,31

6 1,

345

1,37

5 1,

405

1,43

7 1,

453

1,46

8 1,

483

1,49

8

500

600

700

800

900

1,000

1,100

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

2,000

1Q

08

3Q

08

1Q

09

3Q

09

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

3Q

12

1Q

13

3Q

13

1Q

14

3Q

14

1Q

15

3Q

15

1Q

16

3Q

16

1Q

17

3Q

17

1Q

18

3Q

18

1Q

19

3Q

19

1Q

20

3Q

20

# o

f R

igs

Our forecast implies a steep decline in rig activity through the course of 4Q15

We forecast a recovery in activity during 2016, corresponding with a rebound in oil prices. A risk to our forecast remains a front end weighted 2016 spending profile, which may pause, dependent on the progression of commodity prices. As a result our front end rig count forecast may prove low, the progression of recovery in 2016 may pause or reverse.

Sources: KLR Group, LLC Forecasts; BHI, Factset

Quarterly US Lang Rig Count


-

20

40

60

80

100

120

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

35.0%

40.0%

45.0%

50.0%

55.0%

60.0%

65.0%

70.0%

75.0%

80.0%

1Q

10

3Q

10

1Q

11

3Q

11

1Q

12

3Q

12

1Q

13

3Q

13

1Q

14

3Q

14

1Q

15

3Q

15

1Q

16

3Q

16

1Q

17

3Q

17

1Q

18

3Q

18

1Q

19

3Q

19

1Q

20

3Q

20

Funding Gap WTI

-

200

400

600

800

1,000

1,200

1,400

1,600

-

500

1,000

1,500

2,000

2,5001Q

00

1Q0

1

1Q0

2

1Q0

3

1Q04

1Q05

1Q06

1Q07

1Q0

8

1Q0

9

1Q1

0

1Q1

1

1Q1

2

1Q1

3

1Q1

4

1Q1

5

1Q1

6

1Q1

7

1Q1

8

1Q1

9

1Q2

0

US Land Rigs Horizontal Rigs

US Land Rig Count Bottoms as E&P CAPEX Nears Cash Flow From Operations & Funding Gaps Erode

The period of rising oil prices, borrowing base growth, higher debt, lower cost of capital, and significant funding gaps reverses course as commodity prices fall. In our view, E&P companies may spend more closely within operating cash flow in the near term. Any significant re-leveraging of activity may make our activity forecast conservative.

US Land Rigs Trough in 2016, Greater Recovery in 2017 Falling Funding Gaps: Cyclical Deceleration

The US land rig count bottoms in 4Q15/1Q16, as E&Ps return to working closer to organic cash flows. If oil prices sit near the bottom and the industry has deleveraged activity (reduced funding gaps), the negative cash flow headwinds on the US land rigs count have diminished.

Sources: KLR Group, LLC Forecasts; BHI, Factset Sources: KLR Group, LLC Forecasts; BHI, Factset


-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,0001

Q0

0

1Q

01

1Q

02

1Q

03

1Q

04

1Q

05

1Q

06

1Q

07

1Q

08

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09

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11

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17

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20

Ind

exe

d C

AP

EX &

CFO

CFO Indexed (Rolling 2 Quarter Average) CAPEX Indexed

-

200

400

600

800

1,000

1,200

1,400

1,600

100

300

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

1Q

00

1Q

01

1Q

02

1Q

03

1Q

04

1Q

05

1Q

06

1Q

07

1Q

08

1Q

09

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10

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11

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12

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13

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14

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15

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16

1Q

17

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18

1Q

19

1Q

20

Ho

rizo

nta

l Rig

Co

un

t

Ind

exed

CA

PEX

Sp

end

CAPEX Indexed Horizontal Rigs

Our proprietary model distills history to capture the clear relationships between the commodity, cash flows, and US rig counts. Tied to the KLR forecast for oil price recovery, we see a rig count trough in 2016, with a more meaningful recovery in activity in 2017, with oil prices at $85. Key Relationships Captured: • E&P Cash Flow from Operations (CFO) & WTI (R-Squared>0.90) • E&P Cash Flow from Operations (CFO) & CAPEX (R-Squared>0.80) • Historical & Forecasted Funding Gaps (CFO-CAPEX) • Inflation/deflation • Rig Efficiency (well/rig) • Service Cost Intensity • 60 E&P sample set • 15 years of historical data

Proprietary Model Captures Relationships Between WTI, CFO, CAPEX, Funding Gaps, & Rig Counts

Sources: KLR Group, LLC Forecasts; BHI, Factset Sources: KLR Group, LLC Forecasts; BHI, Factset

Indexed Increase in Capex & Cash Flow from Operations Indexed Capex & Horizontal Rig Changes & Forward Forecast


High Yield Energy Market Has Choked-Off E&P’s Capacity To Run Funding Gaps

12.6

5

7

9

11

13

15

17

Dec

-04

Jun

-05

Dec

-05

Jun

-06

Dec

-06

Jun

-07

Dec

-07

Jun

-08

Dec

-08

Jun

-09

Dec

-09

Jun

-10

Dec

-10

Jun

-11

Dec

-11

Jun

-12

Dec

-12

Jun

-13

Dec

-13

Jun

-14

Dec

-14

Jun

-15

Dec

-15

Imp

lie

d Y

ield

(%)

Source: Factset

BofA Merrill Lynch US High Yield Energy Index (MLH0EN)

Prohibitive costs of capital may send a message that debt capital markets are largely closed to E&P operators. With debt markets closing, funding gaps may need to narrow and E&Ps may need to tap equity markets to fund growth or fix balance sheets.


US Land Activity Hinges on Oil Prices & Leverage in the Rig Count Sensitivity Analysis

Oil Price$30 $40 $50 $60 $70 $80 $90 $100 $110 $120

50% 609 863 1,117 1,371 1,625 1,879 2,133 2,387 2,640 2,894

45% 554 785 1,016 1,246 1,477 1,708 1,939 2,170 2,400 2,631

40% 508 719 931 1,142 1,354 1,566 1,777 1,989 2,200 2,412

35% 469 664 859 1,055 1,250 1,445 1,641 1,836 2,031 2,226

30% 435 617 798 979 1,161 1,342 1,523 1,705 1,886 2,067

25% 406 575 745 914 1,083 1,253 1,422 1,591 1,760 1,930

20% 381 540 698 857 1,016 1,174 1,333 1,492 1,650 1,809

15% 358 508 657 806 956 1,105 1,255 1,404 1,553 1,703

10% 339 480 621 762 903 1,044 1,185 1,326 1,467 1,608

5% 321 454 588 722 855 989 1,122 1,256 1,390 1,523

0% 305 432 559 685 812 939 1,066 1,193 1,320 1,447

Fu

nd

ing

Gap

Note: Assumes 80% Horizontal Rig Count/Total Land Rig Count

Our post-recovery forecast lives here.

Our 4Q15/1Q16 forecast lies in this range, further constrictions on funding gaps or oil prices see risks of activity trending down and to the left on the table.

Our Proprietary Model Measures Commodity vs. Industry Funding Gap Sensitivities

Sources: KLR Group, LLC Forecasts; Factset


US Land Drilling Market


1,359

1,055

701 658

498 553

653 736

810

973 1,032 1,033 1,035 1,036 1,038 1,039 1,041

132%

102%

68%64%

48%54%

63%

71%

79%

94%100% 100% 100% 100% 101% 101% 101%

0%

20%

40%

60%

80%

100%

120%

140%

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

1,500+ AC 1,000 - 1,499 AC 1,500+ SCR 1,000 - 1,499 SCR Horizontal Rig Count Implied AC Rig Utilization

AC Rig Utilization May Tighten Through 2016 With Horizontal Land Rig Count Recovery

Rig Market Utilization Climbs Under Our Horizontal Rig Count Forecast

The high end of the land rig market may come into balance in 2H16, if our rig count forecast is correct and fleet growth remains curtailed by the downturn.

Simplified land rig

dispatch curve

Sources: KLR Group, LLC Forecasts; RigData; DrillingInfo


Segmented Market: Better Demand for AC 1,500+HP Rigs, Tougher Competition for the Rest

19 212

820

58

252

371

922

446

389

7 57 100135

21% 22%

47%

12%

23%

27%

15%

-

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

-

100

200

300

400

500

600

700

800

900

1,000

AC(1 - 999hp)

AC(1,000 -

1,499hp)

AC(1,500+hp)

SCR(1 - 999hp)

SCR(1,000 -

1,499hp)

SCR(1,500+hp)

MechTotal

Marketed Supply (Current) Working/Active Utilization

1,051

681

922

439

164 135

42%

24%

15%

-

5%

10%

15%

20%

25%

30%

35%

40%

45%

-

200

400

600

800

1,000

1,200

1,400

ACTotal

SCRTotal

MechTotal

Marketed Supply (Current) Working/Active Utilization

Non-AC Rigs Most Hurt By Downturn AC 1,500+ HP Rigs Remain in Highest Demand

Sources: KLR Group, LLC Forecasts; DrillingInfo; RigData; Quarterly/Annual Rig Operators’ Disclosures Sources: KLR Group, LLC Forecasts; DrillingInfo; RigData; Quarterly/Annual Rig Operators’ Disclosures


HP, NBR, PTEN May Be Winners, Representing >60% of AC Rig Fleet Composition

1 - 999

1,000 -

1,499 1,500+ Total 1 - 999

1,000 -

1,499 1,500+ Total Total % % %

AC AC AC AC SCR SCR SCR SCR Mech TOTAL AC SCR Mech

Helmerich & Payne (HP) - 24 317 341 - - 8 8 - 349 32% 1% 0%

Nabors Industries (NBR) 3 72 103 178 11 33 53 97 1 276 17% 14% 0%

Patterson-UTI Energy (PTEN) - 15 102 117 2 33 42 77 15 209 11% 11% 2%

Precision Dril l ing (PD-TSX) - 26 45 71 1 22 31 54 8 133 7% 8% 1%

Ensign Energy Services (ESI-TSX) 13 1 55 69 - 1 - 1 27 98 7% 0% 3%

Seventy Seven Energy (SSN) - 18 18 36 12 26 14 52 4 92 3% 8% 0%

Unit Corporation (UNT) - - 10 10 4 12 37 53 31 94 1% 8% 3%

Trinidad Drill ing (TDG-TSX) - - 33 33 4 2 11 17 21 71 3% 2% 2%

Xtreme Drill ing & Coil Services 3 4 9 16 - - - - - 16 2% 0% 0%

Cactus Dril l ing Company, LLC - - 12 12 2 15 34 51 - 63 1% 7% 0%

Pioneer Energy Services (PES) - 2 13 15 - 4 8 12 3 30 1% 2% 0%

Sidewinder Dril l ing - 2 10 12 - 4 6 10 20 42 1% 1% 2%

Independence Drill ing, Inc. - - 14 14 - - - - - 14 1% 0% 0%

Oil States International (OIS) - - - - - - - - 34 34 0% 0% 4%

Global Rig Company (GRIC-NO) - - 9 9 - - - - - 9 1% 0% 0%

Felderhoff Brothers Dril l ing - - 3 3 - 4 1 5 15 23 0% 1% 2%

Cyclone Drill ing Inc. - - 6 6 - 9 8 17 3 26 1% 2% 0%

Latshaw Drill ing - 5 5 10 5 11 14 30 1 41 1% 4% 0%

Scandrill - - 1 1 - 4 11 15 1 17 0% 2% 0%

Savanna Energy Services (SVY-TSX) - 5 3 8 - - 1 1 18 28 1% 0% 2%

Other - 38 52 90 17 72 92 181 720 991 9% 27% 78%

Marketed Supply (Current) 19 212 820 1,051 58 252 371 681 922 2,656

% of Total Market

US Land Rig Fleet Composition By Company

In our view, the land contract drillers with the highest concentration of AC rigs should be the long term winners. Our Coverage: • HP: Play on the highest

concentration of AC 1,500+ rigs

• NBR: Leverage to quality fleet, international exposure, and internal transformation story

• PTEN: More lower end rigs in fleet profile, but likely the most stock leverage to a recovery in North American land activity

Sources: DrillingInfo; RigData; Quarterly/Annual Rig Operators’ Disclosures


US Pressure Pumping Market Poised for 2016/2017 Rebound


Simplified Model Suggests A Recovery With Capacity Attrition & Horizontal Rig Count Recovery

Assumptions & Potential Incremental Positive Catalysts that Underlie Our Pressure Pumping Supply/Demand Outlook • Industry sources suggest horsepower capacity in the market is closer to 20m HP • Limited disclosures make it difficult to determine the company composition of the fleet, but we assume that HAL, SLB, and WFT, RES, CJES, and PTEN comprise the majority of

capacity amongst 40+ pressure pumping operators. • Bankruptcy/auctioning of equipment may likely continue to reduce the number of competitors near term • We assume stacked equipment returns, which may prove optimistic if it is not maintained or if it is cannibalized • Natural “wear & tear” supports our 15% annualized attrition rate, as pressure pumping equipment is worked harder on larger fracs with increasing levels of proppant.

(Transmission life ~1 year, Fluid Ends life 1-2months) • HAL/BHI merger may accelerate equipment attrition, as HAL’s transition to Q10 units may see legacy BHI equipment leave the fleet at a faster rate

3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

Horsepower, BOP (m) 20.0 19.4 18.9 18.3 16.8 16.4 14.9 15.3 16.8 17.1 17.5 17.8 18.2 18.5

Stacked (m) (4.0) (5.0) (5.0) (5.0) (4.0) (3.0) (1.0) - - - - - - -

Marketed Horsepower, BOP (m) 16.0 14.4 13.9 13.3 12.8 13.4 13.9 15.3 16.8 17.1 17.5 17.8 18.2 18.5

Additions (m) - - - - 1.0 1.0 2.0 2.0 1.0 1.0 1.0 1.0 1.0 1.0

Attrition/Cannibalization (m) (0.6) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.6) (0.6) (0.6) (0.7) (0.7) (0.7) (0.7)

Marketed Horsepower, EOP (m) 15.4 13.9 13.3 12.8 13.4 13.9 15.3 16.8 17.1 17.5 17.8 18.2 18.5 18.8

Marketed Hoursepower, Per. Avg. (m) 17.7 16.6 16.1 15.6 15.1 15.1 15.1 16.1 16.9 17.3 17.7 18.0 18.3 18.6

Demand (m) 10.5 7.9 8.6 10.1 11.3 12.3 14.6 15.3 15.2 15.1 14.9 14.8 14.7 14.6

Utilization 59% 47% 54% 65% 75% 81% 97% 96% 90% 87% 85% 82% 80% 78%

Attrition Rate (Annual) 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15% 15%

KLR - US Horizontal Rig Count Forecast 658 498 553 653 736 810 973 1,032 1,033 1,035 1,036 1,038 1,039 1,041

Horsepower / Hor. Rig (000) 15.9 15.8 15.6 15.5 15.3 15.2 15.0 14.9 14.7 14.6 14.4 14.3 14.1 14.0

Horsepower / Hor. Rig Efficiency Gains 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1%

Source: BHI; Industry sources; KLR Group, LLC Forecasts


US Proppant Market Balances More Opaque


Proppant Companies: Lagging Absorption of High Fixed Costs Translate Into Later Cycle Play Delayed Recovery for the Proppant Market. The proppant market may recover with an increase in US land drilling activity, but a number of factors likely delay a fuller recovery of capacity utilization. In our view, more visibility for a recovery within land drilling and pressure pumping markets create a better risk/reward for exposure to a recovery in US activity. We acknowledge proppant names may remain high beta, which may lead the group to outperform other sub-segments with exposure to the North American market. Given a number of drivers outlined below, we continue to seek a better entry point, once the risk/reward balance tips more favorably.

Key Drivers & Concerns

• Negative Operating Leverage. High fixed costs business models continue to suffer from adverse operating leverage in the near term without a meaningful improvement in volumes, which we do not see until 2017. In our forecast, proppant demand does not recover to 1H15 run rates until the end of 2016.

• Logistics Asset Overhang. Ownership and leases of rail cars, once a competitive advantage in a tight market, may continue weigh on operating results, as pressure pumping companies prefer to utilize their rail cars to improve operating leverage. A perceived shift in the absorption of logistics infrastructure should prove an important turning point for proppant shares, but we do not foresee the transition in the near to medium term.

• Fragmented Market. Given a fragmented market, we do not have good visibility into capacity coming offline to balance the market. We also suspect that mothballed plants may return to service with relative ease, perpetuating an overhang an industry that is capitalized to service activity closer to the recent US peak.

• Tougher Company Differentiation. Ultimately, the companies with the lowest cost and best operating footprint (scale) may be the longer term winners amongst the proppant group. At the peak, SLCA and FMSA, with the largest logistics networks across key basins, were able to differentiate on service capabilities. In the trough, reduced strain on logistics has limited the focus on this competitive advantage.

• Potential for Consolidation. Given fragmentation of the market, higher cost producers may ultimately exit the market and other companies may be consolidated. Both of these outcomes may be positive catalysts of the group. We have Emerge (EMES) and Hi-Crush (HCLP) as potential M&A targets. In our view, the suspension of distributions for both may translate into a failure of their MLP models. If so, depressed valuations and tougher individual company prospects may see assets better exploited within a larger entity.


Proppant Volume Recovery Does Not Boost Utilization Until Beyond 2016

0

20

40

60

80

100

120

140

160

180

-

200

400

600

800

1,000

1,200

1,400

1,600

1Q

13

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13

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13

4Q

13

1Q

14

2Q

14

3Q

14

4Q

14

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

US Horizontal Rig Count (Forecast)

US Horizontal Rig Count

Indexed Average Proppant Volumes Forecast 55.0%

51.0%50.6%

48.0%

44.0%

46.0%

48.0%

50.0%

52.0%

54.0%

56.0%

SLCA FMSA HCLP CRR

Anemic Volumes Strain High Fixed Cost Operations

Source: Volumes based on CRR; SLCA; FMSA; & KLR Group, LLC Forecasts

Current Capacity Utilization by Public Company

A modest rig count recovery in 2016 likely leaves proppant production capacity under utilized, especially in a fragmented market where we have little visibility into capacity attrition. Balances may improve in 2017, which should prove positive for proppant shares closer to the turn. In our view, evidence of improving market balances may prove too far away and overhang shares near term.

A modest rig count recovery in 2016, but proppant sales volumes only exit the year near 3Q15 levels, in our view. As a result, we do not see a material improvement in utilization and economics, which may delay the recovery proppant shares relative to Land Contract Drillers and Pressure Pumping companies.

Source: Volumes based on CRR; SLCA; FMSA; EMES; HCLP; KLR Group, LLC Forecasts


International Markets


Larger Projects, Less Infrastructure: Creates Lag in International Decline & Recovery

International Activity Declines Lagged North America, But Persist Into 2016. International projects are larger scale, significant capital expenditures, that have long lead times. Once multi-year development plans pass through final investment decision (FID), the projects push forward. As a result, international activity has more consistency. Projects may be pushed to the right and delays may drag on activity when the commodity is under pressure, but approved projects generally move forward. Within the process, year end budgeting cycles, when IOCs decide to move forward with projects, set the tone for international project activity over the coming year. Demonstrated by more stable activity in the Middle East, NOC activity may not closely track the commodity, given varying priorities, policy issues at the national level, and strategic initiatives at OPEC. We continue to see the region pulling up international activity averages. We remain watchful of persistent high Middle East rigs counts, drilling to support a quest for OPEC market share, as upstream spending may begin to conflict with budget constraints. With 2015 largely complete, international rig counts are down ~10% Y/Y. Amid IOC’s bleak 2016 budget tones, we forecast international budgets down another 5% in 2016.

International Production Declines Likely a Key Catalyst for Oil Price Recovery. The resultant decline in international and North American rig counts calls for falling international production within the KLR forecast. (pg. 57) In turn, falling international production, still 85%-90% of global oil supply, likely contributes to the turn in oil market balances. Per above, unlike unconventional activity in the US, international upstream investment may take time to turn. The market may need to incentivize a return of spending with higher oil price scenarios.

Structural Cost Efficiencies May Accelerate Upturn, but Short Term Pricing Pressure Persists. Oil service companies indicate that contract renegotiations and pricing pressure persist. In our view, a lack of meaningful pricing recovery from the 2008/2009 downturn may leave less pricing to strip from existing contract structures. We believe international upstream operators seek greater efficiencies to re-adjust cost structures and make more of their portfolio economic, especially for offshore projects. If operators and oil service companies can bring down break even levels, more projects may come forward during the 2016 and 2017 budgeting cycles to accelerate activity in the upturn.

Structural Need for Greater Rig and Service Intensity in International Markets. International activity remains largely conventional. Productivity per rig has declined ~50% in the last 10 years, as more exploration and greater drilling intensity is needed to offset decline rates from legacy fields and grow production. (pg. 58) We anticipate the need for higher rig counts may persist. In our view, activity declines in 2015/2016 may lead to negative international oil supply revisions, if current rig productivity relationships hold. A short term dearth in rig counts, fuels our forecast for a greater recovery in 2017/2018, as budgeting cycles accelerate activity with a rebound in commodity prices. Although not imminent, a shift toward international unconventional plays or greater transfer of international methods may lend upside to our rig and service intensity assumptions.

Middle East Activity Remains Positive Outlier. OPEC’s battle for market share, which began in November 2014, looks to maintain robust activity in the Middle East. In particular, Saudi Arabia remains a strong outlier, with increased activity since 2014. As OPEC spare capacity narrows as a percentage of demand, the Middle East, and Saudi in particular, may need to press ahead with efforts to maintain spare capacity. Global inventories and oversupply provide a temporary cushion. Both may fade with declining upstream investment across the world. In order to avoid a price spike or a perceived loss of OPEC’s control of the oil market, the group needs to invest in production capacity to meet potential supply shortfalls.


KLR Rig Count Forecast Sees Further 2016 Downside, With Slow 1Q16 Start & Offshore Decline

KLR Global Rig Count Forecast

Source: BHI; Industry sources; KLR Group, LLC Forecasts

2003 2004 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015E 2016E 2017E 2018E 2019E 2020E

Land 1,719 2,008 2,012 2,176 1,269 1,842 2,245 2,235 2,050 2,172 1,121 1,031 1,454 1,488 1,567 1,654

Y/Y 17% 0% 8% (42%) 45% 22% (0%) (8%) 6% (48%) (8%) 41% 2% 5% 6%

Offshore 93 90 73 65 44 32 32 47 56 57 35 24 26 35 37 35

Y/Y (4%) (19%) (10%) (33%) (28%) 2% 48% 18% 2% (39%) (31%) 10% 35% 4% (4%)

North America 1,812 2,098 2,085 2,241 1,313 1,874 2,277 2,282 2,106 2,230 1,155 1,055 1,480 1,523 1,604 1,689

Land 251 260 283 305 281 308 338 342 332 323 267 272 274 297 303 317

4% 9% 8% (8%) 10% 10% 1% (3%) (3%) (17%) 2% 1% 8% 2% 5%

Offshore 64 63 72 79 75 76 86 82 86 74 61 41 48 54 58 56

(2%) 13% 10% (4%) 0% 13% (5%) 6% (14%) (18%) (32%) 18% 11% 8% (3%)

Latin America 316 324 355 384 356 383 424 423 419 397 328 313 322 351 361 373

Land 25 26 28 49 36 45 70 73 85 95 67 59 63 85 87 91

3% 8% 74% (26%) 24% 56% 4% 18% 12% (30%) (12%) 7% 34% 2% 5%

Offshore 45 52 50 49 47 49 48 46 50 50 46 33 34 39 40 43

15% (3%) (1%) (4%) 4% (3%) (3%) 7% 0% (8%) (28%) 4% 15% 3% 8%

Europe 70 77 78 98 84 94 118 119 135 145 113 92 97 124 127 134

Land 36 42 51 50 48 57 51 64 90 94 75 61 52 66 77 79

18% 22% (3%) (3%) 18% (11%) 26% 39% 5% (21%) (18%) (15%) 29% 16% 3%

Offshore 14 16 15 15 13 26 27 31 36 40 32 24 35 37 34 39

14% (6%) 2% (13%) 94% 3% 18% 14% 11% (19%) (25%) 47% 4% (8%) 15%

Africa 50 58 66 65 62 83 78 96 125 134 107 85 87 103 111 118

Land 116 119 124 134 136 150 151 144 142 138 127 121 126 162 176 181

2% 4% 8% 2% 10% 1% (4%) (1%) (3%) (8%) (5%) 4% 29% 8% 3%

Offshore 109 109 117 118 107 120 106 97 103 116 95 86 87 103 110 111

1% 7% 1% (9%) 12% (12%) (8%) 7% 12% (18%) (10%) 2% 17% 8% 1%

Asia Pac 225 228 241 252 243 269 256 241 246 254 222 206 213 265 286 292

Land 214 209 233 246 220 229 253 309 329 360 353 346 349 414 442 457

(3%) 12% 6% (11%) 4% 10% 22% 6% 10% (2%) (2%) 1% 18% 7% 3%

Offshore 33 29 32 34 32 35 39 47 44 46 49 58 68 77 87 97

(13%) 11% 4% (4%) 10% 10% 20% (6%) 6% 6% 18% 17% 14% 13% 11%

Middle East 248 238 265 280 252 265 291 356 372 406 402 404 417 491 529 554

International Land 643 656 720 784 722 789 863 932 978 1,011 889 859 864 1,024 1,085 1,126

Y/Y 2% 10% 9% (8%) 9% 9% 8% 5% 3% (12%) (3%) 1% 18% 6% 4%

International Offshore 382 386 415 429 387 424 432 484 517 565 525 489 506 592 626 651

Y/Y 1% 8% 3% (10%) 9% 2% 12% 7% 9% (7%) (7%) 4% 17% 6% 4%

International Total 1,024 1,042 1,134 1,212 1,109 1,213 1,295 1,415 1,495 1,576 1,414 1,348 1,370 1,616 1,711 1,777

Y/Y 2% 9% 7% (9%) 9% 7% 9% 6% 5% (10%) (5%) 2% 18% 6% 4%

Eastern Hemishere 592 602 650 695 640 711 743 811 878 939 843 788 814 982 1,053 1,099

Y/Y 2% 8% 7% (8%) 11% 5% 9% 8% 7% (10%) (7%) 3% 21% 7% 4%

Western Hemisphere 2,128 2,421 2,440 2,626 1,669 2,257 2,701 2,706 2,525 2,627 1,483 1,368 1,803 1,874 1,965 2,062

Y/Y 14% 1% 8% (36%) 35% 20% 0% (7%) 4% (44%) (8%) 32% 4% 5% 5%


International Production (ex FSU) Falls With Rig Decline, Rig Count Recovery May Lag Commodity Uptick

45.0

46.0

47.0

48.0

49.0

50.0

51.0

52.0

53.0

54.0

-

200

400

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800

1,000

1,200

1,400

1,600

1Q03

3Q0

3

1Q0

4

3Q04

1Q0

5

3Q05

1Q06

3Q0

6

1Q07

3Q07

1Q0

8

3Q08

1Q0

9

3Q0

9

1Q10

3Q1

0

1Q1

1

3Q11

1Q1

2

3Q12

1Q13

3Q1

3

1Q14

3Q1

4

1Q1

5

3Q15

1Q1

6

3Q1

6

1Q17

3Q1

7

1Q18

3Q18

1Q1

9

3Q19

1Q20

3Q2

0

World Production, ex NA & FSU World Rigs, ex NA & FSUKLR Forecasts international production declines through 2017

International rigs counts decline to a slower elongated trough, without meaningful recovery until 2018. Given more stringent scrutiny of larger, longer lead time international projects, confidence to reach final investment decision for these larger capital expenditures may lay the recovery in the oil price.

Source: BHI; IHS Petrodata; KLR Group, LLC Forecasts


Over 10+ Years, International Oil Production/Rig is Down ~50%, vs. North America Up ~20%

100 99 99 94 96 97 95

92 94 96

99 104

112

120

130 133

129 127

100 95

92 92

81

70

79

69

61 57

54 53

60 63 61

53 50 51

40

50

60

70

80

90

100

110

120

130

140

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

E

2016

E

2017

E

2018

E

2019

E

2020

E

Pro

du

ctio

n /

Rig

Ind

exe

d

North America InternationalThe boom in unconventional play in North America has vaulted well, and therefore rig activity.

Field maturity, the need for greater exploration efforts to replace production, slower technology penetration, and a lack of unconventional activity continues to drive down rig productivity in international markets.

Need for greater service intensity to improve production

Need for greater rig and service intensity to improve production. If unconventional techniques or greater use of technology emerges on larger scales, international service companies that possess the technology and intellectual property, may prove the beneficiaries.

North America vs. International Indexed Oil Production / Rig

Source: EIA; IEA; BHI; KLR Group, LLC Forecasts


-

20

40

60

80

100

120

Jan

-13

Mar

-13

May

-13

Jul-

13

Sep-

13

Nov

-13

Jan

-14

Mar

-14

May

-14

Jul-

14

Se

p-1

4

Nov

-14

Jan

-15

Mar

-15

May

-15

Jul-

15

Sep-

15

Iraq Kuwait Oman Saudi Arabia

-

50

100

150

200

250

300

350

400

450

500

600

650

700

750

800

850

900

950

1,000Ja

n-0

5

Au

g-0

5

Mar

-06

Oct

-06

May

-07

Dec

-07

Jul-

08

Feb

-09

Se

p-0

9

Ap

r-1

0

No

v-1

0

Jun

-11

Jan

-12

Au

g-1

2

Mar

-13

Oct

-13

May

-14

De

c-1

4

Jul-

15

ME

Rig

Co

un

ts

Inte

rnat

ion

al, L

ess

ME

Rig

Co

un

ts

International, Less ME ME

Middle East Rig Count Resilience Reflects OPEC (Saudi Arabian) Efforts to Gain Market Share

OPEC may gain market share, but the group needs to expand production, as spare capacity sit near lows as a ~3% to daily production

Middle East Seeks Mkt Share, Holds Rigs Amid Intl. Decline Saudi Arabia Clearly Pushing to Grow Production Capacity

Instability has taken its toll on Iraq, but discussion of budget restrictions amid falling oil-driven cash flows may curtail activity entering 2016.

Source: BHI IEA; KLR Group, LLC Forecasts Source: BHI IEA; KLR Group, LLC Forecasts


Offshore Rig Markets


Distressed Offshore Drilling Sector Offers Values, But Faces Headwinds Through 2016/2017 Offshore Drillers Offers Value for Patient Investors. The offshore drillers remain one of the most reviled sub sectors within oilfield services, even though a number of names present attractive longer term value plays. Oversupply, falling demand through 2016, persistent dayrate declines toward cash costs (or below), and the need for significant rig attrition/cold stacking across floater and jackup fleets may continue to present headwinds for shares. Ultimately, it makes the group a high beta play on a longer term cyclical recovery, which may transition the stocks from laggards to leaders with signs of fundamental recovery in rig market balances. Amid a wide estimate range, we continue to see choppy trading in the near to medium term in the face of low visibility and high short interest for the group. In the interim, efforts to control costs and improve execution efficiency may continue to support positive earnings surprises. Estimates that mirror bearish sentiment set a low bar. Offshore driller shares may need continued rig attrition and signs of demand recovery (2017 budgeting cycle a year out) for sustained share advances versus “short squeeze” rallies. Continued rig retirement/cold stacking announcements, which justify our forecast for 60-70 floater & ~125 jackup retirements, may prove meaningful positive catalysts. For investors seeking exposure to the group, NE ($11.90, B, $16.00PT), ESV($14.96, B, $20.00PT), RDC ($17.50, B, $25.00PT) presently relatively safer plays, while RIG ($12.69, B, $19.00PT) may offer a more interesting transformation story. Balance sheet issues and less attractive valuations rank other drillers further down the list, where PACD ($0.97, H, $3.00PT) and ATW ($13.15, H, $12.50PT) present the highest balance sheet related risks. Proprietary Floater Market Demand Model Sees ~26% Decline in 2016, Fuller Recovery by 2018. Our field-by-field analysis of floater demand sees significantly lower rig counts in 2016, driven by a precipitous ~40% Y/Y decline in exploration and ~17% fall in development drilling (pgs. 61-76). We see little chance for upward revisions to rig demand without a sustained turn in commodity sentiment in front of the 2017 budgeting cycle, where new projects may reach final investment decision (FID). Behind the scenes, we expect project breakeven levels to come down, as upstream operators seek efficiencies in the effort to monetize assets. Beyond 2016, the collapse in exploration spending is not sustainable, if operators look to replace reserves and maintain production profiles. Meanwhile, we expect development demand to remain more stable, as previously approved projects continue and companies continue to seek opportunities to monetize assets. Jackup Market Balances Sloppy, But Less Visible. Since we are not privy to project-by-project data for the jackup market, it is tougher to model. We forecast single digit demand declines in 2016, but believe supply may remain the key driver. Only 15% of the existing 91 newbuild orders come from established drillers, which questions the number of final deliveries. Assuming all are delivered, the market may require ~125 older rigs to exit in 2016/2017 to achieve balance. Given a more fragmented market, we believe the quest for the better supply/demand balances may leave the market sloppy until 2018. With cleaner market balances, better visibility, fewer (potentially) rational players, we prefer floater market exposure. Given a highly speculative order book, many rigs on order may not come to market, which may prove a lurking bullish catalyst for the jackup market. We are not ready to factor order book decline into our supply analysis at this point. Proprietary Rig Attrition Model Targets 60-70 Floater & 125 Jackup Retirements. Originally constructed in 2013, we have refreshed our floater and jackup rig attrition model. As outlined in slides 76-92 below, we created a multi-factor weighting for each rig in the offshore fleet. In our view, rigs with lower scores, idle, soon to roll off contract, facing regulatory surveys, or that require significant capital expenditures may screen for retirement. Ultimately, we believe an incremental 60-70 floaters and ~125 jackups may need to retire or exit the market to bring floater and jackup market balances closer to more manageable 80%-90% utilization levels. Given our rig scores, many of these retirements across fleets may come from older, less capable assets. We anticipate this process may accelerate from the ~40 floaters already retired and limited jackup exits to date. Competition on dayrates may prove more intense during the rig shake-out, so we might experience disorderly markets in 2016.

Consolidation of Distressed Assets, Not Companies. The current downturn may likely see distressed assets come to the market. DO ($20.15, H, $24.00PT) and RIG, given older fleet profiles, may be the most likely acquirers. VTG ($0.00, NR, filed restructuring plan), PGN ($0.20, NR), PACD, ODL-NO (NOK4.80, NR), and SDRL ($4.16, R, $3.50PT) appear the most likely candidates as sources of distressed assets, along with shipyards that may be left in possession of cancelled orders. In our view, we see potential transactions for rigs, not companies, as acquirers may not want to pay up for distressed debt at par. Also, with possible two year holding periods for assets without contracts and low initial contract dayrates, clearing prices for ultra-deepwater rigs may lie closer to $300-400 million (pg. 74-75), well below $650-700 million construction costs. The market may be interested at ~50% of build costs, but it may take “work-out” scenarios to bring the market to those levels.


Offshore Equipment & Services Outperform Offshore Drillers, Until Rig Oversupply Abates

Note: Offshore Drillers index includes RIG, ESV, DO, NE, RDC, and ATW equally weighted performance from 1/1/06 to 12/12/15 Offshore Equipment/Services index includes OIS, FTI, OII, and DRQ equally weighted performance from 1/1/06 to 12/12/15

126%

-59%

149%

115%

(125%) (100%)

(75%) (50%) (25%)

-25%50%75%

100%125%150%175%200%225%250%275%

1Q0

6

3Q0

6

1Q0

7

3Q0

7

1Q0

8

3Q0

8

1Q0

9

3Q0

9

1Q1

0

3Q1

0

1Q1

1

3Q1

1

1Q1

2

3Q1

2

1Q1

3

3Q1

3

1Q1

4

3Q1

4

1Q1

5

3Q1

5

1Q1

6E

3Q1

6E

1Q1

7E

3Q1

7E

Ind

exe

d E

PS

Gro

wth

(%)

Offshore Drillers Offshore Equipment/Services

Offshore Drillers Est Offshore Equipment/Services Est

-62%

127%

(75%) (50%) (25%)

-25%50%75%

100%125%150%175%200%225%250%275%300%325%350%375%400%425%

Jan

-06

Jul-

06

Jan

-07

Jul-

07

Jan

-08

Jul-

08

Jan

-09

Jul-

09

Jan

-10

Jul-

10

Jan

-11

Jul-

11

Jan

-12

Jul-

12

Jan

-13

Jul-

13

Jan

-14

Jul-

14

Jan

-15

Jul-

15

Ind

exe

d S

har

e P

erf

orm

ance

(%)

Offshore Drillers Offshore Equipment/Services

Source: Factset Source: Factset; KLR Group, LLC Forecast

Offshore Equipment Outperforms Offshore Drillers Better Equipment Outlook Explains Performance

An increase in offshore activity may improve the outlook for offshore equipment demand and offshore rigs. Larger utilization issues may drive a lag in dayrate recovery and hamper the earnings profile off the offshore contract drillers. As a result, Equipment names may outperform in the initial phases in the recovery of the oil services group.

The offshore drillers shares remain a structural underperformer relative to offshore equipment shares. A change in the market’s view has greater hurdles for the offshore drillers. Conversely, recent history suggests the potential for multiple expansion ahead of earnings estimate recovery of offshore equipment stocks.


Offshore Driller Liquidation Values (NAV) Illustrate Investor Bias Toward Stronger Balance Sheets

P/NAV

Company Rating12/11

Price

KLR

TargetUpside 2015 2016 2017 2015 2016 2017 2015 2016 2016

SDRL Reduce 4.16$ 3.50$ (16%) 2.2x 3.8x 5.7x 5.8x 7.6x 8.0x $6 $9 45%

RIG Buy 12.69$ 19.00$ 50% 3.4x 26.8x 16.2x 3.9x 8.0x 7.3x $16 $19 67%

ESV Buy 14.96$ 20.00$ 34% 3.4x 6.7x 6.5x 4.6x 6.6x 6.5x $26 $27 55%

DO Accumulate 20.15$ 24.00$ 19% 7.6x 30.8x 70.1x 5.2x 6.9x 7.4x $14 $14 143%

NE Buy 11.90$ 16.00$ 34% 4.5x 10.4x 17.0x 4.7x 6.3x 6.7x $10 $11 110%

RDC Buy 17.50$ 25.00$ 43% 5.3x 7.2x 29.9x 4.0x 4.6x 6.3x $14 $16 110%

ATW Hold 13.15$ 12.50$ (5%) 1.7x 5.0x -- 3.2x 5.3x 8.0x $26 $32 40%

PACD Hold 0.97$ 3.00$ 209% 1.3x (1.8x) (2.9x) 4.2x 6.9x 6.6x ($0) $2 48%

Averages 46% 3.7x 11.1x 20.4x 4.4x 6.5x 7.1x 77%

P / E EV / EBITDA NAV / share

Market appears to favor potential consolidators, with stronger balance sheets on a P/NAV basis (square)

Offshore drillers with perceived weaker balances sheets trade at a discount to liquidation value. (ovals)

ESV, with a strong balance sheet, is an outlier. Potentially, the market is heavily discounting older assets. In our view, a positive screen on a P/NAV basis supports our Buy rating.

Source: Factset; Company Filings/Disclosures KLR Group, LLC Forecast


Company Value Composition – Older Assets Drive Little Value in Our Models


2015 Gross Fleet Value Breakdown ($ million) 2015 Gross Fleet Value Breakdown (%)

Ticker Jackups 2G Semis 3G Semis 4G Semis 5G Semis 6G Semis Other Total

ATW $608 - - $86 - $3,333 - $4,027

DO $169 $13 $150 $399 $362 $4,115 - $5,207

ESV $4,005 - $67 ($12) $2,044 $5,433 $33 $11,570

NE $1,917 - $105 $72 $230 $5,929 - $8,253

PACD - - - - - $2,930 - $2,930

RDC $2,559 - - - - $2,662 - $5,222

RIG $2,080 - $174 $570 $3,060 $11,770 - $17,654

SDRL $4,025 - - $30 $545 $12,770 - $17,370

TOTAL $15,364 $13 $496 $1,144 $6,241 $48,942 $33 $72,233

Ticker Jackups 2G Semis 3G Semis 4G Semis 5G Semis 6G Semis Other Total

ATW 15% - - 2% - 83% - 100%

DO 3% 0% 3% 8% 7% 79% - 100%

ESV 35% - 1% (0%) 18% 47% 0% 100%

NE 23% - 1% 1% 3% 72% - 100%

PACD - - - - - 100% - 100%

RDC 49% - - - - 51% - 100%

RIG 12% - 1% 3% 17% 67% - 100%

SDRL 23% - - 0% 3% 74% - 100%

TOTAL 21% 0% 1% 2% 9% 68% 0% 100%



Fragmented market, numbers of newbuilds from higher risk sponsors, and the need for far large rig attrition/stacking, we see a sloppier/longer jackup downturn

Dayrate Forecast: Floater Dayrates Inflect in 2017, Jackup Downturn Prolonged Until 2018

4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E 1Q18E 2Q18E 3Q18E 4Q18E 1Q19E 2Q19E 3Q19E 4Q19E 1Q20E 2Q20E 3Q20E 4Q20E

Floaters ($kpd)

6G HDHE 320 315 310 305 300 310 345 380 415 450 485 520 555 550 545 540 535 530 530 530 530

6G High 320 315 310 305 300 310 345 380 415 450 485 520 555 545 540 530 525 515 515 515 515

6G Low 320 315 310 305 300 310 345 380 415 450 485 520 555 545 530 520 505 495 495 495 495

5G HDHE 255 250 250 245 240 250 275 305 330 360 390 415 445 430 410 395 380 365 365 365 365

5G High 255 250 250 245 240 250 275 305 330 360 390 415 445 420 400 375 355 330 330 330 330

5G Low 255 250 250 245 240 250 275 305 330 360 390 415 445 410 370 335 300 265 265 265 265

4G HDHE 160 160 155 155 150 155 175 190 210 225 245 260 280 260 245 230 210 195 195 195 195

4G High 160 160 155 155 150 155 175 190 210 225 245 260 280 260 245 225 210 190 190 190 190

4G Low 160 160 155 155 150 155 175 190 210 225 245 260 280 255 235 210 190 165 165 165 165

3G HDHE 145 140 140 135 135 140 155 170 185 205 220 235 250 230 215 195 180 160 160 160 160

3G High 145 140 140 135 135 140 155 170 185 205 220 235 250 230 210 190 170 150 150 150 150

3G Low 145 140 140 135 135 140 155 170 185 205 220 235 250 225 205 180 160 135 135 135 135

Jackups ($kpd)

HDHE JU 120 120 120 120 120 120 120 135 150 165 180 195 210 205 200 190 185 180 180 180 180

Prem JU 85 85 85 85 85 85 85 100 115 130 145 160 175 175 170 170 165 165 165 165 165

High End JU 80 80 80 80 80 85 90 100 110 120 130 140 150 145 145 140 140 135 135 135 135

Standard JU 60 60 60 60 60 65 70 80 85 90 95 100 105 100 95 90 85 80 80 80 80

Sub-Standard JU 50 50 50 50 50 55 60 65 70 75 80 85 90 85 80 70 65 60 60 60 60

Commodity JU 40 40 40 40 40 45 50 55 60 65 70 75 80 75 70 60 55 50 50 50 50

Legacy 40 40 40 40 40 45 50 55 60 65 70 75 80 75 65 60 50 45 45 45 45

Normalized dayrates assumed for 10% capital returns uniformly over each asset’s life

Transitional year toward normalized dayrates

Recovery begins as rig attrition and demand improvement balance the market

Dayrates continue to search for a bottom, forcing lower quality rigs out of the market

Meaningful recovery in dayrates does not arrive until 2018

Source: KLR Group, LLC Forecast


Floater Market Balances Improve With Rig Attrition & Cold Stacking (-67 Floaters)

162

194 199 206

221

235

254

279 288

305

291

273 274 284

292 294

141

167 173 181

191 199

211

244

258 262

226

168

204

238 251

266

87% 86% 87% 88% 87%85%

83%

87%90%

86%78%

58%

75%

87%88%

91%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-

50

100

150

200

250

300

350

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E

Uti

lizat

ion

Nu

mb

er

of R

igs

Market Supply, EOP Contracted / Demand Implied Utilization

We forecast floater demand to fall another ~26% in 2016, without recovery to 2005 levels until 2018

We see more material pricing power emerge as the utilization of marketed supply crosses into the 85%+ range

Source: IHS Petrodata; Company Disclosuers; KLR Group, LLC Forecast


KLR Well Count Forecast Narrows Project Opportunity Set by Probability Weighted Analysis

186

243

280 293

315

168

204

238 251

266

-

50

100

150

200

250

300

350

2016 2017 2018 2019 2020

TOTAL RAW FLOATER DEMAND TOTAL FLOATER DEMAND (KLR Forecast)

Consultant data may look very bullish when un-refined. Understanding which projects have reached FID, have equipment ordered, or may be lower probability potential projects provides a better calibration of demand.

We see a larger opportunity set as potential upside to our forecast. In our view, current iterations of raw data consultants also look far more conservative over the last 12 months.

Source: Inflied, KLR Group, LLC Forecast


Floater Demand Forecast Methodology

•Raw Project Well Count Data Aggregate

•Determine Project Status

•Apply Historical/Projected Probability Weights Probability Weight

•Sort by Project Start Date

•Sort by Region Distribute

•Apply Historical/Projected Well to Rig Ratios Convert Wells to Rig Demand

•Consolidate Analysis Floater Development Rig

Demand

•Less Visibility

•Understand Current Contracting

•Apply Historical Cyclical Relationships Exploration Rig Demand

•Add Exploration & Development Demand TOTAL FLOATER DEMAND


Floating Rig & Subsea Equipment Model: Probability Weighting Methodology

Category Definitions:

• Field in Production : Field is on-stream producing oil, gas or condensate.

• Field Development in Progress: Platform or subsea completions are being constructed and pipelines laid.

• Firm Plan (FID) Early Stage Development: Development plan (PDO) submitted to relevant authority.

• Probable : Development planning stage at company level.

• Possible : Very early stage of field evaluation.

Probability Weights by Categories

Reached FID, so are approved projects, but delays remain variable

We assumed delayed or not executed projects remain in the inventory of future projects, as we probability weight demand, we assume a percentage of the “carried inventory” is completed in the following year. Carried demand does not have a meaningful impact on demand until 2018.

Categories 2015 2016 2017 2018 2019 2020

Ordered 100% 100% 100% 100% 100% 100%

Field in Production - Not Ordered 0% 80% 90% 100% 100% 100%

Field Development in Progress - Not Ordered 0% 80% 90% 100% 100% 100%

Firm Plan (FID) Early Stage Development - Not Ordered 0% 70% 75% 80% 85% 85%

Probable 0% 0% 20% 40% 60% 60%

Possible 0% 0% 15% 35% 45% 45%

Carried Inventory 0% 50% 50% 55% 60% 65%

Further out in the forecast, where less FID projects are known, we assume a greater number of potential projects reach FID and move forward. Our forecast, follows historical trends in the data.


Percentage of Equipment Ordered Illustrates Risk to Development Forecast

335

387

454 457

490

296

229

155

94

34

88%

59%

34%

21%

7%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-

100

200

300

400

500

600

2016 2017 2018 2019 2020

Total Development Wells (KLR Forecast) Total Development Wells Equipment Ordered

% KLR Forecast - Equipment Ordered

Further out in the forecast, where less FID projects are known, we assume a greater number of potential projects reach FID and move forward.

Source: Infield, KLR Group, LLC Forecast


Recovery of Exploration Demand For Floaters Drives Recovery

58

73 69

74 78

83 87

105

136 144

134

112 118

137 135 141

50

60

70

80

90

100

110

120

130

140

150

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

E

20

17

E

20

18

E

20

19

E

20

20

E

69

80 82

107 113 114

122

137

123 118

94

56

86

101

116 125

50

60

70

80

90

100

110

120

130

140

150

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

E

20

17

E

20

18

E

20

19

E

20

20

E

Floater Development Demand Forecast Floater Exploration Demand Forecast

We do not see North American unconventional production stopping the trend of offshore field development. A move up the learning curve and cost efficiencies may continue to yield economic offshore projects.

Exploration may take a break, as capital may focus on efforts to create cash flow from development work.

Source: IHS Petrodata, Company Filings/Disclosures; KLR Group, LLC Forecast Source: IHS Petrodata, Company Filings/Disclosures; KLR Group, LLC Forecast


Floater Supply Forecast

Jackup Supply Forecast

Forecasted Supply of Floaters & Jackups Remains Very Dependent on Attrition

Our forecast calls for the bulk of floater attrition to come at the bottom of the market in 2016. We do note that 25 PBR ($4.48, NR) sponsored newbuilds accounted for in these numbers may be delayed or cancelled due to the ongoing scandal.

Source: IHS Petrodata, Company Filings/Disclosures; KLR Group, LLC Forecast

2015 2016 2017 2018 2019 2020

Market Supply, BOP - 291 273 274 284 292

Newbuilds - 26 15 12 8 2

Attrition/Stacked - (44) (14) (2) - -

Market Supply, EOP 291 273 274 284 292 294

2015 2016 2017 2018 2019 2020

Market Supply, BOP - 499 485 474 462 464

Newbuilds - 56 29 3 2 1

Attrition/Stacked - (70) (40) (15) - -

Market Supply, EOP 499 485 474 462 464 465


Determination of the Marketed Supply of Offshore Rigs

In our view, the market balance for rigs is determined by the marketed supply of rigs that are actively available to work in relation to the demand for rigs in a given period. By our definition the marketed supply of rigs:

Includes: + Contracted Rigs + Idle + Warm Stacked + Hot Stacked + In Port + Moving to Location + Acceptance Testing + En Route + Standby + Waiting on Weather (WOW) + Shipyard

Does not include:

- Under Construction - On Order - Cold Stacked - Accident - Out of Service

All of these rig are active or bidding for work

We do not add newbuilds to the marketed fleet until they are delivered.

We see low probability of legacy cold stacked assets returning to either the floater or jackup fleet


Risk/Reward 6G Floater Purchases May Only Support Distressed Asset Deals

30 25 20 15

9% $663 626$ 570$ 484$

10% $597 569$ 523$ 450$

11% $540 518$ 481$ 418$

12% $490 473$ 443$ 390$

13% $447 434$ 409$ 364$

14% $409 399$ 379$ 340$

15% $376 368$ 351$ 318$

16% $347 340$ 327$ 298$

17% $320 315$ 304$ 280$

18% $297 293$ 284$ 263$

19% $276 273$ 265$ 247$

20% $257 255$ 248$ 233$

21% $240 238$ 233$ 219$

22% $225 223$ 219$ 207$

23% $211 209$ 206$ 196$

24% $198 197$ 194$ 185$

25% $186 185$ 183$ 175$

WA

CC

Estimated Asset Life (years)• Potentially distressed offshore drillers could be

purchased in pieces, not as a whole, as buyers may not want to pay par for discounted debt

• Given offshore market risks, we do not see assets transacting near the $600-700 million build costs

• Clearing prices may depend on debt associated with the asset

• Potential assets on the market from VTG, PGN, PACD, SDRL, Odfjell

• Assumptions: • 6G rig does not work for two years if

purchased today • Normalized dayrate: $515kpd • Normalized OPEX/day: $175kpd • Tax Rate of 35%

6G Rig Purchase Scenarios

Source: KLR Group, LLC Forecast; Company Filings/Disclosures


332

377 392

409 408 408 411 423

456

491 499 485

474 462 464 465

306

340 347 368

325 317 327

356

401 419

380

354 368

393 401 405

92%90% 89% 90%

80%78%

80%

84%88%

85%

76%73% 78%

85% 86% 87%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-

100

200

300

400

500

600

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E

Uti

lizat

ion

Nu

mb

er

of R

igs

Market Supply, EOP Contracted / Demand Implied Utilization

Jackup Market Needs Attrition & Cold Stacking (-125 Jackups), Fragmented, It May be Sloppy

We forecast jackup activity to decline ~7% in 2016. Without the same granularity of data, we assume the jackup market tracks broader market trends. In our view, lower average project break-even levels and heavier weighting of development work may make the downturn less severe for jackups.

We forecast the market tightens into 2018, but it requires an exit of 125 rigs from the marketed supply to make room for 91 newbuild arrivals from 2016 forward. The amount of attrition needed to balance the market may decline if rigs under construction are not delivered.

Sources: KLR Group, LLC Forecast; Company Filings/Disclosures; IHS Petrodata


Offshore Rig Supply & Attrition


Historical Addition/Attrition Column Chart - Floaters

0 0 0

6

13 12 10

1 1 2 4

0 1

9

21 22

31

19

13

24

20

(5)(2) (1) (1)

0 0 0 0 (3)

(7)(4)

0 (1)

0 (1) (2) (1) (2)

0

(15)

(27) (30)

(20)

(10)

-

10

20

30

40

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15R

igs

(Re

tire

d)

/ A

dd

ed

Newbuilds Retirements

Source: IHS Petrodata


2 0 0

4 3 4 0

5 3 4 3

10

16

29

24 21

16 14

41

29

42

(5) (4)(2) (2) (1) (1) (1)

(3)(5)

(7) (7)

(2) (1)(4)

(7)

(1)

(13)(16)

(8)(5)

(10)

(20)

(10)

-

10

20

30

40

50

60

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15R

igs

(Re

tire

d)

/ A

dd

ed

Newbuilds Retirements

Historical Addition/Attrition Column Chart - Jackups

Source: IHS Petrodata


All rigs are given a percentile rank versus the global fleet

Floater Attrition Methodology: Multi-Factor Scores for Offshore Rigs

Variable Deck Load

Derrick/Hook Load

BOP (# Rams)

Water Depth

Drilling Depth

Dynamic Positioning

Dual Activity

Floater Generation

Age

Double Weighted Percentile

Factors

Single Weighted Percentile

Factors

Free Date

(End of Current Contract)

Survey Due Date (Regulatory Survey

That Requires CAPEX)

Rig Ranking Weighed Against Contract

Status and Potential Capital Needs

Rig Attrition: Forecast & List


Older Floaters Rank Poorly on Our Spec Factor Scale

-

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

1.40

1968

1969

1970

1971

1972

1973

1974

1975

1976

1977

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Rig

Fac

tor

Sco

re

Rig Delivery Year

Our forecast for 67 rig retirements is drawn largely from the older floaters amongst the 133 (34%) of 387 floaters rigs that score below 0.50

Factor Scores of the Floater Fleet



Floater Retirement Focus List Floater Retirement Target List Survey Free Floater Retirement Target List Survey Free

Rig Name Manager Market Category Gen Age Status Due Date Date Rig Name Manager Market Category Gen Age Status Due Date Date

1 Aban Ice Aban Offshore Drillship <=3000 3G 40 Drilling 4Q18 Nov-16 31 Paragon MSS1 Paragon Offshore Semi Harsh Standard 3G 36 Drilling 1Q16 Feb-16

2 Deep Venture Arktikmor Drillship 5001-7500 3G 34 Hot stacked 2Q18 Sep-15 32 Paragon MSS2 Paragon Offshore Semi 3001-5000 3G 38 Drilling 3Q16 Apr-16

3 WilPhoenix Awilco Drilling Semi Harsh Standard 3G 33 Yard 3Q17 Nov-17 33 Paragon DPDS2 Paragon Offshore Drillship 5001-7500 3G 34 Yard 1Q17 Feb-16

4 Nanhai VI COSL Semi <=3000 3G 33 Hot stacked 4Q18 May-15 34 Alaskan Star QGOG Constellation Semi <=3000 3G 39 Drilling 4Q19 Nov-16

5 Nanhai V COSL Semi <=3000 3G 32 Drilling 4Q18 Nov-15 35 Scarabeo 3 Saipem Semi <=3000 3G 40 En route 2Q17 Dec-15

6 Nanhai IX COSL Semi 5001-7500 4G 27 Hot stacked 4Q18 May-15 36 Scarabeo 6 Saipem Semi 3001-5000 3G 31 Drilling 3Q14 Dec-15

7 Zagreb 1 Crosco Semi <=3000 3G 38 Warm stacked 3Q16 Mar-15 37 SC Lancer Schahin Drillship 3001-5000 3G 38 Hot stacked 2Q18 Jun-15

8 Zagreb 1 Crosco Semi <=3000 3G 38 Warm stacked 3Q16 Mar-15 38 Kan Tan III Sinopec Offshore OFS Semi <=3000 3G 31 Drilling 3Q19 Jan-16

9 Ocean Patriot Diamond Offshore Semi Harsh Standard 3G 32 Drilling 1Q18 Oct-17 39 Songa Dee Songa Offshore Semi Harsh High Spec 3G 31 Drilling 3Q19 Oct-16

10 Ocean Victory Diamond Offshore Semi 5001-7500 3G 43 Drilling 4Q17 May-17 40 Songa Trym Songa Offshore Semi Harsh Standard 3G 39 Warm stacked 1Q18 Nov-15

11 Ocean Ambassador Diamond Offshore Semi <=3000 3G 40 Drilling 3Q18 Mar-16 41 Songa Venus Songa Opus Offshore Semi <=3000 3G 40 En route 1Q20 Nov-17

12 Ocean Quest Diamond Offshore Semi 3001-5000 3G 42 Warm stacked 4Q17 Jan-16 42 Stena Clyde Stena Semi <=3000 3G 39 Hot stacked 2Q20 Oct-15

13 Ocean Rover Diamond Offshore Semi 5001-7500 3G 42 Drilling 1Q18 Mar-16 43 Stena Spey Stena Semi Harsh Standard 3G 32 Warm stacked 2Q18 Sep-15

14 Ocean Guardian Diamond Offshore Semi Harsh Standard 4G 30 Warm stacked 1Q20 Aug-15 44 Sedco 712 Transocean Semi Harsh Standard 3G 32 Warm stacked 4Q18 Oct-16

15 Bideford Dolphin Dolphin Semi Harsh High Spec 3G 40 Drilling 2Q19 Jan-17 45 Polar Pioneer Transocean Semi <=3000 4G 30 Standby 3Q14 Jun-17

16 Blackford Dolphin Dolphin Semi Harsh Deepwater 3G 41 Drilling 4Q18 Feb-17 46 Transocean Driller Transocean Semi <=3000 4G 24 Drilling 3Q16 Jun-16

17 Bredford Dolphin Dolphin Semi Harsh Standard 3G 35 Drilling 2Q17 Nov-15 47 Paul B. Loyd, Jr. Transocean Semi Harsh High Spec 4G 28 Yard 4Q20 Jun-17

18 Byford Dolphin Dolphin Semi Harsh Standard 3G 41 Drilling 1Q20 Aug-16 48 Actinia Transocean Semi <=3000 3G 33 Yard 4Q17 Nov-15

19 Paragon MDS1 Dynamic Drilling & Srvcs Drillship <=3000 3G 40 Warm stacked 2Q17 Oct-15 49 Sedco 704 Transocean Semi Harsh Standard 3G 41 Drilling 1Q18 Apr-16

20 ENSCO 5004 Ensco Semi <=3000 3G 33 Drilling 2Q16 Dec-16 50 Transocean Winner Transocean Semi Harsh Standard 3G 32 Drilling 1Q16 Jul-16

21 Aban Abraham Etesco Drillship 5001-7500 3G 39 Standby -- Jun-16 51 Sedco 714 Transocean Semi Harsh Standard 3G 32 Warm stacked 1Q19 Feb-16

22 Kan Tan IV Frigstad Offshore Semi <=3000 3G 32 Warm stacked 2Q17 Jun-15 52 Sedco 711 Transocean Semi Harsh Standard 3G 33 Warm stacked 4Q17 Jan-16

23 Hakuryu-5 Japan Drilling Semi <=3000 3G 38 Yard 3Q17 Apr-16 53 M.G. Hulme, Jr. Transocean Semi 3001-5000 3G 32 Hot stacked -- Apr-15

24 Jasper Explorer Jasper Offshore Drillship 3001-5000 3G 42 Warm stacked 1Q17 Jan-15 54 GSF Rig 140 Transocean Semi <=3000 3G 32 Hot stacked 4Q18 Sep-15

25 Jindal Discoverer Jindal Drilling Drillship <=3000 3G 38 Warm stacked 4Q16 Sep-14 55 Transocean John Shaw Transocean Semi Harsh Standard 3G 33 Drilling 2Q19 Jan-16

26 West Alpha North Atlantic Drilling Semi Harsh High Spec 4G 29 Drilling 1Q19 Jul-16 56 GSF Grand Banks Transocean Semi Harsh Standard 3G 31 Hot stacked 1Q19 Sep-15

27 Energy Driller Northern Offshore Semi <=3000 3G 38 Warm stacked 3Q15 May-15 57 Sedco 702 Transocean Semi 5001-7500 3G 42 Drilling 1Q17 Feb-16

28 Energy Searcher Northern Offshore Drillship <=3000 3G 33 Warm stacked 2Q16 May-15 58 Sedco 706 Transocean Semi 5001-7500 3G 39 Drilling 1Q19 Sep-18

29 Deepsea Bergen Odfjell Drilling Semi Harsh Standard 3G 32 Drilling 3Q20 Jun-17 59 Transocean Arctic Transocean Semi Harsh High Spec 4G 29 Drilling 4Q19 Jan-16

30 Paragon DPDS3 Paragon Offshore Drillship 5001-7500 3G 38 Drilling 1Q17 Aug-17 60 Jack Bates Transocean Semi 5001-7500 4G 29 Drilling 3Q16 Feb-16



All rigs are given a percentile rank versus the global fleet

Jackup Attrition Methodology: Multi-Factor Scores for Offshore Rigs

Age Derrick/Hook

Load BOP (# Rams)

Drilling Depth

Variable Deck Load

Double Weighted Percentile

Factors

Single Weighted Percentile

Factors

Free Date

(End of Current Contract)

Survey Due Date (Regulatory Survey

That Requires CAPEX)

Rig Ranking Weighed Against Contract

Status and Potential Capital Needs

Rig Attrition: Forecast & List


-

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1.10

1.20

1.30

1.40

1.50

1.60

19

60

19

61

19

62

19

63

19

64

19

65

19

66

19

67

19

68

19

69

19

70

19

71

19

72

19

73

19

74

19

75

19

76

19

77

19

78

19

79

19

80

19

81

19

82

19

83

19

84

19

85

19

86

19

87

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

Rig

Fa

cto

r S

core

Rig Delivery Year

Similar to Floaters, Older Jackups Rank Poorly on Our Spec Factor Scale

Our pool of 125 rig retirement come from the 194 (29%) of 670 floaters rigs that score below 0.50

Factor Scores of the Jackup Fleet



Jackup Retirement Focus List


JU Retirement Target List Market Survey Free JU Retirement Target List Market Survey Free

Rig Name Manager Category Age Rig Status Due Date Date Rig Name Manager Category Age Rig Status Due Date Date

1 Aban VII Aban Offshore JU 250-IC 35 Hot stacked 4Q18 4Q14 33 ENSCO 88 Ensco JU 250-IC 35 Drilling 3Q17 4Q16

2 Aban V Aban Offshore JU 300-IC 35 Hot stacked 4Q18 4Q14 34 ENSCO 52 Ensco JU 300-IC 35 Drilling 3Q17 3Q17

3 Aban II Aban Offshore JU 250-MS 35 Yard 4Q18 4Q15 35 ENSCO 54 Ensco JU 300-IC 35 Drilling 3Q17 3Q17

4 Aban III Aban Offshore JU 300-IC 35 Drilling 4Q18 2Q18 36 Astra Eurasia Drilling JU <250-IC 35 Drilling 2Q18 1Q17

5 Admarine VI Advanced Energy Systems JU 250-IC 35 Warm stacked 3Q16 1Q15 37 Mercury Focus Focus Energy JU 250-IC 35 Drilling 3Q15 1Q16

6 Admarine III Advanced Energy Systems JU 250-IC 35 Hot stacked 4Q17 4Q15 38 Foresight Driller V Foresight Drilling JU <250-IC 35 Drilling 3Q15 4Q15

7 Arabdrill 17 Arabian Drilling JU 250-IC 35 Drilling 3Q19 2Q19 39 Foresight Driller III Foresight Drilling JU 300-IC 35 Drilling 2Q17 1Q16

8 Arabdrill 8 Arabian Drilling JU <250-IC 35 Drilling -- 2Q17 40 Foresight Driller IX Foresight Drilling JU 301-360-IC 35 Drilling 3Q15 4Q15

9 Sivash Chernomorneftegaz JU <250-IS 35 Drilling 1Q14 4Q20 41 Amazone Gazflot JU <250-IC 35 Warm stacked 2Q16 4Q20

10 Bohai-5 COSL JU <250-IS 35 Drilling 2Q17 1Q16 42 Sandunga Goimar JU 301-360-IC 35 Drilling 3Q17 1Q16

11 Bohai-8 COSL JU <250-IC 35 Drilling 2Q17 1Q16 43 Goimar-1 Goimar JU 300-IC 35 Drilling 1Q17 3Q16

12 Nanhai I COSL JU <250-IC 35 Drilling 2Q14 1Q16 44 Kedarnath GOL Offshore JU 300-IS 35 Drilling 3Q15 1Q16

13 Bohai-10 COSL JU 250-IC 35 Drilling 2Q19 1Q16 45 GSP Saturn GSP JU 300-IC 35 Warm stacked 2Q19 3Q15

14 Bohai-4 COSL JU 300-IC 35 Drilling 2Q17 1Q16 46 Al-Rayyan Gulf Drilling International JU 300-IC 35 Yard 1Q16 4Q15

15 Bohai-9 COSL JU <250-IS 35 Drilling 2Q17 1Q16 47 Hercules 173 Hercules Offshore JU <200-MC 35 Warm stacked 2Q16 4Q15

16 HAIYANGSHIYOU 922 COSL JU <250-IC 35 Drilling 4Q15 1Q16 48 Hercules 260 Hercules Offshore JU 250-IC 35 Drilling 4Q17 2Q20

17 HAIYANGSHIYOU 921 COSL JU <250-IC 35 Drilling 4Q15 1Q16 49 Hercules 205 Hercules Offshore JU 200-MC 35 Drilling 4Q18 4Q15

18 Kan Tan II COSL JU 300-IS 35 Drilling 2Q16 1Q16 50 Hercules 264 Hercules Offshore JU 250-MC 35 Drilling 4Q18 4Q15

19 Bohai-12 COSL JU <250-IC 35 Drilling 2Q17 1Q16 51 Hercules 350 Hercules Offshore JU 301-360-IC 35 Hot stacked 2Q11 4Q15

20 CPOE-7 CPOE JU <250-IC 35 Drilling 1Q14 1Q16 52 Hercules 267 Hercules Offshore JU 250-IC 35 Warm stacked 2Q11 2Q15

21 CPOE-5 CPOE JU <250-IC 35 Drilling 3Q17 1Q16 53 Hercules 201 Hercules Offshore JU 200-MC 35 Warm stacked 1Q19 3Q14

22 CPOE-6 CPOE JU <250-IC 35 Drilling 4Q17 1Q16 54 Hercules 150 Hercules Offshore JU <250-IC 35 Warm stacked 2Q19 3Q14

23 Paragon L786 Dynamic Drilling & Services JU 300-IC 35 Drilling 4Q16 1Q18 55 Hercules 208 Hercules Offshore JU <200-MC 35 Warm stacked 3Q18 2Q15

24 Valiant Driller Dynamic Drilling & Services JU 300-IC 35 Drilling 1Q18 1Q18 56 Hercules 266 Hercules Offshore JU 250-IC 35 Drilling 1Q18 2Q16

25 Paragon M1161 Dynamic Drilling & Services JU 300-IC 35 Drilling 4Q16 2Q18 57 Hercules 262 Hercules Offshore JU 250-IC 35 Drilling 4Q17 4Q19

26 Zoser Egyptian Drilling JU 250-IC 35 Drilling 3Q17 1Q16 58 Deepsea Treasure Jagson JU 300-IC 35 Hot stacked 3Q12 2Q14

27 Senusret Egyptian Drilling JU <250-IC 35 Drilling 1Q17 3Q16 59 Deepsea Fortune Jagson JU 300-IC 35 Drilling 2Q17 2Q18

28 ENSCO 97 Ensco JU 250-IC 35 Drilling 3Q17 1Q19 60 Ben Rinnes KCA Deutag JU 301-360-IC 35 Drilling 2Q17 3Q16

29 ENSCO 89 Ensco JU 250-IC 35 Yard 3Q17 4Q15 61 KS Java Star KS Drilling JU 300-IC 35 Hot stacked 4Q17 4Q15

30 ENSCO 84 Ensco JU 250-IC 35 Drilling 1Q15 4Q15 62 KS Medstar 1 KS Drilling JU 300-IC 35 Warm stacked 3Q15 3Q15

31 ENSCO 53 Ensco JU 300-IC 35 Drilling 4Q18 1Q16 63 Nabors 657 Nabors JU 250-IC 35 Drilling 3Q15 4Q15

32 ENSCO 87 Ensco JU 301-360-IC 35 Drilling 3Q17 4Q15


Jackup Retirement Focus List (cont.) JU Retirement Target List Market Survey Free JU Retirement Target List Market Survey Free

Rig Name Manager Category Age Rig Status Due Date Date Rig Name Manager Category Age Rig Status Due Date Date

64 Nabors 657 Nabors JU 250-IC 35 Drilling 3Q15 4Q15 95 ENSCO 98 Scott and English JU 250-IC 35 Hot stacked 3Q17 4Q15

65 Nabors 656 Nabors JU 250-IC 35 Drilling 3Q15 3Q17 96 Noahs Ark Selective Marine Services JU 300-IC 35 Warm stacked 2Q19 2Q15

66 Nabors 660 Nabors JU 250-IC 35 Drilling 2Q18 4Q16 97 Teras Titanium Selective Marine Services JU 301-360-IC 35 Warm stacked 4Q15 1Q15

67 Nabors 655 Nabors JU <250-IC 35 Drilling 4Q16 4Q17 98 Adriatic IX Shelf Drilling JU 301-360-IC 35 Drilling 1Q16 2Q16

68 Al Bzoom National Drilling JU <250-IC 35 Drilling 4Q16 3Q18 99 High Island IX Shelf Drilling JU 250-IC 35 Drilling 4Q19 1Q16

69 Delma National Drilling JU <250-IC 35 Drilling 1Q17 3Q18 100 Main Pass I Shelf Drilling JU 300-IC 35 Drilling 2Q18 4Q19

70 Brakah National Drilling JU <250-IC 35 Drilling 2Q19 3Q18 101 Comet Shelf Drilling JU <250-IC 35 Drilling 2Q15 2Q16

71 Beynouna National Drilling JU <250-IC 35 Drilling 3Q19 3Q18 102 Key Gibraltar Shelf Drilling JU 300-IC 35 Drilling 1Q17 4Q15

72 Al Yasat National Drilling JU <250-IC 35 Drilling 4Q19 3Q18 103 Trident 16 Shelf Drilling JU 300-IC 35 Drilling 1Q16 1Q17

73 Shahid Modarres NIDC JU <250-MS 35 Drilling -- 4Q15 104 Rig 124 Shelf Drilling JU 250-IC 35 Drilling 2Q15 2Q17

74 Noble Joe Beall Noble JU 300-IC 35 Drilling 2Q16 4Q18 105 Compact Driller Shelf Drilling JU 300-IC 35 Drilling 1Q17 3Q16

75 Noble Charles Copeland Noble JU 250-IC 35 Yard 3Q14 4Q15 106 C.E. Thornton Shelf Drilling JU 300-IC 35 Warm stacked 1Q20 2Q15

76 Noble David Tinsley Noble JU 300-IC 35 Drilling 3Q15 4Q17 107 F.G. McClintock Shelf Drilling JU 300-IC 35 Warm stacked -- 2Q15

77 Al Borz Ocean Oilfield JU 250-IS 35 Drilling 1Q18 4Q15 108 Adriatic X Shelf Drilling JU 301-360-IC 35 Warm stacked 4Q15 3Q15

78 Paragon M825 Paragon Offshore JU 250-IC 35 Drilling 4Q19 1Q16 109 Trident II Shelf Drilling JU 300-IC 35 Warm stacked 4Q16 2Q15

79 Paragon L1115 Paragon Offshore JU 300-IC 35 Warm stacked 1Q17 4Q15 110 Trident XIV Shelf Drilling JU 300-IC 35 Warm stacked 3Q17 1Q15

80 Paragon L784 Paragon Offshore JU 300-IC 35 Drilling 2Q17 2Q18 111 Rig 141 Shelf Drilling JU 250-IC 35 Drilling 4Q17 4Q15

81 Paragon M841 Paragon Offshore JU 361-400-IC 35 Cold stacked 4Q17 4Q15 112 Shengli VIII Shengli Offshore JU <250-IC 35 Drilling 3Q15 4Q15

82 Paragon L782 Paragon Offshore JU 300-IC 35 Warm stacked 2Q16 4Q15 113 Shengli VI Shengli Offshore JU <250-IS 35 Drilling 3Q18 4Q15

83 Paragon L783 Paragon Offshore JU 300-IC 35 Warm stacked 2Q16 3Q15 114 Shengli IX Shengli Offshore JU <250-IC 35 Drilling -- 4Q15

84 Paragon L785 Paragon Offshore JU 300-IC 35 Warm stacked 4Q16 2Q15 115 Shengli VII Shengli Offshore JU <250-IC 35 Drilling 1Q17 4Q15

85 Paragon B152 Paragon Offshore JU <250-IC 35 Drilling 4Q18 4Q17 116 Shiv-Vani Heritage Shiv-Vani JU 300-IC 35 Warm stacked 3Q16 4Q14

86 Paragon Dhabi II Paragon Offshore JU <250-IC 35 Drilling 2Q16 3Q17 117 Khazar VI SOCAR JU 250-IS 35 Warm stacked -- 2Q14

87 Grijalva Perforadora Central JU 200-MC 35 Warm stacked 2Q18 2Q14 118 Spartan 208 Spartan Offshore Drilling JU 250-MC 35 Hot stacked 2Q19 3Q15

88 Sonora Perforadora Mexico JU 250-IC 35 Hot stacked 2Q15 1Q15 119 Spartan 202 Spartan Offshore Drilling JU <250-MS 35 Hot stacked 4Q16 3Q14

89 Bennevis Pyramid Drilling JU 250-IC 35 Drilling 4Q14 1Q17 120 Spartan 303 Spartan Offshore Drilling JU 250-MS 35 Hot stacked 1Q16 4Q14

90 Gilbert Rowe Rowan JU 301-360-IC 35 Drilling 4Q16 4Q15 121 Spartan 151 Spartan Offshore Drilling JU <250-IC 35 Warm stacked 4Q16 2Q16

91 Rowan California Rowan JU 300-IC 35 Drilling 2Q18 3Q16 122 Swift 10 Swift Drilling JU <250-IC 35 Drilling 2Q16 3Q16

92 Rowan Middletown Rowan JU 301-360-IC 35 Drilling 3Q14 3Q18 123 Well Services Rig 110 Well Services Ltd JU <200-MC 35 Drilling 2Q16 4Q15

93 Charles Rowan Rowan JU 301-360-IC 35 Drilling 1Q16 3Q18 124 Well Services Rig 152 Well Services Ltd JU <200-MC 35 Hot stacked 4Q18 1Q14

94 Arch Rowan Rowan JU 301-360-IC 35 Drilling 3Q16 3Q18 125 Well Services Rig 53 Well Services Ltd JU Workover 35 Drilling 4Q18 2Q16



-

5

10

15

20

25

30

35

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16

1Q

17

2Q

17

3Q

17

4Q

17

1Q

18

2Q

18

3Q

18

4Q

18

1Q

19

2Q

19

3Q

19

4Q

19

1Q

20

2Q

20

3Q

20

4Q

20

Established Drillers NOC Chinese State Mexican Players

Offshore/OFS New Entrants Shipyard Risky Drillers Speculative/Other

Jackup Newbuilds: Risks For the ~85% of Fleet Ordered by Non-Established Offshore Drillers

Established Drillers, 18 , 14%

NOC, 5 , 4%

Chinese State, 23 ,

18%

Mexican Players, 10 , 8%Offshore/OFS New

Entrants, 18 , 14%

Shipyard, 8 , 6%

Risky Drillers, 14 , 11%

Speculative/Other,

31 , 25%

Newbuilds by Delivery Quarter Newbuilds by Purchasing Group

We see potential for a number of cancellations from speculative orders and lack of interest in poorly managed rig constructions from established offshore drillers.

Negotiated Delayed Deliveries Persist




Jackup Newbuilds


Rig Water Drilling N Sea Build Drilling Order Delivery Contract

Manager Rig Name Type Depth Depth Capable Shipyard Country Cost Package BOP Cementing Date Date Operator Duration Category

Alliance Offshore Alliance Offshore JU Tbn1 Jackup 400 30,000 N CSSC Huangpu Wenchong Shipyard China - TSC Offshore GE Oil & Gas May-13 Jan-16 Uncontracted - Speculative/Other

Alliance Offshore Alliance Offshore JU Tbn2 Jackup 400 30,000 N CSSC Huangpu Wenchong Shipyard China - TSC Offshore May-13 Dec-17 Uncontracted - Speculative/Other

Alliance Offshore Alliance Offshore JU Tbn3 Jackup 400 30,000 N CSSC Huangpu Wenchong Shipyard China - Jul-15 Dec-17 Uncontracted - Speculative/Other

Apexindo Ayu Jackup 400 35,000 N Dalian Shipbuilding Industry Co. China - Mar-14 Feb-16 Uncontracted - Risky Drillers

Bestford Capital Bestford JU Tbn1 Jackup 350 30,000 N China Merchants Heavy Industry China - Jan-13 Mar-16 Uncontracted - Speculative/Other

Bestford Capital Bestford JU Tbn2 Jackup 350 30,000 N China Merchants Heavy Industry China - Jan-13 Jun-16 Uncontracted - Speculative/Other

Bestford Capital Bestford JU Tbn3 Jackup 350 30,000 N China Merchants Heavy Industry China 180 Sep-13 Sep-16 Uncontracted - Speculative/Other

Bestford Capital Bestford JU Tbn4 Jackup 350 30,000 N China Merchants Heavy Industry China - Nov-13 Dec-16 Uncontracted - Speculative/Other

Bestford Capital Bestford JU Tbn5 Jackup 350 30,000 N China Merchants Heavy Industry China 180 Dec-13 Mar-17 Uncontracted - Speculative/Other

Bestford Capital Bestford JU Tbn6 Jackup 350 30,000 N China Merchants Heavy Industry China - Dec-13 Jun-17 Uncontracted - Speculative/Other

CIMC Raffles Offshore CIMC Raffles JU Tbn5 Jackup 300 29,520 N Yantai CIMC Raffles China - Sep-14 Dec-15 Uncontracted - Shipyard

CIMC Raffles Offshore CIMC Raffles JU Tbn6 Jackup 300 29,520 N Yantai CIMC Raffles China - Jan-15 Sep-16 Uncontracted - Shipyard

Coastal Contracts Coastal Contracts JU Tbn2 Jackup 400 35,000 N Yantai CIMC Raffles China - Nov-13 Dec-15 Uncontracted - Offshore/OFS New Entrants

COSL HAIYANGSHIYOU 943 Jackup 400 30,000 Y Dalian Shipbuilding Industry Co. China - Oct-13 Nov-15 Uncontracted - Risky Drillers

COSL HAIYANGSHIYOU 944 Jackup 400 30,000 N China Merchants Heavy Industry China - Oct-13 Mar-16 Uncontracted - Risky Drillers

CPLEC CP300-3 Jackup 300 N CPLEC China - Mar-12 Dec-15 Uncontracted - Chinese State

CPLEC CP400 Jackup 400 30,000 N CPLEC China - Jul-13 Jul-16 Uncontracted - Chinese State

CPOE CPOE-17 Jackup 400 N Dalian Shipbuilding Industry Co. China - Jun-13 Dec-15 Uncontracted - Chinese State

CPTDC DSJ-300 JU Tbn3 Jackup 300 30,000 N Dalian Shipbuilding Industry Co. China - Mar-12 Nov-15 Uncontracted - Chinese State

CPTDC DSJ-300 JU Tbn4 Jackup 300 30,000 N Dalian Shipbuilding Industry Co. China - May-12 Dec-15 Uncontracted - Chinese State

CPTDC DSJ-300 L1 Jackup 300 30,000 N CPLEC China - Jul-12 Dec-15 Uncontracted - Chinese State

CPTDC DSJ-300 L2 Jackup 300 30,000 N CPLEC China - Apr-13 Dec-15 Uncontracted - Chinese State

CSM Cerberus Jackup 400 35,000 N Yantai CIMC Raffles China 240 Cameron Jan-14 Dec-15 Uncontracted - Offshore/OFS New Entrants

CSM Phoenix Jackup 400 35,000 Y Yantai CIMC Raffles China 240 Cameron Jan-14 Dec-15 Uncontracted - Offshore/OFS New Entrants

CSSC Leasing CSSC JU Tbn1 Jackup 400 35,000 Y Shanghai Waigaoqiao Shipbuilding China - Jan-14 Jun-16 Uncontracted - Chinese State

CSSC Leasing CSSC JU Tbn2 Jackup 400 35,000 Y Shanghai Waigaoqiao Shipbuilding China - Jan-14 Sep-16 Uncontracted - Chinese State

Ensco ENSCO 123 Jackup 400 40,000 Y Keppel FELS Singapore 285 National Oilwell VarcoNational Oilwell Varco Nov-13 Jun-16 Uncontracted - Established Drillers

Ensco ENSCO 140 Jackup 340 30,000 Y Lamprell UAE 215 Woolslayer Shaffer Apr-14 Apr-16 Uncontracted - Established Drillers

Ensco ENSCO 141 Jackup 340 30,000 Y Lamprell UAE 215 Woolslayer Shaffer Apr-14 Sep-16 Uncontracted - Established Drillers

ES Holding ES Holding JU Tbn1 Jackup 350 25,000 Y Qingdao Wuchan Heavy Industry CO. China - Cameron Cameron Nov-12 Jan-16 Uncontracted - Offshore/OFS New Entrants

Essar Oilfields Services Varada 1 Jackup 350 30,000 N ABG Shipyard India 229 Oct-08 Dec-16 Uncontracted - Offshore/OFS New Entrants

Essar Oilfields Services Varada 2 Jackup 350 30,000 N ABG Shipyard India 229 Oct-08 Jun-17 Uncontracted - Offshore/OFS New Entrants

ESSM ESSM JU Tbn2 Jackup 375 30,000 N Shanghai Waigaoqiao Shipbuilding China 180 Aug-13 Jun-16 Uncontracted - Speculative/Other

ESSM ESSM1 Jackup 375 30,000 N Shanghai Waigaoqiao Shipbuilding China 180 Aug-13 Dec-15 Uncontracted - Speculative/Other

Fecon Fecon JU Tbn1 Jackup 400 30,000 Y Keppel FELS Singapore 217 Woolslayer Feb-14 Apr-17 Uncontracted - Speculative/Other

Fecon Fecon JU Tbn2 Jackup 400 30,000 Y Keppel FELS Singapore 217 Woolslayer Feb-14 Aug-17 Uncontracted - Speculative/Other

Fecon Fecon JU Tbn3 Jackup 400 30,000 Y Keppel FELS Singapore 217 Woolslayer Feb-14 Nov-17 Uncontracted - Speculative/Other

Foresight Drilling Vivekanand 1 Jackup 350 30,000 N COSCO Dalian China 170 Aug-12 Dec-15 Uncontracted - Speculative/Other

Foresight Drilling Vivekanand 2 Jackup 350 30,000 N COSCO Dalian China 170 Aug-13 Apr-16 Uncontracted - Speculative/Other

Foresight Drilling Vivekanand 3 Jackup 350 30,000 N COSCO Dalian China 184 May-14 Aug-16 Uncontracted - Speculative/Other

FTS Derricks TS Coral Jackup 400 YShanhaiguan Shipbuilding Industry Co., Ltd. China 218 Jul-13 Mar-17 Uncontracted - Offshore/OFS New Entrants

FTS Derricks TS Emerald Jackup 400 YShanhaiguan Shipbuilding Industry Co., Ltd. China 218 Jul-13 Dec-16 Uncontracted - Offshore/OFS New Entrants

FTS Derricks TS Jade Jackup 400 YShanhaiguan Shipbuilding Industry Co., Ltd. China 218 Jul-13 Jun-17 Uncontracted - Offshore/OFS New Entrants

FTS Derricks TS Opal Jackup 400 YShanhaiguan Shipbuilding Industry Co., Ltd. China 218 Jul-13 Oct-16 Uncontracted - Offshore/OFS New Entrants

FTS Derricks TS Topaz Jackup 400 35,000 N Keppel FELS Singapore 226 Apr-13 Dec-15 Uncontracted - Offshore/OFS New Entrants

GOL Offshore Somnath Jackup 350 N Bharati Shipyard Qatar 165 Aug-06 42384 Uncontracted - Offshore/OFS New Entrants

Grupo R Cantarell I Jackup 400 30,000 N Keppel FELS Singapore 205 Cameron Mar-13 Nov-15 Uncontracted - Mexican Players

Grupo R Cantarell II Jackup 400 30,000 N Keppel FELS Singapore 205 Cameron Mar-13 Nov-15 Uncontracted - Mexican Players

Grupo R Cantarell III Jackup 400 30,000 N Keppel FELS Singapore 205 Cameron Mar-13 Dec-15 Uncontracted - Mexican Players

Grupo R Cantarell IV Jackup 400 30,000 N Keppel FELS Singapore 205 Cameron Mar-13 Jan-16 Uncontracted - Mexican Players


Jackup Newbuilds (Cont.)


Rig Water Drilling N Sea Build Order Delivery Contract

Manager Rig Name Type Depth Depth Capable Shipyard Country CostDrilling Package BOP Cementing Date Date Operator Duration Category

Grupo R Paraiso I Jackup 400 30,000 N Keppel FELS Singapore 206 Cameron Jul-13 Feb-16 Uncontracted - Mexican Players

Grupo R Paraiso II Jackup 400 30,000 N Keppel FELS Singapore 206 Aug-13 Mar-16 Uncontracted - Mexican Players

Gulf Drilling International Halul Jackup 300 30,000 N Keppel FELS Singapore 227 Lee C Moore Cameron Sep-14 Jan-16 Qatar Petroleum 5.2 NOC

Hercules Offshore Hercules Highlander Jackup 400 35,000 Y Jurong Shipyard Pte Ltd Singapore 270 May-14 Apr-16 Maersk Oil 5.3 Risky Drillers

Hercules Offshore Perisai Pacific 102 Jackup 400 30,000 N PPL Shipyard Singapore 208 National Oilwell Varco Feb-13 Mar-16 Uncontracted - Risky Drillers

Hongmao Shipping Haiheng 6 Jackup 375 N China Merchants Heavy Industry China - Sep-14 Aug-16 Uncontracted - Chinese State

Hongmao Shipping Haiheng 7 Jackup 375 N China Merchants Heavy Industry China - Sep-14 Jan-17 Uncontracted - Chinese State

Japan Drilling Hakuryu-14 Jackup 400 35,000 N PPL Shipyard Singapore 240 Nov-14 Oct-16 Uncontracted - Risky Drillers

Japan Drilling Hakuryu-15 Jackup 400 35,000 Y Keppel FELS Singapore 240 Oct-14 Dec-16 Uncontracted - Risky Drillers

KCA Deutag Gullfaks JU Tbn1 Jackup 460 32,808 Y Samsung Heavy Industries South Korea 650 Jun-13 Dec-16 Statoil 8.2 Risky Drillers

KCA Deutag Oseberg JU Tbn1 Jackup 460 32,808 Y Samsung Heavy Industries South Korea 650 Jun-13 Feb-17 Statoil 8.2 Risky Drillers

Keppel FELS Keppel FELS JU Tbn1 Jackup 350 30,000 N Keppel FELS Singapore - Mar-14 Apr-17 Uncontracted - Shipyard

KS Drilling KS JU Tbn3 Jackup 350 N Shanghai Zhenhua Heavy Industries China 199 Jun-14 Nov-16 Uncontracted - Offshore/OFS New Entrants

KS Drilling KS Orient Star 2 Jackup 400 35,000 Y COSCO Qidong China 194 Dreco May-11 Apr-16 Uncontracted - Offshore/OFS New Entrants

Landmark Offshore Oriental Dragon Jackup 400 35,000 N China Merchants Heavy Industry China - Shaffer Apr-14 Oct-15 Uncontracted - Speculative/Other

Landmark Offshore Oriental Phoenix Jackup 400 35,000 N China Merchants Heavy Industry China - Shaffer Apr-14 Dec-15 Uncontracted - Speculative/Other

Lovanda Offshore Lovanda JU Tbn1 Jackup 400 35,000 Y Shanghai Zhenhua Heavy Industries China 200 Feb-14 Jan-17 Uncontracted - Speculative/Other

Lovansing Offshore Lovansing JU Tbn1 Jackup 400 35,000 Y Shanghai Zhenhua Heavy Industries China 200 Feb-14 Jan-17 Uncontracted - Speculative/Other

Maersk Drilling Maersk XL Enhanced 4 Jackup 492 Y Daewoo South Korea - Sep-13 Jun-16 BP 5.2 Established Drillers

Malta Oil & Gas Malta Oil & Gas JU Tbn1 Jackup 450 40,000 N Drydocks World UAE - Feb-15 Dec-17 Uncontracted - NOC

Malta Oil & Gas Malta Oil & Gas JU Tbn2 Jackup 450 40,000 N Drydocks World UAE - Feb-15 Mar-18 Uncontracted - NOC

Marco Polo Drilling Iron V Jackup 400 30,000 N PPL Shipyard Singapore 214 Cameron Nov-13 Nov-15 Uncontracted - Speculative/Other

Momentum Drilling Dynamic Momentum Jackup 350 30,000 N COSCO Dalian China 180 Loadmaster Oct-13 Nov-15 Uncontracted - Speculative/Other

National Drilling NDC JU Tbn7 Jackup 200 30,000 N Lamprell UAE 183 Nov-14 Nov-16 Uncontracted - Risky Drillers

National Drilling NDC JU Tbn8 Jackup 200 30,000 N Lamprell UAE 183 Nov-14 Jan-17 Uncontracted - Risky Drillers

National Drilling NDC JU Tbn9 Jackup 200 30,000 N Lamprell UAE - Apr-15 May-17 Uncontracted - Risky Drillers

Noble Noble Lloyd Noble Jackup 492 32,808 Y Jurong Shipyard Pte Ltd Singapore 596 National Oilwell Varco May-13 Jun-16 Statoil 4.2 Established Drillers

Northern Offshore Energy Edge Jackup 400 Y Shanghai Waigaoqiao Shipbuilding China - Oct-14 Mar-17 Uncontracted - Speculative/Other

Northern Offshore Energy Embracer Jackup 375 30,000 N Shanghai Waigaoqiao Shipbuilding China - Shaffer Apr-14 Mar-17 Uncontracted - Speculative/Other

Northern Offshore Energy Emerger Jackup 375 30,000 N Shanghai Waigaoqiao Shipbuilding China - Shaffer Apr-14 Oct-16 Uncontracted - Speculative/Other

Northern Offshore Energy Encounter Jackup 350 30,000 N COSCO Dalian China 180 National Oilwell VarcoNational Oilwell Varco Schlumberger Oct-13 Jun-17 Uncontracted - Speculative/Other

Northern Offshore Energy Engager Jackup 350 30,000 N COSCO Dalian China 180 National Oilwell VarcoNational Oilwell Varco Schlumberger Oct-13 Dec-16 Uncontracted - Speculative/Other

Northern Offshore Energy Enticer Jackup 400 Y Shanghai Waigaoqiao Shipbuilding China - Oct-14 Sep-17 Uncontracted - Speculative/Other

Not known China Merchants Capital JU Tbn2 Jackup 400 N China Merchants Heavy Industry China - Oct-13 Apr-16 Uncontracted - Chinese State

Not known Clearwater JU Tbn4 Jackup 400 30,000 Y Keppel FELS Singapore 220 Oct-13 Feb-16 Uncontracted - Chinese State

Offshore Logistics Explorer I Jackup 350 30,000 N Yangzijiang Shipbuilding China 170 Nov-12 Apr-16 Uncontracted - Offshore/OFS New Entrants

Oro Negro Animus Jackup 400 30,000 N PPL Shipyard Singapore 208 Loadmaster Cameron Jul-13 Apr-16 Uncontracted - Mexican Players

Oro Negro Supremus Jackup 400 30,000 N PPL Shipyard Singapore 208 Loadmaster Cameron Jul-13 Dec-16 Uncontracted - Mexican Players

Oro Negro Vastus Jackup 400 30,000 N PPL Shipyard Singapore 209 Loadmaster Cameron Halliburton Mar-13 Apr-16 Uncontracted - Mexican Players

Perforadora Central Uxpanapa Jackup 400 30,000 N Keppel AmFELS USA 240 Oct-13 Dec-15 Uncontracted - Mexican Players

Perisai Perisai Pacific 103 Jackup 400 30,000 N PPL Shipyard Singapore 212 National Oilwell Varco Dec-13 Aug-16 Uncontracted - Offshore/OFS New Entrants

Petrolor Oilfield Services Jing Hang Jackup 375 30,000 N Drydocks World – Graha Indonesia - Mar-13 Dec-15 Uncontracted - Speculative/Other

Petrolor Oilfield Services Jing Xuan Jackup 375 30,000 N Drydocks World – Graha Indonesia - Mar-13 Dec-15 Uncontracted - Speculative/Other

PolyNor Drilling Polynor JU Tbn1 Jackup 400 30,000 N China Merchants Heavy Industry China - Oct-13 Apr-16 Uncontracted - Chinese State

PPL Shipyard PPL JU Tbn5 Jackup 400 30,000 N PPL Shipyard Singapore - Cameron Oct-13 Nov-16 Uncontracted - Shipyard

PPL Shipyard PPL JU Tbn6 Jackup 400 30,000 N PPL Shipyard Singapore - Cameron Oct-13 42676 Uncontracted - Shipyard

PPL Shipyard PPL JU Tbn8 Jackup 400 30,000 N PPL Shipyard Singapore - Cameron Nov-13 Dec-16 Uncontracted - Shipyard

Seadrill West Dione Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 National Oilwell Varco Shaffer Jul-13 Dec-17 Uncontracted - Established Drillers

Seadrill West Hyperion Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 National Oilwell Varco Shaffer Jun-13 Dec-16 Uncontracted - Established Drillers

Seadrill West Mimas Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 National Oilwell Varco Shaffer Jul-13 Aug-17 Uncontracted - Established Drillers


Jackup Newbuilds (Cont.)


Rig Water Drilling N Sea Build Order Delivery Contract

Manager Rig Name Type Depth Depth Capable Shipyard Country CostDrilling Package BOP Cementing Date Date Operator Duration Category

Seadrill West Proteus Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 Dreco Shaffer Jan-13 Mar-16 Uncontracted - Established Drillers

Seadrill West Rhea Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 Dreco Shaffer Mar-13 Jun-16 Uncontracted - Established Drillers

Seadrill West Tethys Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 Dreco Shaffer Mar-13 Sep-16 Uncontracted - Established Drillers

Seadrill West Titan Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 Jan-13 Dec-15 Uncontracted - Established Drillers

Seadrill West Umbriel Jackup 400 35,000 Y Dalian Shipbuilding Industry Co. China 230 National Oilwell Varco Shaffer Jun-13 Mar-17 Uncontracted - Established Drillers

Shanghai Waigaoqiao ShipbuildingPROSPECTOR 6 Jackup 400 35,000 Y Shanghai Waigaoqiao Shipbuilding China 211 TTS-Sense Hydril Schlumberger Aug-11 Apr-16 Uncontracted - Chinese State

Shanghai Waigaoqiao ShipbuildingPROSPECTOR 7 Jackup 400 35,000 Y Shanghai Waigaoqiao Shipbuilding China 220 TTS-Sense Cameron Mar-13 Dec-15 Uncontracted - Chinese State

Shanghai Waigaoqiao ShipbuildingPROSPECTOR 8 Jackup 400 35,000 Y Shanghai Waigaoqiao Shipbuilding China 220 TTS-Sense Cameron Mar-13 Mar-16 Uncontracted - Chinese State

Shelf Drilling Shelf Drilling Chaophraya Jackup 350 30,000 N Lamprell UAE 185 May-14 Oct-16 Chevron 5.3 Risky Drillers

Shelf Drilling Shelf Drilling Krathong Jackup 350 30,000 N Lamprell UAE 185 May-14 Apr-17 Chevron 5.2 Risky Drillers

Sinopec Sinopec JU Tbn1 Jackup 300 30,000 N Yantai CIMC Raffles China - Dec-14 Feb-17 Uncontracted - Chinese State

Tai Zhong Binhai TZ400-1 Jackup 400 29,520 N Tai Zhong Bin Hai China - Dec-13 Dec-15 Uncontracted - Shipyard

Tai Zhong Binhai TZ400-2 Jackup 400 29,520 N Tai Zhong Bin Hai China - Apr-15 Aug-17 Uncontracted - Shipyard

Teniz Burgylau Satti Jackup 262 20,000 N Keppel Kazakhstan Kazakhstan 242 Schlumberger Jul-12 Dec-15 KazMunayGaz 4.5 NOC

Tianjin Haiheng HAIHENG CJ50-1 Jackup 375 Y China Merchants Heavy Industry China - Mar-13 Dec-15 Uncontracted - Chinese State

Tianjin Haiheng HAIHENG CJ50-2 Jackup 375 Y China Merchants Heavy Industry China - Mar-13 Dec-15 Uncontracted - Chinese State

Transocean Transocean Cassiopeia Jackup 400 35,000 N Keppel FELS Singapore 265 National Oilwell VarcoNational Oilwell Varco Nov-13 Jan-18 Uncontracted - Established Drillers

Transocean Transocean Centaurus Jackup 400 35,000 N Keppel FELS Singapore 270 National Oilwell VarcoNational Oilwell Varco Nov-13 Jul-18 Uncontracted - Established Drillers

Transocean Transocean Cepheus Jackup 400 35,000 N Keppel FELS Singapore 275 National Oilwell VarcoNational Oilwell Varco Nov-13 Jan-19 Uncontracted - Established Drillers

Transocean Transocean Cetus Jackup 400 35,000 N Keppel FELS Singapore 280 National Oilwell VarcoNational Oilwell Varco Nov-13 Jul-19 Uncontracted - Established Drillers

Transocean Transocean Circinus Jackup 400 35,000 N Keppel FELS Singapore 290 National Oilwell VarcoNational Oilwell Varco Nov-13 Jan-20 Uncontracted - Established Drillers

TS Drilling TS Jasper Jackup 500 35,000 Y Keppel FELS Singapore 500 Mar-14 Dec-17 Uncontracted - Chinese State

Vanda Offshore Vanda Offshore JU Tbn1 Jackup 400 30,000 N China Merchants Heavy Industry China - National Oilwell Varco Sep-14 Mar-17 Uncontracted - Chinese State

Varada Petroleum Varada 3 Jackup 375 30,000 Y ABG Shipyard India 220 Nov-10 Dec-17 Uncontracted - Offshore/OFS New Entrants

Varada Petroleum Varada 4 Jackup 375 30,000 Y ABG Shipyard India 220 Nov-10 Jun-18 Uncontracted - Offshore/OFS New Entrants

Vietsovpetro Tam Dao 05 Jackup 350 35,000 N PV Shipyard Vietnam - Apr-12 Aug-16 Vietsovpetro 10.7 NOC

ZPMC Jap Driller 1 Jackup 400 35,000 N Shanghai Zhenhua Heavy Industries China - Sep-12 Oct-15 Uncontracted - Chinese State


Floater Newbuilds: Most Delivery Risk From PBR Sponsored New Construction

-

1

2

3

4

5

6

7

8

9

10

4Q1

5

1Q1

6

2Q1

6

3Q1

6

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

4Q18

1Q19

2Q1

9

3Q1

9

4Q1

9

1Q2

0

2Q2

0

3Q2

0

4Q2

0

Estabilished Drillers Risky Drillers Speculative/Other Petrobras

Estabilished

Drillers, 20 , 29%

Risky Drillers, 7 , 10%

Speculative/Other, 17 , 25%

Petrobras, 25 ,

36%

Newbuilds by Delivery Quarter Newbuilds by Purchasing Group

Negotiated Delayed Deliveries Persist

With recent SDRL & PACD announcements, both established and more risky offshore drillers have begun to cancel orders.




Water Drilling N Sea Build Order Delivery Contract

Manager Rig Name Rig Type Depth Depth Capable Shipyard Country Cost Drilling Package BOP Cementing Date Date Operator Duration Category

Atwood Atwood Admiral Drillship 10,000 40,000 N Daewoo South Korea 635 Hydril Halliburton Sep-12 Mar-16 Uncontracted - Estabilished Drillers

Atwood Atwood Archer Drillship 10,000 40,000 N Daewoo South Korea 635 Hydril Halliburton Jun-13 Dec-16 Uncontracted - Estabilished Drillers

Caspian Drilling Caspian Drilling Semi Tbn1Semisubmersible 2,625 40,000 N Baku Shipyard LLC Azerbaijan 1,100 Jun-13 Dec-16 Uncontracted - Speculative/Other

CIMC Raffles OffshoreCIMC Semi Tbn1 Semisubmersible 1,640 30,000 Y Yantai CIMC Raffles China 400 Jan-15 Jan-18 Uncontracted - Speculative/Other

CIMC Raffles OffshoreCIMC Semi Tbn2 Semisubmersible 1,640 30,000 Y Yantai CIMC Raffles China 400 Jul-15 Mar-18 Uncontracted - Speculative/Other

COSL HAIYANGSHIYOU 982 Semisubmersible 5,000 30,000 Y Dalian Shipbuilding Industry Co. China - Oct-13 Aug-16 Uncontracted - Speculative/Other

Daewoo (DSME) Cobalt Explorer Drillship 10,000 40,000 N Daewoo South Korea 593 Cameron Schlumberger Jul-13 Jan-16 Uncontracted - Shipyard

Diamond Offshore Ocean GreatWhite Semisubmersible 10,000 35,000 Y Hyundai Heavy Industries South Korea 764 National Oilwell Varco Shaffer Schlumberger May-13 May-16 BP 3.2 Estabilished Drillers

Ensco ENSCO DS-10 Drillship 10,000 40,000 N Samsung Heavy Industries South Korea 625 National Oilwell Varco Jun-13 Feb-17 Uncontracted - Estabilished Drillers

Etesco / OAS Cassino Drillship 10,000 35,000 N Ecovix-Engevix China 914 National Oilwell Varco Schlumberger Mar-12 Dec-19 Petrobras 15.0 Petrobras

Etesco / OAS Comandatuba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 National Oilwell Varco Halliburton Apr-12 Jan-20 Petrobras 15.6 Petrobras

Etesco / OAS Curumim Drillship 10,000 35,000 N Ecovix-Engevix Brazil 908 National Oilwell Varco Schlumberger Mar-12 Mar-17 Petrobras 15.9 Petrobras

Etesco / OAS Itapema Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 National Oilwell Varco Halliburton Apr-12 May-19 Petrobras 15.8 Petrobras

Etesco / OAS Salinas Drillship 10,000 35,000 N Ecovix-Engevix Brazil 778 National Oilwell Varco Schlumberger Mar-12 Nov-17 Petrobras 15.9 Petrobras

Frigstad Offshore Frigstad Deepwater Rig AlphaSemisubmersible 12,000 50,000 N Yantai CIMC Raffles China 650 National Oilwell Varco Jan-13 Jan-16 Uncontracted - Speculative/Other

Frigstad Offshore Frigstad Deepwater Rig BetaSemisubmersible 12,000 50,000 N Yantai CIMC Raffles China 650 National Oilwell Varco Jan-13 Jun-16 Uncontracted - Speculative/Other

Hyundai Heavy IndustriesBollsta Dolphin Semisubmersible 7,500 40,000 Y Hyundai Heavy Industries South Korea 740 Cameron Halliburton May-12 Dec-15 Uncontracted - Shipyard

Hyundai Heavy IndustriesWest Mira Semisubmersible 10,000 40,000 Y Hyundai Heavy Industries South Korea 650 Halliburton May-12 Jan-16 Uncontracted - Shipyard

Keppel FELS Keppel FELS Drsh Tbn1Drillship 12,000 N Keppel FELS Japan - Dec-13 May-17 Uncontracted - Speculative/Other

KNOC KNOC Semi Tbn1 Semisubmersible 5,000 N South Korea - Mar-16 Jun-19 Uncontracted - Speculative/Other

North Atlantic DrillingWest Rigel Semisubmersible 10,000 40,000 Y Jurong Shipyard Pte Ltd Singapore 720 Halliburton Mar-12 Dec-15 Uncontracted - Estabilished Drillers

North Sea Rigs Beacon Atlantic Semisubmersible 1,650 26,247 Y Yantai CIMC Raffles China - National Oilwell Varco Jan-14 Dec-16 Uncontracted - Speculative/Other

North Sea Rigs Beacon Pacific Semisubmersible 1,640 26,247 Y Yantai CIMC Raffles China - National Oilwell Varco Dec-14 Dec-17 Uncontracted - Speculative/Other

North Sea Rigs North Dragon Semisubmersible 1,650 26,247 Y Yantai CIMC Raffles China - National Oilwell Varco Feb-12 Dec-15 Uncontracted - Speculative/Other

Not known Joatinga Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 Aker Solutions Baker Hughes Nov-12 Jul-19 Uncontracted - Speculative/Other

Not known Pacific Zonda Drillship 10,000 40,000 N Samsung Heavy Industries South Korea 634 Shaffer Schlumberger Jan-13 Dec-15 Uncontracted - Speculative/Other

Ocean Rig Ocean Rig Amorgos Drillship 12,000 40,000 N Samsung Heavy Industries South Korea 743 Shaffer Apr-14 Feb-19 Uncontracted - Risky Drillers

Ocean Rig Ocean Rig Crete Drillship 12,000 40,000 N Samsung Heavy Industries South Korea 743 National Oilwell Varco Apr-14 Feb-18 Uncontracted - Risky Drillers

Ocean Rig Ocean Rig Santorini Drillship 12,000 40,000 N Samsung Heavy Industries South Korea 644 National Oilwell Varco Shaffer Schlumberger Sep-13 Jun-17 Uncontracted - Risky Drillers

Odebrecht Boipeba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 National Oilwell Varco Halliburton Apr-12 Jan-18 Petrobras 15.6 Petrobras

Odebrecht Botinas Semisubmersible 10,000 32,808 N BrasFELS Brazil 968 National Oilwell Varco Halliburton Mar-12 Aug-19 Petrobras 15.4 Petrobras

Odebrecht Interlagos Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Brazil 799 National Oilwell Varco Halliburton Apr-12 Sep-18 Petrobras 15.7 Petrobras

Odebrecht Ondina Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Japan 799 National Oilwell Varco Halliburton Dec-12 Jul-16 Petrobras 15.1 Petrobras

Odebrecht Pituba Drillship 10,000 35,000 N Estaleiro Enseada do Paraguacu Japan 799 National Oilwell Varco Halliburton Apr-12 May-17 Petrobras 15.1 Petrobras

Odfjell Galvao Deepsea Guarapari Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Singapore 900 Cameron Baker Hughes Feb-12 Nov-16 Petrobras 15.0 Petrobras

Odfjell Galvao Deepsea Itaoca Drillship 10,000 40,000 N Estaleiro Jurong Aracruz Singapore 841 Cameron Baker Hughes Mar-12 Nov-16 Petrobras 15.9 Petrobras

Odfjell Galvao Deepsea Siri Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 933 Cameron Baker Hughes Mar-12 Dec-18 Petrobras 15.1 Petrobras

Opus Offshore Opus Tiger 2 Drillship 5,000 32,808 N Shanghai Shipyard China - Honghua Group Cameron Sep-11 Jul-16 Uncontracted - Speculative/Other

Opus Offshore Opus Tiger 3 Drillship 5,000 32,808 N Shanghai Shipyard China - Honghua Group Cameron Mar-14 Oct-16 Uncontracted - Speculative/Other

Opus Offshore Opus Tiger 4 Drillship 5,000 32,808 N Shanghai Shipyard China - Honghua Group Cameron Mar-14 Oct-17 Uncontracted - Speculative/Other

Orion Engineering and Management LtdOrion Semi Tbn1 Semisubmersible 3,000 32,800 N Honghua China 320 Oct-15 Jun-18 Uncontracted - Speculative/Other

Petrobras Arpoador Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 877 Cameron B J Services Feb-11 Mar-16 Petrobras 20.1 Petrobras

Petrobras Copacabana Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 National Oilwell Varco B J Services Jun-11 Feb-16 Petrobras 20.1 Petrobras

Petrobras Grumari Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 National Oilwell Varco B J Services Jun-11 Jul-16 Petrobras 10.3 Petrobras

Petrobras Ipanema Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 National Oilwell Varco B J Services Jun-11 Mar-17 Petrobras 10.3 Petrobras

Petrobras Leblon Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 National Oilwell Varco B J Services Jun-11 Nov-17 Petrobras 10.3 Petrobras

Petrobras Leme Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 National Oilwell Varco B J Services Jun-11 Jul-18 Petrobras 10.3 Petrobras

Petrobras Marambaia Drillship 10,000 32,808 N Estaleiro Atlantico Sul Brazil 662 National Oilwell Varco B J Services Feb-11 Dec-18 Petrobras 10.6 Petrobras

Petroserv Frade Semisubmersible 10,000 32,808 N BrasFELS Brazil 862 National Oilwell Varco Halliburton Mar-12 Dec-16 Petrobras 15.4 Petrobras

Petroserv Portogalo Semisubmersible 10,000 32,808 N BrasFELS Brazil 841 National Oilwell Varco Halliburton Mar-12 Apr-18 Petrobras 15.4 Petrobras

Floater Newbuilds



Floater Newbuilds (Cont.)


Water Drilling N Sea Build Order Delivery Contract

Manager Rig Name Rig Type Depth Depth Capable Shipyard Country Cost Drilling Package BOP Cementing Date Date Operator Duration Category

Queiroz Galvao Bracuhy Semisubmersible 10,000 32,808 N BrasFELS Brazil 839 National Oilwell Varco Halliburton Mar-12 Aug-17 Petrobras 15.4 Petrobras

Queiroz Galvao Mangaratiba Semisubmersible 10,000 32,808 N BrasFELS Brazil 939 National Oilwell Varco Halliburton Mar-12 Dec-18 Petrobras 15.4 Petrobras

Queiroz Galvao Urca Semisubmersible 10,000 32,808 N BrasFELS Brazil 901 National Oilwell Varco Halliburton Dec-11 Feb-16 Petrobras 15.5 Petrobras

Seadrill Camburi Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Singapore 838 Cameron Baker Hughes Mar-12 Dec-16 Petrobras 15.4 Estabilished Drillers

Seadrill Itaunas Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 842 Aker Solutions Cameron Baker Hughes Mar-12 Apr-18 Petrobras 16.1 Estabilished Drillers

Seadrill Sahy Drillship 10,000 32,808 N Estaleiro Jurong Aracruz Brazil 964 Cameron Baker Hughes Mar-12 Aug-19 Petrobras 16.1 Estabilished Drillers

Seadrill Sevan Developer Semisubmersible 10,000 35,000 N COSCO Qidong China 526 Aker Kvaerner Cameron B J Services May-11 Apr-16 Uncontracted - Estabilished Drillers

Seadrill West Aquila Drillship 12,000 37,400 N Daewoo South Korea 600 Shaffer Jul-13 Jun-16 Uncontracted - Estabilished Drillers

Seadrill West Dorado Drillship 12,000 37,400 N Samsung Heavy Industries South Korea 600 Jul-13 Mar-17 Uncontracted - Estabilished Drillers

Seadrill West Draco Drillship 12,000 37,400 N Samsung Heavy Industries South Korea 600 Jul-13 Mar-17 Uncontracted - Estabilished Drillers

Seadrill West Libra Drillship 12,000 37,400 N Daewoo South Korea 600 Jul-13 Jun-16 Uncontracted - Estabilished Drillers

Songa Offshore Songa Enabler Semisubmersible 1,640 27,887 Y Daewoo South Korea 685 Baker Hughes Feb-12 Mar-16 Statoil 8.2 Risky Drillers

Songa Offshore Songa Encourage Semisubmersible 1,640 27,887 Y Daewoo South Korea 685 Baker Hughes Feb-12 Nov-15 Statoil 8.4 Risky Drillers

Stena Stena MidMax Semisubmersible 6,562 35,270 Y Samsung Heavy Industries South Korea 800 National Oilwell Varco Cameron Jul-13 Apr-16 Uncontracted - Estabilished Drillers

Transocean Deepwater Conqueror Drillship 10,000 40,000 N Daewoo South Korea 840 Cameron Oct-13 Oct-16 Chevron 5.2 Estabilished Drillers

Transocean Deepwater Pontus Drillship 10,000 40,000 N Daewoo South Korea 875 Cameron Sep-12 Sep-17 Shell 10.0 Estabilished Drillers

Transocean Deepwater Poseidon Drillship 10,000 40,000 N Daewoo South Korea 885 Cameron Schlumberger Sep-12 Dec-17 Shell 10.2 Estabilished Drillers

Transocean Deepwater Proteus Drillship 10,000 40,000 N Daewoo South Korea 840 Cameron Schlumberger Sep-12 Dec-15 Shell 10.3 Estabilished Drillers

Transocean Transocean Drsh Tbn1 Drillship 10,000 40,000 N Jurong Shipyard Pte Ltd Singapore 800 National Oilwell VarcoNational Oilwell Varco Feb-14 May-19 Uncontracted - Estabilished Drillers

Transocean Transocean Drsh Tbn2 Drillship 10,000 40,000 N Jurong Shipyard Pte Ltd Singapore 790 National Oilwell Varco Feb-14 Feb-20 Uncontracted - Estabilished Drillers

Vantage Drilling Sonangol Libongos Drillship 12,000 40,000 N Daewoo South Korea 620 Oct-13 Dec-15 Uncontracted - Risky Drillers

Vantage Drilling Sonangol Quenguela Drillship 12,000 40,000 N Daewoo South Korea 620 Oct-13 Mar-16 Uncontracted - Risky Drillers


Key Offshore Rig Market Metrics


Floater Fleet Snapshot OPERATOR CONTRACTED FLEET NOT CONTRACTED FLEET NEWBUILDS

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Transocean 26 - 2 - - 2 - 4 1 35 66% 76% 4 3 - - - - 1 - - 10 - 18 11 7 4 2 6 1 59

Diamond Offshore 12 - - - - 1 1 1 1 16 62% 80% - 3 1 - - - - - - 6 - 10 4 6 1 - 1 - 27

Ensco 11 - 2 - - 1 1 - - 15 58% 75% 4 - - - - - - - - 7 - 11 5 6 - 1 1 - 27

Seadrill 18 - - - - 1 - - - 19 83% 86% - 3 - - - - - - - 1 - 4 3 1 3 5 8 2 31

Noble 11 - 4 - - - - - - 15 88% 94% - 1 - - - - - - - 1 - 2 1 1 - - - - 17

Ocean Rig 8 - 1 - - 1 - - - 10 91% 91% - 1 - - - - - - - - - 1 1 - - 3 3 2 14

Saipem 4 - 1 - - - - 1 - 6 75% 75% - 1 - - 1 - - - - - - 2 2 - - - - - 8

Maersk Drilling 8 - - - - - - - - 8 100% 100% - - - - - - - - - - - - - - - - - - 8

Atwood 6 - - - - - - - - 6 100% 100% - - - - - - - - - - - - - - - 2 2 - 8

Stena 4 - - - - - - 1 - 5 71% 71% 1 1 - - - - - - - - - 2 2 - - 1 1 - 8

Odfjell Drilling 4 - - - - - - 2 - 6 86% 100% - - - - - - - - - 1 - 1 - 1 - - - - 7

Pacific Drilling 5 - - - - - - - - 5 71% 71% 2 - - - - - - - - - - 2 2 - - - - - 7

Schahin 1 - - - - - - - - 1 25% 25% 3 - - - - - - - - - - 3 3 - - - - - 4

Paragon Offshore 3 - - - - - - - - 3 60% 75% - - - - - - 1 - - 1 - 2 1 1 - - - - 5

North Atlantic Drilling 1 - - - - - - 1 - 2 50% 67% - 1 - - - - - - - 1 - 2 1 1 - 1 1 - 5

Songa Offshore 3 - - - - - - - 1 4 80% 80% - 1 - - - - - - - - - 1 1 - 2 - 2 - 7

Vantage Drilling 2 - - - - - - - - 2 67% 67% - - 1 - - - - - - - - 1 1 - - 2 2 - 5

Awilco Drilling - - - - - 1 - - - 1 50% 50% 1 - - - - - - - - - - 1 1 - - - - - 2

Rowan 4 - - - - - - - - 4 100% 100% - - - - - - - - - - - - - - - - - - 4

Frigstad Offshore - - - - - - - - - - 0% 0% - 1 - - - - - - - - - 1 1 - - 2 2 - 3

Songa Opus Offshore Drilling - 1 - - - - - - - 1 50% 50% 1 - - - - - - - - - - 1 1 - - - - - 2

Aban Offshore 1 - - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - 1

Essar Oilfields Services - - - - - - - - - - 0% 0% - 1 - - - - - - - - - 1 1 - - - - - 1

Other 9 - 1 - - 1 - - - 11 44% 50% 4 7 - 1 - - - - - 2 - 14 11 3 - 9 9 3 34

TOTAL COMPETITIVE 141 1 11 - - 8 2 10 3 176 69% 77% 20 24 2 1 1 - 2 - - 30 - 80 53 27 10 28 38 8 294

SPECULATORS/SHIPYARDS

CIMC Raffles Offshore - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 2 2 2 2

Keppel FELS - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 1 1 - 1

PBR / BRAZIL

Odebrecht 6 - - - - - - - 1 7 100% 100% - - - - - - - - - - - - - - 5 - 5 3 12

QGOG Constellation 9 - - - - - - - - 9 100% 100% - - - - - - - - - - - - - - - - - - 9

Petrobras 4 - - - - - - - - 4 100% 100% - - - - - - - - - - - - - - 7 - 7 2 11

Odfjell Galvao - - - - - - - - - - -- -- - - - - - - - - - - - - - - 3 - 3 1 3

Etesco 1 - 1 - - - - - - 2 100% 100% - - - - - - - - - - - - - - - - - - 2

Etesco / OAS - - - - - - - - - - -- -- - - - - - - - - - - - - - - 5 - 5 3 5

Queiroz Galvao - - - - - - - - - - -- -- - - - - - - - - - - - - - - 3 - 3 - 3

NOC's

COSL 5 - 3 - - - 1 - - 9 82% 82% 1 1 - - - - - - - - - 2 2 - - 1 1 - 12

Petroserv 3 - - - - - - - - 3 75% 75% - - - - - - 1 - - - - 1 1 - 2 - 2 - 6

IPC 3 - - - - - - - - 3 100% 100% - - - - - - - - - - - - - - - - - - 3

Caspian Drilling 1 - - - - 1 - - - 2 100% 100% - - - - - - - - - - - - - - - 1 1 - 3

Gazflot - - - - - - - 2 - 2 100% 100% - - - - - - - - - - - - - - - - - - 2

ONGC 1 - - - - 1 - - - 2 100% 100% - - - - - - - - - - - - - - - - - - 2

KNOC 1 - - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - 1 1 - 2

PetroSaudi - - 1 - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - 1

SOCAR - - - - - - - - - - 0% -- - - - - - - - - 2 1 - 3 - 3 - - - - 3

North Sea Rigs - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 3 3 - 3

Arktikmor - - - - - - - - - - 0% 0% 1 - - - - - - - - - - 1 1 - - - - - 1

TOTAL OTHER 34 - 5 - - 2 1 2 1 45 87% 92% 2 1 - - - - 1 - 2 1 - 7 4 3 25 9 34 11 86

TOTAL FLEET 175 1 16 - - 10 3 12 4 221 72% 79% 22 25 2 1 1 - 3 - 2 31 - 87 57 30 35 37 72 19 380

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OPERATOR CONTRACTED FLEET NOT CONTRACTED FLEET NEWBUILDS

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Ensco 25 - - - - - - - 1 26 63% 76% 4 2 1 - - - - - - 8 - 15 8 7 - 3 3 - 44

Shelf Drilling 25 - - - - 1 - 4 - 30 81% 86% 1 2 - - - - 1 - - 3 - 7 5 2 2 - 2 - 39

Hercules Offshore 7 - - - - - 1 - - 8 30% 44% 2 8 - - - - - - - 9 - 19 10 9 1 1 2 - 29

Paragon Offshore 14 - - - - 1 - - - 15 48% 71% 1 5 - - - - - - - 10 - 16 6 10 - - - - 31

Rowan 15 - 1 - - 4 - - 1 21 75% 81% - 3 - - - - 2 - - 2 - 7 5 2 - - - - 28

Seadrill 11 - - - - - - - - 11 69% 69% 2 2 - - - - - - - - 1 5 5 - - 8 8 - 24

National Drilling 16 - - - - 1 - - - 17 100% 100% - - - - - - - - - - - - - - - 3 3 - 20

Maersk Drilling 12 - - - - - - - - 12 92% 92% - - - - - - 1 - - - - 1 1 - 1 - 1 - 14

Aban Offshore 8 - - - - 1 - - - 9 60% 60% 6 - - - - - - - - - - 6 6 - - - - - 15

Noble 10 - - - - - - 1 1 12 86% 86% - - - - - 1 1 - - - - 2 2 - 1 - 1 - 15

Transocean 7 - - - - - - - - 7 70% 100% - 1 - - - - - - - 2 - 3 - 3 - 5 5 1 15

Atwood 3 - - - - - - - - 3 60% 60% 2 - - - - - - - - - - 2 2 - - - - - 5

Saipem 5 - - - - 1 - - - 6 100% 100% - - - - - - - - - - - - - - - - - - 6

Nabors 4 - - - - - - - - 4 67% 100% - - - - - - - - - 2 - 2 - 2 - - - - 6

Diamond Offshore 1 - - - - - - - - 1 17% 100% - - - - - - - - - 5 - 5 - 5 - - - - 6

Vantage Drilling 2 - - - - - 1 - - 3 75% 75% - 1 - - - - - - - - - 1 1 - - - - - 4

North Atlantic Drilling 3 - - - - - - - - 3 100% 100% - - - - - - - - - - - - - - - - - - 3

Other 87 - 4 - - 5 - 1 (3) 98 60% 69% 20 20 - 1 - - 2 - 2 19 (2) 64 44 20 2 32 34 4 196

TOTAL COMPETITIVE 255 - 5 - - 14 2 6 - 286 65% 75% 38 44 1 1 - 1 7 - 2 60 (1) 155 95 60 7 52 59 5 500

SPECULATORS/OTHER 11 - - - - - - - - 11 79% 79% 1 1 - - - - - - - 1 - 3 3 - - 45 45 1 59

PBR / BRAZIL

Petrobras 2 - - - - - - - - 2 50% 100% - - - - - - - - - 2 - 2 - 2 - - - - 4

NOC's

COSL 26 - 2 - - 1 - - - 29 88% 88% 4 - - - - - - - - - - 4 4 - - 2 2 - 35

Gazflot - - - - - - - 2 - 2 100% 100% - - - - - - - - - - - - - - - - - - 2

ONGC 6 - - - - - - - - 6 100% 100% - - - - - - - - - - - - - - - - - - 6

Sinopec - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 1 1 - 1

SOCAR - - - - - - - - - - 0% -- - 1 - - - - - - 1 1 - 3 - 3 - - - - 3

North Sea Rigs - - - - - - - - - - -- -- - - - - - - - - - - - - - - - - - - -

Arktikmor 1 - - - - - - - - 1 100% 100% - - - - - - - - - - - - - - - - - - 1

PV Drilling 2 - 1 - - - - - - 3 75% 75% - 1 - - - - - - - - - 1 1 - - - - - 4

Vietsovpetro 4 - - - - - - - - 4 100% 100% - - - - - - - - - - - - - - 1 - 1 - 5

PEMEX 2 - - - - - - - - 2 100% 100% - - - - - - - - - - - - - - - - - - 2

Arabian Drilling 5 - - - - - - - - 5 83% 83% - 1 - - - - - - - - - 1 1 - - - - - 6

Gulf Drilling International 7 - - - - - - - - 7 78% 78% - - - - - - 2 - - - - 2 2 - 1 - 1 - 10

Teniz Burgylau - - - - - - - - - - -- -- - - - - - - - - - - - - - - 1 - 1 - 1

MEXICAN PLAYERS

Grupo R - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 6 6 - 6

Oro Negro 4 - - - - - - - - 4 80% 80% 1 - - - - - - - - - - 1 1 - - 3 3 - 8

Perforadora Central 2 - - - - - - - - 2 33% 33% 2 1 - - - - - - - - 1 4 4 - - 1 1 - 7

SHIPYARDS

PPL Shipyard - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 4 4 - 4

CIMC Raffles Offshore - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 2 2 2 2

Keppel FELS - - - - - - - - - - -- -- - - - - - - - - - - - - - - - 1 1 - 1

TOTAL OTHER 72 - 3 - - 1 - 2 - 78 79% 83% 8 5 - - - - 2 - 1 4 1 21 16 5 3 65 68 3 167

TOTAL FLEET 327 - 8 - - 15 2 8 - 364 67% 77% 46 49 1 1 - 1 9 - 3 64 - 176 111 65 10 117 127 8 667

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Jackup Fleet Snapshot



Regional View of Floater Fleet


6G 5G 4G 3G 2G Total

C NC Util. C NC Util. C NC Util. C NC Util. C NC Util. C NC Util. Total

US GOM 43 5 90% 4 - 100% - - -- - - -- - 4 -- 47 9 84% 56

S America 29 2 94% 6 1 86% 2 - 100% 5 - 100% 7 1 88% 49 4 92% 53

NW Europe 10 3 77% 3 2 60% 6 - 100% 14 4 78% 5 4 56% 38 13 75% 51

W Africa 27 6 82% 2 7 22% - 1 -- - 1 -- 1 3 25% 30 18 63% 48

SE Asia 4 2 67% 1 3 25% - 2 -- 1 2 33% 5 4 56% 11 13 46% 24

Far East 4 2 67% - 1 -- 1 - 100% 4 2 67% 2 - 100% 11 5 69% 16

Med/Black Sea 1 - 100% 2 - 100% - - -- 2 1 67% 1 2 33% 6 3 67% 9

Aus/NZ 1 - 100% 1 - 100% 2 - 100% 2 - 100% 1 1 50% 7 1 88% 8

C America - 4 -- - 6 -- - 1 -- 1 - 100% 2 - 100% 3 11 21% 14

Indian Ocean 1 1 50% 1 - 100% 1 - 100% 1 2 33% 1 1 50% 5 4 56% 9

Caspian 1 - 100% 1 - 100% 1 - 100% 1 3 25% - - -- 4 3 57% 7

Mexico 4 - 100% - - -- - - -- - - -- 1 - 100% 5 - 100% 5

Canada East 3 - 100% - - -- - - -- - 1 -- - - -- 3 1 75% 4

Middle East - - -- - - -- - - -- - 1 -- - 1 -- - 2 -- 2

US Pacific - - -- - - -- - - -- 1 - 100% 1 - 100% 2 - 100% 2

US Alaska - - -- - - -- - - -- - - -- - - -- - - -- -

Baltic - - -- - - -- - - -- - - -- - - -- - - -- -

128 25 84% 21 20 51% 13 4 76% 32 17 65% 27 21 56% 221 87 72% 308


Premium High Spec. Standard HE Legacy/ (Non IC) Total

C NC Util. C NC Util. C NC Util. C NC Util. C NC Util. C NC Util. Total

US GOM 3 5 38% 1 4 20% - 19 -- - - -- 4 30 12% 8 58 12% 66

S America 1 - 100% 3 - 100% - - -- - - -- 3 4 43% 7 4 64% 11

NW Europe - - -- - - -- - 1 -- 39 11 78% 1 - 100% 40 12 77% 52

W Africa 6 2 75% 6 1 86% 3 9 25% - - -- - - -- 15 12 56% 27

SE Asia 21 15 58% 6 8 43% 11 6 65% - - -- 1 4 20% 39 33 54% 72

Far East 5 2 71% 1 - 100% 7 - 100% - - -- 21 - 100% 34 2 94% 36

Med/Black Sea 4 1 80% 1 1 50% 3 2 60% - - -- 2 1 67% 10 5 67% 15

Aus/NZ 2 1 67% - - -- - - -- - - -- - - -- 2 1 67% 3

C America 1 - 100% 1 - 100% - - -- - - -- 1 1 50% 3 1 75% 4

Indian Ocean - - -- 10 1 91% 22 1 96% - - -- 2 1 67% 34 3 92% 37

Caspian - - -- 2 1 67% 3 - 100% - - -- 1 3 25% 6 4 60% 10

Mexico 18 3 86% 7 1 88% 9 5 64% - - -- - 2 -- 34 11 76% 45

Canada East - - -- - - -- - - -- - - -- - - -- - - -- -

Middle East 24 4 86% 11 4 73% 65 20 76% - - -- 29 2 94% 129 30 81% 159

US Pacific - - -- - - -- - - -- - - -- - - -- - - -- -

US Alaska - - -- - - -- - - -- - - -- 1 - 100% 1 - 100% 1

Baltic - - -- 2 - 100% - - -- - - -- - - -- 2 - 100% 2

85 33 72% 51 21 71% 123 63 66% 39 11 78% 66 48 58% 364 176 67% 540

Regional View of Jackup Fleet



Subsea Equipment Market: Favorable Offshore Exposure


Subsea Equipment Screens Well, As Sentiment & 2016/2017 Orders Return to Chase Project Opportunity Set Equipment Providers Better Risk/Reward for Offshore Exposure Than Offshore Drillers. As outlined by our proprietary offshore equipment demand model, the outlook for subsea tree and offshore equipment demand (deliveries) looks challenged in 2016/2017. New tree orders should begin to recover from a low in 2015, but not near 2012/2013 peaks until 2020 and beyond. Facing fewer structural challenges than the offshore drillers, offshore equipment providers may provide a better risk/reward as a means to play the offshore space for four reasons: 1. No Supply Glut. Equipment players may see plant capacity fall to ~60% (pg. 103), but do not suffer from a major supply glut that may require meaningful attrition and/or spur disorderly market

activity beyond standard industry concessions on pricing. 2. Group Gets More Multiple Credit For Growth from Inventory of Demand. The group is more likely to expand multiples as the commodity rebounds and investors discount higher growth due a

higher inventory of potential projects (pg. 100). 3. Drive for Lower Breakeven Levels for Deepwater Projects Co-opts Equipment Players. The process of upstream operators identifying equipment standardization opportunities and discovering

process efficiencies likely co-opts the offshore equipment players, which helps to solidify the consolidation of the industry to fewer relevant competitors. In our view, greater connection between downhole and mudline solutions, with a greater technology overlay, further limits the number of higher-end versus second tier providers over time.

4. Cost Cutting & Efficiencies Drive Better Economics As Cycle Turns. Cost efficiencies and more streamlined organizations may help margins as offshore activity recovers. Pricing power may lag the eventual cyclical recovery, but lower project breakeven costs, as a positive outgrowth of the current downturn, may help to improve volumes in the recovery.

We Favor FTI & SLB, as Industry Evolution Favors Scale Efficiency, & Technology. The largest offshore upstream operators continue to struggle with returns vs. growth. We believe that offshore cost overruns, which have skewed returns and angered investors, may fade with lower project break-even economics. Deepwater plays, once frontier projects, may begin to benefit from greater experience, higher process efficiency, and greater levels of standardization as the deepwater asset class matures. Coincidentally, the accountants may begin to outweigh engineers, as returns, versus engineering marvels, move to prominence. In practice, upstream operators may need to seek equipment providers that can co-create and standardize solutions, add value with intellectual property that lowers unit cost, and maintains efficiency to the point of installation. In our view, SLB and FTI vault above GE ($30.26, NR) and AKSO (NOK34.36, NR), the other major players in the space that have suffered from different stumbling blocks, including staffing departures, execution issues, and restructurings. SLB may bring the most to the table in terms of innovation, likely through linkage between downhole and mudline architectures. In our view, FTI offers the most “pure-play” exposure, with its Forsys JV with Technip, which may compete better on efficiencies, scale, standardization, and expertise that may enter projects earlier at the FEED study phase.

Proprietary Subsea Tree Model Forecasts Slight Rebound in 2016 Deliveries, Meaningful Order Recovery Waits for 2017. Under the same probability weighting mechanism applied to offshore rig demand, we forecast flat to down subsea equipment deliveries, as equipment providers work through inventories, with anemic subsea tree orders below low 2014 levels in 2016. In our view, tree orders may recover to levels above the 2014 order run rate in 2017-2019, but not near 2012 and 2013 peak order flow until 2020 and beyond. A linear relationship, lower order flow from 2014-2016, must impact deliveries beyond 2016, and hamper the economics of the subsea tree business. A higher proportion of manifolds and other complex equipment elements may prove subsea trees alone a conservative benchmarking tool (pg. 103). Our subsea tree demand outlook leaves equipment players subject to a lower run rate of activity. As upstream operators work through project inventories to lower breakeven costs, we maintain a more bullish bias that our outlook may prove conservative. As investor sentiment towards growth turns positive, investors may expand offshore equipment stock multiples to discount the potential for a greater number of projects to materialize.

December 15, 2015 100

Forecast Subsea Tree Deliveries Sees Flattish Offshore Activity Given Project Delays

61

34

70

14

5

11

8

13

2

15

3

17

9

208

269

19

6

282

26

7

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3

18

6

29

4

30

3

402

36

0

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6

246

25

3

26

2 3

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28

3 33

1

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9

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Subsea Tree Deliveries - Raw Subsea Tree Deliveries - Probability Weighted

The scale of the potential tree demand list may provide room for upward revisions to our estimates, if probabilities for more projects improve. In our view, the possible upside may drive multiple expansion for the subsea equipment names with a turn in commodity markets

Forecasted Subsea Tree Deliveries vs. Potentially Bullish Inventory of Projects

Our forecast draws from the same data as our rig demand, which is probability weighted as outlined above for rig demand concerning the same projects. (See pg. 69)

Sources: KLR Group, LLC Forecast; Company Filings/Disclosures; Industry Data

December 15, 2015 101

Trees Ordered vs. Forecast Leaves 4Q15 Manageable, but Offers Sluggish Order Recovery Until 2017

438451

424437

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373

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414

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2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Expected Orders - Forecast Orders - Actual

KLR Subsea Tree Order Forecast vs. Actual Tree Orders

The falloff in orders in 2014 impacts the trajectories of deliveries in 2016 and beyond, given 2-3 year lead times on larger projects.


December 15, 2015 102

Greater Field Complexity Creates the Need for Economies of Learning To Lower Project Costs

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Midwater Deepwater Ultra-Deepwater According to our forecast deepwater and ultra-deepwater projects may continue to gain share in the proportion of equipment orders. Inexperience made a smaller number of initial projects expensive, and likely over-engineered. We anticipate that incremental projects may gain efficiencies and see lower cost gained from prior experience and standardization of equipment/practices.

We see the potential for a higher content of equipment in addition to trees to add to the dollar value of equipment package orders. In particular, manifolds, control systems, boosting, separation, and more automation may continue to lift revenue/per tree and support capacity utilization.


December 15, 2015 103

Subsea Equipment Manufacturing Utilization Declines May Hurt Fixed Costs Absorption, Pricing, & Economics

66%

37%

76%

97%

79%

88%87%90%91%

94%

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88%83%

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Total Capacity Utilization Total Deliveries Tree Capacity Utilization

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15

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16

20

17

20

18

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19

20

20

Subsea Tree Manufacturing Capacity & Utilization Manifold Delivery Forecast

Higher manifold deliveries, as a function of greater field complexity may help support capacity absorption.

Sources: KLR Group, LLC Forecast; Company Filings/Disclosures; Sources: KLR Group, LLC Forecast; Company Filings/Disclosures;

December 15, 2015 104

Concentration of Deliveries/Demand with Large Customers

Subsea Tree Deliveries – Probability Weighted Subsea Tree Orders – Probability Weighted Wells by company 2015 2016 2017 2018 2019 2020 TOTAL % Total

1 Petrobras 66 27 42 56 65 43 299 16%

2 Total 25 16 44 38 22 41 187 10%

3 Eni 21 23 33 30 14 8 129 7%

4 BP 13 12 16 22 38 25 126 7%

5 Shell 20 20 12 15 21 30 118 6%

6 Chevron 28 23 15 20 18 9 113 6%

7 ExxonMobil 24 20 16 14 21 10 104 6%

8 Statoil 24 9 19 9 19 15 95 5%

9 EnQuest 12 2 13 2 5 6 40 2%

10 Tullow - 20 7 7 3 3 41 2%

11 Anadarko 6 5 4 3 6 16 40 2%

12 Woodside 3 2 3 6 16 8 38 2%

13 Hess 5 - 4 9 10 7 34 2%

14 Noble 2 8 5 8 3 5 32 2%

15 Premier 3 - 14 8 2 4 31 2%

16 Husky 5 6 10 5 0 1 27 1%

17 Murphy 5 4 2 11 4 1 26 1%

18 CNOOC 7 1 4 4 8 6 30 2%

19 Inpex - 7 1 5 2 4 19 1%

20 Freeport-McMoRan 4 8 2 4 - - 18 1%

21 KNOC 3 7 - 2 3 2 17 1%

22 Eni CNPC - - - - 3 12 15 1%

23 Apache 5 7 - 1 1 1 15 1%

24 LLOG 6 3 4 2 - - 15 1%

25 ConocoPhill ips 2 - 3 2 1 8 16 1%

26 BG Group 6 - 3 4 1 - 14 1%

27 DNO RAK 2 4 3 3 1 1 13 1%

28 Canadian Natural Resources 4 3 2 1 2 - 12 1%

29 Wintershall-BASF - - 3 6 1 2 12 1%

30 BHP Bill iton 5 2 1 1 2 - 11 1%

Wells by company 2015 2016 2017 2018 2019 2020 TOTAL % Total

1 Petrobras 2 11 23 42 63 88 227 14%

2 Total 15 16 7 16 28 45 127 8%

3 Shell 7 28 21 17 26 19 118 7%

4 BP 19 9 26 19 17 15 105 7%

5 Chevron 3 19 22 12 10 30 96 6%

6 Eni 36 13 15 5 10 8 87 5%

7 Statoil 8 15 10 18 13 22 86 5%

8 ExxonMobil 1 18 15 21 12 15 82 5%

9 Anadarko 3 8 14 11 10 4 48 3%

10 Woodside 2 4 7 13 10 5 42 3%

11 Hess 1 4 19 6 1 2 33 2%

12 Noble 4 6 7 4 3 5 30 2%

13 Eni CNPC - - 15 - 5 4 24 2%

14 CNOOC 1 4 6 10 6 4 31 2%

15 ONGC 3 4 1 1 1 13 23 1%

16 Murphy 3 4 8 4 1 2 22 1%

17 Tullow - 7 5 3 3 3 22 1%

18 Cobalt - - - - - 16 16 1%

19 BG Group - 4 2 1 0 9 17 1%

20 PEMEX - 0 1 1 3 12 17 1%

21 ConocoPhillips - 3 2 4 6 2 17 1%

22 Queiroz Galvao 1 - - 5 4 3 13 1%

23 Apache 10 - 1 1 - - 12 1%

24 Husky - 7 5 0 0 - 12 1%

25 Cairn - - - 1 4 6 11 1%

26 BP SOCAR Statoil ExxonMobil Chevron Inpex TPAO Itochu ONGC- 3 3 - - 4 10 1%

27 EnQuest 2 0 2 1 - 5 10 1%

28 Premier - - 2 3 3 3 12 1%

29 Repsol Sinopec - - - 2 3 6 11 1%

30 Freeport-McMoRan 9 - - - - - 9 1%

Sources: KLR Group, LLC Forecast; Company Filings/Disclosures; Sources: KLR Group, LLC Forecast

December 15, 2015 105

OneSubsea, 22%

FMC, 43%

GEOG, 13%

Aker Solutions, 18%

Dril-Quip, 2%Others, 2%

Top 30 Subsea Tree Orders Customers: One Subsea & FMC Dominate Market Share

Market Share by Subsea Tree Orders Since 2005

OneSubsea FMC Dril-Quip

1 Petrobras 40% 35% 1% 24% --

2 Total 20% 53% 0% 27% --

3 Shell 1% 83% 15% -- --

4 Statoil -- 55% 8% 38% --

5 BP 63% 27% 10% -- --

6 Chevron 33% 32% 35% -- --

7 Eni 17% 21% 44% 19% --

8 ExxonMobil 14% 27% 59% -- --

9 EnQuest -- 49% 10% 41% --

10 BHP Billiton 92% -- 8% -- --

11 Tullow -- 96% 2% -- 2%

12 CNOOC 19% 19% 51% 11% --

13 Anadarko -- 98% 2% -- --

14 Husky 100% -- -- -- --

15 Woodside -- 73% 27% -- --

16 Murphy 9% 23% -- 63% 5%

17 Premier -- 11% 17% -- 71%

18 Noble 91% 6% -- 3% --

19 BG Group EGPC Petronas 100% -- -- -- --

20 Maersk -- -- 100% -- --

21 LLOG -- 100% -- -- --

22 ConocoPhillips -- 97% -- -- 3%

23 DNO RAK 8% -- -- 92% --

24 Hess 40% 56% 4% -- --

25 Reliance -- -- -- 100% --

26 PEMEX 32% 68% -- -- --

27 Freeport-McMoRan 50% 50% -- -- --

28 Sinopec 23% -- 77% -- --

29 Inpex -- -- 100% -- --

30 Centrica -- 20% 75% -- 5%

GEOG VetcoGray Aker Solutions

Subsea Tree Order Market Share 2010-2014

Operators listed in order of the number of tree orders since 2005

Source: Infield, Company Filings/Disclosures

Source: Infield, Company Filings/Disclosures

December 15, 2015 106

Companies

December 15, 2015 107

Large Cap Integrated Oilfield Services

December 15, 2015 108

Schlumberger: Buy, $105PT, Embracing Change: Scale, Technology, Transformation, & Business Model Evolution Investment Thesis. We are initiating coverage of SLB with a Buy rating and $105 price target. We are buyers of SLB for four key reasons. First, the company has the scale, footprint and market power to gain leverage across geographic markets within a recovery of exploration and development activity. Second, SLB’s process and efficiency transformation programs, applied across a large scope of businesses, may improve margins and asset turns through efficiency gains. Third, SLB’s technology leadership may continue to support higher margins and longer product cycles relative to peers. Last, a gravitation towards performance/incentive-based business models may help SLB capture upside from improved client economics provided from the company’s platform and expertise. In addition to upside to the turn in the cycle, given its positive free cash flow profile, the stock also serves as a defensive play within the oil services group. Our 2016 EPS lies near consensus, which suggest trough scenarios are reflected in the stock. Our above consensus 2017 EPS, suggests room for upward revisions, which may offer an upside catalyst for the shares.

Key Drivers

• Focus on Core Strengths and Transformation. SLB’s ability to draw on competitive advantages, particularly scale and geographic footprint, may lead to outperformance in an environment of shrinking budgets, limited visibility, a shift away from higher margin exploration work, and declining rig counts across regions. Given scale, SLB may drive internal transformation initiatives across processes and procurement that can lower costs (potentially up to 30%) to offset near term challenges to oilfield economics. Implemented across large scale operations, simple transformation initiatives that may better integrate of technology and workflow, lean/automated manufacturing, increase utilization (asset turns), and reduce non-productive time may improve returns. The 3Q/15 results already highlighted up to 30% capacity gains seen from multi-skilling employees to execute a number of different drilling services, instead of calling on several discrete service teams. In our view, incremental training cycles may implement further multi-skilling as well as more remote operation practices, which require less headcount per job. Since transformation initiative are in early stages, we see the opportunity for SLB to positively surprise on margins in coming quarters.

• Migration Toward Incentive-Based Models. SLB may continue to benefit from the expansion of incentive-based contracts, in integrated project management (IPM), production management (SPM), leasing contract models, and other bundled/integrated solutions, where the company may earn bonuses for increased efficiency, exceeding targets, and superior increases in production. Incentive-based arrangements align incentives with clients and play into SLB’s strengths in scale, footprint, technology, and efficiency/execution goals of its transformation initiatives. Currently, integrated service work represents 30%-40% of SLB’s business, with a large international footprint. As upstream operators look to lower per barrel costs, we see room for further penetration for integrated service arrangements that align economic incentives.

• Ability to Drive Technology Adoption. SLB may be able to drive further technology adoption, especially in international markets. In North America, where E&Ps are more skeptical of externally developed solutions, a focus on well cost versus economic recoveries may prove a hurdle to the use of novel technologies. International projects, where SLB may wield more control, allow for more technology adoption. We suspect that that an upturn in the cycle and return of more exploration may help SLB upsell higher margin, new technologies. In good times, new technologies may host incremental margins near 40%. In the near term, we are focused on the continued penetration of Broadband for well optimization in North America, the evolution of the Rig of the Future (automation and integrated drilling systems), and the linkage of downhole with the mudline through the CAM acquisition/OneSubsea, as potential positive catalysts.

• Execution of CAM Acquisition. In our view, the CAM acquisition may prove a test case for SLB transformation initiatives, alternate risk/performance-based business models, and drive for greater technology adoption. SLB’s ability to high-grade the CAM manufacturing operations and solutions may provide a positive catalyst for the shares. In addition to ~$600 million in cost synergies (headcount, back office, geographic bases, procurement), we see opportunities for technology advancement that links reservoir and well technology to wellhead and surface technology and introduces software/sensors/automation to lower cost per barrel. Better performance-based business models may reduce BOP downtime, with the introduction of automation and process improvements, which allows SLB/CAM to participate in improved economics. Implementation of SLB principles and addition of scale, may enhance growth (target 50% growth in first 5 years) and improve margins and returns of the legacy CAM operations, positive catalysts for SLB shares.

December 15, 2015 109

Schlumberger (SLB) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Oilfield Services 45,364 48,580 35,580 34,216 43,111 10,248 9,010 8,472 7,850 7,737 8,113 8,918 9,448 9,954 10,300 11,231 11,626

CAM 8,373 10,652 8,883 7,028 7,065 2,328 2,268 2,253 2,034 1,895 1,770 1,704 1,659 1,679 1,726 1,788 1,873

Total Revenues 53,737 59,232 44,463 41,244 50,177 12,576 11,278 10,725 9,884 9,632 9,883 10,622 11,107 11,632 12,026 13,019 13,499

Oilfield Services 9,404 10,576 6,515 5,368 8,071 1,993 1,708 1,521 1,293 1,216 1,234 1,381 1,537 1,674 1,852 2,162 2,383

CAM - - - 637 658 - - - - 193 163 142 138 142 152 169 195

Corporate & Other (725) (848) (769) (744) (843) (192) (199) (198) (180) (174) (178) (192) (200) (204) (205) (217) (217)

EBIT 8,679 9,728 5,747 5,260 7,887 1,801 1,509 1,323 1,114 1,235 1,219 1,331 1,475 1,612 1,799 2,115 2,361

Interest Income 23 31 31 33 49 8 6 8 9 10 5 9 9 10 11 13 14

Interest (Expense) (369) (347) (308) (299) (300) (76) (79) (78) (75) (75) (75) (75) (75) (75) (75) (75) (75)

EBT 8,333 9,412 5,470 4,994 7,636 1,733 1,436 1,253 1,048 1,171 1,149 1,265 1,409 1,548 1,735 2,053 2,300

Income Taxes (1,903) (2,063) (1,123) (996) (1,524) (362) (302) (250) (209) (234) (229) (252) (281) (309) (346) (410) (459)

Minority Interest (33) (67) (51) (56) (56) (13) (10) (14) (14) (14) (14) (14) (14) (14) (14) (14) (14)

Net Income (Operating) 6,397 7,282 4,296 3,942 6,056 1,358 1,124 989 825 923 906 999 1,114 1,225 1,375 1,629 1,827

Discontinued Operations - (205) - - - - - - - - - - - - - - -

Extraordinaries (after-tax) 469 (1,639) (383) - - (383) - - - - - - - - - - -

Net Income (GAAP) 6,866 5,438 3,913 3,942 6,056 975 1,124 989 825 923 906 999 1,114 1,225 1,375 1,629 1,827

EPS (Operating) 4.80 5.56 3.36 2.81 4.35 1.06 0.88 0.78 0.65 0.66 0.64 0.71 0.80 0.88 0.99 1.17 1.31

EPS (GAAP) 5.15 4.15 3.06 2.81 4.35 0.76 0.88 0.78 0.65 0.66 0.64 0.71 0.80 0.88 0.99 1.17 1.31

Dividend per Share 1.25 1.51 2.00 2.00 2.00 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50

Basic Shares Outstanding 1,323 1,296 1,269 1,396 1,387 1,276 1,269 1,265 1,265 1,400 1,398 1,395 1,393 1,390 1,388 1,386 1,383

Diluted Shares Outstanding 1,334 1,309 1,277 1,403 1,394 1,285 1,280 1,272 1,272 1,407 1,405 1,402 1,400 1,397 1,395 1,393 1,390

EBITDA 12,345 13,822 9,911 9,982 13,018 2,843 2,556 2,349 2,163 2,382 2,387 2,523 2,691 2,854 3,066 3,411 3,687

Depreciation & Amortization 3,666 4,094 4,164 4,721 5,131 1,042 1,047 1,026 1,049 1,146 1,168 1,191 1,216 1,241 1,268 1,296 1,326

Cash Flow Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Cash From Operations (CFO) 9,965 11,214 9,224 13,015 12,670 1,770 2,314 2,543 2,597 3,382 4,612 2,373 2,649 2,819 3,051 3,184 3,616

Capital Expenditures (3,943) (3,976) (2,574) (3,299) (4,014) (606) (587) (590) (791) (771) (791) (850) (889) (931) (962) (1,042) (1,080)

Free Cash Flow (FCF) 5,628 6,917 5,854 9,263 8,204 1,063 1,436 1,659 1,696 2,500 3,706 1,410 1,647 1,775 1,976 2,029 2,424

Acquisitions/Divestures/Investments (234) (1,302) 443 (2,772) - (109) 497 55 - (2,772) - - - - - - -

Cash From Financing (CFF) (4,597) (6,683) (5,345) (3,593) (3,573) (1,231) (878) (2,603) (633) (900) (899) (898) (896) (895) (894) (893) (892)

Other 2,236 (740) 153 - - (530) 163 520 - - - - - - - - -

Increase (Decrease) in Cash 3,033 (1,808) 1,105 2,898 4,630 (807) 1,218 (369) 1,063 (1,173) 2,808 512 751 880 1,082 1,136 1,532

Key Balance Sheet Statistics 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Total Capital 52,690 51,180 50,464 68,656 71,471 50,382 51,306 50,189 50,464 68,081 68,171 68,355 68,656 69,069 69,633 70,452 71,471

Total Debt 13,176 13,330 12,248 12,286 12,286 12,726 13,341 12,248 12,248 12,286 12,286 12,286 12,286 12,286 12,286 12,286 12,286

Net Debt 4,443 5,387 4,141 4,053 (577) 5,487 5,598 5,204 4,141 8,124 5,317 4,804 4,053 3,173 2,091 955 (577)

Debt/Total Capital 25.0% 26.0% 24.3% 17.9% 17.2% 25.3% 26.0% 24.4% 24.3% 18.0% 18.0% 18.0% 17.9% 17.8% 17.6% 17.4% 17.2%

Net Debt/Capital 8.4% 10.5% 8.2% 5.9% -0.8% 10.9% 10.9% 10.4% 8.2% 11.9% 7.8% 7.0% 5.9% 4.6% 3.0% 1.4% -0.8%

Total Debt/EBITDA 1.1X 1.0X 1.2X 1.2X 0.9X 1.1X 1.3X 1.3X 1.4X 1.3X 1.3X 1.2X 1.1X 1.1X 1.0X 0.9X 0.8X

BVPS 29.63 28.92 29.92 40.17 42.47 29.30 29.66 29.83 30.04 39.66 39.79 39.99 40.27 40.64 41.11 41.77 42.57

TBVPS 15.07 13.53 14.16 12.30 14.40 13.67 14.00 14.00 14.22 11.85 11.94 12.09 12.33 12.64 13.07 13.68 14.44

December 15, 2015 110

Schlumberger (SLB) Valuation PRICE TARGET SCENARIOS

Disc Rate EBITDA Multiple PV/Equity Target Upside $Millions 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E

0.4% 235.3x $230,327 $164 135% Levered Cash Flow:

2.4% 41.2X $209,648 $150 115% Net Income 5,534.0 6,866.0 5,438.0 3,912.8 3,941.8 6,056.4 9,200.8 11,215.1 13,116.8

4.4% 22.6X $191,203 $136 95% Depreciation & Amortization 3,466.0 3,666.0 4,094.0 4,163.9 4,721.2 5,131.5 5,630.5 6,238.2 6,970.9

6.4% 15.6X $174,713 $125 79% Capitalized Interest - - - - - - - - -

8.4% 11.9X $159,939 $114 63% Deferred Taxes (76.0) 832.3 55.0 52.9 252.1 385.5 583.7 710.8 830.7

10.4% 9.6X $146,673 $105 50% Translation Adjustment Other - - - - - - - - -

12.4% 8.0X $134,737 $96 37% Operating Cash Flow (before working cap.) 8,924.0 11,364.3 9,587.0 8,129.5 8,915.2 11,573.3 15,415.1 18,164.0 20,918.4

14.4% 6.9X $123,977 $89 27% Net Cash from Investing Activities (6,768.0) (4,177.0) (5,278.0) (2,130.7) (6,072.0) (4,014.1) (4,880.7) (5,938.1) (7,071.4)


18.4% 5.4X $105,464 $75 7% Capitalized G&A - - - - - - - - -

20.4% 4.9X $97,492 $70 0% Less: Net Capital Expenditures (before Cap Int) 6,768.0 4,177.0 5,278.0 2,130.7 6,072.0 4,014.1 4,880.7 5,938.1 7,071.4

Working Capital Change (2,287.0) (1,227.0) 1,897.0 952.9 3,767.7 765.2 (1,059.6) (536.4) (850.9)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 1,636.0 (393.0) (37.0) (1,142.0) - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 2,807.0 8,807.3 2,449.0 6,187.9 (924.5) 6,794.0 11,593.9 12,762.4 14,697.9

Risk Free Rate 4.00% Terminal Multiple 9.6X

Debt Risk Spread 200 EBITDA 23,576.5

Equity Risk Premium 6.0% Terminal Enterprise Value 226,153.2

Beta (Adjusted) 1.10 Subtract: Long Term Debt (Terminal Year) (12,286.0)

Cost of Equity 12.6% Subtract: Preferred Stock (Terminal Year) -

Marginal Cost of Debt 6.0% Add: Cash (Terminal Year) 34,950.3

Cost of Debt, after tax 3.9% Subtract Levered FCF from Operations for Explict Forecast (44,923.7)

Net Debt/Total Capital 25.0% Subtract: Changes in Equity for Explict Forecast -

WACC 10.4% Subtract: Dividends for Explict Forecast (13,778.5)

Terminal Multiple: 9.6X Terminal Value (1) 190,115.4

Levered Free Cash Flow (2) (924.5) 6,794.0 11,593.9 12,762.4 204,813.3

(1) Reflects a ~10.4% WACC applied to 2020 EBITDA. Terminal value is computed at year-end 2020.

(2) Assumes investment occurs at beginning of year, levered free cash flow is year-end.

Discounted Cash Flow Analysis

December 15, 2015 111

Company Risks Macro: • Sustained Weakness in Commodity Prices. Persistent weakness in commodity prices may negatively impact oilfield service company returns. This risk is magnified for companies with weaker

balance sheets and higher near term liabilities. • Access to Capital Markets: The ability of many oilfield service companies to withstand the downturn hinges on their access to capital. If capital markets begin to close off to the industry it would be

difficult for many companies to maintain their existing operating plans. • Foreign Exchange Volatility. The sector’s international component leaves earnings exposed to foreign exchange volatility. • Climate Change Regulation. The increased attention on climate change and greenhouse gas (GHG) emissions could lead to new regulations aimed at limiting future GHG emissions. If enacted these

regulations could impose additional costs for both operators and service providers.

Company Centric: • Contracting Risk: The new and rolling contracts across the oil services business may perpetuate lower dayrates and falling contract pricing, even if renegotiations occur during the initial phases of a

recovery. • Continued Oversupply in Rig Market: Day rates could remain depressed if the rig market remains oversaturated resulting from fewer rig retirements than forecasted. • Rig Productivity Gains: If onshore rigs continue to achieve new productivity gains, the demand for onshore rigs could continue to deteriorate, particularly in the lower end of the onshore rig

market. Greater levels of efficiency and productivity gains may limit demand for rigs and services. • Lumpy Cash Flows: The lumpy nature of the equipment & manufacturing industry could cause a significant lag between the recovery in the oil and gas industry and the improvement in the

equipment & manufacturing industry’s cash flow position. • Cost Escalation: Fixed price long term contracts common in the oilfield equipment & manufacturing leave industry participants particularly vulnerable to cost increases. This risk could be magnified

for contracts entered into during a low price environment. • Adoption of New Technologies: Many providers are relying on new technologies to improve margins. However, there is a risk that the industry may continue to prefer lower cost options.

Alternatively, selection of technology will create upside for winners and risks for losers.

December 15, 2015 112

Halliburton: Accumulate, $46PT, Visibility & Integration Risks Leave Us Cautious Investment Thesis. We are initiating coverage of HAL with an Accumulate rating and $46 price target. HAL is ideally positioned amongst the integrated services companies to benefit from the early stages of recovery led by North American land activity. Longer term, we see the addition of BHI product lines and consolidation of competition, across geographies as a positive. In our view, these positives are reflected in the upside to our mid-cycle valuation. Nearer term, we remain cautious. In our view, 4Q15 and 2016 consensus EPS looks high and concerns around closing the BHI transaction, including the status and pricing of divestitures, overhang the shares. As our model attempts to consolidate BHI, we see greater concerns around a lack of visibility on the speed at which HAL can integrate and close the performance/margin gap for laggard BHI operations, which were historically plagued by execution and supply chain issues. Given recent releases that suggest information system integration may take 1-2 years, internal measurement, tracking, and management adjustments may not be seamless, even for the highly competent team at HAL. These nagging factors leaves our combined company 2016 EPS well below consensus, which may present a risk of a negative surprises in the near term. Longer term, we believe signs of improving market balances, potential for margin improvements from the BHI integration, and a broader, more competitive international product offering from the combined HAL/BHI should drive upside in the shares. We see value in HAL shares, but believe there may be an opportunity to be a more aggressive buyer once our suspected digestion issues with the integration of BHI are identified and resolved.

Key Drivers

• Integration of BHI Offers Increased Scope and Opportunity for Margin Improvements On Legacy BHI Operations. The US land market may prove the fastest to recover as higher cash flow from rising commodity prices translate into higher US upstream spending. North America would represent 40%-60% of the combined HAL/BHI revenue, historically. Accordingly, the combined company has the highest leverage of the large cap oil services companies to the recovery of the market. HAL/BHI’s high market share in pressure pumping, possibly the most hyper-cyclical business in North America, amplifies the combined company’s earnings upside in a tightening hydraulic fracturing market in coming quarters. In recent years, North American margins for HAL have been 500-1,000bps higher than those of BHI. As HAL integrates BHI and removes inefficiencies on route to its target for $2 billion in synergies by the end of 2016, we see potential for a greater economic lift from better managed operations in a 2016/2017 recovery scenario. In our view, lack of visibility of the timing of operational improvements for legacy BHI businesses and potential for emerging issues leaves our confidence in near term our estimates low. As highlighted on HAL’s 3Q/15 call, overhead carried in front of the closing of the BHI merger reduced margins by 400bps. Adjustment of the cost structure, optimizing the combined logistics network, further management delayering, and better supply chain management, likely leaves a leaner organization with a steeper earnings trajectory into a recovery.

• More Competitive International Offering. A broader product offering (addition of artificial lift and chemicals) may leave the merged HAL/BHI more competitive in international markets, especially when bidding for integrated project or bundled solutions. We anticipate the elimination of $1 billion from fixed costs from the international footprint from real estate (redundant bases), logistics, security, support services, personnel, management, may help to improve margins for the combined business, where BHI margins traditionally lagged those of HAL.

• Value of Divestitures and Ability to Pay Down Debt. HAL announced the sale of is drill bits business, directional drilling business, LWD, MWD, expandable liner hangers, BHI’s core completion tools (packers, flow control, subsurface safety, intelligent well systems, permanent monitoring, sand control), the BHI sand control business in the GoM, and BHI’s offshore cementing business in Australia, Brazil, GoM, Norway, and UK. Per 2013 results, the divestitures represent $5.2 billion in revenue, below the $7.5 billion threshold of divestitures, which would allow the deal to be terminated. In our view, the deal may go through, with divestitures concurrent with the closing of the merger. HAL has secured a guarantee for $8.6 billion in bridge financing, but we would like to see cash acquired from these divestitures used to pay down this debt. Given cash deals may lower market valuations, we make the rough assumption that assets may yield ~$3.5 billion in cash. Even with cash used to pay down debt, our Total Debt/EBITDA floats between 4-6x through 2016 (~26% net debt /capital). Decent cash realizations on divestitures remain important to the balance sheet.

December 15, 2015 113

Halliburton (HAL) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

North America 15,212.0 17,698.0 10,442.9 11,767.2 17,792.9 3,542.0 2,671.0 2,488.0 1,741.9 2,387.7 2,602.5 3,208.0 3,569.0 4,103.7 4,245.8 4,652.3 4,791.0

Latin America 3,909.0 3,875.0 3,163.8 4,278.3 4,768.8 949.0 767.0 739.0 708.8 1,062.8 1,061.3 1,071.8 1,082.4 1,119.4 1,165.2 1,230.6 1,253.8

Europe / Africa / CIS 5,225.0 5,490.0 4,106.1 5,804.9 6,532.0 1,097.0 1,095.0 1,021.0 893.1 1,411.0 1,412.7 1,492.9 1,488.3 1,452.3 1,532.3 1,743.3 1,804.1

Middle East / Asia 5,056.0 5,807.0 5,460.4 8,068.7 8,995.8 1,462.0 1,386.0 1,334.0 1,278.4 1,983.5 1,987.9 2,023.9 2,073.4 2,114.7 2,152.1 2,303.0 2,426.0

BHI Industrial & Other - - - 1,337.1 1,623.4 - - - - 308.0 317.3 348.2 363.6 387.8 392.6 418.6 424.5

Divested Revenue - - - (2,834.8) (3,563.5) - - - - (651.9) (671.3) (737.5) (774.1) (824.6) (851.6) (928.3) (958.9)

Total Revenues 29,402.0 32,870.0 23,173.2 29,919.1 38,089.5 7,050.0 5,919.0 5,582.0 4,622.2 6,193.0 6,393.1 7,059.1 7,439.1 7,965.5 8,243.7 9,000.9 9,316.0

North America 2,606.0 3,216.0 329.4 509.1 2,579.2 279.0 130.0 8.0 (87.6) (77.0) 83.9 191.4 310.8 469.9 602.5 718.8 788.1

Latin America 522.0 431.0 440.1 565.6 758.3 122.0 112.0 108.0 98.1 126.5 134.5 146.3 158.3 169.3 182.1 198.4 208.4

Europe / Africa / CIS 696.0 689.0 520.1 754.8 979.1 86.0 164.0 150.0 120.1 168.9 179.6 202.6 203.8 206.1 225.1 264.8 283.1

Middle East / Asia 872.0 1,074.0 1,152.4 1,296.7 1,696.5 281.0 307.0 298.0 266.4 297.5 314.7 332.2 352.3 376.9 401.5 441.2 476.9

Divested EBIT - - - (291.3) (561.7) - - - - (47.4) (66.6) (81.5) (95.8) (114.1) (131.9) (151.7) (163.9)

General & Corporate (447.4) (362.0) (262.9) (303.9) (354.3) (69.0) (70.0) (58.0) (65.9) (71.2) (74.3) (78.0) (80.4) (83.3) (85.8) (91.2) (94.0)

EBIT 4,248.6 5,048.0 2,179.2 2,531.0 5,097.1 699.0 643.0 506.0 331.2 437.2 613.0 758.2 896.2 1,075.1 1,244.4 1,434.7 1,553.6

Interest expense (303.0) (383.0) (410.0) (885.1) (1,048.1) (106.0) (106.0) (99.0) (99.0) (99.0) (262.0) (262.0) (262.0) (262.0) (262.0) (262.0) (262.0)

Other, net (1,043.0) (2.0) (281.0) - - (224.0) (23.0) (34.0) - - - - - - - - -

EBT 2,902.6 4,663.0 1,488.2 1,645.9 4,048.9 369.0 514.0 373.0 232.2 338.2 351.0 496.2 634.2 813.1 982.3 1,172.6 1,291.6

Income Taxes (686.9) (1,241.0) (252.5) (482.2) (1,128.8) 51.0 (135.0) (107.0) (61.5) (89.6) (93.0) (131.5) (168.1) (215.5) (260.3) (310.7) (342.3)

Minority Interest (8.0) (1.0) 1.0 4.0 4.0 (2.0) 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Net Income (Operating) 2,207.7 3,421.0 1,236.7 1,167.8 2,924.1 418.0 380.0 267.0 171.7 249.6 259.0 365.7 467.1 598.6 723.0 862.9 950.3

Discontinued Operations 22.0 64.0 (5.0) - - (4.0) (1.0) - - - - - - - - - -

Extraordinaries (after-tax) 573.9 (233.0) (1,701.0) - - (1,057.0) (325.0) (319.0) - - - - - - - - -

Net Income (GAAP) 2,803.6 3,252.0 (469.3) 1,167.8 2,924.1 (643.0) 54.0 (52.0) 171.7 249.6 259.0 365.7 467.1 598.6 723.0 862.9 950.3

EPS (Operating) 2.45 4.01 1.45 0.87 2.16 0.49 0.44 0.31 0.20 0.19 0.19 0.27 0.35 0.44 0.53 0.64 0.70

EPS (GAAP) 3.11 3.82 (0.55) 0.87 2.16 (0.76) 0.06 (0.06) 0.20 0.19 0.19 0.27 0.35 0.44 0.53 0.64 0.70


Basic Shares Outstanding 898.8 847.8 853.0 1,348.6 1,356.6 850.0 852.0 855.0 855.0 1,345.6 1,347.6 1,349.6 1,351.6 1,353.6 1,355.6 1,357.6 1,359.6

Diluted Shares Outstanding 901.8 852.3 853.5 1,348.6 1,356.6 850.0 854.0 855.0 855.0 1,345.6 1,347.6 1,349.6 1,351.6 1,353.6 1,355.6 1,357.6 1,359.6

EBITDA 6,148.6 7,174.0 4,037.9 4,681.6 7,351.7 1,259.0 1,099.0 923.0 756.9 965.6 1,147.0 1,298.8 1,443.8 1,628.7 1,804.2 2,001.6 2,127.9

Depreciation & Amortization 1,900.0 2,126.0 1,858.7 2,150.6 2,254.6 560.0 456.0 417.0 425.7 528.4 534.0 540.6 547.6 553.6 559.8 566.9 574.3


Cash From Operations (CFO) 4,447.0 4,062.0 4,747.6 3,754.3 3,601.0 812.0 1,183.0 26.0 2,726.6 955.5 2,059.4 101.2 638.2 612.6 1,116.1 590.0 1,282.4

Capital Expenditures (2,934.0) (3,283.0) (2,279.6) (2,094.3) (2,285.4) (704.0) (519.0) (525.0) (531.6) (479.1) (494.5) (545.8) (574.9) (527.4) (545.7) (595.8) (616.5)

Free Cash Flow (FCF) 1,513.0 779.0 2,468.1 1,660.0 1,315.7 108.0 664.0 (499.0) 2,195.1 476.4 1,564.9 (444.6) 63.3 85.2 570.4 (5.8) 665.9

Acquisitions/Divestures/Investments 64.0 145.0 (198.0) (4,822.0) - 22.0 (319.0) 99.0 - (4,822.0) - - - - - - -

Cash From Financing (CFF) (1,853.0) (1,333.0) (766.9) 7,440.4 (975.3) (153.0) (153.0) (307.0) (153.9) 8,168.1 (242.2) (242.6) (242.9) (243.3) (243.6) (244.0) (244.4)

Other 148.0 344.0 496.0 - - 26.0 184.0 286.0 - - - - - - - - -

Increase (Decrease) in Cash (128.0) (65.0) 1,999.2 4,278.4 340.4 3.0 376.0 (421.0) 2,041.2 3,822.5 1,322.7 (687.1) (179.6) (158.1) 326.8 (249.8) 421.5


Total Capital 21,397.0 24,107.0 23,356.8 49,833.0 51,992.6 23,432.0 23,523.0 23,339.0 23,356.8 49,468.9 49,485.7 49,608.8 49,833.0 50,188.4 50,667.7 51,286.6 51,992.6

Total Debt 7,816.0 7,840.0 7,891.0 20,886.0 20,886.0 7,841.0 7,838.0 7,891.0 7,891.0 20,886.0 20,886.0 20,886.0 20,886.0 20,886.0 20,886.0 20,886.0 20,886.0

Net Debt 5,460.0 5,549.0 3,600.8 12,317.4 11,977.0 5,547.0 5,168.0 5,642.0 3,600.8 12,773.3 11,450.7 12,137.8 12,317.4 12,475.5 12,148.8 12,398.5 11,977.0


Net Debt/Capital 25.5% 23.0% 15.4% 24.7% 23.0% 23.7% 22.0% 24.2% 15.4% 25.8% 23.1% 24.5% 24.7% 24.9% 24.0% 24.2% 23.0%


BVPS 15.1 19.1 18.1 21.5 22.9 18.3 18.4 18.1 18.1 21.2 21.2 21.3 21.4 21.6 22.0 22.4 22.9

TBVPS 12.7 16.4 15.6 10.7 12.2 15.6 16.0 15.6 15.6 10.5 10.5 10.5 10.7 10.9 11.3 11.7 12.2

December 15, 2015 114

Halliburton (HAL) Valuation PRICE TARG ET SCEN ARIO S

Disc Rate EBITDA M ultip le PV /Equity Targe t U pside $M illions 2012 2013 2014 2015 2016E 2017E

1.6% 64.3x $95,965 $72 95% Le ve re d Cash F low :

3.6% 28.1X $87,251 $65 76% N e t Incom e 2,635.0 2,803.6 3,252.0 (469.3) 1,167.8 2,924.1

5.6% 18.0X $79,459 $60 62% De pre ciation & A m ortization 1,628.0 1,900.0 2,126.0 1,858.7 2,150.6 2,254.6

7.6% 13.2X $72,474 $54 46% Capital ize d In te re st - - - - - -

9.6% 10.5X $66,201 $50 35% De fe rre d Tax e s 97.4 279.9 (454.0) (391.3) 154.7 362.1

11.6% 8.7X $60,555 $46 24% Translation A d justm e nt O the r - - - - - -

13.6% 7.4X $55,464 $42 14% O pe rating Cash F low (be fore w orking cap.) 4,360.4 4,983.5 4,924.0 998.1 3,473.0 5,540.8

15.6% 6.4X $50,864 $38 3% N e t Cash from Inve sting A ctiv itie s 181.0 64.0 145.0 (198.0) (4,822.0) -

17.6% 5.7X $46,700 $35 (5% ) Cap ital ize d In te re st - - - - - -

19.6% 5.1X $42,925 $32 (13% ) Cap ital ize d G& A - - - - - -

21.6% 4.6X $39,496 $30 (19% ) Le ss: N e t Capital Expe nditure s (be fore Cap Int) (181.0) (64.0) (145.0) 198.0 4,822.0 -

W orking Cap ital Change (853.0) (551.0) (576.0) 1,551.5 111.7 (2,146.5)

W e ighte d Ave rage Cost of Capital (W ACC) Change in De bt/P re fe rre d - 2,968.0 - - 8,322.0 -

N otional Tax Rate 35.0% Le ve re d Fre e Cash F low from O pe rations 5,394.4 2,630.5 5,645.0 (751.4) (9,782.7) 7,687.3

Risk Fre e Rate 4.00% Te rm inal Multip le

De bt Risk Spre ad 250 EBITDA

Equity Risk P re m ium 6.0% Te rm inal Ente rprise V alue

Be ta (A d juste d) 1.25 Subtract: Long Te rm De bt (Te rm inal Ye ar)

Cost of Equity 14.0% Subtract: P re fe rre d Stock (Te rm inal Ye ar)

Marginal Cost o f De bt 6.5% A dd: Cash (Te rm inal Ye ar)

Cost o f De bt, afte r tax 4.2% Subtract Le ve re d FCF from O pe rations for Ex p lict Fore cast

N e t De bt/Total Cap ital 25.0% Subtract: Change s in Equ ity for Ex p l ict Fore cast

W ACC 11.6% Subtract: D iv ide nds for Ex p lict Fore cast

Te rm inal M ultip le : 8.7X Te rm inal V alue (1)

Le ve re d Fre e Cash F low (2) (9,782.7) 7,687.3

(1) Re f le cts a ~11.6% W A CC app lie d to 2020 EBITDA . Te rm in al valu e is com pute d at ye ar-e n d 2020.

(2) A ssum e s inve stm e nt occurs at be ginn ing o f ye ar, le ve re d fre e cash f low is ye ar-e n d .

Discounte d Cash F low Analysis

December 15, 2015 115











December 15, 2015 116

Weatherford: Accumulate, $10.25, Execution Improving, Still a “Show Me” Story Amid Sea of Cheap Stocks Investment Thesis. We are initiating coverage of WFT with an Accumulate rating and a $10.25 price target. WFT has traveled a rocky road in recent years, with great advances on internal control issues, greater focus through divestitures, and progress on cash flow generation. In our view, these improvements, a stable cash flow/balance sheet, and a trajectory for earnings recovery in 2016/2017 are reflected in our estimates. Evidence of market share gains, cost cutting benefits, and better absorption of spare capacity in the WFT system may lead to upward estimate revisions. We see upside in the shares, but believe WFT shares cannot see significant multiple expansion until investors gain confidence in the company’s consistent execution and the returns structure begins to close the gap with its larger peers (SLB & HAL).

Key Drivers

• Emergence from Growth to Returns Based Company. If WFT can narrow the return on assets gap with the larger competitors, the shares may be worth over $20. While progress has been made and may continue, we are not willing to make the assumption that WFT narrows the gap in the near term. After years of acquisitions, heavy spending on growth CAPEX, and low return contracts, WFT is in the process to transition to a focus on four core business segments, returns over growth, and cash flow. The company has dug itself out of its internal control issues, divested non-core businesses, and the land rig business awaits the right market for sale. Strategically, we believe WFT is headed in the right direction, as demonstrated by better than expected 3Q15 results and first free cash flow since 3Q10, but changes at WFT remain a “show me” story. In our view, the recent change in leadership in six out of eight geographies and seven of twelve product lines may suggest positive momentum, but draws attention to the need to fix internal execution/process issues that may take additional time to correct. Meanwhile, WFT’s failed attempt to finance a bid for HAL’s Sperry drilling, rattled investor confidence in WFT’s focus on the core business. Potentially, a strategic fit within Formation Evaluation, but a hurdle for investor belief in management’s new mantra of execution over expansion. As a poor pricing culled the offering, investors may draw comfort in WFT’s focus on cost of capital weighed against returns vs. a deal.

• Capacity Absorption & Cost Cutting. Given 25%-30% spare capacity in the system, WFT claims they can run on $400 million maintenance CAPEX for the next few years. A positive for free cash flow, but a negative inference for operating leverage and a meaningful recovery in margins until 2017. WFT may get some help from efficiency and cost cutting initiatives, which began to show results in North America and may follow for international operations. To date, WFT has taken $1.7 billion of cost taken out of the system ($600 million permanent), achieved 11k headcount reductions with a new target of 14k, and closed 70 North American facilities to date, with 20 more facilities to close by the end of 2015. The ratio of support costs to total costs has gone to ~42% from 59%, with the target of 30%-35% by 2017, as WFT looks to rationalize support overhead, likely bloated from lagging acquisition integrations. Amid continue business decline and international initiatives, we would expect further positive cash flow generated from working capital.

• Market Share Gains from Consolidation. WFT has a large, underutilized global footprint, as a carry from its high investment and growth phase, which may set the stage for the company to gain market share from upstream operators seeking alternative providers amid industry consolidation. In our view, WFT may be well positioned in international markets, where NOC’s may look to spread their business over more than just SLB and HAL or may be required to limit exposure to any given provider (combined HAL/BHI has very large market share for completions with Statoil). WFT believes that is has 10% international market share, which can expand. Geographically, we see opportunities in the Middle East (activity to support OPEC market share), West Africa, and Europe. Additionally, WFT may be able to expand its more limited offshore exposure through managed pressure drilling, but a slowdown from early-adopter, PBR, may extend the timeline for progress. Given a spotty international contracting history, most recently highlighted by the Zubair contract, WFT may need to demonstrate a track record of disciplined growth and market share gains to get credit, and potentially upside in our estimates & valuation.

• Cash Flow & Balance Sheet Appear Stable. A 50%+ total debt/capital ratio and 5-6 turns of Total Debt / EBITDA though 2016 may keep balance sheet issue on investor’s dashboards. With guidance for $200-300 million in FCF in 4Q15 and broadly better cash flow guidance, WFT appears to have internal cash flows to finance $350 million maturity in February 2016 and $350 million in June 2017, with no leverage ratio or covenants on public bonds. WFT’s $2.25 billion revolver, with ~$1 billion outstanding, has a 60% total debt to capital ratio threshold (difficult to forecast due to adjustments for FX, etc), but our forecast suggests WFT may remain within the bounds of the covenant.

December 15, 2015 117

Weatherford (WFT) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

North America 6,390.0 6,852.0 3,497.8 3,620.6 5,289.9 1,163.0 808.0 824.0 702.8 735.2 809.3 987.8 1,088.2 1,239.0 1,269.3 1,377.2 1,404.4

Middle East / North Africa / Asia 3,164.0 3,095.0 1,966.6 1,939.6 2,079.2 533.0 516.0 445.0 472.6 480.8 481.8 485.3 491.8 496.3 499.8 529.7 553.4

Europe / West Africa / CIS 2,693.0 2,584.0 1,540.7 1,403.3 1,579.0 417.0 418.0 361.0 344.7 338.6 347.8 349.4 367.6 358.4 370.5 418.2 432.0

Latin America 3,016.0 2,380.0 1,807.8 1,766.8 1,900.8 486.0 463.0 421.0 437.8 442.1 441.5 441.5 441.5 452.1 466.0 488.6 494.1

Land Rigs - - 742.7 746.4 907.2 195.0 185.0 186.0 176.7 173.2 181.8 190.9 200.5 210.5 221.0 232.1 243.7

Total Revenues 15,263.0 14,911.0 9,555.6 9,476.7 11,756.1 2,794.0 2,390.0 2,237.0 2,134.6 2,169.9 2,262.2 2,455.0 2,589.6 2,756.2 2,826.6 3,045.8 3,127.5

North America 822.0 1,028.0 (209.1) (128.2) 429.4 (10.0) (92.0) (54.0) (53.1) (62.9) (44.9) (25.2) 4.9 42.7 81.8 130.1 174.8

Middle East / North Africa / Asia 262.0 261.0 213.3 198.8 224.0 69.0 55.0 42.0 47.3 48.6 49.1 50.0 51.1 52.1 53.0 57.5 61.4

Europe / West Africa / CIS 298.0 422.0 218.3 153.2 221.0 71.0 65.0 43.0 39.3 36.9 36.2 38.1 41.9 44.5 49.7 60.3 66.6

Latin America 341.0 360.0 325.3 253.3 330.3 98.0 85.0 73.0 69.3 63.4 61.1 63.3 65.5 71.6 78.5 87.2 93.1

Land Rigs - - 43.4 45.0 61.2 10.0 4.0 16.0 13.4 11.4 10.2 11.2 12.2 13.4 14.6 15.9 17.3

Research & Development (266.0) (290.0) (232.4) (237.2) (294.3) (64.0) (59.0) (56.0) (53.4) (54.3) (56.6) (61.5) (64.8) (69.0) (70.8) (76.2) (78.3)

Corporate G&A (200.0) (178.0) (189.9) (190.6) (236.5) (56.0) (46.0) (45.0) (42.9) (43.7) (45.5) (49.4) (52.1) (55.4) (56.9) (61.3) (62.9)

EBIT 1,257.0 1,603.0 168.9 94.4 735.1 118.0 12.0 19.0 19.9 (0.5) 9.6 26.5 58.8 99.8 149.9 213.4 272.0

Net Interest (Expense) (516.0) (478.0) (475.6) (428.8) (397.3) (131.0) (117.0) (114.0) (113.6) (109.5) (107.3) (105.7) (106.4) (104.5) (102.3) (96.8) (93.7)

Other, net (125.0) (37.0) (6.0) - - - (18.0) 12.0 - - - - - - - - -

EBT 616.0 1,088.0 (312.7) (334.4) 337.8 (13.0) (123.0) (83.0) (93.7) (110.0) (97.7) (79.1) (47.6) (4.7) 47.6 116.6 178.3

Income Taxes (122.0) (258.0) 123.9 110.4 (111.5) (9.0) 52.0 50.0 30.9 36.3 32.2 26.1 15.7 1.6 (15.7) (38.5) (58.8)

Minority Interest (31.0) (45.0) (34.6) (38.1) (47.3) (11.0) (6.0) (9.0) (8.6) (8.7) (9.1) (9.9) (10.4) (11.1) (11.4) (12.3) (12.6)

Net Income (Operating) 463.0 785.0 (223.3) (262.2) 179.1 (33.0) (77.0) (42.0) (71.3) (82.4) (74.6) (62.9) (42.3) (14.2) 20.5 65.9 106.9

Discontinued Operations - - - - - - - - - - - - - - - - -

Extraordinaries (after-tax) (808.0) (1,369.0) (625.0) - - (85.0) (412.0) (128.0) - - - - - - - - -

Net Income (GAAP) (345.0) (584.0) (848.3) (262.2) 179.1 (118.0) (489.0) (170.0) (71.3) (82.4) (74.6) (62.9) (42.3) (14.2) 20.5 65.9 106.9

EPS (Operating) 0.60 1.01 (0.29) (0.34) 0.23 (0.04) (0.10) (0.05) (0.09) (0.11) (0.10) (0.08) (0.05) (0.02) 0.03 0.08 0.14

EPS (GAAP) (0.45) (0.75) (1.09) (0.34) 0.23 (0.15) (0.63) (0.22) (0.09) (0.11) (0.10) (0.08) (0.05) (0.02) 0.03 0.08 0.14

Dividend per Share - - - - - - - - - - - - - - - - -

Basic Shares Outstanding 768.8 776.8 778.5 779.0 779.0 778.0 778.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0

Diluted Shares Outstanding 774.0 778.5 778.5 779.0 779.0 778.0 778.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0 779.0

EBITDA 2,659.0 2,974.0 1,387.5 1,289.1 1,963.0 434.0 323.0 317.0 313.5 295.0 307.1 326.2 360.8 403.7 455.8 521.3 582.1

Depreciation & Amortization 1,402.0 1,371.0 1,218.6 1,194.7 1,227.8 316.0 311.0 298.0 293.6 295.5 297.5 299.7 302.0 303.9 305.9 307.9 310.1


Cash From Operations (CFO) 1,229.0 1,056.1 704.5 711.6 1,513.2 (42.0) 327.0 98.0 321.5 231.7 196.8 58.3 224.8 229.1 444.4 293.5 546.2

Capital Expenditures (1,575.0) (1,450.0) (606.0) (398.0) (382.1) (224.0) (187.0) (131.0) (64.0) (91.1) (95.0) (103.1) (108.8) (89.6) (91.9) (99.0) (101.6)

Free Cash Flow (FCF) (346.0) (393.9) 98.5 313.6 1,131.1 (266.0) 140.0 (33.0) 257.5 140.6 101.8 (44.8) 116.0 139.5 352.5 194.5 444.6

Acquisitions/Divestures/Investments 466.0 1,784.0 8.0 - - - 20.0 (12.0) - - - - - - - - -

Cash From Financing (CFF) 9.0 (1,183.0) 238.0 (350.0) (350.0) 325.0 (8.0) (79.0) - (350.0) - - - - (350.0) - -

Other 6.0 (168.1) (42.0) - - (21.0) (53.0) 32.0 - - - - - - - - -

Increase (Decrease) in Cash 135.0 39.0 302.5 (36.4) 781.1 38.0 99.0 (92.0) 257.5 (209.4) 101.8 (44.8) 116.0 139.5 2.5 194.5 444.6


Total Capital 16,889.0 14,483.0 13,316.7 12,704.5 12,533.5 14,361.0 13,996.0 13,388.0 13,316.7 12,884.2 12,809.7 12,746.8 12,704.5 12,690.2 12,360.8 12,426.7 12,533.5

Total Debt 8,727.0 7,525.0 7,704.0 7,354.0 7,004.0 7,832.0 7,824.0 7,704.0 7,704.0 7,354.0 7,354.0 7,354.0 7,354.0 7,354.0 7,004.0 7,004.0 7,004.0

Net Debt 8,292.0 7,051.0 6,927.5 6,614.0 5,482.9 7,320.0 7,213.0 7,185.0 6,927.5 6,786.9 6,685.1 6,729.9 6,614.0 6,474.4 6,121.9 5,927.4 5,482.9


Net Debt/Capital 49.1% 48.7% 52.0% 52.1% 43.7% 51.0% 51.5% 53.7% 52.0% 52.7% 52.2% 52.8% 52.1% 51.0% 49.5% 47.7% 43.7%


BVPS 10.55 8.94 7.21 6.87 7.10 8.39 7.93 7.30 7.20 7.10 7.00 6.92 6.87 6.85 6.88 6.96 7.10

TBVPS 4.94 4.50 3.07 2.73 2.96 4.14 3.65 3.16 3.07 2.96 2.86 2.78 2.73 2.71 2.74 2.82 2.96

December 15, 2015 118

Weatherford (WFT) Valuation PRICE TARGET SCENARIOS


5.7% 17.4x $11,417 $14.75 67% Levered Cash Flow:

7.7% 12.9X $10,598 $13.50 53% Net Income (805.0) (345.0) (584.0) (848.3) (262.2) 179.1 569.4 681.3 692.1

9.7% 10.3X $9,859 $12.75 44% Depreciation & Amortization 1,282.0 1,402.0 1,371.0 1,218.6 1,194.7 1,227.8 1,263.1 1,331.2 1,475.8

11.7% 8.5X $9,189 $11.75 33% Capitalized Interest - - - - - - - - -

13.7% 7.3X $8,581 $11.00 24% Deferred Taxes (13.0) (33.0) (66.0) (475.0) - - - - -

15.7% 6.4X $8,029 $10.25 16% Translation Adjustment Other - - - - - - - - -

17.7% 5.6X $7,525 $9.75 10% Operating Cash Flow (before working cap.) 464.0 1,024.0 721.0 (104.8) 932.5 1,406.9 1,832.5 2,012.5 2,167.9

19.7% 5.1X $7,065 $9.00 2% Net Cash from Investing Activities (2,306.0) (1,109.0) 334.0 (598.0) (398.0) (382.1) (435.9) (1,161.5) (1,898.0)

21.7% 4.6X $6,645 $8.50 (4%) Capitalized Interest - - - - - - - - -

23.7% 4.2X $6,259 $8.00 (10%) Capitalized G&A - - - - - - - - -

25.7% 3.9X $5,905 $7.50 (15%) Less: Net Capital Expenditures (before Cap Int) 2,306.0 1,109.0 (334.0) 598.0 398.0 382.1 435.9 1,161.5 1,898.0

Working Capital Change (207.0) 298.0 136.0 756.3 (221.0) 106.3 (494.4) (101.1) (117.4)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 990.0 9.0 (1,183.0) 238.0 (350.0) (350.0) - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (2,625.0) (392.0) 2,102.0 (1,697.1) 1,105.5 1,268.5 1,891.0 952.1 387.3









WACC 15.7% Subtract: Dividends for Explict Forecast -


Levered Free Cash Flow (2) 1,105.5 1,268.5 1,891.0 952.1 9,092.7




December 15, 2015 119











December 15, 2015 120

Small/Mid Cap Oil Services

December 15, 2015 121

Core Labs: Buy, $155PT, High Returns, High Payout, High Upside With Industry Uptick Investment Thesis. We are initiating coverage of CLB with a BUY rating and $155 price target. One of the best franchises in the oilfield, CLB shares offer an attractive combination of leverage to both land and deepwater activity recovery; longer term growth through ties to greater field complexity and efforts for enhanced resource recovery; a high returns business ; and a full payout strategy, through a constant dividend and variable share repurchase program. In our view, leverage to free cash flows through high distributions may continue to drive a premium valuations. With an expectations of a 2016/2017 upstream activity recovery, 2016 EPS may be flattish on 2015, but we see growing expectations for a meaningful 2017 EPS recovery as a positive catalyst for the shares. In the meantime, distributions pay shareholders to wait.

Key Drivers

• Growth in Oilfield Service & Analytical Intensity. The complexity of incremental fields and enhanced resource recovery at legacy fields drive the need for greater service and analytical intensity. In Reservoir Description, greater complexity and enhanced recovery equates to greater volume of higher end core and fluids testing through every phase of field development, with an improved mix of higher-margin services, and ultimately higher turns on a low fixed cost lab overhead. For Production Enhancement, this translates into higher volumes and more value-added services (high end perforating guns) in field development. Near term, lower activity in North American, except resilience in the GoM, and a lagging decline international activity lowers earnings through 2016. We believe that furloughs, multiskilling, and other cost cutting efforts may offset some of the near term challenges. In our view, 2017 may see an earnings recovery. Longer term, CLB is well positioned to achieve goals for growth 200-400bps faster than the industry, increased penetration with existing and new customers, and entrance into 40-50 new fields per year. We also assume an improved mix with products like Digital Rock, that taps CLB’s rock characterization database, analytics to help with well re-stimulations, and offerings to help with enhanced oil recovery, especially in international markets like the Middle East.

• High Returns Business Model. CLB touts one of the highest free cash flow (FCF) margins amongst oilfield service companies. Management executes a business model that creates standardized products, namely reservoir core tests/analytics and enhancement products (high end perforating guns), which achieve superior returns through high incremental margins of 35-45%, due to low marginal unit cost and leverage on low fixed overhead. Thus, high cash flow returns, above the cost of capital, produce a pattern of value creation. Meanwhile, barriers to entry, including intellectual property, specialized equipment integrated into standardized customer processes, and experienced staff with low turnover shield the business from potential competitive threats that may chip away at excess returns.

• High Payout Capital Budgeting Strategy Maintains Exposure to a High Returns Operating Model. Focus on core, high margin businesses, with emphasis on excess cash returns to shareholders versus potentially dilutive empire building ambitions that may dilute economics, maintains the shares’ exposure to a high return structure. At the same time, a focus on ROIC has guided management away from investments in riskier, high operating costs environments, like Brazil, Iraq, and Mexico, where other oil service companies suffer consistent issues. With steady growth and high free cash flow generation, investors pay premiums for direct exposure to high returns and value creation through rising dividends and more variable share repurchases, which have produced superior total returns. Under these premises, we believe CLB’s strategy should continue to warrant a premium, with cost of capital lowered by high cash flow margins, a low cost of debt, and support from yield-based valuation metrics.

• Business Model Sustainability. CLB operates with a centralized set of labs and manufacturing for its Production Enhancement equipment, which creates a fairly low fixed overhead. With a high FCF margin and payout, over time CLB has come to post negative shareholders equity. In recent quarters, the company has drawn on its credit facility to fund share repurchases, which may persist though the downturn. Given that CLB should remain within its 2.5X Total Debt / EBITDA covenant for its extended 5 year term for revolver and continue to generate FCF, we do not see an issue with the heightened Net Debt to Capital ratio, which should decline with a cyclical recovery.

December 15, 2015 122

Core Labs (CLB) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Reservoir Description 522.3 519.0 468.2 439.3 478.9 121.8 118.9 117.9 109.6 108.1 109.1 110.4 111.7 114.8 118.0 121.3 124.7

Production Enhancement 452.4 467.6 266.4 232.2 299.0 75.1 70.6 64.9 55.8 54.0 55.6 59.3 63.3 67.5 72.1 77.0 82.4

Reservoir Management 98.8 98.7 59.2 59.6 72.4 16.7 14.4 14.4 13.7 13.8 14.5 15.2 16.0 16.8 17.6 18.5 19.4

Total Revenues 1,073.5 1,085.2 793.8 731.0 850.4 213.6 203.9 197.3 179.0 175.9 179.2 184.9 191.0 199.2 207.8 216.9 226.5

Reservoir Description 146.0 144.6 123.1 112.0 126.9 32.4 31.5 32.0 27.1 26.8 27.5 28.4 29.3 30.3 31.2 32.2 33.2

Production Enhancement 155.3 167.8 49.7 43.1 75.0 13.4 14.8 12.5 8.9 8.1 8.9 11.6 14.5 15.9 17.7 19.6 21.8

Reservoir Management 31.8 37.3 16.6 18.0 22.5 4.3 3.4 4.8 4.1 4.1 4.4 4.6 4.9 5.2 5.5 5.8 6.1

Corporate and other 3.0 0.5 0.3 1.3 1.3 0.5 (0.9) 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

EBIT 336.0 350.2 189.7 174.4 225.8 50.7 48.8 49.7 40.5 39.3 41.1 44.9 49.1 51.6 54.7 58.0 61.5

Interest expense (9.3) (10.6) (12.5) (15.1) (16.8) (2.4) (3.1) (3.5) (3.5) (3.6) (3.7) (3.8) (4.0) (4.1) (4.2) (4.3) (4.3)

EBT 326.7 339.6 177.2 159.3 208.9 48.2 45.7 46.2 37.0 35.7 37.4 41.1 45.1 47.5 50.5 53.7 57.2

Income Tax (81.8) (80.0) (40.3) (35.8) (47.0) (11.1) (10.2) (10.6) (8.3) (8.0) (8.4) (9.2) (10.1) (10.7) (11.4) (12.1) (12.9)

Noncontrolling Interest (0.4) (1.1) (0.1) (0.8) (0.8) 0.4 (0.1) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2)

Net Income (Operating) 244.5 258.4 136.8 122.7 161.2 37.5 35.4 35.4 28.5 27.5 28.8 31.6 34.8 36.6 38.9 41.4 44.1

Extraordinaries (after-tax) (1.7) (1.0) (2.8) - - - (0.8) (2.0) - - - - - - - - -

Net Income (GAAP) 242.8 257.5 134.0 122.7 161.2 37.5 34.6 33.4 28.5 27.5 28.8 31.6 34.8 36.6 38.9 41.4 44.1

EPS (Operating) 5.32 5.79 3.19 2.92 3.89 0.86 0.82 0.83 0.67 0.65 0.68 0.75 0.83 0.88 0.94 1.00 1.07

EPS (GAAP) 5.28 5.77 3.12 2.92 3.89 0.86 0.81 0.78 0.67 0.65 0.68 0.75 0.83 0.88 0.94 1.00 1.07




EBITDA 361.5 376.9 217.0 203.0 255.5 57.2 55.8 56.6 47.4 46.4 48.2 52.1 56.3 58.9 62.1 65.5 69.1

Depreciation & Amortization 25.5 26.7 27.4 28.6 29.8 6.6 6.9 6.9 7.0 7.0 7.1 7.2 7.3 7.3 7.4 7.5 7.6


Cash From Operations (CFO) 298.1 305.3 290.3 133.6 164.1 79.6 46.7 123.1 41.0 33.5 31.6 32.8 35.7 37.7 39.7 42.1 44.5

Capital Expenditures (35.4) (36.6) (23.7) (23.4) (25.6) (6.9) (5.4) (6.0) (5.4) (5.6) (5.7) (5.9) (6.1) (6.4) (6.6) (6.9) (5.7)

Free Cash Flow (FCF) 262.7 268.7 266.6 110.2 138.4 72.7 41.3 117.1 35.6 27.9 25.8 26.9 29.6 31.4 33.1 35.1 38.9

Acquisitions/Divestures/Investments (4.2) (3.6) (14.8) - - 0.7 (15.3) (0.3) - - - - - - - - -

Cash From Financing (CFF) (249.1) (249.5) (174.0) (110.2) (138.4) (76.6) (22.5) (40.8) (34.0) (27.9) (25.8) (26.9) (29.6) (31.4) (33.1) (35.1) (38.9)

Other (3.6) (17.4) (81.2) - - (1.0) (0.0) (80.1) - - - - - - - - -

Increase (Decrease) in Cash 5.9 (1.7) (3.3) (0.0) 0.0 (4.2) 3.4 (4.1) 1.5 - - - - - - - -


Total Capital 430.3 443.6 415.7 450.1 494.8 399.5 422.6 415.8 415.7 420.8 429.2 439.5 450.1 460.9 472.3 484.1 494.8

Total Debt 267.0 356.0 437.3 499.3 531.6 373.0 421.5 428.0 437.3 452.6 469.9 486.0 499.3 510.8 520.4 528.0 531.6

Net Debt 241.9 332.7 417.3 479.3 511.6 353.9 398.9 409.5 417.3 432.6 449.9 466.0 479.3 490.8 500.4 508.0 511.6


Net Debt/Capital 56.2% 75.0% 100.4% 106.5% 103.4% 88.6% 94.4% 98.5% 100.4% 102.8% 104.8% 106.0% 106.5% 106.5% 106.0% 104.9% 103.4%


BVPS 3.55 1.96 (0.50) (1.17) (0.89) 0.61 0.03 (0.29) (0.51) (0.75) (0.96) (1.11) (1.18) (1.20) (1.16) (1.06) (0.89)

TBVPS (0.24) (1.96) (4.97) (5.73) (5.52) (3.42) (4.43) (4.78) (5.02) (5.28) (5.51) (5.67) (5.76) (5.80) (5.78) (5.70) (5.55)

December 15, 2015 123

Core Labs (CLB) Valuation PRICE TARGET SCENARIOS



2.0% 50.8X $7,222 $170 52% Net Income 216.1 242.8 257.5 134.0 122.7 161.2 189.6 201.5 200.6

2.5% 40.5X $7,052 $166 48% Depreciation & Amortization 22.9 25.5 26.7 27.4 28.6 29.8 30.9 32.1 33.4


3.5% 28.8X $6,727 $159 42% Deferred Taxes 3.6 6.8 4.1 (11.4) (31.9) (31.9) (31.9) (31.9) (31.9)


4.5% 22.4X $6,420 $152 36% Operating Cash Flow (before working cap.) 242.6 275.1 288.2 150.0 119.4 159.0 188.6 201.7 202.2

5.0% 20.1X $6,273 $148 32% Net Cash from Investing Activities (31.0) (33.0) (36.7) (36.3) (23.4) (25.6) (23.5) (24.9) (31.7)


6.0% 16.7X $5,991 $141 26% Capitalized G&A - - - - - - - - -

6.5% 15.5X $5,855 $138 23% Less: Net Capital Expenditures (before Cap Int) 31.0 33.0 36.7 36.3 23.4 25.6 23.5 24.9 31.7

Working Capital Change 31.6 (5.8) (3.6) 54.9 (7.8) (16.9) (7.5) (5.8) (3.4)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 8.7 33.0 101.8 79.6 62.0 32.3 9.7 0.7 4.4

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 171.3 214.9 153.4 (20.9) 41.7 118.0 162.9 181.7 169.4


Debt Risk Spread 92 EBITDA 311.0


Beta (Adjusted) 1.00 Subtract: Long Term Debt (Terminal Year) 546.5


Marginal Cost of Debt 4.9% Add: Cash (Terminal Year) 20.0

Cost of Debt, after tax 3.2% Subtract Levered FCF from Operations for Explict Forecast (673.8)


WACC 4.0% Subtract: Dividends for Explict Forecast (459.2)


Levered Free Cash Flow (2) 41.7 118.0 162.9 181.7 7,437.0




December 15, 2015 124











December 15, 2015 125

Superior Energy Svcs: Buy, $21 PT, Positioned for Industry Consolidation as 4th Largest Integrated Services Co. Investment Thesis. We are initiating coverage of SPN with a Buy rating and $21 price target. We are buyers of SPN for exposure to a broader recovery of activity in North America and international markets, both onshore and offshore. Leverage to recovery may be found in larger, safer names, but the market may not appreciate improved operating leverage from integration efforts/internal restructuring and the potential for SPN to gain share as it emerges as the 4th largest integrated service provider amid industry consolidation. A solid balance sheet supports a positive risk/reward and potential for accretive deals or a return of capital as a positive catalyst. In our view, SPN has participated in bidding for HAL/BHI divestitures, which may offer SPN a pathway toward new product lines and international expansion.

Key Drivers

• Leverage to North American & International Cyclical Upturn. SPN hosts a number of “block and tackle” businesses that face near term headwinds, as upstream activity finds bottom (SPN sees 10%-15% international spending decline in 2016), but offers great exposure to a recovery of the North American and international rig counts, both onshore and offshore. Recovery in some businesses, like drill pipe rentals and other consumables, may accelerate, given a draw in inventories and cannibalization of equipment on idle assets. SPN has taken steps to increase its presence in international markets (22% of 3Q15 revenue), with new business heads to help drive business in Middle East. Likewise, the company looks to exit unprofitable countries, like Mexico, while steadily increase penetration and diversify product lines in other regions: coiled tubing in Saudi Arabia, Stimulation in India, Cementing in Indonesia, and a few product lines in Columbia.

• Integration Better Positions Company in Recovery. First efforts to integrate acquired businesses, like Complete Energy Services, may add an additional $50 million in annual cost saving over 3Q/15 run rates, through equal reductions in the cost of goods sold and SG&A (fewer offices, procurement, head count). The internal reorganization may “right-size” overhead, but also helps to consolidate product/service lines into better bundled offerings, especially amongst well servicing, coiled tubing, electric line, slickline, pressure control tools, pressure control services, and plug & abandonment. More centralized, versus field-based, procurement at the customer level prefers bundled offerings, with price incentives. In our view, as secondary services providers struggle with scale and fade from the market, the new structure better positions SPN to gain share.

• Potential to Gain Market Share with Industry Consolidation. We believe SPN’s more integrated structure may also help to garner market share within a consolidating competitive landscape. As the soon-to-be 4th largest integrated oil services provider, SPN may gain market share, as domestic and international customers look to maintain diversity amongst service providers. At the same time, the company may benefit from the acquisition of business lines sold as part of the HAL/BHI merger. SPN may seek HAL/BHI assets in order to expand its offering, garner intellectual property, and grow its international footprint.

• Debt & Liquidity Remain a Positive. Through the downturn, FCF remains positive, debt ratios reasonable, and for the time being SPN remains investment grade. The company does not have a maturity until 2017 ($335 million term loan). In our view, a strong balance sheet leaves SPN free to pursue M&A opportunities (HAL/BHI business lines), invest in organic growth, or return capital to shareholders. All three uses of capital may prove a positive catalyst for the shares.

December 15, 2015 126

Superior Energy Services (SPN) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Drilling Products 838.5 923.8 598.0 457.4 570.1 199.5 148.7 130.5 119.4 112.4 113.1 114.6 117.3 126.4 136.4 147.5 159.8

Onshore Completion & Workover Services 1,596.7 1,727.9 948.5 680.4 847.0 351.0 226.4 202.8 168.3 166.6 167.9 169.3 176.6 189.7 203.8 218.7 234.8

Production Services 1,445.6 1,356.1 797.8 682.1 853.0 251.5 208.7 164.0 173.6 167.1 164.4 169.3 181.4 194.4 208.9 219.4 230.3

Technical Solutions 731.1 548.8 447.9 385.4 445.1 115.3 127.0 104.1 101.5 97.0 93.4 95.9 99.1 103.7 108.6 113.7 119.0

Total Revenues 4,611.8 4,556.6 2,792.2 2,205.4 2,715.3 917.2 710.8 601.4 562.8 543.1 538.7 549.1 574.4 614.3 657.7 699.3 743.9

Drilling Products 562.4 633.5 79.7 23.5 92.1 47.2 19.0 7.6 6.0 5.1 4.5 5.7 8.2 11.4 19.1 28.0 33.6

Onshore Completion & Workover Services 513.2 526.4 (141.7) (114.0) 14.6 (1.2) (44.3) (53.5) (42.7) (40.6) (32.5) (24.3) (16.6) (8.3) 1.3 9.8 11.7

Production Services 433.6 410.9 (95.8) (73.1) 14.9 (22.7) (21.0) (24.9) (27.2) (27.1) (27.4) (15.6) (3.1) (0.4) 3.8 5.1 6.5

Technical Solutions 224.4 251.0 (13.1) (9.6) 23.3 (1.4) 3.5 (7.7) (7.5) (7.1) (2.2) (0.8) 0.6 2.2 4.5 7.0 9.7

DD&A (625.9) (650.8) - - - - - - - - - - - - - - -

SG&A (628.3) (624.4) - - - - - - - - - - - - - - -

EBIT 479.4 546.6 (170.9) (173.2) 144.9 21.8 (42.8) (78.5) (71.4) (69.8) (57.7) (35.0) (10.8) 4.9 28.6 49.9 61.4

Interest Expense, net (104.4) (96.7) (97.9) (101.6) (95.0) (23.2) (25.4) (22.6) (26.7) (25.9) (25.8) (25.0) (24.9) (24.1) (24.1) (23.4) (23.4)

Other (expense) 2.0 (7.7) (13.7) (12.5) (12.5) (1.0) (6.5) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1)

EBT 377.0 442.2 (282.6) (287.3) 37.4 (2.4) (74.7) (104.3) (101.3) (98.8) (86.6) (63.1) (38.8) (22.3) 1.4 23.4 34.9

Income Taxes (126.5) (161.4) 98.0 97.7 (12.7) 0.9 27.3 35.5 34.4 33.6 29.4 21.5 13.2 7.6 (0.5) (7.9) (11.9)


Discontinued Operations - (23.0) (24.1) - - (9.6) (9.9) (4.6) - - - - - - - - -

Extraordinaries (after-tax) (361.8) - (1,475.5) - - - (727.7) (747.8) - - - - - - 0.0 - -

Net Income (GAAP) (111.3) 257.8 (1,684.1) (189.6) 24.7 (11.1) (785.0) (821.2) (66.8) (65.2) (57.2) (41.7) (25.6) (14.7) 0.9 15.4 23.0

EPS (Operating) 1.56 1.79 (1.23) (1.26) 0.16 (0.01) (0.31) (0.46) (0.44) (0.43) (0.38) (0.28) (0.17) (0.10) 0.01 0.10 0.15

EPS (GAAP) (0.69) 1.64 (11.19) (1.26) 0.16 (0.07) (5.22) (5.45) (0.44) (0.43) (0.38) (0.28) (0.17) (0.10) 0.01 0.10 0.15

Dividend per Share - 0.32 0.32 0.32 0.32 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08



EBITDA 1,105.3 1,197.4 442.0 424.3 759.2 184.0 115.6 68.2 74.2 77.4 91.0 115.1 140.9 155.8 181.2 204.3 217.8


SG&A 628.3 624.4 520.8 445.2 442.7 151.0 129.7 123.2 117.0 114.7 112.4 110.1 107.9 109.0 110.1 111.2 112.3


Cash From Operations (CFO) 892.2 1,033.0 679.6 432.7 553.6 234.3 199.2 132.0 114.1 105.2 103.0 108.7 115.7 116.6 130.9 148.8 157.3



Acquisitions/Divestures/Investments (23.8) 133.6 (47.9) - - (46.4) - (1.4) - - - - - - - - -


Other 17.5 4.4 (4.5) - - (27.5) 27.7 (4.6) - - - - - - - - -

Increase (Decrease) in Cash 104.8 197.0 114.7 12.3 110.9 21.8 85.4 33.4 (26.0) 20.6 (23.6) 27.0 (11.7) 35.6 0.7 57.8 16.8


Total Capital 5,798.0 5,728.5 3,976.5 3,668.9 3,595.5 5,698.6 4,930.5 4,095.1 3,976.5 3,904.1 3,795.2 3,746.2 3,668.9 3,651.9 3,606.1 3,619.2 3,595.5

Total Debt 1,666.5 1,648.8 1,593.2 1,484.3 1,395.5 1,644.2 1,645.0 1,642.7 1,593.2 1,588.2 1,538.8 1,533.8 1,484.3 1,484.3 1,439.9 1,439.9 1,395.5

Net Debt 1,470.5 1,255.7 1,085.5 964.4 764.5 1,229.4 1,144.7 1,109.0 1,085.5 1,059.9 1,034.1 1,002.1 964.4 928.8 883.6 825.8 764.5


Net Debt/Capital 25.4% 21.9% 27.3% 26.3% 21.3% 21.6% 23.2% 27.1% 27.3% 27.1% 27.2% 26.7% 26.3% 25.4% 24.5% 22.8% 21.3%


BVPS 25.76 25.95 15.84 14.49 14.59 27.05 21.83 16.27 15.81 15.36 14.97 14.68 14.49 14.38 14.37 14.46 14.59

TBVPS 7.62 7.58 6.00 4.67 4.77 7.85 6.93 6.44 5.99 5.54 5.14 4.85 4.67 4.55 4.54 4.63 4.77

December 15, 2015 127

Superior Energy Services (SPN) Valuation PRICE TARGET SCENARIOS



8.6% 11.7X $4,591 $31 129% Net Income 365.9 (111.3) 257.8 (1,684.1) (189.6) 24.7 145.1 185.4 197.0

10.6% 9.5X $4,164 $28 107% Depreciation & Amortization 509.3 625.9 650.8 - - - - - -


14.6% 6.9X $3,440 $23 70% Deferred Taxes 71.2 109.5 (74.9) 7.7 48.1 11.2 14.3 (49.6) (195.3)

16.6% 6.0X $3,132 $21 55% Translation Adjustment Other 355.4 407.2 (163.4) 1,715.6 39.1 39.1 39.1 39.1 39.1

18.6% 5.4X $2,855 $19 40% Operating Cash Flow (before working cap.) 1,301.8 1,031.3 670.4 39.2 (102.5) 75.0 198.5 175.0 40.8

20.6% 4.9X $2,606 $18 33% Net Cash from Investing Activities (1,974.0) (632.8) (482.5) (445.4) (263.2) (305.5) (602.1) (637.4) (748.2)


24.6% 4.1X $2,177 $15 11% Capitalized G&A - - - - - - - - -

26.6% 3.8X $1,992 $14 3% Less: Net Capital Expenditures (before Cap Int) 1,974.0 632.8 482.5 445.4 263.2 305.5 602.1 637.4 748.2

Working Capital Change (206.9) (43.9) 337.3 230.4 (14.4) (124.5) (95.4) (44.5) (52.9)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 147.5 (169.8) (19.0) (75.8) (108.9) (88.9) (88.9) (72.9) (57.0)

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (612.8) 612.3 (130.5) (560.8) (242.4) (17.2) (219.3) (345.0) (597.5)




Beta (Adjusted) 1.55 Subtract: Long Term Debt (Terminal Year) -

Cost of Equity 19.8% Subtract: Preferred Stock (Terminal Year) (9.3)


Cost of Debt, after tax 6.8% Subtract Levered FCF from Operations for Explict Forecast 1,421.3


WACC 16.6% Subtract: Dividends for Explict Forecast 0.4


Levered Free Cash Flow (2) (242.4) (17.2) (219.3) (345.0) 7,912.3




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December 15, 2015 129

Frank’s International, Buy $23PT, Top Tier Brand, Upside from “Self Help”, Offshore Discount Investment Thesis. We are initiating coverage of Frank’s International with a Buy rating and $23 price target. FI is a high market share, quality casing and tubular franchise offered at a discount to our mid-cycle valuation due to the cyclical downturn, “teething pains” during initial quarters as a public company, and negative near term outlook for high margin complex deepwater projects. In our view, shares may outperform if FI combines solid brand recognition with a streamlined internal structure established to operate as a public versus private company. We believe 2016 EPS estimates remain high, which may create some volatility in the shares. Longer term, we see potential positive catalysts from delivery on a “self help” agenda, expanded market share in under represented markets, and operating leverage with a recovery of the land market. Key Drivers • Quality Franchise with Opportunities to Grow Market Share. As the premium operator in the casing and tubular services business, FI offers a great quality franchise to play a 2017 recovery in the

offshore sector. The company is the “provider of choice” on the most complex wells and for the most difficult casing problems. As a result, the company enjoys ~25% market share for offshore work (only ~15% in Brazil) at high margins (between 35%-50%). The high returns, well branded, and relationship driven business may not be diluted with expansions into ancillary lower margin businesses. Although a mix shift away from higher margin complex wells has hurt FI in the downturn, the continued evolution of the market into more technical completions, with exotic metallurgy, cables for data flow, and tooling automation for remote operation, plays toward FI’s competitive advantages and may drive more higher margin business. As the technology advance favors FI as the premium provider, better rigs and work on future prototypes may help solidify FI position, as the company looks to gain market share with its equipment built into rigs.

• “Self Help” Agenda to Provide Positive Catalysts. FI looks to recover 5%-8% price reductions from a litany of ”self help” initiatives in order to offset the margin impacts. FI’s agenda centers around efforts to reduce costs, standardize internal processes to gain efficiency, lower procurement costs though more centralized planning, de-stocking inventory, implementation of lean manufacturing practices, and unlock working capital ($100 million). Although these plans echo those seen across the oil services sector, we consider the changes as a function of the company’s transition toward operating as a public versus a private company. In our view, the internal transition may help FI yield more consistent results and better set investor expectations. FI has already cut 15% of its workforce and shut seven US land bases, where implementation of lean initiatives began early in 2015. We expect further actions, with the next phase of lean initiatives beginning in the international business, to improve economics and amplify earnings recovery with a turn in the upstream cycle.

• Operating Leverage in US Land May Help. Only 8%-10% of FI’s business is generated on land, of which 40% of land customers are blue chip upstream operators. Lower well complexity makes the land business a more commoditized service. A fragmented competitive landscape, hosting a number of “mom and pop”/small private players in survival mode, has driven land business economics to breakeven margins vs. 20%+ margins in a better parts of the cycle. In our view, land pricing has decreased 10%+. Although a smaller part of the business, an upturn in US land drilling may prove a catalyst for upward estimate revisions, as operating leverage may lead to upside surprises.

• Strong Balance Sheet & FCF Provides Opportunity for M&A & Share Repurchase. FI has no debt and FCF through our forecast, which gives the company flexibility for acquisitions to facilitate geographic expansion into markets like the Middle East and Asia/Pacific, where it has 10%-20% and 20%-30% market shares, respectively. Comparatively, FI has 50%+ market share in the Gulf of Mexico and West Africa. Acquisitions to expand market share in under represented markets may prove a positive catalyst for the shares.

• Potential Overhang from Insider Ownership. The Mosing family holds 57.6% of the common shares and 83.2% of the voting rights, including its preferred share holdings. The family has three board seats. Potential sale of these shares is an overhang, but unlikely at current share levels.

December 15, 2015 130

Frank’s International (FI) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

International Services 475.3 531.3 447.8 360.8 456.2 124.2 122.6 103.1 97.9 93.0 88.4 87.5 91.9 98.3 108.1 118.9 130.8

US Services 434.9 439.6 332.8 270.3 381.8 109.3 78.4 74.4 70.7 67.2 63.8 67.0 72.4 83.2 95.7 100.5 102.5

Tubular Services 171.7 175.7 218.9 220.0 234.0 44.0 53.2 62.4 59.3 56.3 53.5 54.6 55.7 56.8 57.9 59.1 60.2

Total Revenues 1,081.9 1,146.6 999.5 851.1 1,072.0 277.4 254.3 239.9 227.9 216.5 205.7 209.0 219.9 238.3 261.7 278.5 293.6

International Services 199.6 231.5 183.7 138.6 183.8 52.3 55.3 39.2 37.0 35.3 33.8 33.7 35.8 38.8 43.2 48.2 53.6

US Services 198.4 180.6 97.4 77.5 155.4 44.9 16.7 18.2 17.6 17.1 16.6 20.1 23.8 29.9 37.3 42.1 46.1

Tubular Services 42.5 38.4 38.9 42.1 44.5 3.1 8.0 16.0 11.9 11.0 10.2 10.4 10.6 10.8 11.0 11.2 11.4

Corporate & Other 0.1 (0.0) 0.0 0.0 0.1 (0.0) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Depreciation & Amortization (78.2) (90.0) (109.8) (111.0) (104.2) (24.0) (27.7) (29.0) (29.0) (28.5) (28.0) (27.5) (27.0) (26.6) (26.2) (25.8) (25.6)

Other - - - - - - - - - - - - - - - - -

EBIT 362.4 360.3 210.3 147.3 279.5 76.3 52.3 44.3 37.4 34.9 32.5 36.6 43.2 52.9 65.3 75.7 85.6

Interest & dividend income - - 0.0 - - 0.0 - - - - - - - - - - -

Interest expense (0.7) 0.1 0.1 - - - (0.0) 0.2 - - - - - - - - -

Other, net (0.1) (39.2) (27.7) (24.1) (24.1) (6.7) (9.0) (6.0) (6.0) (6.0) (6.0) (6.0) (6.0) (6.0) (6.0) (6.0) (6.0)

EBT 361.7 321.2 182.8 123.1 255.3 69.6 43.3 38.5 31.4 28.9 26.5 30.6 37.2 46.8 59.3 69.7 79.6

Income Taxes (42.4) (78.9) (49.3) (38.5) (79.9) (15.5) (12.0) (12.0) (9.8) (9.0) (8.3) (9.6) (11.6) (14.7) (18.5) (21.8) (24.9)

Income Taxes (2.6) (15.4) (5.5) (5.2) (10.7) (2.2) (0.4) (1.6) (1.3) (1.2) (1.1) (1.3) (1.6) (2.0) (2.5) (2.9) (3.3)


Discontinued Operations 40.9 - - - - - - - - - - - - - - - -

Extraordinaries (after-tax) (6.8) (13.0) (12.8) - - (7.8) (2.7) (2.3) - - - - - - - - -

Net Income (GAAP) 350.8 213.9 115.2 79.5 164.8 44.2 28.3 22.5 20.3 18.7 17.1 19.7 24.0 30.2 38.3 44.9 51.3

EPS (Operating) 1.99 1.09 0.61 0.38 0.79 0.25 0.15 0.12 0.10 0.09 0.08 0.09 0.11 0.14 0.18 0.21 0.25

EPS (GAAP) 2.21 1.03 0.55 0.38 0.79 0.21 0.14 0.12 0.10 0.09 0.08 0.09 0.11 0.14 0.18 0.21 0.25




EBITDA 440.6 450.4 320.1 258.3 383.7 100.3 80.0 73.3 66.5 63.4 60.5 64.1 70.2 79.5 91.5 101.5 111.1






Acquisitions/Divestures/Investments 49.1 (0.7) (75.7) - - 0.1 (78.5) 2.8 - - - - - - - - -

Cash From Financing (CFF) 227.1 (74.2) (97.3) (93.1) (93.1) (23.2) (23.7) (27.1) (23.3) (23.3) (23.3) (23.3) (23.3) (23.3) (23.3) (23.3) (23.3)

Other (282.0) (36.6) (47.8) (32.2) (32.2) (24.0) (18.0) 2.3 (8.0) (8.0) (8.0) (8.0) (8.0) (8.0) (8.0) (8.0) (8.0)

Increase (Decrease) in Cash 87.2 84.4 19.5 58.7 (1.5) 9.1 (23.7) 32.3 1.8 33.8 30.5 0.8 (6.4) (9.2) (9.9) 4.9 12.6


Total Capital 1,098.5 1,213.0 1,220.6 1,198.9 1,262.6 1,223.7 1,232.7 1,225.6 1,220.6 1,214.0 1,205.8 1,200.2 1,198.9 1,203.9 1,216.9 1,236.5 1,262.6

Total Debt 0.4 0.3 0.2 0.2 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Net Debt (404.6) (489.1) (508.6) (567.3) (565.8) (498.2) (474.5) (506.8) (508.6) (542.4) (572.9) (573.7) (567.3) (558.2) (548.3) (553.2) (565.8)


Net Debt/Capital -36.8% -40.3% -41.7% -47.3% -44.8% -40.7% -38.5% -41.4% -41.7% -44.7% -47.5% -47.8% -47.3% -46.4% -45.1% -44.7% -44.8%


BVPS 6.91 5.84 5.84 5.73 6.03 5.87 5.89 5.85 5.83 5.80 5.76 5.73 5.73 5.75 5.81 5.91 6.03

TBVPS 6.82 5.77 5.71 5.60 5.91 5.80 5.77 5.73 5.71 5.67 5.64 5.61 5.60 5.63 5.69 5.78 5.91

December 15, 2015 131

Frank’s International (FI) Valuation PRICE TARGET SCENARIOS


0.0% N/A $7,082 $34 123% Levered Cash Flow:

1.5% 65.6X $6,599 $32 110% Net Income - 350.8 213.9 115.2 79.5 164.8 252.4 289.9 320.5

3.5% 28.4X $6,026 $29 90% Depreciation & Amortization - 78.2 90.0 109.8 111.0 104.2 100.6 99.5 99.2


7.5% 13.3X $5,055 $25 64% Deferred Taxes - 3.6 28.0 15.0 4.6 9.5 14.5 16.7 18.5


11.5% 8.7X $4,273 $21 38% Operating Cash Flow (before working cap.) - 432.6 331.9 240.0 195.0 278.5 367.5 406.1 438.2

13.5% 7.4X $3,940 $19 25% Net Cash from Investing Activities - (135.4) (173.6) (180.5) (70.6) (75.0) (91.9) (96.7) (100.8)


17.5% 5.7X $3,365 $17 12% Capitalized G&A - - - - - - - - -

19.5% 5.1X $3,118 $15 (2%) Less: Net Capital Expenditures (before Cap Int) - 135.4 173.6 180.5 70.6 75.0 91.9 96.7 100.8

Working Capital Change - (213.0) (60.0) 155.9 35.5 (103.8) (66.5) (39.2) (42.4)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred - (472.9) (0.1) (0.1) - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations - 983.2 218.4 (96.4) 88.9 307.3 342.1 348.6 379.8















December 15, 2015 132











December 15, 2015 133

Oil States: Buy, $43PT, Quality Franchises At Trough Valuations, Positioned for Recovery Investment Thesis. We are initiating coverage with a Buy rating and $43 price target. OIS is attractive as a collection of market-share leading, quality franchises, with a solid balance sheet, that trades at a cyclical trough valuation. Signs of better balances in the oil market during 2016 may prove a catalyst for an inflection in both the Completions segment, highly levered to complex North American completions, and Offshore Products, geared toward a later cycle recovery in deepwater development activity. High 2016 estimates may lead to negative revisions, but we would use potential volatility as a buying opportunity. In our view, upward revisions to conservative consensus 2017 estimates should prove a far greater positive catalyst for OIS shares, relative to pinpointing the 2016 earnings low.

Key Drivers

• High Quality Exposure to Complex Completions in North American Land. The completions segment focuses on higher-end services for complex horizontal, service intensive multi-zone completions. With our expectation for a recovery in US land activity in 2016/17, the OIS Completions segment (85%-90% US, of which 10%-15% is GoM) may see improved product mix and regain the 5%-10%+ pricing power it has lost in the downturn. The combination of mix, pricing, cost reductions (30% headcount cut since 2014YE, closed 15% of ~50 service facilities to streamline operations) should drive operating leverage and an earnings recovery from 2016 EPS lows. In our view, positive mix shift toward premium products, like isolation tools 40-50% market share, versus frac stacks, which face more commoditization and pricing competition may lift mix. The cost saving of 3-4 days provided by isolation tools, which allows simultaneous wireline and pressure pumping, matter less as spread cost fall, but more as much as activity ramps and oil services inflation returns. Within Completions, five service lines, all patent protected, represent 70-80% of EBITDA (Frac Stacks, Isolation Tools (Frac/Pressure Pumping Support), Wireline Support, Ball Launchers (sliding sleeve), Tempress (drillouts &fishing). All are leveraged to a recovery of US land activity.

• Offshore Products Turns with Deepwater Activity. The erosion of “book & turn” offshore activity shifted Offshore Products to 60%-65% backlog derived, versus a more typical 50%/50% mix. Margins are down ~400bps from recent highs , with our expectation that a further erosion of floater activity in 2016 may take margins to the mid/upper-teens. Since 60%-65% of the segment is tied to floating production systems and subsea pipelines, we do not expect a more meaningful recovery of segment economics until deepwater development activity has a chance to re-accelerate in 2017. Current 2017 consensus EPS does not reflect a meaningful rebound in activity. The 10%-15% of backlog that is more drilling centric may likely accelerate, as destocking and equipment purchase delays from offshore drillers reverse trend to cope with a recovery in activity levels. In the interim, OIS initiatives for procurement savings, where 65%+ of cost is materials, may lead margins to surprise to the upside with a modest recovery in activity.

• Drilling Services Remains a Legacy Asset Cash Flow Business. OIS land rigs, albeit well maintained according to the company, remain at the low end of an over-supply market. The company’s 34, 500-750HP rigs target the vertical, oil drilling market, primarily in the Permian and Rockies. A smaller, yet cash flow positive business segment, relies on relationships with a small number of clients. Not a primary driver for the shares, but we would expect that utilization (currently ~30%), dayrates, and margins may improve with a North American upstream activity recovery in 2016.

• Historically Under-Levered Balance Sheet Leaves Room for Growth Investment. With Total Debt/TTM EBITDA below 1.0x, relative to historic 1.5x average/target, OIS’s balance sheet may have flexibility for M&A, given the average OIS acquisition around $50 million average acquisition and an average $75 million a year in the budget for acquisitions. Further acquisitions of bolt-on offerings, like Montgomery Machine (subsea components) and consolidation of small operators, who may like to continue to participate in running their business, may be targets for OIS at the trough of the cycle. If not, OIS has ~$130 million left on its share repurchase authorization, which may support the shares.

December 15, 2015 134

Oil States International (OIS) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Completion Services 577.6 656.9 309.9 255.2 433.5 118.1 69.4 66.7 55.6 55.6 57.2 66.1 76.3 88.1 101.8 117.6 125.9

Drilling Services 170.5 201.1 65.6 53.3 93.5 23.7 16.7 16.5 8.7 10.0 11.6 14.4 17.2 19.6 22.6 24.7 26.6

Offshore Products 882.6 961.6 724.7 639.7 809.7 195.6 183.1 175.6 170.4 165.3 160.3 155.5 158.6 174.5 191.9 211.1 232.2

Total Revenues 1,630.7 1,819.6 1,100.2 948.1 1,336.7 337.4 269.3 258.9 234.7 230.9 229.1 236.0 252.1 282.2 316.3 353.4 384.8

Completion Services 197.9 223.7 58.6 38.3 91.7 33.4 9.2 9.1 7.0 6.9 7.7 10.2 13.4 17.2 20.9 25.3 28.3

Drilling Services 47.7 57.0 10.0 8.4 18.4 4.2 2.6 1.9 1.3 1.4 1.7 2.3 2.9 3.5 4.3 4.9 5.6

Offshore Products 175.0 221.7 159.1 113.7 156.8 43.6 41.9 39.5 34.1 31.4 28.9 26.0 27.4 31.0 36.0 41.7 48.2

Corporate & Other (61.6) (56.2) (45.5) (47.4) (66.8) (12.4) (10.4) (11.0) (11.7) (11.5) (11.5) (11.8) (12.6) (14.1) (15.8) (17.7) (19.2)


EBIT 81.4 321.4 53.8 (13.0) 73.8 36.3 10.8 7.7 (1.0) (3.6) (4.7) (4.6) (0.2) 6.4 14.0 22.6 30.7

Interest & dividend income 2.4 0.6 0.6 1.0 0.4 0.1 0.1 0.2 0.2 0.3 0.3 0.3 0.2 0.2 0.1 0.1 0.1


Other, net 1.6 1.6 - - - - - - - - - - - - - - -

EBT 9.5 306.4 49.1 (13.6) 72.3 34.8 9.3 6.4 (1.3) (3.7) (4.8) (4.7) (0.3) 6.2 13.7 22.2 30.2

Income Taxes 29.8 (107.6) (14.1) 3.4 (18.1) (11.7) (1.7) (1.0) 0.3 0.9 1.2 1.2 0.1 (1.5) (3.4) (5.6) (7.5)

Net Income (Operating) 39.3 198.7 35.1 (10.2) 54.2 23.1 7.5 5.4 (1.0) (2.8) (3.6) (3.5) (0.3) 4.6 10.3 16.7 22.6

Discontinued Operations 394.2 15.0 0.2 - - 0.2 - 0.0 - - - - - - - - -


Net Income (GAAP) 421.3 142.2 26.5 (10.2) 54.2 19.6 6.1 1.7 (1.0) (2.8) (3.6) (3.5) (0.3) 4.6 10.3 16.7 22.6

EPS (Operating) 0.71 3.74 0.70 (0.20) 1.08 0.45 0.15 0.11 (0.02) (0.06) (0.07) (0.07) (0.01) 0.09 0.21 0.33 0.45

EPS (GAAP) 7.57 2.68 0.53 (0.20) 1.08 0.38 0.12 0.03 (0.02) (0.06) (0.07) (0.07) (0.01) 0.09 0.21 0.33 0.45




EBITDA 359.1 446.2 182.1 112.9 200.0 68.9 43.2 39.5 30.6 28.2 26.9 26.8 31.0 37.6 45.3 54.2 62.9



Cash From Operations (CFO) 687.3 438.0 350.8 61.0 0.1 114.7 107.2 31.0 98.0 27.9 23.8 11.6 (2.3) (12.6) (9.3) (0.7) 22.7


Free Cash Flow (FCF) 229.7 238.8 223.3 (52.8) (160.3) 76.4 76.7 7.4 62.8 0.2 (3.7) (16.8) (32.5) (46.4) (47.2) (43.2) (23.4)

Acquisitions/Divestures/Investments 565.9 3.4 (30.9) - - (33.5) 1.1 1.4 - - - - - - - - -

Cash From Financing (CFF) (430.6) (787.7) (95.8) - 99.6 (17.5) (60.7) (17.6) - - - - - - 33.0 43.2 23.4

Other (18.9) (0.5) (1.3) - - (6.6) 0.3 5.0 - - - - - - - - -

Increase (Decrease) in Cash 346.1 (546.0) 95.2 (52.8) (60.7) 18.8 17.4 (3.7) 62.8 0.2 (3.7) (16.8) (32.5) (46.4) (14.2) - -


Total Capital 3,596.6 1,488.0 1,413.8 1,403.6 1,557.5 1,474.1 1,432.7 1,414.8 1,413.8 1,411.0 1,407.4 1,403.9 1,403.6 1,408.3 1,451.6 1,511.4 1,557.5

Total Debt 973.2 147.4 160.1 160.1 259.7 206.3 157.4 160.1 160.1 160.1 160.1 160.1 160.1 160.1 193.2 236.3 259.7

Net Debt 373.9 94.1 11.7 64.5 224.7 134.2 67.9 74.4 11.7 11.4 15.2 31.9 64.5 110.9 158.2 201.3 224.7


Net Debt/Capital 10.4% 6.3% 0.8% 4.6% 14.4% 9.1% 4.7% 5.3% 0.8% 0.8% 1.1% 2.3% 4.6% 7.9% 10.9% 13.3% 14.4%


BVPS 47.17 25.26 24.88 24.85 25.93 24.89 25.25 25.07 25.05 24.99 24.92 24.85 24.85 24.94 25.14 25.48 25.93

TBVPS 35.54 19.51 18.43 18.35 19.44 18.42 18.76 18.58 18.56 18.50 18.43 18.36 18.35 18.45 18.65 18.99 19.44

December 15, 2015 135

Oil States International (OIS) Valuation PRICE TARG ET SCEN ARIO S


1.3% 75.1x $3,282 $66 135% Le ve re d Cash F low :

3.3% 30.0X $2,991 $60 114% N e t Incom e - 421.3 142.2 26.5 (10.2) 54.2

5.3% 18.8X $2,732 $55 96% De pre ciation & A m ortization - 277.7 124.8 128.3 125.9 126.3

7.3% 13.6X $2,501 $50 78% Capital ize d In te re st - - - - - -

9.3% 10.7X $2,293 $46 64% De fe rre d Tax e s - (8.0) (12.0) (3.3) 1.4 (7.2)

11.3% 8.8X $2,106 $43 53% Translation A d justm e nt O the r - - - - - -

13.3% 7.5X $1,938 $39 39% O pe rating Cash F low (be fore w orking cap.) - 690.9 255.0 151.5 117.1 173.3

15.3% 6.5X $1,786 $36 28% N e t Cash from Inve sting A ctiv itie s - 108.4 (195.9) (158.5) (113.8) (160.4)

17.3% 5.8X $1,649 $33 18% Cap ital ize d In te re st - - - - - -

19.3% 5.2X $1,525 $31 10% Cap ital ize d G& A - - - - - -

21.3% 4.7X $1,413 $29 3% Le ss: N e t Capital Expe nditure s (be fore Cap Int) - (108.4) 195.9 158.5 113.8 160.4

W orking Cap ital Change - 714.1 174.0 396.1 (56.2) (173.2)

W e ighte d Ave rage Cost of Capital (W ACC) Ch ange in De bt/P re fe rre d - (340.9) (565.8) 12.7 - 99.6

N otional Tax Rate 35.0% Le ve re d Fre e Cash F low from O pe rations - 426.2 450.9 (415.7) 59.5 86.4


De bt Risk Spre ad 250 EBITDA




Marginal Cost o f De b t 6.5% A dd : Cash (Te rm inal Ye ar)

Cost o f De bt, afte r tax 4.2% Subtract Le ve re d FCF from O pe rations for Ex p lict Fore cast




Le ve re d Fre e Cash F low (2) 59.5 86.4

(1) Re f le cts a ~11.3% W A CC app lie d to 2020 EBITDA . Te rm in al value is com pute d at ye ar-e nd 2020.

(2) A ssu m e s inve stm e nt occurs at be ginn ing o f ye ar, le ve re d fre e cash f low is ye ar-e n d .


December 15, 2015 136











December 15, 2015 137

C&J Services, Buy, $7.50 PT, Walks Covenant Tightrope With 2H16 Recovery, PT Upside Post Debt Risks Investment Thesis. We are initiating coverage of CJES with a Buy rating and $7.50 price target. We fully recognize that we are making a high risk/high return call, which hinges on our forecast for a moderate recovery of North American land activity in 2H16. Under our above consensus forecast for 2016/2017, we have CJES squeaking by recently moderated debt covenants, which require minimum cumulative adjusted EBITDA thresholds and terms. If we are too optimistic, CJES may be at the mercy of the banks in 2H/16. If CJES survives to the other side of he debt chasm, the stock may be worth ~$15-20/share in a more normalized risk environment versus the ~24% WACC factored into our valuation. We anticipate that the shares may remain volatile, in the face of CJES’s binary story and shaken investor confidence after the company missed a negatively preannounced 3Q/15 due to execution issues. CJES may also see potential upside catalysts from and effective integration of NBR, benefits from an integrated business model, a bundled service offering in the upturn, and potential to gain market share as the pressure pumping market consolidates.

Key Drivers

• Bullish Call Hinges on a 2H16 Pressure Pumping Recovery. A bullish outlook on CJES requires a view North American land activity picks up in 2H/16, which spurs a recovery in pressure pumping economics. Industry sources suggest that out of 20m HP in the pressure pumping market, only 10-12m HP is active. In our view, the market may underestimate the degree of fleet attrition from cannibalization of units for maintenance and greater “wear-and-tear” from higher service intensity per well. The combination of fleet attrition and our forecast for an increase in US land rig counts, leaves a higher probability that the pressure pumping market may become more balanced in 2H/16. The modest improvement in Completion Services economics return CJES towards profitability in 2017 in our forecast. Although near term quarters may prove choppy, signs of a turn should be a positive catalyst for the shares.

• Renegotiation of the Revolver Leaves Some Breathing Room. The reduction of the revolver to $400 million, suspension of leverage ratio covenants, and institution of EBITDA thresholds through 2Q/3Q17 removes some of the near term overhang on name, which resulted from increased debt loads due to the NBR business acquisitions. With only $94 million of $400 million drawn, CJES continues to have liquidity amid this rough patch. During 4Q15, we see CJES drawing ~$36 million additional capital from the facility. We do see CJES staying within adjusted EBITDA, cumulative EBITDA, and various carried EBITDA borrowing basket parameters by a narrow margin in 2H16. As leverage ratios normalize in 2017, we see CJES migrating back towards its historically lower leverage rates.

• NBR Integration. Assimilation of the NBR business lines, with better execution and efficiency, may help to improve margins. After realizing ~$15 million per quarter in cost savings in 2015, we see an opportunity for an additional $2-3 million per quarter from procurement savings and other efficiencies. The addition of workover rigs, which brings the fleet closer to 500, may add some consistency to demand & earnings stability, as workover rigs install artificial lift solutions throughout the life cycle of a well.

• Integrated Business Model & Bundled Services. CJES believes its integrated business model, where R&T manufactures products at a price points 35%-40% below market, creates a competitive cost advantage, particularly for wireline. A more integrated model, with a broader product offering after the NBR acquisition, creates a focus on scale and bundled offerings of pressure pumping, coiled tubing, wireline, downhole tools, completion tools, and production services. In our view, the efficiency and bundled services, makes CJES’s offering more attractive to the E&P industry focused on centralized procurement, who seek to refine their stable of suppliers.

• Industry Consolidation May Yield Market Share To CJES. In our view, CJES may stand gain market share in a consolidated market, where smaller players have exited and larger players have merged. Post the HAL/BHI merger, we expect that upstream operators may look to sponsor a select number of alternate providers amongst the remaining stable operators in order to prevent too much concentration amongst oil service providers and avert aggregation of pricing power within supply chains.

December 15, 2015 138

C&J Energy Services (CJES) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Completions Services - - 1,204.4 1,082.7 1,783.0 371.0 332.5 256.9 244.0 233.3 256.6 282.3 310.5 357.1 410.6 472.2 543.1

Well Support Services - - 451.7 555.3 896.6 16.1 153.1 150.9 131.6 118.4 127.0 145.1 164.9 189.3 219.4 235.3 252.6

Other Services/Corporate - - 79.1 78.8 78.8 14.1 25.6 19.7 19.7 19.7 19.7 19.7 19.7 19.7 19.7 19.7 19.7

Total Revenues 1,070.3 1,607.9 1,735.1 1,716.8 2,758.3 401.2 511.2 427.5 395.2 371.4 403.3 447.0 495.1 566.0 649.7 727.2 815.4

Completions Services - - 73.7 96.0 337.3 49.8 24.5 (8.6) 8.1 9.3 18.0 26.8 41.9 66.1 77.0 89.7 104.5

Well Support Services - - 69.3 91.6 207.0 4.3 22.2 23.6 19.3 17.0 18.9 24.5 31.2 39.6 50.2 56.2 61.0

Other Services/Corporate 190.7 253.5 (100.4) (88.0) (87.0) (22.3) (26.3) (26.4) (25.4) (23.5) (21.5) (21.5) (21.5) (21.5) (21.5) (21.5) (22.5)


Gain/Loss on disposal of assets/Other (0.7) 0.0 0.4 - - 0.7 (0.2) (0.1) - - - - - - - - -

EBIT 115.3 145.4 (225.5) (176.7) 206.5 (4.9) (61.4) (86.3) (72.8) (69.5) (54.7) (38.1) (14.5) 19.8 42.9 62.4 81.5


Other income - - 0.4 - - (0.2) 3.2 (2.6) - - - - - - - - -

EBT 108.8 135.5 (306.5) (275.9) 107.3 (10.3) (82.1) (117.3) (96.9) (94.2) (79.5) (62.9) (39.2) (5.0) 18.1 37.6 56.7

Income Taxes (41.6) (50.2) 105.8 96.1 (37.4) 2.9 28.3 40.9 33.7 32.8 27.7 21.9 13.7 1.7 (6.3) (13.1) (19.7)




Net Income (GAAP) 66.4 68.8 (615.9) (179.8) 70.0 (32.7) (65.1) (455.0) (63.1) (61.4) (51.8) (41.0) (25.6) (3.3) 11.8 24.5 36.9

EPS (Operating) 1.2 1.5 (2.0) (1.5) 0.6 (0.1) (0.5) (0.7) (0.5) (0.5) (0.4) (0.4) (0.2) (0.0) 0.1 0.2 0.3

EPS (GAAP) 1.2 1.2 (6.0) (1.5) 0.6 (0.5) (0.6) (3.9) (0.5) (0.5) (0.4) (0.4) (0.2) (0.0) 0.1 0.2 0.3




EBITDA 190.7 253.5 42.6 99.7 457.3 31.8 20.3 (11.4) 1.9 2.9 15.4 29.8 51.6 84.1 105.7 124.5 143.1



Cash From Operations (CFO) 422.7 181.8 80.6 110.5 219.0 47.7 55.5 (0.8) (21.8) 37.0 21.2 27.7 24.6 35.2 48.5 63.2 72.1


Free Cash Flow (FCF) 264.7 (125.8) (83.3) 13.3 33.5 (0.9) (13.2) (25.0) (44.2) 16.0 (1.6) 2.4 (3.4) 3.1 3.0 12.3 15.1

Acquisitions/Divestures/Investments (13.5) (38.8) (660.6) - - (691.4) (13.1) 43.9 - - - - - - - - -

Cash From Financing (CFF) (72.7) 158.6 746.0 - - 725.7 1.8 (17.6) 36.0 - - - - - - - -

Other (53.4) 1.6 2.8 - - (3.6) (3.1) 9.5 - - - - - - - - -

Increase (Decrease) in Cash 125.2 (4.4) 5.0 13.3 33.5 29.8 (27.6) 10.9 (8.1) 16.0 (1.6) 2.4 (3.4) 3.1 3.0 12.3 15.1


Total Capital 860.4 1,131.8 2,058.5 1,898.8 1,988.8 2,593.9 2,533.2 2,080.5 2,058.5 2,002.1 1,955.3 1,919.3 1,898.8 1,900.5 1,917.3 1,946.8 1,988.8

Total Debt 164.2 349.9 1,166.0 1,166.0 1,166.0 1,129.2 1,131.4 1,129.9 1,166.0 1,166.0 1,166.0 1,166.0 1,166.0 1,166.0 1,166.0 1,166.0 1,166.0

Net Debt 149.8 339.9 1,151.0 1,137.6 1,104.1 1,089.4 1,119.1 1,106.8 1,151.0 1,135.0 1,136.6 1,134.2 1,137.6 1,134.5 1,131.5 1,119.1 1,104.1


Net Debt/Capital 17.4% 30.0% 55.9% 59.9% 55.5% 42.0% 44.2% 53.2% 55.9% 56.7% 58.1% 59.1% 59.9% 59.7% 59.0% 57.5% 55.5%

Total Debt/EBITDA 0.9X 1.4X 27.4X 11.7X 2.5X 8.9X 13.9X -24.8X 154.9X 100.2X 19.0X 9.8X 5.7X 3.5X 2.8X 2.3X 2.0X

BVPS 12.6 13.8 8.7 6.3 7.0 24.5 12.0 8.1 7.6 7.1 6.7 6.4 6.3 6.3 6.4 6.7 7.0

TBVPS 6.6 7.7 4.2 2.3 3.0 10.8 4.3 4.1 3.6 3.2 2.8 2.5 2.3 2.3 2.4 2.7 3.0

December 15, 2015 139

C&J Energy Services (CJES) Valuation PRICE TARGET SCENARIOS



15.6% 6.4X $1,140 $9.75 103% Net Income - 66.4 68.8 (615.9) (179.8) 70.0 178.0 221.6 182.9

17.6% 5.7X $1,062 $9.00 87% Depreciation & Amortization - 74.7 108.1 268.4 276.4 250.9 244.9 244.7 244.7

19.6% 5.1X $992 $8.50 77% Capitalized Interest - - - - - - - - -

21.6% 4.6X $927 $8.00 66% Deferred Taxes - 12.1 33.2 (94.0) (0.5) 0.2 0.5 0.6 0.5

23.6% 4.2X $868 $7.50 56% Translation Adjustment Other - - - - - - - - -

25.6% 3.9X $814 $7.00 46% Operating Cash Flow (before working cap.) - 153.2 210.2 (441.5) 96.2 321.0 423.4 466.8 428.1

27.6% 3.6X $764 $6.50 35% Net Cash from Investing Activities - (171.5) (346.4) (824.4) (97.1) (185.5) (239.7) (245.0) (249.9)


31.6% 3.2X $677 $5.75 20% Capitalized G&A - - - - - - - - -

33.6% 3.0X $638 $5.50 14% Less: Net Capital Expenditures (before Cap Int) - 171.5 346.4 824.4 97.1 185.5 239.7 245.0 249.9

Working Capital Change - (22.4) (32.6) (20.8) (5.8) (122.0) (24.9) (25.5) (27.6)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred - (72.7) 158.6 752.7 - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations - 76.8 (262.2) (1,997.8) 4.9 257.6 208.6 247.4 205.8


Debt Risk Spread 1,500 EBITDA 624.5













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December 15, 2015 141

Flotek Industries, Buy, $14.50PT, FracMax Noise Blurs Growth Trajectory of CnF Investment Thesis. We are initiating coverage of FTK with a Buy rating and $14.50 price target. The secular growth trajectory for FTK’s CnF technology and shift toward a direct marketing business model remain exciting, despite a recent stumble around a data error within FTK’s FracMax analytics and marketing model. In our view, FracMax errors create a near term credibility issue, especially as data integrity overhangs product validations in progress with a handful of E&P operators. If we assume this is a minor software flaw, rather than a pressing legal matter, weakness in the shares is an opportunity to buy a the secular CnF growth story at a discount. Our estimates are above consensus, which signals further momentum with upward revisions. In our view, FTK is an interesting small cap name to understand, as part of the industry trend towards unconventional well optimization through logistical efficiencies, optimum technology, data analysis, and now chemistry. CnF sales growth may return to the front of the debate, as the FracMax data issue fades. We are buyers around FracMax related weakness.

Key Drivers

• Secular growth story for CnF. FTK’s Complex nano-Fluid (CnF) technology is a disruptive technology and secular growth story. Simply stated, it is a combination of surfactants, solvents, and water with patented, environmentally friendly, chemistry used in well stimulation and re-stimulation activity to increase penetration and recovery from wells. Via performance tracking from proprietary FracMax software, CnF solutions have a substantial well data set to show a 20-30% production increase through use of the product. FTK claims about a 10% market share in US land wells, but looks to expand that market share to 30% by the end of 2016. Strong counter cyclical growth (~25% Q/Q in 3Q/15) suggests a high adoption rate. With smaller customers easier to convert to new technologies, we can see larger leaps in demand with the conversion of larger, late adopters. Even if we risk FTK’s market penetration targets, share gains and a modest US land rig count recovery in 2016/17 translates into tremendous growth. As of 3Q15, FTK had increased its customer base to nearly three dozen from a dozen over the last year. Currently, there are no similar competing technologies and FTK’s products are patent protected, which makes the CnF story more interesting. If the product expands efficiency beyond logistics and mechanics and into chemistry, lowering costs for fracs and re-fracs etc., a high growth profile appears warranted (~400% revenue growth from 3Q15 to exit of 2017). FTK discussed international interest from the Middle East (Saudi Arabia & UAE), which may leave room for upward revisions to our demand forecast.

• Direct to Customer Business Model May Improve Market Penetration & Margins. FTK has set up Flotek Store and expanded its business development efforts to market directly to E&P customers. More direct sales allows FTK to better control product pricing/markups rather than distributors. Traditionally, Cnf was “rebranded” by SLB, HAL, Universal, CJES and other pressure pumpers/service providers, who may retain the high margins from the product. In our view, more direct sales may improve margins and utilization across operators not exposed to the product. For example, SLB is not a significant adopter, whose customers may be influenced by a greater direct sales effort.

• Activist Investor Looks to Expand Product Scope. Praesidium Investment Management has taken an activist stake with intention to promote Flotek’s products beyond the oil field and recognize the value of the FracMax software/database by breaking it out into a separate business unit. Praesidium may recognize untapped opportunities and value in FracMax, but we continue to monitor the situation for fear of lost focus on growth opportunities in the oil/gas markets. The announcement of the recent FracMax issues clouds the potential outcomes from the activist initiatives.

• Drilling & Production Leveraged to Cyclical Recovery. The Drilling and Production Technologies segments should recover cyclically with the market. The combined offering of downhole tools (Teledrift and Telepulse) and artificial lift are attractive, but represent under 20% of revenue and an operating loss in 2Q15. While cyclical recovery may augment earnings, investor’s focus on FTK should remain on the Chemistry segment.

• Financing Requirements. FTK has financing needs to meet if it wishes to grow. The current $75 million credit facility, with 49.7m available at end of 2Q15, may suffice near term, but FTK may need to expand its debt capacity. In this environment, fickle capital markets remain a concern regarding the marginal cost of debt.

December 15, 2015 142

Flotek Industries (FTK) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Energy Chemistry 200.9 268.8 229.5 366.0 583.2 46.6 56.5 60.2 66.2 73.7 83.7 96.6 112.0 125.9 141.9 154.2 161.2

Drilling Technologies 112.4 113.3 51.6 45.7 66.3 18.7 12.3 10.8 9.7 10.2 10.7 11.8 13.0 14.3 15.7 17.3 19.0

Production Technologies 14.8 16.0 12.2 13.0 18.9 3.6 2.7 3.1 2.8 2.9 3.1 3.4 3.7 4.1 4.5 4.9 5.4

Consumer & Industrial 42.9 51.1 56.8 57.4 59.8 13.5 15.5 13.9 14.0 14.1 14.3 14.4 14.6 14.7 14.9 15.0 15.2

Total Revenues 371.1 449.2 350.1 482.2 728.2 82.4 87.0 87.9 92.7 101.0 111.8 126.2 143.3 159.0 176.9 191.4 200.8

Energy Chemistry 88.5 117.9 88.4 162.5 270.4 16.1 20.4 24.3 27.6 31.7 36.8 43.2 50.8 57.8 65.7 71.8 75.2

Drilling Technologies 43.2 45.7 16.1 11.7 19.9 6.0 4.1 3.3 2.7 2.7 2.7 2.9 3.4 3.9 4.6 5.3 6.1

Production Technologies 5.2 6.5 2.4 2.5 4.7 0.7 0.6 0.6 0.4 0.5 0.6 0.7 0.8 0.9 1.1 1.3 1.5

Consumer & Industrial 10.7 12.9 14.0 12.8 13.3 3.7 4.1 3.1 3.1 3.1 3.2 3.2 3.2 3.3 3.3 3.3 3.4

SG&A (78.2) (87.1) (95.5) (129.6) (195.7) (23.9) (23.0) (23.6) (24.9) (27.1) (30.0) (33.9) (38.5) (42.7) (47.5) (51.4) (54.0)

R&D (3.8) (5.0) (6.5) (8.3) (12.5) (1.3) (1.7) (2.0) (1.6) (1.7) (1.9) (2.2) (2.5) (2.7) (3.0) (3.3) (3.4)

Other 0.4 0.1 (1.6) - - (0.8) (0.8) - - - - - - - - - -


EBIT 58.7 81.2 6.1 39.7 87.1 (2.1) 1.0 2.8 4.5 6.3 8.4 10.9 14.2 17.3 20.8 23.6 25.3

Interest expense (2.1) (1.6) (0.8) 1.9 1.9 (0.4) (0.4) (0.5) 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Other income 0.3 (0.4) (0.1) 0.3 0.3 (0.2) (0.0) 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

EBT 57.0 79.2 5.2 41.9 89.3 (2.7) 0.5 2.4 5.0 6.8 8.9 11.4 14.8 17.8 21.4 24.2 25.9

Income Taxes (20.8) (25.4) (0.5) (14.7) (31.2) 0.7 0.0 (0.4) (0.9) (2.4) (3.1) (4.0) (5.2) (6.2) (7.5) (8.5) (9.1)

Net Income (Operating) 36.2 53.8 4.7 27.2 58.0 (2.0) 0.6 2.0 4.2 4.4 5.8 7.4 9.6 11.6 13.9 15.7 16.8

Gain/(Loss) on Sale of Assets - (0.2) 1.3 - - 0.8 0.5 - - - - - - - - - -

Extraordinaries (after-tax) - - (13.9) - - (0.3) (13.6) - - - - - - - - - -

Net Income (GAAP) 36.2 53.6 (7.9) 27.2 58.0 (1.5) (12.5) 2.0 4.2 4.4 5.8 7.4 9.6 11.6 13.9 15.7 16.8

EPS (Operating) 0.67 0.97 0.09 0.50 1.06 (0.04) 0.01 0.04 0.08 0.08 0.11 0.14 0.17 0.21 0.25 0.29 0.31

EPS (GAAP) 0.67 0.97 (0.14) 0.50 1.06 (0.03) (0.23) 0.04 0.08 0.08 0.11 0.14 0.17 0.21 0.25 0.29 0.31




EBITDA 65.6 90.8 18.8 51.6 100.1 1.4 4.6 5.6 7.3 9.1 11.3 13.9 17.3 20.4 24.0 26.9 28.7





Free Cash Flow (FCF) 24.5 28.9 16.9 17.6 19.1 0.9 1.6 4.2 10.2 5.4 6.0 4.1 2.1 (0.8) 4.8 5.9 9.2

Acquisitions/Divestures/Investments (47.7) (1.8) 1.5 - - (0.1) 0.7 0.9 - - - - - - - - -

Cash From Financing (CFF) 22.7 (28.8) (6.0) - - 0.6 (2.4) (4.2) - - - - - - - - -

Other 0.5 0.2 (0.5) - - (0.2) 0.1 (0.4) - - - - - - - - -

Increase (Decrease) in Cash 0.0 (1.5) 11.9 17.6 19.1 1.2 (0.0) 0.5 10.2 5.4 6.0 4.1 2.1 (0.8) 4.8 5.9 9.2


Total Capital 311.9 350.0 350.7 392.2 464.5 353.4 342.0 342.9 350.7 358.7 368.1 379.0 392.2 407.3 424.8 444.1 464.5

Total Debt 62.1 44.0 47.8 47.8 47.8 48.0 52.2 47.8 47.8 47.8 47.8 47.8 47.8 47.8 47.8 47.8 47.8

Net Debt 59.4 42.8 34.6 17.0 (2.2) 45.5 49.7 44.8 34.6 29.2 23.2 19.1 17.0 17.8 13.0 7.1 (2.2)


Net Debt/Capital 19.0% 12.2% 9.9% 4.3% -0.5% 12.9% 14.5% 13.1% 9.9% 8.1% 6.3% 5.0% 4.3% 4.4% 3.1% 1.6% -0.5%


BVPS 4.64 5.51 5.54 6.27 7.58 5.61 5.34 5.37 5.51 5.66 5.83 6.03 6.27 6.54 6.86 7.21 7.58

TBVPS 1.97 2.91 2.92 3.66 4.98 2.94 2.68 2.76 2.91 3.05 3.22 3.42 3.66 3.94 4.25 4.61 4.98

December 15, 2015 143

Flotek Industries (FTK) Valuation PRICE TARGET SCENARIOS



6.8% 14.8X $1,076 $19.50 80% Net Income - 36.2 53.6 (7.9) 27.2 58.0 70.9 80.6 105.0

8.8% 11.4X $992 $18.00 67% Depreciation & Amortization - 7.3 9.7 11.1 11.9 13.0 14.2 15.5 16.8


12.8% 7.8X $848 $15.50 43% Deferred Taxes - 0.8 (1.5) (7.8) - - - - -


16.8% 6.0X $731 $13.50 25% Operating Cash Flow (before working cap.) - 44.2 61.8 (4.6) 39.2 71.0 85.1 96.1 121.8



22.8% 4.4X $592 $11.00 2% Capitalized G&A - - - - - - - - -

24.8% 4.0X $553 $10.00 (7%) Less: Net Capital Expenditures (before Cap Int) - 62.7 21.7 11.8 14.5 14.6 16.9 18.2 17.3

Working Capital Change - (20.8) (40.4) 26.7 (21.4) (51.6) (14.0) (16.4) (22.5)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred - 28.0 (18.5) 3.7 - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations - (25.6) 99.0 (46.8) 46.1 108.0 82.3 94.3 127.0




Beta (Adjusted) 1.15 Subtract: Long Term Debt (Terminal Year) (47.8)






Terminal Multiple: 6.8X Terminal Value (1) 978.6





December 15, 2015 144











December 15, 2015 145

Newpark Resources: Buy, $7.25PT, Emerging Consolidation Beneficiary Augments Cyclical Recovery Story Investment Thesis. We are initiating coverage of NR with a Buy rating and $7.25 price target. In addition to positive catalysts from a potential recovery of North American activity in 2016/2017, we believe the secular trend of industry consolidation may drive Fluids market share to NR, which may prove a tailwind for the shares. With cyclical recovery, we also see a shift in mix toward higher end fluids offerings (in part with a recovery in offshore activity) and matt wellsite construction solutions, which suffered from heightened efforts to cut well costs in the downturn. Given the potential for upward revisions from mix and operating leverage, along with a trough valuation near tangible book value, we see favorable risk reward in the shares.

Key Drivers

• Premium Business Model in Commoditized Fluid Market. NR is the third largest player in the drilling fluids market behind SLB and HAL, with market share in the low teens. Not trying to compete on price in a largely commoditized market, NR looks to gain share through the upsell of higher technology fluids solutions and better customer service. Its focus lies on jobs with greater well complexity, where NR may differentiate from the competition. Currently, 25% of the Fluids business is driven by patented solutions versus commodity offerings. With upstream operators focused on well cost (AFE) versus well productivity (EUR), NR may have suffered from lost share to lower cost bundled offerings from larger competitors. In our view, an inflection in commodity prices and turn in the upstream cycle may reverse this trend. As NR looks to expand market penetration, the company must earn customer trust through the provision of more basic solutions and superior service. As the cycle turns and emphasis shifts from AFE to EUR, NR may further penetrate new customers and the broader market with higher end offerings, through the introduction of NR labs, co-creation of solutions, and tailored services. The strategy has seen recent success in share gains in international markets.

• Focus on Fluids & Viable Alternative to Consolidators. Given a balanced presence across markets, NR looks well positioned as a viable alternative to the integrated oil service companies. In NR’s view, the fluids business is largely overlooked and relegated to “off the shelf” offerings within the larger competitors, which provides the opportunity to gain market share with a more fluids-focused approach. Although it may take time to gain share, recent NR hires from large competitors in the Gulf of Mexico and international markets may lend to NR’s premise that the fluids business may be a “step-child” within integrated services providers. In our view, recent industry consolidation may lead upstream operators to reduce their business concentration with larger diversified oil service companies through select sponsorship of services providers, like NR. A material shift in market share may add upside to our estimates.

• Adoption of New Technologies: Evolution. NR has introduced a new water based drilling fluid, Evolution, to compete against commoditized diesel and synthetic based fluids on performance. Evolutions value proposition centers on environmental benefits, 30% better bits speeds relative to other water-based environmentally-friendly offerings, and equal lubricity with oil-based products, and lower waste disposal costs due to fewer environmental issues. At the height of the last cycle, Evolution was 30% of NR’s product mix, but has fallen to ~18%. In our view, at 2X the costs of competitive products, Evolution has yielded market share to lower end products in the market. We see a turn in the cycle, with less stringent well cost scrutiny, and greater focus on environmental (regulatory) concerns in North America as a potential tailwind for the product over the next two years. Given Evolution is a significantly higher margin product, better traction may improve our margin outlook.

• Superior Matts Product Remains Cyclical. On every metric, NR’s flexible matts outmatch competitor wood matts for well side construction. They are environmentally safer, require less trucking (2X matts per truck versus wood), and require less site preparation and rock hauling. That said, the business remains leveraged to the falling rig count, so utilization has fallen to 20-30% from ‘sold out’ status and 40-50% margins at the recent market peak. Again, we expect a sharp turn in economics for the segment with a turn in the cycle.

• Leverage Ratios May Raise Flags in 2016. NR has no balance drawn on its $200 million revolving credit facility (can be expanded to $350 million), but does have $173 million of Senior Notes due October 2017. NR’s declining earnings profile through 2016 and rising leverage ratios rise may cross the covenants of NR’s revolver. Per our understanding, NR’s revolver allows for 4.0X Total Debt/EBITDA. Recent behavior of the banks suggest that these covenants may be renegotiated, especially in light of NR’s low net debt and healthy cash flow profile. NR maintains a B+ rating from S&P. We apply a higher discount for the balance sheet risk. With no balance on the revolver and no financing needs to weather the near term downturn, we still like the risk/reward in NR shares.

December 15, 2015 146

Newpark Resources (NR) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Fluid Systems 926.4 965.0 575.9 515.3 721.2 171.9 140.3 138.8 124.9 118.6 124.6 130.8 141.3 155.4 170.9 188.0 206.8

Mats & Integrated Services 116.0 153.4 89.9 59.2 93.2 36.6 23.3 15.4 14.6 13.9 14.3 14.7 16.2 18.7 21.5 24.7 28.4

Total Revenues 1,042.4 1,118.4 665.8 574.5 814.4 208.5 163.6 154.2 139.5 132.5 138.9 145.6 157.5 174.1 192.4 212.7 235.2

Fluid Systems 72.6 95.6 (6.8) 1.2 52.2 (1.7) (0.2) (1.2) (3.6) (3.6) 0.6 1.3 2.8 6.2 10.3 15.0 20.7

Mats & Integrated Services 49.4 70.5 21.7 0.6 15.4 15.6 6.6 (0.1) (0.3) (0.5) (0.0) 0.4 0.8 1.2 2.5 4.1 7.6

Corporate office (27.6) (35.5) (28.8) (30.7) (32.0) (7.8) (8.0) (5.2) (7.8) (7.7) (7.7) (7.7) (7.6) (7.8) (7.9) (8.1) (8.2)

EBIT 94.4 130.6 (13.8) (28.8) 35.6 6.1 (1.7) (6.6) (11.7) (11.8) (7.1) (6.0) (4.0) (0.3) 4.8 11.1 20.0


FX & Other (4.6) (1.0) (1.2) - - (1.6) 0.4 - - - - - - - - - -

EBT 78.6 119.2 (23.7) (37.4) 27.1 2.3 (3.5) (8.7) (13.9) (13.9) (9.2) (8.1) (6.2) (2.4) 2.7 8.9 17.9

Income Taxes (27.8) (40.7) 8.3 13.1 (9.5) (1.3) 0.9 3.9 4.8 4.9 3.2 2.8 2.2 0.9 (0.9) (3.1) (6.3)

Net Income (Operating) 50.8 78.4 (15.4) (24.3) 17.6 1.0 (2.6) (4.8) (9.0) (9.0) (6.0) (5.3) (4.0) (1.6) 1.8 5.8 11.6

Discontinued Operations 12.7 1.2 - - - - - - - - - - - - - - -

Extraordinaries (after-tax) 1.8 22.7 (1.3) - - - (1.7) 0.4 - - - - - - - - -

Net Income (GAAP) 65.3 102.3 (16.7) (24.3) 17.6 1.0 (4.3) (4.5) (9.0) (9.0) (6.0) (5.3) (4.0) (1.6) 1.8 5.8 11.6

EPS (Operating) 0.50 0.78 (0.18) (0.29) 0.21 0.01 (0.03) (0.06) (0.11) (0.11) (0.07) (0.06) (0.05) (0.02) 0.02 0.07 0.14

EPS (GAAP) 0.64 1.02 (0.20) (0.29) 0.21 0.01 (0.05) (0.05) (0.11) (0.11) (0.07) (0.06) (0.05) (0.02) 0.02 0.07 0.14




EBITDA 138.6 172.6 30.4 17.5 81.3 16.7 8.9 5.0 (0.1) (0.1) 4.5 5.6 7.5 11.2 16.3 22.5 31.4



Cash From Operations (CFO) 151.9 89.2 152.8 108.4 (4.3) 31.6 50.2 25.4 45.7 44.0 28.7 35.9 (0.2) (7.3) (0.3) 1.7 1.5


Free Cash Flow (FCF) 84.0 (17.8) 88.2 67.0 (46.5) 13.1 34.4 8.3 32.4 33.4 18.3 25.7 (10.4) (17.7) (10.9) (8.9) (9.0)

Acquisitions/Divestures/Investments 7.9 93.0 (13.6) - - 0.3 0.8 (14.8) - - - - - - - - -

Cash From Financing (CFF) (72.5) (48.7) (7.5) - - (1.6) (2.7) (3.2) - - - - - - - - -

Other (0.3) (7.2) (5.8) - - (5.1) (1.0) 0.2 - - - - - - - - -

Increase (Decrease) in Cash 19.0 19.2 61.2 67.0 (46.5) 6.6 31.6 (9.4) 32.4 33.4 18.3 25.7 (10.4) (17.7) (10.9) (8.9) (9.0)


Total Capital 766.7 809.6 777.0 768.7 802.4 795.2 792.2 782.0 777.0 772.0 770.0 768.8 768.7 771.2 776.9 786.8 802.4

Total Debt 185.7 184.1 178.4 178.4 178.4 182.4 181.7 178.4 178.4 178.4 178.4 178.4 178.4 178.4 178.4 178.4 178.4

Net Debt 119.8 99.1 32.2 (34.8) 11.7 90.7 58.5 64.6 32.2 (1.2) (19.5) (45.2) (34.8) (17.1) (6.2) 2.7 11.7


Net Debt/Capital 15.6% 12.2% 4.1% -4.5% 1.5% 11.4% 7.4% 8.3% 4.1% -0.2% -2.5% -5.9% -4.5% -2.2% -0.8% 0.3% 1.5%

Total Debt/EBITDA 1.3X 1.1X 5.9X 10.2X 2.2X 2.7X 5.1X 8.9X -350.5X -506.5X 9.9X 7.9X 6.0X 4.0X 2.7X 2.0X 1.4X

BVPS 5.68 6.22 7.14 7.11 7.52 7.31 7.14 7.27 7.21 7.15 7.13 7.11 7.11 7.14 7.21 7.33 7.52

TBVPS 4.51 5.15 5.92 5.89 6.29 6.07 5.92 6.04 5.98 5.92 5.90 5.89 5.89 5.91 5.98 6.10 6.29

December 15, 2015 147

Newpark Resources (NR) Valuation PRICE TARGET SCENARIOS


7.0% 14.2x $934 $11.25 125% Levered Cash Flow:

9.0% 11.1X $854 $10.25 105% Net Income - 50.8 78.4 (15.4) (24.3) 17.6 58.0 70.4 88.6

11.0% 9.1X $782 $9.50 90% Depreciation & Amortization - 44.2 42.0 44.3 46.4 45.7 45.3 45.3 45.3


15.0% 6.7X $658 $8.00 60% Deferred Taxes - (7.8) (2.3) (12.2) - - - - -


19.0% 5.3X $557 $6.75 35% Operating Cash Flow (before working cap.) - 87.2 118.1 16.6 22.1 63.3 103.3 115.7 133.9



25.0% 4.0X $438 $5.25 5% Capitalized G&A - - - - - - - - -

27.0% 3.7X $405 $5.00 (0%) Less: Net Capital Expenditures (before Cap Int) - 60.1 14.0 78.3 41.4 42.2 44.5 45.5 46.7

Working Capital Change - 57.8 (25.7) 121.0 70.3 (83.6) (21.4) (21.4) (29.3)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred - (73.7) (0.3) (6.2) - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations - 43.1 130.2 (176.5) (89.7) 104.6 80.2 91.5 116.6










Terminal Multiple: 5.9X Terminal Value (1) 994.8

Levered Free Cash Flow (2) (89.7) 104.6 80.2 91.5 1,111.3




December 15, 2015 148











December 15, 2015 149

Proppant Companies

December 15, 2015 150

US Silica: Hold, $20PT, Best Positioned Within Difficult Business Investment Thesis. We are initiating coverage of SLCA with a Hold rating and $20 price target. Low utilization and high fixed costs challenge the proppant industry, but SLCA is likely best positioned in the group. SLCA may benefit from low cost production sources and a superior logistics network, but we do not see the volume recovery needed to provide sufficient operating leverage until 2017. A faster shutting of industry capacity may improve our outlook, but remains a potential overhang depending on the speed of re-activation. A SLCA-led consolidation of the group may prove positive as well. For now, we see other oilfield serves sub-sectors with better risk/rewards relative to our mid-cycle valuation, as upstream activity turns in 2016/2017. We look to get more aggressive on SLCA shares when we have a better sense when capacity utilization may hit a bullish tipping point (>80%+) and pricing power becomes more favorable. We note that upward revisions to low 2017 EPS, may prove a positive catalyst in 2016.

Key Drivers

• Volume Story, Contribution Margin Recover at a Lag. Despite a 15%-20% increase in proppant intensity per well, we forecast sand volumes down 15% 2015/2014 and continued incremental pricing weakness and negative operating leverage through 1Q/16. In our view, SLCA shares may remain under pressure until pricing and volume trends begin to flatten. Unlike other segments of the market, sand proppant economics may lag a recovery in activity, as large capacity expansions in recent years may continue to plague industry utilization. We forecast that SLCA plant utilization drops below 50% in 2016, dire considering they are well positioned on the cost curve. Plant closures, exit of small, private players, and delayed expansion projects may shrink the market, but without a more meaningful increase in volumes, unlikely until 2017/2018, pricing and contribution margins/ton likely remains depressed. Thus, we do not see a meaningful earnings recovery until 2017, but see pricing power returning at a lag. The bright spot has been brown sand (Cadre acquisition), as SLCA has seen some switching to brown from white sand in an effort to lower costs.

• Growing Market Share. Pressure pumpers are consolidating their sources of sand supply in the downturn, which benefits SLCA. SLCA sees their market share expanding from 11% at YE 2014 to 18% at YE 2015. As a result, two customers, HAL and SLB, represent nearly half of SLCA volume. Ultimately, the company’s tie to the two largest pressure pumpers, especially after the closing of the BHI acquisition, may accelerate SLCA volume growth into the recovery.

• Managing Capacity & Lowering Costs Through the Downturn. The company has been able to adjust its cost structure and change its expansion plans, but fixed cost operating leverage remains a victim of the downturn. SLCA has shut plants and pushed off the Fairchild and Pacific capacity expansions until 2017 or later. The company has ~200 cost cutting initiatives in place, with a goal to increase contribution margins by $1-$2, and plans to reduce SG&A by 20% in 2015. Luckily, the shift of production to the lower cost Ottowa, Sparta, and Utica plants may keep EBITDA positive.

• Rail Logistics: Double Edged Sword. The roll off of rail car overhead may help earnings in the recovery, but remains a slow process, where volumes may not recover in time to help utilization. In good times, capacity within rail logistics was a well-executed, key competitive advantage. In the downturn, SLCA claims that unused rail cars contribute to the current $7-$8 drag on contribution margins. Currently, SLCA has 1,460 cars in storage (at $550/month, totaled at $2.4 million/Q or $2/Q of contribution margin). Compounding the problem, in basin deliveries from transloads have decrease to 50% from 60-70% at the peak, as customers like SLB and HAL look to utilize their own rail cars. The logistics fee of $3-$4/ton is lost in that shift in delivery mix.

• Consolidate Market Via M&A. Although SLCA’s balance sheet looks a little stretched on a Total Debt/EBITDA basis over the next few quarters, Debt/Capital ratios are reasonable. The company claims that banks are open to finance M&A. SLCA would like to be a consolidator (get up to 30%-35% market share through M&A), but claim that capacity on offer appears to be higher marginal costs and without proper logistics. The obvious targets would may be the two public MLPs, HCLP ($6.19, NR) and EMES ($5.42, NR), as recent distribution cuts may break their MLP business models.

• ISP Adds Stability. The ISP sand business may go from 14% of contribution margin to 80% at the proppant demand bottom. With help from the introduction of higher margin product introductions (30-40) & market share gains, ISP may keep contribution margin above $20. SLCA may benefit from the earnings stability of this less glamourous segment.

December 15, 2015 151

US Silica (SLCA) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Oil and Gas Proppants 347.4 662.8 418.1 335.1 576.8 148.8 90.9 102.0 76.5 65.8 74.7 88.8 105.9 125.6 136.2 149.7 165.2

Industial and Specialty Products 198.5 214.0 219.4 225.3 240.0 55.2 56.7 53.4 54.2 55.0 55.9 56.8 57.7 58.6 59.5 60.5 61.4

Total Revenues 546.0 876.7 637.5 560.4 816.7 204.0 147.5 155.4 130.7 120.8 130.5 145.6 163.5 184.2 195.7 210.2 226.7

Oil and gas (201.5) (406.7) (324.4) (272.4) (423.6) (96.6) (77.6) (85.5) (64.7) (55.6) (61.7) (71.7) (83.3) (96.8) (102.6) (108.8) (115.4)

Industrial and Specialty Products (141.6) (152.9) (144.1) (138.6) (144.2) (39.7) (37.1) (33.5) (33.8) (34.1) (34.5) (34.8) (35.2) (35.5) (35.9) (36.2) (36.6)

Other Expenses (5.5) (7.0) (7.2) (8.1) (8.1) (2.3) (0.8) (2.0) (2.0) (2.0) (2.0) (2.0) (2.0) (2.0) (2.0) (2.0) (2.0)

SG&A (47.9) (77.4) (60.5) (60.2) (87.8) (27.0) (6.6) (13.6) (13.4) (13.0) (14.0) (15.6) (17.6) (19.8) (21.0) (22.6) (24.4)

DD&A (36.4) (45.0) (57.3) (61.8) (65.0) (13.2) (13.7) (15.2) (15.2) (15.3) (15.4) (15.5) (15.6) (15.9) (16.1) (16.4) (16.6)

EBIT 113.1 187.8 44.0 19.3 88.1 25.1 11.7 5.7 1.5 0.8 2.9 5.8 9.8 14.2 18.1 24.2 31.6


Other Income, Net 1.7 0.8 0.4 1.2 1.2 0.0 (0.2) 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

EBT 99.5 170.3 18.0 (6.2) 62.6 18.3 5.3 (0.6) (4.9) (5.6) (3.5) (0.5) 3.5 7.8 11.7 17.8 25.3

Income tax expense (22.0) (39.8) (3.7) 1.5 (15.6) (3.5) (0.7) (0.7) 1.2 1.4 0.9 0.1 (0.9) (2.0) (2.9) (4.4) (6.3)

Net Income (Operating) 77.5 130.6 14.4 (4.6) 46.9 14.8 4.6 (1.3) (3.7) (4.2) (2.6) (0.4) 2.6 5.9 8.8 13.3 19.0


Extraordinaries (after-tax) (2.3) (9.0) 3.8 - - - 5.4 (1.6) - - - - - - - - -

Net Income (GAAP) 75.3 121.5 18.2 (4.6) 46.9 14.8 10.0 (2.9) (3.7) (4.2) (2.6) (0.4) 2.6 5.9 8.8 13.3 19.0

EPS (Operating) 1.45 2.41 0.27 (0.09) 0.87 0.27 0.08 (0.03) (0.07) (0.08) (0.05) (0.01) 0.05 0.11 0.16 0.25 0.35

EPS (GAAP) 1.41 2.24 0.34 (0.09) 0.87 0.27 0.18 (0.05) (0.07) (0.08) (0.05) (0.01) 0.05 0.11 0.16 0.25 0.35




EBITDA 149.6 232.8 101.4 81.1 153.1 38.3 25.4 20.9 16.7 16.1 18.3 21.3 25.5 30.1 34.2 40.5 48.3



Cash From Operations (CFO) 48.7 180.6 51.2 (13.5) 22.1 19.8 18.7 (2.0) 14.7 4.9 (5.9) (6.9) (5.6) (3.8) 5.1 8.1 12.7


Free Cash Flow (FCF) (11.7) 88.1 0.6 (47.1) (43.2) 6.4 4.9 (13.1) 2.3 (2.4) (13.7) (15.6) (15.4) (18.5) (10.6) (8.7) (5.4)

Acquisitions/Divestures/Investments (74.6) (98.3) 29.5 - - 0.1 4.6 24.8 - - - - - - - - -

Cash From Financing (CFF) 106.0 112.0 (47.7) (26.7) (26.7) (23.3) (8.4) (9.4) (6.7) (6.7) (6.7) (6.7) (6.7) (6.7) (6.7) (6.7) (6.7)

Other (2.4) 87.3 (0.2) - - 2.0 (2.1) (0.1) - - - - - - - - -

Increase (Decrease) in Cash 17.2 189.0 (17.9) (73.7) (69.9) (14.7) (1.1) 2.3 (4.3) (9.0) (20.4) (22.3) (22.1) (25.2) (17.2) (15.4) (12.1)


Total Capital 680.7 906.1 879.9 848.6 868.8 892.2 897.4 890.2 879.9 869.0 859.7 852.6 848.6 847.8 849.9 856.6 868.8

Total Debt 371.5 502.3 492.5 492.5 492.5 494.2 493.4 492.5 492.5 492.5 492.5 492.5 492.5 492.5 492.5 492.5 492.5

Net Debt 218.2 159.9 197.1 270.8 340.7 166.4 171.1 192.8 197.1 206.1 226.5 248.8 270.8 296.0 313.2 328.6 340.7


Net Debt/Capital 32.1% 17.6% 22.4% 31.9% 39.2% 18.6% 19.1% 21.7% 22.4% 23.7% 26.3% 29.2% 31.9% 34.9% 36.9% 38.4% 39.2%


BVPS 5.80 7.44 7.19 6.62 7.00 7.35 7.50 7.40 7.21 7.01 6.83 6.70 6.62 6.61 6.65 6.77 7.00

TBVPS 4.21 5.77 5.52 4.95 5.32 5.68 5.83 5.72 5.53 5.33 5.15 5.02 4.95 4.93 4.97 5.10 5.32

December 15, 2015 152

US Silica (SLCA) Valuation PRICE TARGET SCENARIOS



5.1% 19.4X $1,494 $28 43% Net Income 79.2 75.3 121.5 18.2 (4.6) 46.9 120.5 146.3 148.0



11.1% 9.0X $1,146 $22 12% Deferred Taxes 1.1 4.6 6.0 (20.9) (49.9) (49.9) (49.9) (49.9) (49.9)


15.1% 6.6X $968 $19 (3%) Operating Cash Flow (before working cap.) 105.3 116.3 172.6 54.6 7.3 62.0 141.1 173.7 182.9

17.1% 5.8X $892 $17 (13%) Net Cash from Investing Activities (104.5) (60.1) (190.9) (50.5) (33.6) (65.3) (82.8) (92.6) (99.8)

19.1% 5.2X $823 $16 (18%) Capitalized Interest - - - - - - - - -

21.1% 4.7X $761 $15 (24%) Capitalized G&A - - - - - - - - -

23.1% 4.3X $704 $14 (29%) Less: Net Capital Expenditures (before Cap Int) 104.5 60.1 190.9 50.5 33.6 65.3 82.8 92.6 99.8


Weighted Average Cost of Capital (WACC) Change in Debt/Preferred (8.1) 110.0 130.3 (5.7) - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 24.3 (15.3) (182.8) (23.3) (5.5) 36.6 87.6 99.1 98.1















December 15, 2015 153











December 15, 2015 154

Fairmount Santrol: Hold, $2.30PT, Negative Operating Leverage & Covenant Concerns Hurt Story Investment Thesis. We are initiating FMSA with a Hold rating and $2.30 price target. After an IPO in the mid-teens, the shares trade in the mid-$2 range, as FMSA has been caught by falling proppant demand in combination with a high fixed cost overhead and cash flow erosion. We see financial risks, centered on potential for cash needs and breached leverage ratio covenants, negative tangible book value, and negative FCF in coming quarters, as reasons for concern. Since we see a delayed recovery in proppant economics into 2017, in light of a large industry capacity overhang, we would prefer to stay on the sidelines. High capital costs may become an issue, but we believe FMSA should survive the downturn. Given high operating leverage, we believe the story may host a more attractive risk/return further into the recovery.

Key Drivers

• Large Infrastructure Footprint Creates Negative Operating Leverage. Declines in proppant demand have been offset by a 10%-15 % increase in proppant usage per well, but we still see volumes down ~20% for FMSA 2016/2015, with further pricing weakness. Given a high fixed cost structure, lower volumes and capacity utilization create negative operating leverage. Recovery of volumes and capacity absorption may not come until 2017, with a further lag likely for a recovery in proppant prices. FMSA is particularly vulnerable, as the number #1 and #2 rank in resin-coasted and raw sand capacities, respectively, and the largest distribution footprint in the industry, with 42 distribution terminals (75% exclusive to FMSA). As a result, we forecast EPS losses and thin EBITDA margins through 2017, until volumes and capacity absorption recover. Closing/idling plants, consolidating distribution/transload facilities, and reducing rail cars in the system may help with variable costs. That said, the impact of excess rail car and distribution capacity may linger as FMSA looks to maintain its footprint.

• Low Well Cost Focus Hurts Resin-Coated Demand. Upstream operators look to lower costs by replacing higher cost ceramic and resin-coated sand volumes with higher volumes of lower cost raw sand. Resin coated products have greater conductivity and crush strength than raw sand, as well as prevent sand flow back in to the wellbore, which reduce operating costs and increase production rates. In a cost-conscious environment, E&Ps may forego these benefits to post lower absolute well costs, and potentially target shallower wells, which lends to less use of resin-coated products. As the largest resin-coated sand producer, FMSA suffers from these cost cutting trends.

• Covenant Issues Create Risks With Falling Cash Flow . We applaud FMSA’s foresight to extend the maturity of its Term Loan B-1 loan ($161 million) to match the Term Loan B-2 in September 2019. The remaining undrawn credit facility, reduced to $100 million from $125 million. FMSA had $28.5 million available at the end of 3Q/15 after letters of credit. The credit facility’s covenants have been renegotiated, but 4.75x Total Debt/ EBITDA threshold remains through 2016, which we forecast FMSA’s to break, limiting the availability on the revolver to $31.2 million. Given a negative cash flow profile through 2017, with potential financing needs and payouts for the Propel SSP product acquired, we see financial risks to the story. The 17%+ reduction in SG&A in 2015, a reduction in inventories, and a move towards maintenance CAPEX may help, but FMSA may have more limited levers to pull on its fixed overhead.

• New Proppant Technologies May Prove a Bright Spot. The introduction and penetration may make our estimates conservative. FMSA is in the process of introducing Proppel SSP, a self-suspending proppant transport solution, that reduces proppant settling, penetrates further to get exposure to more surface area, requires fewer chemical additions, less water, less horsepower, with a 50% increase in initial production rates. A solid value proposition, albeit with limited visibility on new product adoption, success with a higher value-add, higher margin product may lead our estimates higher.

December 15, 2015 155

Fairmount Santrol (FMSA) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Proppant Solutions 856.2 1,232.2 709.0 488.9 824.6 272.9 188.2 141.6 106.4 96.8 109.2 129.3 153.5 180.0 195.0 213.9 235.7

Industrial & Recreational Products 132.2 124.2 121.1 125.9 135.5 28.6 33.2 29.4 30.0 30.6 31.2 31.7 32.3 32.9 33.5 34.2 34.8

Total Revenues 988.4 1,356.5 830.1 614.7 960.0 301.5 221.3 171.0 136.4 127.4 140.3 161.1 185.9 213.0 228.5 248.0 270.5

Proppant Solutions Margin 296.3 430.8 152.8 76.0 188.8 83.8 36.6 18.9 13.5 12.4 15.6 20.7 27.3 34.9 41.1 50.5 62.3

Industrial & Recreational Products Margin 34.8 34.5 24.8 39.4 41.8 7.1 (0.9) 9.2 9.4 9.6 9.8 9.9 10.1 10.2 10.4 10.5 10.7

Cost of Sales (5.0) - - - - - - - - - - - - - - - -

SG&A (47.4) (74.2) (52.5) (48.2) (48.2) (15.8) (12.7) (12.0) (12.0) (12.0) (12.0) (12.0) (12.0) (12.0) (12.0) (12.0) (12.0)

DD&A (37.8) (59.4) (63.1) (62.8) (65.8) (16.2) (16.3) (15.3) (15.4) (15.5) (15.6) (15.8) (15.9) (16.1) (16.3) (16.6) (16.8)

Stock compensation expense (10.1) (16.6) (9.9) (10.7) (10.7) (1.9) (2.6) (2.7) (2.7) (2.7) (2.7) (2.7) (2.7) (2.7) (2.7) (2.7) (2.7)

Other operating expense (2.8) (3.2) 13.7 - - (0.2) 13.1 0.8 - - - - - - - - -

EBIT 228.0 311.9 65.7 (6.4) 105.8 56.8 17.2 (1.1) (7.2) (8.2) (5.0) 0.1 6.7 14.2 20.4 29.8 41.4


Other Income, net (16.2) 2.2 5.2 10.3 10.3 - - 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6

EBT 149.9 253.3 8.7 (59.7) 52.5 41.5 2.3 (14.4) (20.6) (21.5) (18.3) (13.2) (6.6) 0.9 7.0 16.4 28.1

Income Tax Expense (45.2) (78.9) 7.5 29.9 (26.3) (10.6) 0.6 7.2 10.3 10.8 9.2 6.6 3.3 (0.5) (3.5) (8.2) (14.1)

Net income attributable to NCI (0.7) (0.2) (0.3) (0.3) (0.3) (0.1) (0.0) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1)

Net Income (Operating) 104.0 174.2 16.0 (30.1) 25.9 30.8 2.9 (7.3) (10.4) (10.8) (9.2) (6.7) (3.4) 0.4 3.4 8.1 14.0

Extraordinaries (after-tax) - (0.9) (27.7) - (0.0) - 11.2 (38.9) - - - - - - - - -

Net Income (GAAP) 104.0 173.2 (11.7) (30.1) 25.9 30.8 14.1 (46.2) (10.4) (10.8) (9.2) (6.7) (3.4) 0.4 3.4 8.1 14.0

EPS (Operating) 0.63 1.05 0.10 (0.19) 0.16 0.18 0.02 (0.05) (0.06) (0.07) (0.06) (0.04) (0.02) 0.00 0.02 0.05 0.09

EPS (GAAP) 0.63 1.04 (0.07) (0.19) 0.16 0.18 0.08 (0.29) (0.06) (0.07) (0.06) (0.04) (0.02) 0.00 0.02 0.05 0.09




EBITDA 265.7 371.3 128.8 56.5 171.6 73.0 33.5 14.2 8.2 7.3 10.7 15.8 22.7 30.4 36.7 46.3 58.2





Free Cash Flow (FCF) 63.1 64.6 150.4 (11.2) 2.5 45.6 66.6 13.4 24.8 10.1 (4.1) (8.2) (9.0) (8.5) 1.8 3.2 6.0

Acquisitions/Divestures/Investments (468.0) 5.2 - - - - - - - - - - - - - - -

Cash From Financing (CFF) 411.8 (93.6) (20.7) - - (4.6) (15.1) (0.9) - - - - - - - - -

Other (1.0) 83.0 (2.3) - - 0.5 5.7 (8.5) - - - - - - - - -

Increase (Decrease) in Cash 5.9 59.1 127.4 (11.2) 2.5 41.4 57.1 4.0 24.8 10.1 (4.1) (8.2) (9.0) (8.5) 1.8 3.2 6.0


Total Capital 1,096.8 1,286.1 1,263.9 1,243.1 1,278.3 1,311.8 1,325.3 1,271.9 1,263.9 1,255.4 1,248.5 1,244.1 1,243.1 1,245.8 1,251.6 1,262.0 1,278.3

Total Debt 1,262.1 1,252.6 1,241.5 1,241.5 1,241.5 1,250.8 1,246.4 1,241.5 1,241.5 1,241.5 1,241.5 1,241.5 1,241.5 1,241.5 1,241.5 1,241.5 1,241.5

Net Debt 1,244.3 1,175.7 1,037.2 1,048.4 1,045.9 1,132.4 1,071.0 1,062.0 1,037.2 1,027.2 1,031.2 1,039.4 1,048.4 1,056.9 1,055.1 1,051.9 1,045.9


Net Debt/Capital 113.5% 91.4% 82.1% 84.3% 81.8% 86.3% 80.8% 83.5% 82.1% 81.8% 82.6% 83.5% 84.3% 84.8% 84.3% 83.3% 81.8%


BVPS (1.00) 0.20 0.14 0.01 0.23 0.37 0.47 0.19 0.14 0.09 0.04 0.02 0.01 0.03 0.06 0.13 0.23

TBVPS (2.18) (0.91) (0.94) (0.94) (0.58) (0.74) (0.63) (0.94) (0.95) (0.97) (0.98) (0.97) (0.94) (0.89) (0.82) (0.72) (0.58)

December 15, 2015 156

Fairmount Santrol (FMSA) Valuation PRICE TARG ET SCEN ARIO S


15.4% 6.5x $503 $3.10 33% Le ve re d Cash F low :

17.4% 5.7X $471 $2.90 24% N e t Incom e 148.9 104.0 173.2 (11.7) (30.1) 25.9

19.4% 5.1X $441 $2.70 16% De pre ciation & A m ortization 27.6 35.9 55.4 63.1 62.8 65.8

21.4% 4.7X $414 $2.60 12% Cap ital ize d In te re st - - - - - -

23.4% 4.3X $389 $2.40 3% De fe rre d Tax e s - - - - - -

25.4% 3.9X $366 $2.30 (1% ) Translation A d justm e nt O the r - - - - - -

27.4% 3.6X $345 $2.10 (10% ) O pe rating Cash F low (be fore w orking cap.) 176.4 139.9 228.6 51.5 32.8 91.8

29.4% 3.4X $325 $2.00 (14% ) N e t Cash from Inve sting A ctiv itie s (107.4) (579.5) (138.3) (101.1) (43.0) (67.2)

31.4% 3.2X $307 $1.90 (18% ) Cap ital ize d In te re st - - - - - -

33.4% 3.0X $291 $1.80 (23% ) Cap ital ize d G& A - - - - - -

35.4% 2.8X $275 $1.70 (27% ) Le ss: N e t Capital Expe nditure s (be fore Cap Int) 107.4 579.5 138.3 101.1 43.0 67.2

W orking Cap ital Change (19.0) 0.3 (90.9) 155.7 (32.9) (54.0)

W e ighte d Ave rage Cost of Capital (W ACC) Change in De bt/P re fe rre d (121.1) 410.4 (108.7) (20.7) - -

N otional Tax Rate 35.0% Le ve re d Fre e Cash F low from O pe rations 209.2 (850.3) 289.8 (184.6) 22.7 78.6


De bt Risk Spre ad 1,500 EBITDA




Marginal Cost o f De bt 19.0% A dd: Cash (Te rm inal Ye ar)

Cost o f De bt, afte r tax 12.4% Subtract Le ve re d FCF from O pe rations for Ex p l ict Fore cast




Le ve re d Fre e Cash F low (2) 22.7 78.6

(1) Re f le cts a ~25.4% W A CC app lie d to 2020 EBITDA . Te rm inal value is com p u te d at ye ar-e n d 2020.

(2) A ssum e s inve stm e nt occurs at be ginn ing o f ye ar, le ve re d fre e cash f low is ye ar-e n d .


December 15, 2015 157











December 15, 2015 158

Carbo Ceramics: Hold, $15.25PT, Needs Migration TO EUR From Well Cost Focus Investment Thesis. We are initiating CRR with a Hold rating and $15.25 price target. A potential recovery for the ceramic proppant market hinges on both a recovery of North American activity and a shift away from sand in search of higher volume recoveries per well. The migration back to ceramics most likely comes at a lag to activity recovery and requires a renewed focus on higher ultimate recovery rates, with less stringent focus on well costs and initial production rates. Given a focus on higher and optimally placed sand proppant volumes, visibility on a change in well designs remains opaque. With a high fixed overhead and debt covenants in question, we do not see an favorable risk/reward. Concerns vetted, we would be cautious to be short CRR, as lower share float and high short interest creates amplified volatility on swings in the shares.

Key Drivers

• Ceramics Suffer from Focus on Well Cost (AFE) vs. Estimated Ultimate Recovery (EUR). CRR has seen a shift away from ceramic to sand, which may continue to plague economics until commodity prices turn. In a lower commodity price environment, E&Ps shifted focus on perceived lower well costs versus maximized oil recovery. Well cost concerns, combined with a shift toward higher sand proppant volume intensity per well, crushed CRR’s ceramic volumes and pricing power. Increasingly, wells “tail in” with ceramic proppant (10%-20% of well proppant volumes), but without sufficient volumes to offset the shift toward sand in completions. Some may debate the claim, but we are willing to believe that larger, higher crush strength ceramic proppant offers higher conductivity over the life of the well. Unfortunately for CRR, the focus on initial production (IP) volumes, not the forward shape of the production curve, remains the key well performance metric. Problems with well production over time may see the sand/ceramic decision revisited, but a return to higher cost options may not occur until commodity prices rebound. Private E&P companies may have more discretion to use ceramic, but public companies, struggling to show lower well costs relative to IP rates to investors, may continue to press for fracs with greater volumes of sand.

• Debt Covenants Remain an Overhang. CRR has one credit facility that matures at the end of 2018, with $88 million drawn. Since CRR was at risk of breaching the covenant of the facility, the terms were renegotiated, with the facility reduced to $90 million from $100 million, covenant ratios waived (leverage ratio to 2.5x max and fixed charge ratio to 1.5x max) until end of 2016. A minimum asset coverage ratio was introduced, which we believe CRR can meet. In our view, CRR may be in breach of the original leverage ratio covenants once the waiver expires at the end of 2016. Given our forecast for negative EBITDA until 2017, CRR may need to refinance with high priced debt. Regardless of the financing choice, without a recovery in ceramic proppant volumes and economics, the debt issue may remain an overhang on the shares.

• Dividend Cut Another Potential Negative Catalyst. Given a negative cash flow outlook, limited market visibility, and potential impending debt covenant issues, we anticipate that CRR may eliminate all or part of its $0.10/Q dividend in an effort to conserve cash. In our view, investors likely expect the outcome, but potential selling from holders that require a dividends may create volatility in the shares.

• Manage Capacity & Fixed Cost Structure. Similar to other oil service companies, CRR cut variable costs, mothballed plants, and deferred expansion plans. With production largely narrowed to its most efficient Toomsboro plant, most of the cost cutting appears reflected in results. With ~60% of its costs fixed, versus variable, CRR may have limited incremental options to cut costs to improve EBITDA margins.

• Competition Abating from Imports. Given low ceramic prices, CRR may benefit from limited Chinese and Brazilian imports. Likewise, inventory fire sales may be close to removing slack capacity from the market. Although volume recovery may lag, lower imports and inventories may prove healthy for CRR and the market.

• Potential Upside from Kryptophere and New Technologies. It remains too early to tell if greater kryptophere penetration in deepwater markets may boost earnings with higher product profit margins. At multiple times the pricing of other ceramic offerings, kryptosphere may have a significant impact, given higher volumes. Although the immediate future of kryptoshere remains opaque, CRR may likely continue to benefit from adoption of its new “guard” technologies (Scaleguard, Saltguard, etc.).

December 15, 2015 159

Carbo Ceramics (CRR) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Proppant Revenue 615.4 604.0 245.7 183.7 266.8 63.6 66.2 68.9 47.0 42.4 44.4 46.6 50.3 55.8 62.5 70.0 78.5

Other Revenue 52.0 44.3 30.9 29.1 34.6 10.1 7.0 6.9 6.8 6.8 7.1 7.5 7.8 8.1 8.5 8.8 9.2

Total Revenues 667.4 648.3 276.6 212.8 301.3 73.7 73.3 75.8 53.8 49.1 51.5 54.0 58.1 63.9 71.0 78.8 87.6

Cost of Sales (474.4) (461.7) (282.2) (249.6) (294.5) (69.8) (72.3) (74.9) (65.2) (60.1) (61.2) (62.4) (65.9) (69.7) (72.3) (74.9) (77.6)

SG&A (68.4) (71.0) (49.7) (34.0) (39.2) (15.2) (14.6) (11.3) (8.6) (7.9) (8.2) (8.6) (9.3) (8.3) (9.2) (10.2) (11.4)

Start-up Costs - (0.8) - - - - - - - - - - - - - - -

Loss on Disposal or Asset Impairment - - (0.0) (0.1) (0.1) - - (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0)

EBIT 124.6 114.8 (55.4) (70.9) (32.4) (11.2) (13.7) (10.4) (20.1) (18.9) (18.0) (17.0) (17.1) (14.1) (10.5) (6.3) (1.4)

Interest Income, net 0.8 0.4 - - - - - - - - - - - - - - -

F/X (loss) gain, net (0.0) (0.0) - - - - - - - - - - - - - - -

Other (expense) (0.2) (0.4) 0.2 - - (0.1) 0.4 (0.1) - - - - - - - - -

EBT 125.2 114.8 (55.2) (70.9) (32.4) (11.3) (13.3) (10.4) (20.1) (18.9) (18.0) (17.0) (17.1) (14.1) (10.5) (6.3) (1.4)

Income Tax (40.3) (37.0) 15.9 16.3 7.4 4.9 4.0 2.4 4.6 4.3 4.1 3.9 3.9 3.2 2.4 1.5 0.3

Net Income (Operating) 84.9 77.8 (39.3) (54.6) (24.9) (6.4) (9.4) (8.0) (15.5) (14.5) (13.8) (13.1) (13.2) (10.9) (8.1) (4.9) (1.1)

Extraordinaries (after-tax) - (20.9) (35.7) - - (22.2) (7.6) (5.9) - - - - - - - - -

Net Income (GAAP) 84.9 56.9 (75.0) (54.6) (24.9) (28.6) (17.0) (13.9) (15.5) (14.5) (13.8) (13.1) (13.2) (10.9) (8.1) (4.9) (1.1)

EPS (Operating) 3.70 3.39 (1.71) (2.37) (1.08) (0.28) (0.41) (0.35) (0.67) (0.63) (0.60) (0.57) (0.57) (0.47) (0.35) (0.21) (0.05)

EPS (GAAP) 3.70 2.48 (3.26) (2.37) (1.08) (1.24) (0.74) (0.60) (0.67) (0.63) (0.60) (0.57) (0.57) (0.47) (0.35) (0.21) (0.05)

Dividend per Share 1.14 1.26 0.83 - - 0.33 0.10 0.20 0.20 - - - - - - - -



EBITDA 172.1 165.7 (0.6) (14.0) 27.6 1.8 0.3 3.5 (6.2) (4.9) (3.8) (2.7) (2.6) 0.5 4.3 8.8 13.9



Cash From Operations (CFO) 137.6 105.8 102.7 12.7 3.9 53.1 6.3 8.7 34.6 14.4 0.5 1.2 (3.4) (3.2) 0.1 2.2 4.7


Free Cash Flow (FCF) 37.6 (55.7) 41.0 (28.4) (54.4) 30.2 (7.4) (6.0) 24.2 4.9 (9.5) (9.3) (14.6) (15.5) (13.6) (13.0) (12.2)

Acquisitions/Divestures/Investments - - - - - - - - - - - - - - - - -

Cash From Financing (CFF) (33.4) (11.5) 45.5 (0.0) 2.6 41.8 17.7 (9.3) (4.6) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) (0.0) 2.6

Other (0.6) (2.8) (0.5) - - (0.2) 0.2 (0.6) - - - - - - - - -

Increase (Decrease) in Cash 3.6 (70.0) 86.0 (28.4) (51.8) 71.8 10.4 (15.9) 19.6 4.9 (9.5) (9.3) (14.6) (15.5) (13.6) (13.0) (9.6)


Total Capital 793.2 799.0 693.1 645.1 630.9 750.2 736.6 713.0 693.1 679.5 667.4 656.1 645.1 636.4 630.3 627.4 630.9

Total Debt - 25.0 88.0 88.0 90.6 75.0 95.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 88.0 90.6

Net Debt (94.3) 0.7 (22.3) 6.2 60.6 (21.1) (11.6) (2.7) (22.3) (27.2) (17.8) (8.5) 6.2 21.7 35.3 48.4 60.6


Net Debt/Capital -11.9% 0.1% -3.2% 1.0% 9.6% -2.8% -1.6% -0.4% -3.2% -4.0% -2.7% -1.3% 1.0% 3.4% 5.6% 7.7% 9.6%

Total Debt/EBITDA 0.0X 0.2X -143.1X -6.3X 3.3X 10.6X 78.4X 6.3X -3.5X -4.5X -5.8X -8.2X -8.4X 40.0X 5.1X 2.5X 1.6X

BVPS 33.48 33.82 29.72 27.63 26.83 32.08 31.45 30.51 29.71 29.15 28.64 28.14 27.64 27.23 26.95 26.81 26.83

TBVPS 32.21 32.60 28.42 26.33 25.53 30.50 30.01 29.21 28.41 27.85 27.34 26.84 26.33 25.93 25.65 25.51 25.53

December 15, 2015 160

Carbo Ceramics (CRR) Valuation PRICE TARGET SCENARIOS



13.4% 7.5X $492 $21.50 32% Net Income 105.4 84.9 56.9 (75.0) (54.6) (24.9) 47.6 72.7 110.5

15.4% 6.5X $452 $19.75 21% Depreciation & Amortization 44.9 47.5 50.9 54.8 56.9 60.0 64.5 69.7 74.4


19.4% 5.2X $383 $16.75 3% Deferred Taxes 11.2 10.1 (5.8) (27.9) 8.5 3.9 (7.4) (11.3) (17.2)

21.4% 4.7X $353 $15.25 (7%) Translation Adjustment Other - - - - - - - - -

23.4% 4.3X $326 $14.25 (13%) Operating Cash Flow (before working cap.) 161.5 142.5 101.9 (48.1) 10.8 38.9 104.7 131.1 167.7

25.4% 3.9X $301 $13.00 (20%) Net Cash from Investing Activities (77.2) (99.9) (161.5) (61.7) (41.2) (58.3) (85.0) (83.5) (80.2)

27.4% 3.7X $279 $12.00 (26%) Capitalized Interest - - - - - - - - -

29.4% 3.4X $258 $11.25 (31%) Capitalized G&A - - - - - - - - -

31.4% 3.2X $240 $10.50 (36%) Less: Net Capital Expenditures (before Cap Int) 77.2 99.9 161.5 61.7 41.2 58.3 85.0 83.5 80.2

Weighted Average Cost of Capital (WACC) Working Capital Change (10.2) (12.2) (39.5) 140.2 (4.6) (41.5) (38.6) (53.6) (83.7)

Notional Tax Rate 35.0% Change in Debt/Preferred - - 25.0 63.0 - 2.6 17.0 11.1 5.8

Risk Free Rate 4.00% Levered Free Cash Flow from Operations 94.5 54.7 (45.1) (313.1) (25.8) 19.6 41.2 90.2 165.4

Debt Risk Spread 1,350 Terminal Multiple 4.7X

Equity Risk Premium 6.0% EBITDA 220.5

Beta (Adjusted) 1.20 Terminal Enterprise Value 1,031.8

Cost of Equity 24.7% Subtract: Long Term Debt (Terminal Year) (124.4)

Marginal Cost of Debt 17.5% Subtract: Preferred Stock (Terminal Year) -

Cost of Debt, after tax 11.4% Add: Cash (Terminal Year) 30.0

Net Debt/Total Capital 25.0% Subtract Levered FCF from Operations for Explict Forecast (290.6)

WACC 21.4% Subtract: Changes in Equity for Explict Forecast -

Terminal Multiple: 4.7X Subtract: Dividends for Explict Forecast (32.2)

Terminal Value (1) 614.5

Levered Free Cash Flow (2) (25.8) 19.6 41.2 90.2 779.9




December 15, 2015 161











December 15, 2015 162

Oilfield Equipment

December 15, 2015 163

National Oilwell Varco: Buy, $52 PT, Rig Equipment Fears Create Value Play in Top Notch Franchise Investment Thesis. We are initiating coverage of NOV with a Buy rating and $52 price target. NOV shares do not reflect the long term value of its market leading franchises, as investors place high emphasis on the downturn in the offshore rig construction cycle, which is likely factored into sentiment. That said, we do recognize the risk of cancellations for Brazilian rig equipment orders, which represent $3 billion in backlog. Our EPS is also marginally below consensus, which presents a risk. Although rig market consolidation does not bode well for orders through 2017, a potential for a recovery in North American and international upstream activity in 2016/2017 may benefit the Wellbore and Completion & Production segments (40% of revenue). We see an opportunity to purchase one of the best oilfield equipment/services franchises, with strong market positions across oilfield capital equipment and consumables, at a cyclical low versus our mid-cycle valuation. NOV’s strong balance sheet, FCF, and opportunities for accretive acquisitions, which remain a staple of its growth strategy, offers a good risk/reward.

Key Drivers

• Offshore Rig Market Concerns Weigh Too Heavily on the NOV Story. The downturn in the offshore market casts a shadow on new floater and jackup orders until at least 2017. Much may depend on the number of both floater and jackup orders cancelled and rigs retired from the market over the next few years. Longer term, we see high grading of the fleet to more capable rigs as a persistent trend, particularly for the offshore rig fleet. Ultimately, rig equipment aftermarket may benefit from servicing these more complex units and replacing large capital equipment, as part of maintenance delayed by the downturn. We believe, declining backlog and poor book-to-bill ratios in the near term are cyclical, not permanent. Rig Systems declines from a third to a quarter of revenues in our model . As floater and jackup fleets come into balance and a normal pattern of activity growth resumes, Rig System orders and economics may normalize. In our view, linear extrapolation of the current downtrend is overdone. We yield to the bears on further headline risk from potential cancellations of Brazilian/Sete rig orders (~22 rig packages/$3.1 billion, where NOV work has been suspended), but feel an abundance of negative sentiment in the market may already discount these risks in the shares.

• International Land & Aftermarket Rig Market May Offer Support. Land rigs represent 40% of the Rig System newbuild rig backlog, of which 50% is international. Land rigs represent a more consistent order base. Currently, AC rigs comprise approximately 30% of the North American land fleet and only 10% of the international land rig fleet, so both remain early in the high-grading/replacement cycle. Although the decline in US rig counts likely slows new orders for North American land rigs, NOV sees international land rigs orders ($15-$50+/rig) as a potential bright spot for rig systems, with an increase in demand for complete rig packages from the Middle East, where rig counts remain resilient.

• Supply of Competitors to Larger Consolidators Supports Business Lines. NOV supplies equipment and components to oil services consolidators (HAL & SLB), but may prove a more important supplier to the next tier of oil services players that may compete in discrete product lines with large integrated services providers. In our view, we do not see upstream operators allowing an abnormal concentration of market shares. Instead, we see potential sponsorship of alternative providers, outside of the large integrated service companies, may negate threats from industry consolidation and potentially enhance NOV’s business across product lines.

• Cyclical Recovery: Wellbore and Completion & Production (C&P). The collection of consumable, rental, and capital equipment businesses within Wellbore and C&P may recover with the cycle. Representing approximately 40% of revenue, both segments have seen top line numbers fall ~35%. As the upstream cycle turns in 2016/2017 in both domestic and international markets, operating leverage in these business units may surprise both our estimates and consensus to the upside. Not only may NOV need to supply an uptick of demand for consumables in short term activity, but the restocking to more normalized inventories as well. The likely improvement in pricing power as the demand surges across the consumable product lines may be acute. We believe the recovery in these segments may serve as the most prominent near term catalyst for NOV shares to trade higher.

• Strong Balance Sheet & FCF Creates Opportunities. NOV’s solid balance sheet and FCF, throughout our forecast, creates opportunities for organic investment, M&A (bolt on products and geographic expansion), and return of capital to shareholders. All capital budgeting scenarios may support NOV shares. In the interim, Total Debt/EBITDA below 3.0x leaves the company stable in the current downturn.

December 15, 2015 164

National Oilwell Varco (NOV) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Rig Systems - 9,848.0 7,266.8 4,975.7 3,971.6 2,523.0 1,930.0 1,496.0 1,317.8 1,277.6 1,260.8 1,235.9 1,201.4 1,103.5 1,015.0 946.3 906.8

Rig Aftermarket - 3,222.0 2,527.4 2,444.2 2,580.9 719.0 657.0 570.0 581.4 593.0 604.9 617.0 629.3 635.6 642.0 648.4 654.9

Wellbore Technologies - 5,722.0 3,688.6 2,863.8 3,415.7 1,171.0 956.0 834.0 727.6 705.7 684.6 718.8 754.7 792.5 832.1 873.7 917.4

Completion & Production Solutions - 4,645.0 3,386.2 3,172.2 3,719.7 948.0 873.0 798.0 767.2 766.1 775.5 800.1 830.5 866.2 906.4 950.1 996.9

Eliminations - (1,997.0) (1,799.8) (1,426.4) (1,451.0) (541.0) (507.0) (392.0) (359.8) (354.3) (352.5) (357.4) (362.1) (360.2) (359.9) (362.4) (368.5)

Total Revenues 21,999.0 21,440.0 15,069.1 12,029.6 12,236.9 4,820.0 3,909.0 3,306.0 3,034.1 2,988.1 2,973.2 3,014.4 3,053.9 3,037.6 3,035.5 3,056.2 3,107.5

Rig Systems - 2,084.0 1,440.8 796.1 635.5 511.0 419.0 300.0 210.8 204.4 201.7 197.7 192.2 176.6 162.4 151.4 145.1

Rig Aftermarket - 909.0 663.2 607.8 642.1 206.0 152.0 154.0 151.2 151.2 151.2 151.2 154.2 155.7 157.3 162.1 167.0

Wellbore Technologies - 1,486.0 586.8 360.0 584.8 229.0 146.0 119.0 92.8 88.2 83.9 89.8 98.1 110.9 133.1 157.3 183.5

Completion & Production Solutions - 924.0 531.6 479.3 735.7 163.0 141.0 117.0 110.6 112.3 115.6 121.3 130.1 144.3 169.1 196.3 225.9

Eliminations - (676.4) (746.8) (582.2) (592.2) (227.0) (213.0) (160.0) (146.8) (144.6) (143.9) (145.9) (147.8) (147.0) (146.9) (147.9) (150.4)

D&A 755.0 778.0 751.3 797.4 912.2 190.0 190.0 184.0 187.3 191.3 196.1 201.7 208.2 215.4 223.4 232.2 241.1

EBIT 3,525.0 3,948.6 1,724.2 863.7 1,093.7 692.0 455.0 346.0 231.2 220.2 212.5 212.4 218.6 225.1 251.6 287.0 330.0

Interest Expense (111.0) (105.0) (99.1) (92.3) (92.3) (26.0) (26.0) (24.0) (23.1) (23.1) (23.1) (23.1) (23.1) (23.1) (23.1) (23.1) (23.1)

Interest Income 12.0 18.0 11.0 9.9 11.6 5.0 2.0 2.0 2.0 2.6 1.7 2.9 2.9 2.8 2.9 2.9 2.9

Minority Interest 33.0 58.0 16.0 - - 9.0 7.0 - - - - - - - - - -

Other, Net (58.0) (32.0) (106.5) (59.1) (59.1) (47.0) (30.0) (14.8) (14.8) (14.8) (14.8) (14.8) (14.8) (14.8) (14.8) (14.8) (14.8)

EBT 3,401.0 3,887.6 1,545.6 722.3 953.9 633.0 408.0 309.2 195.4 185.0 176.3 177.5 183.6 190.1 216.7 252.0 295.1

Income Tax Provision (1,036.8) (1,100.9) (400.6) (179.9) (237.6) (164.0) (111.0) (77.0) (48.7) (46.1) (43.9) (44.2) (45.7) (47.4) (54.0) (62.8) (73.5)

Non-Cotrolling interest - (5.0) (2.0) (4.0) (4.0) (3.0) 3.0 (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0)

Net Income (Operating) 2,364.3 2,781.7 1,143.0 538.4 712.3 466.0 300.1 231.2 145.7 137.9 131.4 132.3 136.9 141.7 161.7 188.3 220.6

Discontinued Operations - 52.0 - - - - - - - - - - - - - - -


Net Income (GAAP) 2,329.0 2,502.0 899.7 538.4 712.3 310.0 289.0 155.0 145.7 137.9 131.4 132.3 136.9 141.7 161.7 188.3 220.6

EPS (Operating) 5.52 6.48 2.93 1.41 1.87 1.14 0.77 0.61 0.38 0.36 0.34 0.35 0.36 0.37 0.42 0.49 0.58

EPS (GAAP) 5.44 5.83 2.31 1.41 1.87 0.76 0.74 0.41 0.38 0.36 0.34 0.35 0.36 0.37 0.42 0.49 0.58




EBITDA 4,280.0 4,726.6 2,475.5 1,661.1 2,005.9 882.0 645.0 530.0 418.5 411.6 408.6 414.2 426.8 440.5 475.1 519.2 571.1



Cash From Operations (CFO) 3,612.0 2,619.0 1,411.5 1,297.4 1,607.1 114.0 194.0 410.0 693.5 394.4 346.1 269.8 287.1 386.4 404.2 409.3 407.2

Capital Expenditures (669.0) (699.0) (421.9) (658.5) (1,128.2) (130.0) (104.0) (98.0) (89.9) (118.5) (147.6) (179.8) (212.7) (241.9) (272.1) (304.5) (309.6)

Free Cash Flow (FCF) 2,943.0 1,920.0 989.6 638.9 478.9 (16.0) 90.0 312.0 603.6 275.9 198.5 90.0 74.4 144.5 132.1 104.8 97.5

Acquisitions/Divestures/Investments (2,447.0) (544.0) (120.0) (200.0) (200.0) (23.0) (21.0) (26.0) (50.0) (50.0) (50.0) (50.0) (50.0) (50.0) (50.0) (50.0) (50.0)

Cash From Financing (CFF) 269.5 (1,464.0) (1,988.7) (182.9) (182.9) (436.0) (565.0) (942.0) (45.7) (45.7) (45.7) (45.7) (45.7) (45.7) (45.7) (45.7) (45.7)

Other (648.5) 256.0 (63.0) - - (37.0) 16.0 (42.0) - - - - - - - - -

Increase (Decrease) in Cash 117.0 168.0 (1,182.1) 256.0 96.0 (512.0) (480.0) (698.0) 507.9 180.2 102.8 (5.7) (21.3) 48.8 36.4 9.1 1.8


Total Capital 22,043.0 20,402.0 19,935.1 20,034.6 20,468.0 20,343.0 20,766.0 20,343.0 19,935.1 19,847.0 19,829.9 19,922.2 20,034.6 20,081.9 20,161.5 20,295.0 20,468.0

Total Debt 3,149.0 3,166.0 3,983.0 3,983.0 3,983.0 4,245.0 4,305.0 3,983.0 3,983.0 3,983.0 3,983.0 3,983.0 3,983.0 3,983.0 3,983.0 3,983.0 3,983.0

Net Debt (287.0) (370.0) 1,629.1 1,373.1 1,277.1 1,221.0 1,761.0 2,137.0 1,629.1 1,448.9 1,346.1 1,351.8 1,373.1 1,324.4 1,288.0 1,278.9 1,277.1


Net Debt/Capital -1.3% -1.8% 8.2% 6.9% 6.2% 6.0% 8.5% 10.5% 8.2% 7.3% 6.8% 6.8% 6.9% 6.6% 6.4% 6.3% 6.2%


BVPS 52.13 48.37 46.97 48.98 50.37 46.75 48.98 47.78 48.05 48.29 48.51 48.74 48.98 49.23 49.54 49.91 50.37

TBVPS 19.20 18.14 14.76 16.04 17.42 15.46 16.09 14.84 15.10 15.34 15.57 15.80 16.04 16.29 16.59 16.97 17.42

December 15, 2015 165

National Oilwell Varco (NOV) Valuation PRICE TARGET SCENARIOS



2.7% 37.6X $28,204 $75 125% Net Income 2,517.0 2,364.3 2,781.7 1,143.0 538.4 712.3 1,122.0 1,353.9 1,527.5

4.7% 21.5X $25,723 $68 104% Depreciation & Amortization 628.0 755.0 778.0 751.3 797.4 912.2 1,055.6 1,207.5 1,360.4


8.7% 11.5X $21,520 $57 71% Deferred Taxes (97.0) (33.0) (300.0) (122.0) - - - - -


12.7% 7.9X $18,135 $48 44% Operating Cash Flow (before working cap.) 3,048.0 3,086.3 3,259.7 1,772.2 1,335.7 1,624.5 2,177.6 2,561.4 2,887.9

14.7% 6.8X $16,691 $44 32% Net Cash from Investing Activities (3,463.0) (3,116.0) (1,243.0) (541.9) (858.5) (1,328.2) (1,505.7) (1,587.4) (1,630.2)


18.7% 5.4X $14,207 $38 14% Capitalized G&A - - - - - - - - -

20.7% 4.8X $13,138 $35 5% Less: Net Capital Expenditures (before Cap Int) 3,463.0 3,116.0 1,243.0 541.9 858.5 1,328.2 1,505.7 1,587.4 1,630.2

Working Capital Change (3,201.0) 402.0 905.0 (131.5) (38.3) (17.3) (412.9) (545.5) (411.8)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 2,637.0 599.0 18.0 815.0 - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 149.0 (1,030.8) 1,093.7 546.7 515.6 313.6 1,084.8 1,519.4 1,669.5











Levered Free Cash Flow (2) 515.6 313.6 1,084.8 1,519.4 28,544.5




December 15, 2015 166











December 15, 2015 167

FMC Technologies: Buy, $43PT, Best Equipment Leverage to Offshore Consumables Recovery Investment Thesis. We are initiating coverage to FTI with a Buy Rating and $43 price target. Given a declining earnings profile, already discounted into shares, we see a slight industry rebound in subsea orders in 2016/2017 as a potential positive catalyst for the shares. After a sluggish recent Subsea order pace over 2014-2015, we see a potential for a recovery in equipment demand to meet an upturn in offshore activity in 2017. Traction regarding equipment standardization and efficiencies gained with the formation of Forsys (amongst other industry cost saving initiatives) may leave the current outlook on offshore equipment demand too bearish, as project costs come down. Similarly, 2016 should find the trough in Surface activity, with a need to restock wellheads and fluid control (pressure pumping) consumables a looming positive catalyst as operating leverage returns in 2017. In our view, beaten up FTI shares may see meaningful upside with a modest recovery in both subsea and surface activity.

Key Drivers

• Forsys Maintains FTI’s Competitive Footing. FTI and Technip joint venture provides a competitive response to SLB/CAM and a means to market greater efficiency to clients at the time offshore operators are looking to lower breakeven costs. While it remains to be seen if market share may change between Forsys and CAM/SLB, each may gain shares if GE, Aker Solutions, and Dril-Quip become less competitive. FTI may benefit from a vendor-based offering with greater efficiency in subsea umbilical, riser and flowline systems (SURF) and subsea production and processing systems (SPS). Forsys may prove less competitive with SLB/CAM on the linkage of reservoir data with downhole and topside equipment, but the pace of adoption of a more integrated system remains slow to date. Meanwhile, the company has caught up to SLB/CAM with the award of its first multi-phase pump with a separation and boosting order from Shell in Brazil. FTI may argue the SLB/CAM solutions force IOCs to yield too much control of the project details, seen as proprietary. In our view, the solution that yields the best results may win. Forsys may benefit from greater involvement at the FEED study phase of projects (involved in two so far), where FTI can help drive more equipment standardization and more efficient coordination of project installation. If Forsys and/or the industry can deliver on 25%-30% cost reductions, as promised, deepwater project awards may return faster and in greater numbers than current expectations.

• Subsea Orders Inflection in 2016/17 vs. Declining Subsea Segment Through 2017. Our data shows a recovery a recovery in tree orders in order to meet demand of offshore activity in 2017. A return of order volumes may prove the key driver for FTI shares, outweighing declining EPS. In our view, the market already discounts declining subsea segment economics in 2016 and 2017, as higher margin backlog rolls off the books. Recent subsea restructurings and further cost rationalizations may help cushion the margin impact, but a mix of lower backlog pull through and muted economics from at the beginning phases of incremental business may weigh on FTI’s EPS through 2017. Since there is a significant inventory of offshore project orders on the radar, FTI shares have room for multiple expansion, as investors see the bottom of earnings and begin to discount growth. If investors gain confidence in an inflection in offshore activity, we expect FTI shares to outperform.

• Surface Recovery in 2H16/1H17 May Drive Upside Surprises. The surface business has suffered from the decline in North America, which was ~50% of the Surface (wellheads & pressure pumping consumables) business at its peak. In our view 2016 may prove a recovery year, as North American rigs counts may see a modest recovery with commodity prices, a restructuring and streamlining of the business lends operating leverage, and orders may accelerate to restock pressure pumping fleets after a prolonged period of equipment. If all of these factors align and the wellhead and wireline businesses regain a positive trajectory, our estimates may prove conservative in 2017.

• Solid Balance Sheet & FCF Creates Flexibility. Free cash flow positive through 2016/2017 in our forecast and Total Debt/EBITDA under 2x, FTI remains a safe play on offshore recovery. Given a strong balance sheet, FTI may find opportunities to acquire novel, bolt-on technologies. Potential acquisitions may offer upside to our estimates.

December 15, 2015 168

FMC Technologies (FTI) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Subsea Technologies 4,725.8 5,266.4 4,547.7 4,222.9 4,559.1 1,157.2 1,239.4 1,093.7 1,057.4 1,032.5 1,030.3 1,044.6 1,115.5 1,089.0 1,101.7 1,135.6 1,232.8

Surface Technologies 1,806.8 2,130.7 1,495.5 1,262.0 1,640.5 446.3 363.3 361.0 324.9 316.8 308.9 315.0 321.3 353.5 388.8 427.7 470.5

Energy Infrastructure 618.6 557.5 392.4 348.1 350.9 100.9 101.4 97.1 93.0 88.3 87.4 86.6 85.7 81.4 85.5 89.8 94.3

Intercompany eliminations (25.0) (12.0) (31.7) (27.2) (27.2) (9.2) (8.9) (6.8) (6.8) (6.8) (6.8) (6.8) (6.8) (6.8) (6.8) (6.8) (6.8)

Total Revenues 7,126.2 7,942.6 6,403.9 5,805.8 6,523.3 1,695.2 1,695.2 1,545.0 1,468.5 1,430.8 1,419.8 1,439.4 1,515.8 1,517.1 1,569.2 1,646.2 1,790.7

Subsea Technologies 553.4 748.2 696.1 545.1 464.3 168.7 183.5 185.3 158.6 147.1 139.1 130.6 128.3 117.1 110.2 110.7 126.4

Surface Technologies 257.2 392.8 154.1 75.8 176.1 62.9 27.5 37.7 26.0 19.0 17.0 18.9 20.9 26.5 36.9 49.2 63.5

Energy Infrastructure 69.1 52.6 12.5 12.2 23.0 2.9 5.3 (0.3) 4.6 3.5 2.6 2.6 3.4 4.1 5.1 6.3 7.5

Corporate & Eliminations (46.2) (65.2) (60.1) (59.5) (66.9) (16.3) (14.0) (14.7) (15.1) (14.7) (14.6) (14.8) (15.5) (15.6) (16.1) (16.9) (18.4)

EBIT 833.5 1,128.4 802.7 573.5 596.6 218.2 202.3 208.0 174.2 155.0 144.1 137.3 137.1 132.1 136.2 149.3 179.1

Interest income 1.0 - 2.7 13.7 13.2 - - - 2.7 3.4 3.3 3.4 3.5 3.3 3.4 3.3 3.2

Interest (expense) (33.7) (32.5) (32.6) (33.2) (34.1) (7.3) (9.0) (8.1) (8.2) (8.2) (8.3) (8.3) (8.4) (8.4) (8.5) (8.5) (8.6)

Other (expense) (57.1) (49.2) (80.1) (56.0) (56.0) (25.9) (19.9) (20.3) (14.0) (14.0) (14.0) (14.0) (14.0) (14.0) (14.0) (14.0) (14.0)

EBT 743.7 1,046.7 692.7 498.0 519.7 185.0 173.4 179.6 154.7 136.2 125.2 118.5 118.2 113.0 117.0 130.1 159.6

Income Tax (218.8) (343.4) (168.0) (129.5) (135.1) (36.9) (51.2) (39.6) (40.2) (35.4) (32.6) (30.8) (30.7) (29.4) (30.4) (33.8) (41.5)

Minority interest (5.2) (5.4) (0.7) (0.2) (0.2) (0.5) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1)


Extraordinaries (after-tax) (14.4) 0.9 (87.2) - - - (14.2) (58.0) (15.0) - - - - - - - -

Net Income (GAAP) 505.3 698.8 436.9 368.3 384.4 147.6 107.9 82.0 99.4 100.8 92.6 87.6 87.4 83.5 86.6 96.2 118.1

EPS (Operating) 2.17 2.94 2.26 1.69 1.85 0.63 0.52 0.61 0.50 0.45 0.42 0.40 0.41 0.39 0.41 0.47 0.58

EPS (GAAP) 2.11 2.95 1.89 1.69 1.85 0.63 0.46 0.35 0.44 0.45 0.42 0.40 0.41 0.39 0.41 0.47 0.58




EBITDA 1,043.3 1,360.9 1,057.1 867.4 899.7 276.0 255.7 279.3 246.1 227.5 217.3 211.1 211.5 207.0 211.6 225.3 255.7





Free Cash Flow (FCF) 481.3 488.1 585.8 429.1 249.9 88.9 (14.4) 216.6 294.7 158.9 127.4 96.4 46.3 112.4 70.4 54.7 12.4

Acquisitions/Divestures/Investments 2.5 105.6 (0.7) - - 5.3 3.3 (9.3) - - - - - - - - -


Other (2.9) (46.7) (55.5) - - (15.5) (10.1) (29.9) - - - - - - - - -

Increase (Decrease) in Cash 57.0 239.7 276.4 (34.9) (114.1) 56.3 (107.9) 124.3 203.7 (32.1) 36.4 5.4 (44.7) 21.4 (20.6) (36.3) (78.6)


Total Capital 3,779.3 4,145.6 4,152.8 4,057.2 4,077.6 3,776.6 3,884.2 3,800.2 3,808.6 3,718.4 3,720.0 3,716.6 3,713.0 3,705.5 3,701.1 3,706.3 3,733.4

Total Debt 1,372.3 1,308.9 1,303.7 1,339.7 1,375.7 1,316.4 1,286.6 1,294.7 1,303.7 1,312.7 1,321.7 1,330.7 1,339.7 1,348.7 1,357.7 1,366.7 1,375.7

Net Debt 973.2 670.1 388.5 459.4 609.4 621.3 699.4 583.2 388.5 429.5 402.1 405.7 459.4 447.0 476.6 521.8 609.4


Net Debt/Capital 25.8% 16.2% 9.4% 11.3% 14.9% 16.5% 18.0% 15.3% 10.2% 11.6% 10.8% 10.9% 12.4% 12.1% 12.9% 14.1% 16.3%


BVPS 9.69 10.37 10.82 10.87 11.34 10.52 11.15 10.85 10.98 10.81 10.92 11.00 11.08 11.13 11.21 11.32 11.55

TBVPS 5.94 6.84 7.58 7.86 8.63 7.06 7.69 7.50 7.69 7.55 7.71 7.86 8.01 8.14 8.29 8.48 8.79

December 15, 2015 169

FMC Technologies (FTI) Valuation PRICE TARGET SCENARIOS



3.8% 26.4X $13,465 $60 107% Net Income 429.0 505.3 698.8 436.9 368.3 384.4 625.3 754.6 868.3



9.8% 10.2X $10,438 $46 59% Deferred Taxes (9.8) (20.4) (18.1) 29.1 (5.0) (5.2) (8.5) (10.2) (11.7)


13.8% 7.3X $8,892 $39 35% Operating Cash Flow (before working cap.) 565.4 694.7 913.2 720.3 657.2 682.3 930.1 1,068.7 1,192.1

15.8% 6.3X $8,229 $37 28% Net Cash from Investing Activities (1,019.9) (311.6) (298.8) (259.0) (203.2) (195.7) (225.9) (240.0) (254.8)


19.8% 5.1X $7,084 $32 11% Capitalized G&A - - - - - - - - -

21.8% 4.6X $6,589 $29 0% Less: Net Capital Expenditures (before Cap Int) 1,019.9 311.6 298.8 259.0 203.2 195.7 225.9 240.0 254.8


Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 708.2 (307.6) (59.7) (5.2) 36.0 36.0 36.0 36.0 36.0

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (567.4) 1,059.5 380.8 374.6 443.0 687.2 860.6 863.6 1,057.4








Net Debt/Total Capital 25.0% Subtract: Changes in Equity for Explict Forecast 2,100.0







December 15, 2015 170











December 15, 2015 171

Oceaneering Intl.: Accumulate, $49PT, Rig Attrition Deflates EPS, As 2016 Consensus EPS Looks High Investment Thesis. We are initiating coverage of Oceaneering International with a Accumulate rating and $49 price target. Our mid-cycle valuation leaves moderate upside, but 2016 and 2017 consensus EPS appears ripe for negative revisions to better reflect a decline in deepwater activity, rig utilization, rig retirements, and a lack of visibility on factors that may suppress the core ROV and Products businesses. We anticipate negative estimate revisions may lead shares to re-test recent lows. Since deepwater activity may recover at a lag to commodity prices, we do not forecast an improvement in earnings momentum for ROVs and Subsea Products (90% of 3Q/15 EBIT) until 2H17. Suspended guidance and questions surrounding rig-based ROV utilization remain an overhangs on OII shares. Near term challenges aside, OII remains a strong, conservatively managed franchise, with 60%+ market share of the drilling ROV market, a solid offering subsea products, potential upside from a resumption of maintenance & repair work (IMR), solid cash flow, and a safe balance sheet. We see better value elsewhere, but continue to assess OII’s merits as a later cycle play. Key Drivers • Leverage to Deepwater Recovery. OII holds ~60% market share in the floater ROV market and leverage to offshore development through its Subsea Products and Subsea Projects segments. We

forecast floater retirements and a further 20%+ decline in floater activity in 2016 may decrease ROV utilization to the ~60’s% range in 2016, with a proportional impact on Subsea Products. As utilization falls and pricing follows, we see negative operating leverage in the ROV and Products businesses. Products may find support from backlog, including the recent Appomattox umbilical contract win, but at a cost of lower margins that stems from industry-wide overcapacity in umbilical manufacturing. As we chart the path forward, oil prices may need to stabilize, with a directional bias toward recovery, in order for deepwater projects to reach FID and activity to inflect in 2017. We do not see a meaningful a rebound in estimates or a recovery in the shares until market gains confidence in the timing and trajectory of a recovery in offshore activity. In our view, further offshore fleet growth, the key driver for the high return ROV franchise may lie further beyond a recovery, but too far out to warrant meaningful multiple expansion in the current environment.

• Negative Earnings Momentum & EPS Revisions Through 2017. After lowering 2015 guidance successively in recent quarters and suspending guidance for 2016, investors have struggle to gain confidence with EPS estimates. We believe that our sub-$2 EPS estimates for 2016 and 2017 are conservative, but our confidence in our assumptions remains weak. The rate of business decline through rig retirements and lost operating leverage in the model remains a “wild card” in our estimates. Our estimates are below consensus, which suggests negative estimate revisions could be a headwind during coming quarters.

• Strong Balance Sheet & FCF Provides Lower Risk Profile for Offshore/Deepwater Exposure. Despite falling EPS, OII remains FCF positive through the downturn. We see Net debt/Capital falling from a 2Q/15 high and Total Debt/EBITDA peaking below 2.0x at the bottom of the cycle. Given more stretched balance sheets amongst the offshore drillers and other oil service peers, OII shares do offer some relative safety and potential upside with a positive turn in the upstream cycle. With a favorable balance sheet, we see only a moderate probability of a dividend cut, despite concerns about a prolonged downturn and low earnings predictability.

• Potential Accretive M&A for Product Addition or Geographic Footprint. The downturn may give OII the opportunity to expand its subsea product offering and/or its geographic exposure through M&A at attractive valuations. OII’s deals gravitate toward smaller digestible companies, but may also allow OII to employ cash, accretively.

December 15, 2015 172

Oceaneering International (OII) Model Income Statement 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

Remotely operated vehicles (ROV) 981.7 1,069.0 802.0 662.2 745.3 219.4 216.4 198.4 167.7 169.8 166.5 163.2 162.6 177.8 182.4 190.1 195.0

Subsea Products 1,027.8 1,238.7 906.9 796.0 795.5 240.7 240.1 220.0 206.1 206.1 203.2 197.5 189.2 191.4 194.9 200.5 208.7

Subsea Projects 509.4 588.6 605.6 437.4 352.3 153.6 172.3 147.2 132.5 117.9 117.9 106.1 95.5 85.0 89.2 93.7 84.3

Asset Integrity - Inspection 481.9 500.2 382.4 352.8 335.3 98.5 95.5 95.6 92.7 90.9 89.1 87.3 85.5 83.8 82.2 83.8 85.5

Advanced technologies 286.1 263.0 330.2 358.0 372.5 74.5 86.0 82.3 87.3 88.2 89.0 89.9 90.8 91.7 92.7 93.6 94.5

Total Revenues 3,287.0 3,659.6 3,026.9 2,606.3 2,600.8 786.8 810.3 743.6 686.3 672.8 665.7 644.1 623.7 629.7 641.4 661.6 668.0

Remotely operated vehicles (ROV) 285.3 320.6 209.4 142.9 172.6 62.2 61.3 52.4 33.5 34.0 33.3 43.1 32.5 37.3 38.3 54.0 42.9

Subsea Products 231.1 281.2 197.6 129.8 121.5 50.0 51.3 55.1 41.2 38.1 34.5 30.6 26.5 27.7 29.2 31.1 33.4

Subsea Projects 93.9 107.9 108.2 65.2 56.3 22.3 30.6 28.8 26.5 14.7 18.6 16.5 15.3 11.5 15.0 15.5 14.3

Asset Integrity - Inspection 55.2 55.5 26.2 31.0 31.7 5.0 4.5 8.5 8.1 7.9 7.8 7.6 7.6 7.7 7.7 8.0 8.3

Advanced technologies 25.0 13.2 15.5 10.7 11.1 5.0 6.3 1.6 2.6 2.6 2.7 2.7 2.7 2.7 2.8 2.8 2.8

Corporate (unallocated) - G&A (142.0) (150.0) (123.1) (96.2) (96.2) (37.9) (37.1) (24.1) (24.1) (24.1) (24.1) (24.1) (24.1) (24.1) (24.1) (24.1) (24.1)

EBIT 548.4 628.3 433.9 283.3 296.9 106.7 116.9 122.5 87.9 73.3 72.8 76.5 60.6 62.9 68.9 87.4 77.7

Interest income 0.6 0.3 0.8 2.4 3.5 0.2 0.1 0.2 0.3 0.5 0.5 0.6 0.7 0.8 0.9 0.9 0.9


Equity earnings of unconsolidated affiliates 0.1 (0.1) 2.9 6.3 6.3 (0.3) 0.0 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6

Other income (expense) (1.3) (0.4) 0.4 (0.1) 0.0 0.7 (0.5) 0.1 0.1 (0.1) 0.0 0.0 (0.0) 0.0 (0.0) (0.0) 0.0

EBT 545.6 623.5 412.8 266.2 281.0 101.2 110.2 118.0 83.5 68.9 68.5 72.3 56.5 58.9 64.9 83.4 73.8

Income Tax (172.0) (195.1) (130.8) (84.8) (89.6) (31.7) (35.0) (37.6) (26.6) (21.9) (21.8) (23.0) (18.0) (18.8) (20.7) (26.6) (23.5)

NET INCOME (Operating) 373.6 428.3 282.0 181.4 191.4 69.5 75.2 80.4 56.9 46.9 46.7 49.3 38.5 40.1 44.2 56.8 50.3

Extraordinary Item (after-tax) (2.1) - (21.6) - - - (9.8) (11.8) - - - - - - - - -

Net Income(GAAP) 371.5 428.3 260.4 181.4 191.4 69.5 65.5 68.5 56.9 46.9 46.7 49.3 38.5 40.1 44.2 56.8 50.3

EPS (Operating) 3.4 4.0 2.9 1.9 2.0 0.7 0.8 0.8 0.6 0.5 0.5 0.5 0.4 0.4 0.5 0.6 0.5

EPS (GAAP) 3.4 4.0 2.6 1.9 2.0 0.7 0.7 0.7 0.6 0.5 0.5 0.5 0.4 0.4 0.5 0.6 0.5


Diluted CEPS (Operating) 5.3 6.1 5.4 4.5 4.8 1.3 1.4 1.5 1.2 1.1 1.1 1.2 1.1 1.1 1.1 1.3 1.2



EBITDA 750.6 858.1 680.3 541.3 567.5 164.7 180.3 184.5 150.8 136.9 137.0 141.4 126.0 129.1 136.0 155.5 147.0


Cash Flow Statement 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

Cash from Operations (CFO) 528.9 730.2 561.1 522.6 416.8 8.1 192.4 172.6 188.1 124.9 122.2 148.8 126.8 100.8 99.6 108.1 108.3


Free Cash Flow (FCF) 146.3 343.3 377.3 392.3 221.0 (41.3) 147.0 128.2 143.4 91.2 88.9 116.6 95.6 63.0 54.7 55.2 48.2

Acquisitions/Divestures/Investments 4.9 (37.7) (249.1) - - 1.2 (229.9) (20.4) - - - - - - - - -

Cash From Financing (CFF) (184.6) 51.6 (156.2) (102.9) (102.9) (82.8) (72.1) 24.4 (25.7) (25.7) (25.7) (25.7) (25.7) (25.7) (25.7) (25.7) (25.7)

Other 4.3 (18.0) (13.8) - - (3.3) 41.1 (51.6) - - - - - - - - -

Increase (Decrease) in Cash (29.1) 339.3 (41.8) 289.3 118.1 (126.2) (113.9) 80.5 117.7 65.5 63.1 90.9 69.8 37.2 29.0 29.4 22.4

Key Balance Sheet Statistics 2013 2014 2015E 2016E 2017E 1Q15 2Q15 3Q15 4Q15E 1Q16E 2Q16E 3Q16E 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E

Total Capital 2,043.4 2,407.6 2,417.5 2,496.0 2,584.5 2,333.7 2,391.1 2,386.4 2,417.5 2,438.7 2,459.7 2,483.2 2,496.0 2,510.3 2,528.8 2,559.9 2,584.5

Total Debt - 750.0 797.5 797.5 797.5 750.0 792.9 797.5 797.5 797.5 797.5 797.5 797.5 797.5 797.5 797.5 797.5

Net Debt (91.4) 319.3 408.6 119.3 1.2 445.5 602.3 526.3 408.6 343.1 280.0 189.1 119.3 82.1 53.1 23.6 1.2


Net Debt/Capital -4.5% 13.3% 16.9% 4.8% 0.0% 19.1% 25.2% 22.1% 16.9% 14.1% 11.4% 7.6% 4.8% 3.3% 2.1% 0.9% 0.0%


BVPS 18.8 15.5 16.5 17.6 18.5 15.9 16.2 16.2 16.7 17.0 17.2 17.4 17.6 17.7 17.9 18.2 18.5

TBVPS 15.6 12.4 12.2 13.2 14.1 12.7 11.8 11.9 12.4 12.6 12.8 13.1 13.2 13.3 13.5 13.9 14.1

December 15, 2015 173

Oceaneering International (OII) Valuation PRICE TARGET SCENARIOS



3.3% 30.0X $6,617 $69 81% Net Income 289.0 371.5 428.3 260.4 181.4 191.4 265.4 300.9 380.5



9.3% 10.7X $5,122 $53 39% Deferred Taxes 20.7 51.8 74.3 18.4 8.3 8.8 12.2 13.8 17.5





19.3% 5.2X $3,470 $36 (5%) Capitalized G&A - - - - - - - - -

21.3% 4.7X $3,227 $34 (11%) Less: Net Capital Expenditures (before Cap Int) 317.9 377.6 424.6 432.9 130.3 195.7 329.1 353.0 381.2

Working Capital Change (70.1) (149.6) 11.1 53.9 74.9 (54.1) (146.4) (46.4) (99.4)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred (27.0) (93.7) 750.0 50.0 - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 265.4 491.2 (453.2) (11.7) 242.5 329.2 387.8 328.1 465.0















December 15, 2015 174











December 15, 2015 175

Forum Technologies: Buy, $19PT, Cyclical Capital Equipment & Consumables Recovery Play Investment Thesis. We are initiating coverage of FET with an Buy rating and $19 price target. Attractive against our mid-cycle valuation, FET offers a balanced exposure to a cyclical upstream recovery for capital equipment and drilling consumables, with a strong linkage to US land (~75% onshore & ~60% US total revenue). We also see later cycle upside from a recovery in offshore market, largely through its ROV business. In our view, 2016 consensus estimates may prove too high, but we see a bottoming of 2016 expectations and forecast for a 2017 recovery as a positive catalyst for the shares. As these fundamentals improve with cyclical recovery, operating leverage within consumables and capital equipment product lines may leave our estimates conservative. As we assume a higher marginal cost of capital for the smaller cap company, a reduced risk profile may lead us to rethink our price target to the upside, especially given FET’s low leverage and FCF generation. Although FET has a history of growth through acquisitions, we see a high marginal cost of capital and less willing sellers as a potential barrier to deals at the bottom of the cycle, but a potential positive for the shares as the upstream market recovers.

Key Drivers

• Declining Fundamentals Across Business Lines Into 2016. Most of the decline in growth and margins across business lines has appeared in operating results, but we forecast further weakness through the beginning of 2016 led by a further declines in upstream activity. With improvement in US land rig counts, we see a meaningful recovery for FET’s sales of drilling consumables and “wear & tear” replacement items beginning in 2H16, augmented by a restocking cycle. At a lag, we anticipate a recovery in land rig capital equipment orders, as the AC market recovers and creates the need for new constructions. With a rebound in offshore activity, FET’s ROV manufacturing business may improve with higher levels of field development activity. In the interim, FET’s Valves business leverages midstream and downstream projects may add some stability to the mix.

• Fuller Integration & Internal Efficiencies Should Help Margins. Prior to the downturn, FET benefitted from continued integration of previous acquisitions. In our view, continued progress on integration and internal improvement may help operating margins further in 2016. FET has initiatives to promote lean manufacturing processes across product lines, more performance measurement, process quality controls to remove waste from the system, procurement aggregation (already yielding savings in the high single digits). We suspect results may lag with a few inventory turns, but FET suggests potential margin improvements up to 500bps. Success with internal initiatives, matched with cyclical recovery may prove our 2H/16 estimates conservative.

• M&A Catalysts May Not Recover Until Turn of the Cycle. Acquisitions of niche, complimentary products, remains a core tenant of FET’s growth strategy. With wide bid/ask spreads and higher cost of capital we see less opportunity for positive M&A growth catalysts in the near term. In the trough of the cycle, FET may not have sufficient currency. More importantly, small acquisition targets may not see limitations to growth, which may be solved by inclusion in a larger organization. Historically, FET, who has penetration into a client base, may offer expanded markets for companies yet to achieve the scale and brand recognition needed to an become approved supplier to larger customers.

• Leverage Ratios May Add Volatility to the Story. FET hosts a net debt to capital under 20%, but its $400 million 2021 Senior Notes trade near double digit yield levels. We estimates that Total Debt/EBITDA may elevate in 2016. Given a longer dated maturity on existing debt, we see no critical issues, but less favorable credit ratios may lead to some volatility in FET shares. Even though we see FET remaining FCF positive through the downturn, a high marginal cost of capital may limit M&A and growth initiative optionality.

December 15, 2015 176

Forum Technologies (FET) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Drilling & Subsea 940.8 1,126.4 660.5 549.5 725.1 215.1 169.7 139.1 136.7 134.3 133.3 137.1 144.8 150.9 168.8 190.4 215.0

Production & Infrastructure 585.4 614.5 447.6 387.9 480.2 133.2 114.9 106.2 93.3 91.0 93.5 98.3 105.2 111.1 117.5 122.9 128.6

Eliminations (1.5) (1.2) (0.8) (1.1) (1.1) (0.0) (0.2) (0.3) (0.3) (0.3) (0.3) (0.3) (0.3) (0.3) (0.3) (0.3) (0.3)

Total Revenues 1,524.8 1,739.7 1,107.3 936.3 1,204.2 348.3 284.4 245.0 229.7 225.0 226.5 235.1 249.7 261.8 286.0 313.0 343.4

Drilling & Subsea 205.5 252.9 102.9 66.8 117.1 48.4 22.4 17.8 14.3 14.8 15.3 17.1 19.5 21.9 26.2 31.4 37.6

Production & Infrastructure 100.3 124.1 64.1 39.5 67.5 21.8 18.9 14.5 8.9 8.2 8.9 10.3 12.1 13.9 15.9 17.8 19.9

Corporate & Other (26.4) (37.2) (12.9) (24.3) (31.3) (8.5) (0.2) 1.8 (6.0) (5.8) (5.9) (6.1) (6.5) (6.8) (7.4) (8.1) (8.9)


EBIT 218.7 274.7 88.2 18.9 94.9 45.4 24.7 17.5 0.6 0.8 2.4 5.8 9.9 14.0 19.9 26.6 34.4


Loss/(Gain) on F/X & Other (5.4) - - - - - - - - - - - - - - - -

EBT 195.0 244.8 58.5 (9.5) 66.5 37.8 17.1 10.1 (6.5) (6.3) (4.7) (1.3) 2.8 6.9 12.8 19.5 27.3

Income Tax (56.0) (68.9) (14.6) 2.2 (15.3) (10.6) (2.6) (2.8) 1.5 1.4 1.1 0.3 (0.6) (1.6) (2.9) (4.5) (6.3)

Net Income (Operating) 139.0 175.9 44.0 (7.3) 51.2 27.2 14.5 7.3 (5.0) (4.8) (3.6) (1.0) 2.2 5.3 9.9 15.0 21.0

Extraordinaries (after-tax) (9.4) (0.1) (15.0) (6.0) - - (5.6) (3.4) (6.0) (6.0) - - - - - - -

Net Income (GAAP) 129.6 175.8 29.0 (13.3) 51.2 27.2 8.9 3.9 (11.0) (10.8) (3.6) (1.0) 2.2 5.3 9.9 15.0 21.0

EPS (Operating) 1.46 1.84 0.48 (0.08) 0.56 0.30 0.16 0.08 (0.05) (0.05) (0.04) (0.01) 0.02 0.06 0.11 0.16 0.23

EPS (GAAP) 1.36 1.84 0.32 (0.15) 0.56 0.30 0.10 0.04 (0.12) (0.12) (0.04) (0.01) 0.02 0.06 0.11 0.16 0.23




EBITDA 279.4 339.8 154.1 81.9 153.3 61.7 41.1 34.1 17.2 17.1 18.3 21.3 25.2 29.0 34.6 41.1 48.6



Cash From Operations (CFO) 211.4 270.0 188.3 184.9 (11.2) 58.1 5.1 54.5 70.6 70.7 61.4 56.8 (3.9) 1.9 (6.7) (4.4) (1.9)


Free Cash Flow (FCF) 151.1 216.2 153.4 160.6 (42.5) 46.7 (3.2) 46.2 63.7 64.9 55.5 50.6 (10.4) (4.9) (14.1) (12.6) (10.9)

Acquisitions/Divestures/Investments (293.0) (20.1) (59.1) - - (60.2) 0.8 0.3 - - - - - - - - -

Cash From Financing (CFF) 76.5 (161.1) (27.5) (0.2) (0.2) 34.7 (29.3) (32.9) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1) (0.1)

Other 63.9 2.1 (3.5) - - (13.9) 5.6 4.8 - - - - - - - - -

Increase (Decrease) in Cash (1.5) 37.0 63.3 160.4 (42.7) 7.3 (26.1) 18.3 63.7 64.8 55.4 50.6 (10.5) (5.0) (14.2) (12.6) (10.9)


Total Capital 1,843.4 1,824.2 1,821.7 1,787.6 1,812.0 1,860.7 1,873.1 1,833.4 1,821.7 1,810.2 1,799.9 1,792.1 1,787.6 1,786.2 1,789.4 1,797.7 1,812.0

Total Debt 513.1 428.9 402.9 402.9 402.9 468.6 438.3 402.9 402.9 402.9 402.9 402.9 402.9 402.9 402.9 402.9 402.9

Net Debt 473.5 352.3 263.0 102.7 145.4 384.7 380.5 326.7 263.0 198.2 142.8 92.2 102.7 107.6 121.8 134.5 145.4


Net Debt/Capital 25.7% 19.3% 14.4% 5.7% 8.0% 20.7% 20.3% 17.8% 14.4% 11.0% 7.9% 5.1% 5.7% 6.0% 6.8% 7.5% 8.0%


BVPS 13.93 14.62 15.52 15.15 15.42 15.21 15.69 15.65 15.52 15.39 15.28 15.20 15.15 15.13 15.17 15.26 15.42

TBVPS 2.44 3.41 4.04 3.95 4.47 3.57 3.94 4.09 4.04 3.98 3.94 3.93 3.95 4.00 4.10 4.25 4.47

December 15, 2015 177

Forum Technologies (FET) Valuation PRICE TARGET SCENARIOS



6.9% 14.5X $2,427 $27 121% Net Income 151.3 129.6 175.8 29.0 (13.3) 51.2 128.2 169.5 206.2



12.9% 7.8X $1,866 $21 72% Deferred Taxes (6.3) 19.8 (4.5) - - - - - -





22.9% 4.4X $1,240 $14 15% Capitalized G&A - - - - - - - - -

24.9% 4.0X $1,147 $13 6% Less: Net Capital Expenditures (before Cap Int) 184.5 353.3 73.9 94.1 24.3 31.3 39.3 38.7 37.1

Working Capital Change (58.8) (23.3) 9.3 78.9 155.8 (94.2) (49.4) (40.4) (44.0)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 55.2 94.6 (83.0) (26.0) - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 15.8 (214.4) 236.5 (52.0) (130.4) 172.5 194.2 225.9 266.0




Beta (Adjusted) 1.28 Subtract: Long Term Debt (Terminal Year) 402.9











December 15, 2015 178











December 15, 2015 179

Dril-Quip: Accumulate, $75PT, Compelling Offshore Recovery Story Investment Thesis. We are initiating coverage of DRQ with an Accumulate rating and a $75 price target. DRQ offers a compelling exposure to an offshore recovery, but its shares partly reflect the relative attractiveness to equipment peers. We like DRQ’s leverage to offshore drilling consumables, through a well consolidated wellhead and specialty connector business. A virtual duopoly, DRQ shares roughly 85% market share with GE (40%-45% mkt shares, respectively), which helps to maintain pricing and competitive discipline within this corner of the offshore equipment market. Vertically integrated, with a low cost overhead, and more flexible control of variable costs, via reduced hours, less overtime, and furloughs, DRQ is better able to manage gross margins in the downturn. With no long term debt and FCF throughout our forecast, we continue to like the prospect for share repurchases. Similar to offshore equipment peers, DRQ faces the headwinds near term. That said, our estimates stand above consensus for 2017, which may translate to upward revisions as 2016 progresses. With order/equipment delivery lead times closer to 6-9months, DRQ stands to benefit from an order recovery in 2H/16 in anticipation of a potential recovery in offshore activity in 2017. Recent industry destocking of wellheads, subsea trees, and specialty connectors may amplify initial orders for the cyclical recovery. In our view, low expectations, met by a possible re-stocking surge in front of a 2017/2018 inflection in activity remains the largest looming catalyst for the stock. In our view, longer term investors should look to build positions, especially if cautious year end guidance and volatility provides opportunities below $60. Key Drivers • Orders May Turn in 2016 to Meet 2017 Demand. New orders may continue to lag in coming quarters as floater counts decline through 2016, but inflect to meet our forecast for floater activity to

recover in the 2H/17. Lead times for wellhead, specialty connectors, and subsea trees range between at least 6-9 months. DRQ’s discussion of an increase in quotation activity likely represents the early signs that orders may come in the 2H/16 time frame. We see visibility on orders as a potential positive catalyst for the DRQ shares.

• Destocking May Amplify Recovery. Since 1Q14, the number of contract floaters is down ~13%. Over the same period, DRQ new orders are down ~85%. Clearly, the discrepancy represents industry de-stocking. In the face of a potential inflection in offshore activity in 2017, operators may need to meet rising equipment demand, restock inventories, and replenish spares and parts stocks neglected during the downturn. A surge in restocking activity may lead 2017 EPS estimates higher, a positive catalyst for DRQ shares.

• Vertical Integration & Cost Cutting Plan Leaves DRQ Prepared for Recovery. Cost cutting to offset a likely ~5% decrease in pricing across product lines may help to reduce the impact on gross margins. As opposed to cutting headcount (except in Brazil), DRQ plans reduced hours and overtime for machinists and engineers as backlog is delivered. Given over two years of training time, retention of engineers provides business continuity and longer term savings on training. Training lead times may prove shorter and less of an issue for machinists, but retention of employees affords DRQ an ability to ramp production faster in an upturn. Coupled with vertical integration, DRQ may prove better positioned to deliver on orders at the turn of the cycle.

• Strong Balance Sheet, FCF, & Share Repurchases. DRQ has no long-term debt and ~$800 million in backlog, which limits risks to the story. FCF positive through the downturn, we expect DRQ to continue to repurchase shares.

December 15, 2015 180

Dril-Quip (DRQ) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Product Group 731.6 773.2 670.5 513.1 505.9 187.5 176.1 157.8 149.1 139.2 131.5 124.1 118.2 115.6 122.1 129.0 139.2

Service Group 140.8 157.8 162.5 141.8 139.8 38.5 39.2 43.6 41.2 38.5 36.3 34.3 32.7 31.9 33.8 35.7 38.5

Total Revenues 872.4 931.0 833.0 654.9 645.7 226.0 215.3 201.4 190.3 177.7 167.8 158.4 150.9 147.5 155.9 164.7 177.6

Cost of Sales (513.9) (513.5) (460.4) (396.9) (381.4) (125.1) (117.7) (108.1) (109.4) (105.7) (103.2) (96.6) (91.3) (88.5) (92.8) (97.2) (103.0)

SG&A (87.3) (99.2) (79.0) (69.6) (70.4) (24.3) (20.1) (17.3) (17.3) (17.3) (17.4) (17.4) (17.5) (17.5) (17.6) (17.6) (17.7)

Engineering & Product Development (40.1) (45.9) (46.2) (37.5) (37.0) (12.2) (11.4) (11.7) (10.9) (10.2) (9.6) (9.1) (8.6) (8.4) (8.9) (9.4) (10.2)

EBIT 231.0 272.3 247.4 150.9 156.9 64.3 66.1 64.3 52.7 44.5 37.6 35.3 33.5 33.0 36.6 40.5 46.7

Interest (Expense), Net (0.0) (0.0) (0.0) - - (0.0) (0.0) (0.0) - - - - - - - - -

Interest Income 0.6 0.7 0.9 1.8 2.2 0.0 0.2 0.3 0.4 0.4 0.4 0.5 0.5 0.5 0.6 0.5 0.5

EBT 231.6 272.9 248.3 152.6 159.0 64.4 66.3 64.6 53.1 44.8 38.0 35.7 34.0 33.6 37.2 41.0 47.3

Income Taxes (58.9) (68.2) (58.8) (38.2) (39.8) (15.5) (18.1) (13.8) (11.4) (11.2) (9.5) (8.9) (8.5) (8.4) (9.3) (10.3) (11.8)


Extraordinaries (after-tax) (2.8) 4.2 (4.0) - - 4.8 (8.8) - - - - - - - - - -

Net Income (GAAP) 169.9 208.9 185.5 114.5 119.3 53.7 39.3 50.8 41.7 33.6 28.5 26.8 25.5 25.2 27.9 30.8 35.5

EPS (Operating) 4.23 5.09 4.90 3.02 3.22 1.25 1.24 1.32 1.09 0.88 0.75 0.71 0.68 0.67 0.75 0.83 0.96

EPS (GAAP) 4.16 5.20 4.80 3.02 3.22 1.38 1.01 1.32 1.09 0.88 0.75 0.71 0.68 0.67 0.75 0.83 0.96




EBITDA 260.3 303.4 277.9 181.2 185.8 71.8 73.8 71.9 60.5 52.2 45.2 42.8 40.9 40.4 43.9 47.7 53.9



Cash From Operations (CFO) 162.8 149.3 212.9 249.7 39.9 87.6 25.4 45.7 54.2 69.2 55.6 66.7 58.2 42.5 0.9 2.1 (5.7)


Free Cash Flow (FCF) 120.1 106.7 190.9 231.7 22.1 81.5 20.4 40.2 48.9 64.3 51.0 62.3 54.0 38.4 (3.4) (2.4) (10.5)

Acquisitions/Divestures/Investments 0.8 1.0 0.2 - - 0.1 0.0 0.0 - - - - - - - - -

Cash From Financing (CFF) 0.5 (187.4) (51.7) (54.5) (60.1) 0.3 (18.2) (21.0) (12.8) (13.1) (13.4) (13.8) (14.1) (14.5) (14.8) (15.2) (15.6)

Other 5.8 (6.0) (5.0) - - (6.4) 6.4 (5.0) - - - - - - - - -

Increase (Decrease) in Cash 127.2 (85.7) 134.4 177.2 (38.0) 75.4 8.5 14.3 36.1 51.2 37.6 48.5 39.9 24.0 (18.2) (17.6) (26.1)


Total Capital 1,242.0 1,245.2 1,344.7 1,404.7 1,463.8 1,270.1 1,315.8 1,315.8 1,344.7 1,365.2 1,380.3 1,393.3 1,404.7 1,415.4 1,428.4 1,444.0 1,463.8

Total Debt - - - - - - - - - - - - - - - - -

Net Debt (384.4) (298.7) (433.1) (610.3) (572.3) (374.1) (382.7) (397.0) (433.1) (484.3) (521.9) (570.4) (610.3) (634.3) (616.1) (598.4) (572.3)


Net Debt/Capital -30.9% -24.0% -32.2% -43.4% -39.1% -29.5% -29.1% -30.2% -32.2% -35.5% -37.8% -40.9% -43.4% -44.8% -43.1% -41.4% -39.1%


BVPS 30.41 30.98 34.76 37.11 39.51 32.62 33.83 34.13 35.07 35.79 36.37 36.91 37.41 37.90 38.45 39.08 39.83

TBVPS 30.41 30.98 34.76 37.11 39.51 32.62 33.83 34.13 35.07 35.79 36.37 36.91 37.41 37.90 38.45 39.08 39.83

December 15, 2015 181

Dril-Quip (DRQ) Valuation PRICE TARGET SCENARIOS



2.4% 41.2X $4,053 $106 82% Net Income 119.2 169.9 208.9 185.5 114.5 119.3 179.7 236.4 302.9



8.4% 11.9X $3,125 $82 41% Deferred Taxes 0.3 (1.2) (3.1) (9.9) (9.9) (9.9) (9.9) (9.9) (9.9)





18.4% 5.4X $2,099 $55 (5%) Capitalized G&A - - - - - - - - -

20.4% 4.9X $1,947 $51 (12%) Less: Net Capital Expenditures (before Cap Int) 49.0 41.9 41.6 21.8 18.0 17.8 22.4 30.2 37.2

Working Capital Change (173.8) (46.2) (120.3) 95.5 114.9 (98.5) (160.5) (215.5) (269.3)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred (0.0) - - - - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 270.6 202.3 315.6 88.9 1.9 219.0 336.0 439.8 553.7















December 15, 2015 182











December 15, 2015 183

Land Contract Drillers

December 15, 2015 184

Helmerich & Payne: Buy, $78, Well Positioned, Best in Class Fleet Investment Thesis

We are initiating coverage of HP with a Buy rating and $78 price target. We are buyers of HP for 5 reasons 1) its top quality fleet may be quick to return to work in a North American Recovery 2) Absorption of underutilized rigs and overhead in international markets may create operating leverage with a turn in the market 3) Vertical integration creates opportunities to upgrade the fleet, answer demand growth, and innovate rig designs 4) HP may continue to benefit from the high grading of the US and international fleet, as a longer term thematic story 5) a safe balance sheet augments risk/reward.

Key Drivers

• Best North American Fleet Profile. HP’s fleet is nearly all AC rigs, comprising about 1/3 of the US AC rig fleet. In our view, the fleet may benefit from a cyclical recovery in 2016/2017 and continued structural move toward higher capability rigs in unconventional plays in the US market. Well positioned across North American Plays and key E&Ps across its high end fleet, HP’s operations remain supported by sticky business and longer term contracts, which may offer security against competition in the market and ability to extend term on contracts. Given scale and fleet quality, HP may also benefit from cyclical consolidation amongst suppliers, demonstrated in the addition of 10 new customers in 2015.

• Potential International Operating Leverage & Growth Opportunities. International operations carry cyclically depressed margins, as HP carries the overhead of 13 idle rigs in three countries, which have only one rig operating (Columbia, Ecuador, Bahrain). A turn in the cycle, which brings these rigs back to work, may create significant operating leverage. The international market lags the land rig replacement cycle, which may create growth opportunities for HP.

• Advantage of Vertical Integration. Vertically integrated, HP has its own facility to build rigs, which can produce 1 rig/month. The vertical integration enhances the company’s ability to respond to the global rig replacement cycle, also innovate FlexRig designs. In the down cycle, the capacity may allow HP to upgrade rigs to padd capable status, 7,500 PSI mud pumps, or greater hook load capacities to prepare for a turn in the market.

Balance Sheet /Cash Flow Strength

HP’s balance sheet is over capitalized, given a negative net debt. The company is investment grade, with a $40 million maturity by mid 2016 another $500 million in 2025. Given free cash flow throughout our forecast, we are not overly concerned about the balance sheet or the dividend.

Agency Rating Inv. Grade Last Action Date

S&P BBB+ YES None Mar 15

Fitch -- -- -- --

50

79

212

8 36

12

72

1-

50

100

150

200

250

AC FlexRig5AC FlexRig4AC FlexRig3SCR Rigs

U.S. Land Rigs

Total Working

U.S. Land, 121, 85%

U.S. Offshore, 4, 3%

Argentina, 11, 8%

Bahrain, 1, 1%Colombia, 2, 1%Equador, 1, 1%U.A.E., 2, 1%

Int'l, 17, 12%

Working Rigs

U.S. Land, 349, 88%U.S. Offshore, 9, 2%

Int'l, 40, 10%

Total Rigs

Sources: FactSet, HP, DrillingInfo, IHS Petrodata December 15, 2015 185

Helmerich & Payne (HP) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

US Land 2,785.4 3,100.0 2,388.0 1,447.1 2,079.8 868.3 646.2 494.6 379.0 344.2 337.2 362.2 403.4 453.4 493.5 548.8 584.1

Offshore 221.9 250.8 241.0 77.4 92.5 69.5 62.6 55.7 53.3 19.4 19.1 19.1 19.7 21.1 22.1 23.8 25.5

International land 366.8 355.5 386.7 274.2 386.1 92.9 98.2 106.2 89.4 72.6 67.3 62.8 71.5 80.4 87.5 101.6 116.6

Other 13.5 13.4 14.2 12.2 12.2 4.2 3.7 3.2 3.1 3.1 3.1 3.1 3.1 3.1 3.1 3.1 3.1

Total Revenues 3,387.6 3,719.7 3,029.9 1,810.9 2,570.6 1,034.8 810.7 659.7 524.7 439.2 426.7 447.2 497.7 557.9 606.2 677.2 729.3

Direct operating costs (1,852.8) (1,991.4) (1,783.2) (1,099.5) (1,506.4) (554.2) (461.0) (444.0) (323.9) (269.7) (261.2) (270.1) (298.5) (331.6) (356.7) (395.5) (422.6)

SG&A (126.3) (135.1) (134.9) (135.8) (186.1) (32.9) (34.9) (29.4) (37.7) (32.9) (32.0) (33.5) (37.3) (41.3) (44.3) (48.8) (51.8)

R&D (15.2) (15.9) (16.1) (14.4) (18.0) (4.2) (4.9) (3.3) (3.8) (4.0) (3.8) (3.1) (3.5) (3.9) (4.2) (4.7) (5.1)


Other (7.6) 1.1 0.2 - - - - 1.8 (1.6) - - - - - - - -

EBIT 930.2 1,054.8 518.8 (20.4) 294.4 305.9 160.3 40.5 12.2 (16.6) (16.0) (3.6) 15.7 39.3 59.6 87.1 108.5

Interest & dividend income 1.7 1.6 5.8 5.6 4.6 0.3 2.5 1.6 1.4 1.4 1.4 1.4 1.4 1.3 1.2 1.1 1.0


Other, net 19.4 2.6 (2.6) (4.0) (4.0) 0.3 0.1 (1.9) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0) (1.0)

EBT 945.1 1,054.4 507.0 (44.0) 269.8 305.9 160.4 33.9 6.8 (22.5) (21.8) (9.4) 9.8 33.3 53.5 80.9 102.2

Income Taxes (333.6) (372.9) (182.8) 15.8 (97.1) (121.2) (55.4) (4.1) (2.2) 8.1 7.9 3.4 (3.5) (12.0) (19.3) (29.1) (36.8)

Net Income (Operating) 611.5 681.5 324.2 (28.2) 172.7 184.8 105.0 29.8 4.6 (14.4) (14.0) (6.0) 6.3 21.3 34.2 51.8 65.4

Discontinued Operations 15.2 (0.0) (0.0) - - (0.0) 0.0 (0.0) (0.0) - - - - - - - -

Extraordinaries (after-tax) 110.0 27.3 98.0 37.1 6.4 18.3 44.5 61.1 (25.9) 8.3 9.6 9.6 9.6 6.4 - - -

Net Income (GAAP) 736.6 708.7 422.2 9.0 179.1 203.0 149.5 90.9 (21.2) (6.1) (4.4) 3.6 15.9 27.7 34.2 51.8 65.4

EPS (Operating) 5.67 6.25 2.99 (0.26) 1.60 1.70 0.97 0.27 0.04 (0.13) (0.13) (0.06) 0.06 0.20 0.32 0.48 0.61

EPS (GAAP) 6.84 6.50 3.90 0.08 1.66 1.87 1.38 0.84 (0.20) (0.06) (0.04) 0.03 0.15 0.26 0.32 0.48 0.61




EBITDA 1,393.4 1,577.2 1,095.8 561.2 860.1 443.5 310.0 183.0 159.3 132.6 129.7 140.5 158.4 181.1 201.0 228.2 249.8



Cash From Operations (CFO) 997.2 1,118.5 1,418.7 602.9 628.2 389.7 422.9 335.0 271.2 185.3 147.3 136.9 133.4 139.4 151.2 157.2 180.4

Capital Expenditures (809.1) (952.9) (1,133.5) (362.2) (514.1) (369.0) (394.3) (208.5) (161.6) (87.8) (85.3) (89.4) (99.5) (111.6) (121.2) (135.4) (145.9)


Acquisitions/Divestures/Investments 260.2 80.0 (23.1) - - 7.1 15.2 (4.5) (40.9) - - - - - - - -

Cash From Financing (CFF) (93.1) (379.4) 88.5 (296.3) (296.3) (133.5) 417.3 (64.5) (130.8) (74.1) (74.1) (74.1) (74.1) (74.1) (74.1) (74.1) (74.1)

Other 92.6 46.8 6.4 - - (3.6) 6.5 (5.6) 9.2 - - - - - - - -

Increase (Decrease) in Cash 447.9 (87.0) 357.1 (55.6) (182.2) (109.3) 467.5 51.8 (52.9) 23.3 (12.1) (26.6) (40.2) (46.3) (44.1) (52.3) (39.5)


Total Capital 4,638.7 4,971.0 5,429.1 5,141.7 5,024.5 4,962.2 5,574.5 5,593.1 5,429.1 5,348.9 5,270.4 5,199.9 5,141.7 5,095.3 5,055.5 5,033.2 5,024.5

Total Debt 195.0 80.0 531.6 531.6 531.6 41.0 572.1 571.5 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6 531.6

Net Debt (252.9) (280.9) (186.4) (130.8) 51.3 (210.6) (147.0) (199.4) (186.4) (209.7) (197.6) (171.0) (130.8) (84.5) (40.5) 11.8 51.3


Net Debt/Capital -5.5% -5.7% -3.4% -2.5% 1.0% -4.2% -2.6% -3.6% -3.4% -3.9% -3.7% -3.3% -2.5% -1.7% -0.8% 0.2% 1.0%


BVPS 41.23 44.85 45.20 42.79 41.70 45.21 46.16 46.29 45.46 44.71 43.98 43.33 42.79 42.36 41.99 41.78 41.70

TBVPS 41.23 44.85 45.20 42.79 41.70 45.21 46.16 46.29 45.46 44.71 43.98 43.33 42.79 42.36 41.99 41.78 41.70

December 15, 2015 186

Helmerich & Payne (HP) Valuation PRICE TARGET SCENARIOS



3.8% 26.4X $11,812 $110 114% Net Income - 736.6 708.7 422.2 9.0 179.1 366.2 534.9 762.0

5.8% 17.3X $10,788 $101 97% Depreciation & Amortization - 455.6 523.5 577.2 581.6 565.7 570.5 581.3 590.3


9.8% 10.2X $9,050 $84 64% Deferred Taxes - 29.6 27.1 146.9 - - - - -


13.8% 7.3X $7,647 $71 38% Operating Cash Flow (before working cap.) - 1,221.8 1,259.4 1,146.2 590.6 744.8 936.7 1,116.2 1,352.3

15.8% 6.3X $7,048 $66 28% Net Cash from Investing Activities - (548.8) (872.9) (1,156.6) (362.2) (514.1) (651.0) (670.4) (694.4)


19.8% 5.1X $6,015 $56 9% Capitalized G&A - - - - - - - - -

21.8% 4.6X $5,570 $52 1% Less: Net Capital Expenditures (before Cap Int) - 548.8 872.9 1,156.6 362.2 514.1 651.0 670.4 694.4

Working Capital Change - 25.5 (51.4) 39.1 12.3 (116.5) (65.0) (72.7) (85.1)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred - - (115.0) 451.7 - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations - 647.5 552.8 (501.1) 216.1 347.2 350.7 518.5 743.0









WACC 11.8% Subtract: Dividends for Explict Forecast (1,481.4)






December 15, 2015 187











December 15, 2015 188

Nabors Industries, Buy, $13PT, Attractive Transformation Story Investment Thesis

We are initiating coverage of NBR with a Buy rating and $13 price target. NBR continues to transform, with the exit of non-core business, high grading of its fleet, and streamlining of its overhead. With minimal financial risk, positive free cash flow, NBR offers and attractive play on recovery of the cycle. We like NBR’s international exposure relative to other land drillers, given greater earnings stability, a need for rig upgrades in international markets, and better economics. In our view, consensus 2017 EPS remain too low, and upward revisions may prove a positive catalyst for the shares.

Key Drivers

• US Rig Count Recovery. The precipitous decline in US land drilling activity has idled many of NBR’s rigs, with legacy rigs hit hardest. Although utilization numbers may continue to decline, we see a recovery in North American activity in 2H16 as a catalyst for the shares. Combined with corporate cost savings (54% staffing reduction), procurement savings ($22 million goal), and the introduction of a broader, more differentiated service offering, NBR may benefit from operating leverage in the recovery.

• Structural Growth From International Exposure. NBR has 50% of its rigs in international markets, which have higher margins and an increasing structural demand for higher spec. rigs to replace an aging, lower spec. fleet. The business may suffer with a decline in international rig counts in 2016, but continues to prove more resilient, given a greater mix of longer term contracts tied to larger scale, longer lead time projects. We favor NBR’s exposure to the Middle East, where OPEC’s (Saudi’s) push for market share gains may offset weakness in other regions.

• Rig Services Wild Card. The Ryan (directional drilling) and Canrig (top drives) businesses may prove a wild card, as they allow NBR to offer additional services, capture more margin through vertical integration, and help in the create of new rig designs with more automation and downhole responsiveness. The allows NBR to differentiate, but also jump ahead on the technology curve.


NBR’s balance sheet is not a concern. It recently secured a new $325 million term loan to repay its upcoming $350 million September 2016 maturity. The only debt covenant lies with its $2.1 billion revolver (available), a 60% net debt to capital limit, which NBR meets comfortably.


S&P BBB- YES None Nov 2015

Fitch BBB YES None Nov 2015

U.S. Land, 69, 33%


Canada, 17, 8%

Africa, 11, 5%

Lat. America, 42, 20%

Asia Pacific, 12, 6%

Middle East, 53, 26%

Europe, 1, 1%

I'nat, 119, 58%

Working Rigs

U.S. Land, 278, 54%


Canada, 58, 11%

I'nat, 168, 32%

Total Rigs

180

97

1

62

7 -0

20

40

60

80

100

120

140

160

180

AC SCR Mech

U.S. Land RigsTotal Working

Sources: FactSet, Nabors.com

December 15, 2015 189

Nabors Industries (NBR) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

US Drilling 1,914.8 2,160.0 1,219.0 910.2 1,542.2 453.8 321.2 259.9 184.1 181.4 204.8 242.7 281.2 316.9 363.9 409.2 452.2

Canada Drilling 361.7 335.2 137.0 82.1 120.5 57.8 21.4 29.9 27.9 20.0 10.3 23.0 28.9 27.1 18.8 33.7 40.9

International Drilling 1,464.3 1,623.1 1,901.3 1,763.5 1,934.2 445.4 458.2 516.2 481.5 453.3 442.7 436.9 430.7 443.3 470.6 498.6 521.7

Rig Services 595.4 687.3 388.0 252.1 333.4 144.1 100.6 73.5 69.8 66.4 63.0 59.9 62.9 69.2 76.1 87.5 100.6

Competiona Services 4,931.6 5,492.9 4,033.5 3,260.1 4,263.6 208.1 - - - - - - - - - - -

Production Services 9,267.7 10,298.4 7,679.0 6,268.0 8,193.8 158.5 - - - - - - - - - - -

Other (Eliminations) (192.0) (259.6) (193.1) (161.6) (211.2) (46.6) (38.4) (67.1) (41.0) (38.7) (38.7) (41.0) (43.2) (46.0) (49.9) (55.3) (59.9)

Total Revenues 18,343.4 20,337.3 15,164.8 12,374.3 16,176.3 1,421.2 863.0 812.5 722.3 682.3 682.1 721.4 760.5 810.4 879.4 973.7 1,055.4

US Drilling 755.7 835.7 479.3 306.4 604.4 187.7 136.5 94.5 60.5 59.1 67.7 81.8 97.9 115.3 138.1 163.0 188.0

Canada Drilling 119.0 108.5 35.5 10.5 26.1 18.5 3.7 7.5 5.8 3.0 0.1 2.9 4.5 4.7 2.8 7.8 10.8

International Drilling 524.5 610.2 729.0 582.9 660.2 201.0 177.0 186.5 164.5 152.1 146.5 142.7 141.6 147.6 159.3 171.5 181.8

Rig Services 43.9 81.3 22.8 (11.2) 6.6 21.6 6.3 (2.5) (2.7) (2.9) (3.1) (3.2) (2.1) (0.9) 0.5 2.3 4.7

CompletionServices 161.0 94.8 (27.8) - - (27.8) - - - - - - - - - - -

Production Services 205.6 207.9 23.0 - - 23.0 - - - - - - - - - - -

D&A (1,094.7) (1,145.1) (979.5) (911.8) (848.9) (281.0) (218.2) (240.1) (240.2) (235.1) (230.1) (225.5) (221.2) (217.2) (213.6) (210.4) (207.7)

Other (149.0) (195.3) (138.9) (92.5) (120.8) (41.7) (35.4) (38.4) (23.5) (22.2) (22.2) (23.4) (24.7) (26.3) (28.6) (31.6) (34.3)

EBIT 566.0 598.0 143.3 (115.7) 327.5 101.3 70.0 7.5 (35.5) (45.9) (41.0) (24.8) (4.0) 23.2 58.6 102.5 143.2

Interest (Expense) (223.4) (177.9) (179.2) (174.1) (174.1) (46.6) (44.5) (44.4) (43.7) (43.5) (43.5) (43.5) (43.5) (43.5) (43.5) (43.5) (43.5)

Financial Income (loss) 96.6 11.8 3.3 4.6 7.1 1.0 1.2 (0.0) 1.2 0.7 1.1 1.3 1.4 1.6 1.7 1.8 2.0

Other Financial Items 43.9 (16.9) (26.3) - - (15.3) (2.1) (8.8) - - - - - - - - -

Minority interest (7.2) (1.4) (75.4) (115.8) 4.0 0.1 0.0 (34.8) (40.7) (33.6) (32.7) (27.6) (21.8) (13.6) (1.7) 6.3 13.1

EBT 475.9 413.5 (134.2) (401.1) 164.5 40.4 24.6 (80.6) (118.7) (122.4) (116.2) (94.6) (67.9) (32.4) 15.0 67.1 114.8

Income Taxes (76.7) (78.2) 19.2 20.1 (31.2) 17.9 (66.4) 61.8 5.9 6.1 5.8 4.7 3.4 1.6 (0.8) (3.4) (28.7)

Net Income (Operating) 399.3 335.3 (115.0) (381.0) 133.3 58.3 (41.8) (18.8) (112.8) (116.3) (110.4) (89.9) (64.5) (30.8) 14.3 63.8 86.1

Discontinued Operations (17.3) 0.0 (41.1) - - (0.8) 5.0 (45.3) - - - - - - - - -

Extraordinaries (after-tax) (242.0) (1,051.0) (165.7) - - 66.1 - (231.8) - - - - - - - - -

Net Income (GAAP) 140.0 (715.7) (321.8) (381.0) 133.3 123.6 (36.8) (295.8) (112.8) (116.3) (110.4) (89.9) (64.5) (30.8) 14.3 63.8 86.1

EPS (Operating) 1.35 1.14 (0.40) (1.32) 0.46 0.20 (0.15) (0.07) (0.40) (0.41) (0.38) (0.31) (0.22) (0.11) 0.05 0.22 0.29

EPS (GAAP) 0.47 (2.39) (1.11) (1.32) 0.46 0.42 (0.13) (1.02) (0.40) (0.41) (0.38) (0.31) (0.22) (0.11) 0.05 0.22 0.29

Dividend per Share - - 0.18 0.24 0.24 - 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06



EBITDA 1,660.7 1,743.1 1,122.8 796.1 1,176.4 382.3 288.2 247.6 204.7 189.1 189.1 200.7 217.2 240.3 272.2 313.0 351.0

Depreciation & Amortization 1,094.7 1,145.1 979.5 911.8 848.9 281.0 218.2 240.1 240.2 235.1 230.1 225.5 221.2 217.2 213.6 210.4 207.7


Cash From Operations (CFO) 1,782.9 1,783.6 950.9 633.6 812.9 315.0 202.4 87.6 345.9 170.4 152.5 151.9 158.8 171.1 190.0 218.5 233.3


Free Cash Flow (FCF) (38.4) (37.7) 49.2 292.1 366.7 (49.2) (0.1) (89.8) 188.2 88.5 70.7 65.4 67.5 73.9 84.4 101.6 106.7

Acquisitions/Divestures/Investments (52.8) 109.0 623.2 - - 704.8 (75.7) (5.9) - - - - - - - - -


Other (588.2) (224.2) (28.2) - - (19.8) 7.3 (15.8) - - - - - - - - -

Increase (Decrease) in Cash (277.1) - (78.7) 223.0 296.7 84.9 (149.3) (185.3) 171.1 71.3 53.5 48.1 50.2 56.5 67.0 84.1 89.1


Total Capital 9,263.7 9,263.7 8,119.2 7,669.1 7,732.5 8,784.3 8,689.7 8,249.1 8,119.2 7,985.7 7,858.2 7,751.0 7,669.1 7,620.9 7,617.7 7,664.0 7,732.5

Total Debt 4,355.0 4,355.0 3,746.8 3,746.8 3,746.8 3,825.5 3,757.7 3,746.8 3,746.8 3,746.8 3,746.8 3,746.8 3,746.8 3,746.8 3,746.8 3,746.8 3,746.8

Net Debt 3,816.1 3,816.1 3,296.6 3,073.6 2,776.9 3,201.7 3,285.2 3,467.7 3,296.6 3,225.3 3,171.9 3,123.8 3,073.6 3,017.1 2,950.2 2,866.0 2,776.9


Net Debt/Capital 41.2% 41.2% 40.6% 40.1% 35.9% 36.4% 37.8% 42.0% 40.6% 40.4% 40.4% 40.3% 40.1% 39.6% 38.7% 37.4% 35.9%


BVPS 16.58 16.64 15.32 13.64 13.67 17.33 17.24 15.85 15.34 14.82 14.32 13.90 13.57 13.35 13.30 13.41 13.60

TBVPS 15.99 16.05 14.80 13.12 13.15 17.05 16.75 15.32 14.81 14.29 13.80 13.38 13.05 12.84 12.78 12.90 13.09

December 15, 2015 190

Nabors Industries (NBR) Valuation PRICE TARGET SCENARIOS



7.6% 13.2X $5,163 $18 107% Net Income 164.0 140.0 (715.7) (321.8) (381.0) 133.3 484.8 549.3 398.1

9.6% 10.4X $4,780 $17 96% Depreciation & Amortization 1,055.8 1,094.7 1,145.1 979.5 911.8 848.9 807.5 785.1 783.8


13.6% 7.4X $4,120 $14 61% Deferred Taxes 145.1 (240.2) (240.2) (100.8) - - - - -


17.6% 5.7X $3,575 $13 50% Operating Cash Flow (before working cap.) 1,364.9 994.5 189.2 557.0 530.8 982.2 1,292.3 1,334.5 1,181.9

19.6% 5.1X $3,339 $12 38% Net Cash from Investing Activities (1,339.2) (1,874.1) (1,712.3) (278.6) (341.6) (446.3) (540.1) (693.4) (782.0)


23.6% 4.2X $2,925 $10 15% Capitalized G&A - - - - - - - - -

25.6% 3.9X $2,744 $10 15% Less: Net Capital Expenditures (before Cap Int) 1,339.2 1,874.1 1,712.3 278.6 341.6 446.3 540.1 693.4 782.0

Working Capital Change (61.1) 174.4 - (25.2) 102.8 (169.3) (160.3) (83.2) 11.2

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred (246.3) 431.2 431.8 (609.4) - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 333.1 (1,485.2) (1,955.0) 912.9 86.4 705.2 912.5 724.3 388.7















December 15, 2015 191











December 15, 2015 192

Paterson-UTI: Buy, $23PT, North American Land Rig Leverage Investment Thesis

We are initiating coverage of PTEN with an Buy rating and $23 price target. The bull case for PTEN is a capacity absorption story levered to the recovery of the North American land market. We favor PTEN’s availability of premium rigs, which may go to work first, into our forecast of 2H/16 activity recovery. Given a lean organization that has scaled costs proportionally with rigs working, the company does not have a “transformation” theme within its thesis. PTEN does have pressure pumping exposure, which compounds its cyclical exposure to a recovery of US land activity. With a straightforward structure and healthy balance sheet, we are buyers of PTEN for concentrated exposure to a North American land drilling recovery.

Key Drivers

• Fleet Well Positioned for US Rig Count Recovery. Of its 220 land rig fleet, 159 are premium APEX rigs, of which the majority (126) are the most desired 1,500HP AC rigs. As we forecast North American upstream activity to increase with commodity prices in 2H/16, PTEN may be well positioned to increase its working rig count within unconventional plays. In our view, better capacity absorption and pricing power may prove consensus estimates too conservative for 2017.

• Pressure Pumping. Similar to the land drilling segment, the pressure pumping business remains a utilization story. As activity increases in 2016, with a recovery in total horsepower balances in the market, PTEN’s economics may improve in terms of the number of total jobs. We forecast that a recovery in margins may lag a recovery in activity, but may contribute to the bounce of the pressure pumping segment in 2017.


We forecast PTEN may remain FCF positive, with CAPEX dropping to maintenance levels (~$200 million). The company’s term loans have limited debt covenants, 45% debt to capital, and the $500 million revolver has a 50% debt to capital covenant. We do not see PTEN’s balance sheet approaching these levels.


S&P NR -- -- --

Fitch NR -- -- --

Sources: FactSet, Patterson UTI, DrillingInfo

4

61

132

121 11

67

3-

20

40

60

80

100

120

140

500 - 999hp 1,000 - 1,499hp 1,500 - 1,999hp 2,000hp +

U.S. Land Rigs by Horsepower Total Working

AC, 63, 77%SCR, 16, 19%

Mechanical, 3, 4%

Working US Land Rigs

AC, 117, 56%SCR, 77, 37%

Mechanical, 15, 7%

3Q15 US Land Rig Fleet

December 15, 2015 193

Paterson-UTI (PTEN) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Drilling 1,717.4 1,838.8 1,165.0 797.7 1,148.8 401.5 288.3 261.8 213.4 187.0 185.3 204.8 220.5 245.3 278.9 302.0 322.7

Pressure Pumping 979.2 1,293.3 726.2 578.0 923.2 249.7 176.6 154.4 145.4 137.7 130.0 146.6 163.7 191.7 219.6 247.5 264.4

Other (Oil & Gas) 57.3 50.2 25.7 22.6 24.5 6.5 7.8 6.0 5.4 5.5 5.6 5.7 5.8 5.9 6.1 6.2 6.3

Total Revenues 2,753.8 3,182.3 1,917.0 1,398.3 2,096.5 657.7 472.8 422.3 364.3 330.2 320.9 357.1 390.0 442.9 504.5 555.7 593.3

Drilling 748.7 772.2 550.1 354.2 550.6 188.7 134.5 125.1 101.9 82.8 80.4 90.8 100.3 113.9 132.2 145.9 158.6

Pressure Pumping 234.9 257.0 95.5 37.2 96.7 37.0 33.9 15.8 8.8 7.9 8.2 9.5 11.6 14.0 20.3 27.6 34.8

Other (Oil & Gas) 44.3 37.1 11.7 (0.5) 2.4 3.7 5.0 3.5 (0.5) (0.4) (0.2) (0.0) 0.1 0.3 0.5 0.7 0.9

SG&A (73.9) (80.1) (89.1) (73.0) (71.6) (32.8) (19.2) (18.6) (18.5) (18.4) (18.3) (18.2) (18.1) (18.0) (17.9) (17.9) (17.8)


Other 3.4 15.8 8.6 5.4 5.4 2.9 3.0 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4

EBIT 360.0 283.1 (132.9) (379.7) (53.8) 24.1 (24.8) (49.9) (82.3) (102.8) (105.2) (94.0) (77.7) (55.3) (25.0) 1.0 25.5

Interest Income 0.9 1.0 1.2 2.2 5.3 0.3 0.3 0.3 0.3 0.3 0.5 0.6 0.8 1.0 1.2 1.4 1.7


Other, net 1.7 16.8 0.0 0.1 0.1 - - 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

EBT 334.2 271.1 (160.1) (383.1) (54.1) 15.8 (33.7) (58.9) (83.4) (103.9) (106.1) (94.8) (78.3) (55.7) (25.2) 1.0 25.8

Income Taxes (121.7) (87.9) 56.8 134.1 18.9 (6.7) 14.7 19.6 29.2 36.4 37.2 33.2 27.4 19.5 8.8 (0.4) (9.0)

Net Income (Operating) 212.6 183.2 (103.4) (249.0) (35.2) 9.1 (19.0) (39.3) (54.2) (67.5) (69.0) (61.6) (50.9) (36.2) (16.4) 0.7 16.8

Asset Impairments - - (103.5) - - - - (103.5) - - - - - - - - -

Goodwill Impairments - (73.4) (92.2) - - (9.0) - (83.2) - - - - - - - - -

Extraordinaries (after-tax) (24.6) - - - - - - - - - - - - - - - -

Net Income (GAAP) 188.0 109.8 (299.0) (249.0) (35.2) 0.1 (19.0) (226.0) (54.2) (67.5) (69.0) (61.6) (50.9) (36.2) (16.4) 0.7 16.8

EPS (Operating) 1.46 1.26 (0.71) (1.71) (0.24) 0.06 (0.13) (0.27) (0.37) (0.46) (0.47) (0.42) (0.35) (0.25) (0.11) 0.00 0.12

EPS (GAAP) 1.29 0.75 (2.05) (1.71) (0.24) 0.00 (0.13) (1.55) (0.37) (0.46) (0.47) (0.42) (0.35) (0.25) (0.11) 0.00 0.12




EBITDA 954.1 986.1 568.2 317.9 578.1 196.6 154.2 125.8 91.6 71.9 70.1 82.0 93.9 110.2 135.1 156.3 176.5



Cash From Operations (CFO) 888.9 1,087.7 941.0 427.7 610.8 405.0 235.7 165.4 134.9 101.1 96.5 111.7 118.4 132.6 147.0 160.5 170.7

Capital Expenditures (662.5) (1,052.3) (732.9) (209.8) (314.5) (241.5) (222.2) (144.6) (124.7) (49.5) (48.1) (53.6) (58.5) (66.4) (75.7) (83.4) (89.0)


Acquisitions/Divestures/Investments 10.4 (143.1) 21.7 - - 5.8 4.9 11.0 - - - - - - - - -

Cash From Financing (CFF) (108.9) 221.2 (189.2) (58.3) (58.3) (122.1) (30.3) (22.3) (14.6) (14.6) (14.6) (14.6) (14.6) (14.6) (14.6) (14.6) (14.6)

Other 10.9 (320.0) (11.5) - (63.8) (3.4) 1.4 (9.5) - - - - - - - - -

Increase (Decrease) in Cash 138.8 (206.5) 29.1 159.7 174.2 43.9 (10.4) (0.0) (4.4) 37.0 33.8 43.5 45.3 51.6 56.8 62.6 67.1


Total Capital 3,448.5 3,891.3 3,427.3 3,120.0 3,026.6 3,778.5 3,740.5 3,496.1 3,427.3 3,345.2 3,261.7 3,185.5 3,120.0 3,069.3 3,038.3 3,024.4 3,026.6

Total Debt 692.5 985.5 865.0 865.0 865.0 880.0 872.5 865.0 865.0 865.0 865.0 865.0 865.0 865.0 865.0 865.0 865.0

Net Debt 443.0 942.5 792.9 633.2 395.2 793.1 796.0 788.5 792.9 755.8 722.0 678.5 633.2 581.6 524.8 462.3 395.2


Net Debt/Capital 12.8% 24.2% 23.1% 20.3% 13.1% 21.0% 21.3% 22.6% 23.1% 22.6% 22.1% 21.3% 20.3% 18.9% 17.3% 15.3% 13.1%


BVPS 18.92 19.91 17.58 15.48 14.84 19.89 19.65 18.06 17.59 17.03 16.45 15.93 15.48 15.13 14.92 14.82 14.84

TBVPS 17.77 18.40 16.94 14.84 14.20 18.38 18.15 17.42 16.95 16.39 15.81 15.29 14.84 14.49 14.28 14.18 14.20

December 15, 2015 194

Paterson-UTI (PTEN) Valuation PRICE TARGET SCENARIOS



4.9% 20.3X $4,592 $32 116% Net Income 299.4 188.0 109.8 (299.0) (249.0) (35.2) 132.7 163.6 138.4



10.9% 9.2X $3,551 $25 69% Deferred Taxes 160.4 50.6 43.7 (117.5) (33.5) (4.7) 17.9 22.0 18.6



16.9% 5.9X $2,793 $20 35% Net Cash from Investing Activities (908.0) (652.1) (1,195.4) (711.2) (209.8) (314.5) (667.2) (928.4) (1,144.2)


20.9% 4.8X $2,402 $17 15% Capitalized G&A - - - - - - - - -

22.9% 4.4X $2,232 $16 8% Less: Net Capital Expenditures (before Cap Int) 908.0 652.1 1,195.4 711.2 209.8 314.5 667.2 928.4 1,144.2

Working Capital Change 96.6 33.5 (95.3) 248.1 7.2 13.3 11.0 0.1 0.1

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 188.7 (6.3) 293.0 (122.5) - - - - 41.6

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (206.8) 156.7 (520.9) (388.6) 203.5 269.7 89.2 (103.6) (351.3)











Levered Free Cash Flow (2) 203.5 269.7 89.2 (103.6) 5,291.8




December 15, 2015 195











December 15, 2015 196

Offshore Contract Drillers

December 15, 2015 197

Gross Fleet Value Contract Cov.

Segment $/Share % of Ttl 2015 2016 2016 2017

6G 26 74% 12,770 13,279 70% 44%

5G 1 3% 545 629 -- --

4G 0 0% 30 (22) 58% --

3G - -- - - -- --

HDHE 1 3% 553 449 100% 42%

Prem 7 20% 3,472 3,643 54% 32%

Std - -- - - -- --

Low - -- - - -- --

Other - -- - - 67% 67%

Gross GFV, Current 35 100% 17,370 17,977

Other Assets 3,737 2,824

Liabilities & Dividends (18,368) (16,179)

NAV 2,739 4,623

Shares Outstanding 493 496

NAV/Share 5.55 9.31

Last Price 4.16 4.16

P/NAV 75% 45%

4.6X 4.5X4.9X

5.4X5.0X 4.8X

6.6X7.0X

3.2X

55%57%

60%57%

48% 48%

47%45%

37%

0%

10%

20%

30%

40%

50%

60%

70%

0.0X

1.0X

2.0X

3.0X

4.0X

5.0X

6.0X

7.0X

8.0X

2010 2011 2012 2013 2014 2015 2016 2017 2018

To

tal D

eb

t / A

sse

ts

To

tal D

eb

t / E

BIT

DA

Total Debt / EBITDA Total Debt / Assets

Seadrill Ltd: Reduce, $3.50PT, Caught By Cyclical Downturn Investment Thesis

We are initiating coverage of SDRL with a Reduce rating and $3.50 price target. The severe downturn in the offshore rig market choked SDRL’s aggressive growth, leverage, and payout strategy, which had propelled the company during the structural expansion of the deepwater market and offshore rig upgrade cycle. We cannot see a positive risk/reward in SDRL shares, given high potential for the SDRL to breach leverage covenants on its credit facilities without near term contract announcements. With debt trading at mid-20’s% yields, we see further risks and a prohibitive cost of capital to refinance ~$1.7 billion in debt maturities, credit facility amortization payments, and meet our estimated ~$1.5 billion funding gap through 2017 for newbuilds, potentially alleviated by negotiated delayed deliveries. Heavily discounting these risks (~30% WACC), we see shares range-bound with greater downside risk. A historically good banking client, SDRL (Fredriksen entities) may coax the banks into carrying the company through the downturn, so we expect a light at the end of the tunnel, but believe the outlook may get darker first. We remain watchful, as a quality fleet with leverage to cyclical recovery may offer tremendous upside ($30+/share), if the story sheds risk.


Two facilities and one unsecured bond maturities (total ~$750 million), with a balance of facility amortization payments comprise ~$1.7 billion in debt due within 12 months. We see leverage ratios breaching recently amended credit facility covenants (5-6x Net Debt/EBITDA) in 2H16/1H17, without new rig contracts, which look less likely. With SDRL’s debt and MLP (SDPL) trading at mid-20%+ yields, we see shares under pressure unless banks loosen debt terms and SDRL negotiates newbuild delays. Given Fredriksen’s history with restructuring at Frontline (FRO), the possibility is not off the table.

Near Term Availability/Catalysts

• Idle rigs (6 semis, 1 drillship, 4 jackups) may weigh on cash flow, with contracts a positive catalyst. As rigs roll off contract and potential newbuilds arrive without contracts, we see 12 floaters and 11 jackups being idled/stacked time before the end of 2017.

• Announcements of delayed newbuild (8 jackups, 5 floaters) deliveries may prove a positive catalyst.

• We see risks in SDRL’s exposure to PBR (5 floaters contracted, 15%-20% 4Q/15 revenue, SeaBras), but have not altered contract terms in our forecast.

Rig Retirements Forecast

• We do not forecast SDRL rig retirements, given a young average fleet age across asset classes.


S&P NR

Moody’s NR

December 15, 2015 198

Seadrill Ltd (SDRL) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Floaters 3,410.0 3,282.0 2,848.8 2,173.9 2,386.0 832.0 786.0 647.0 583.8 546.3 562.0 544.2 521.5 460.5 505.8 632.1 787.7

Jackups 1,132.0 1,468.0 1,265.4 818.9 843.9 377.0 328.0 306.0 254.4 217.9 212.4 197.5 191.0 174.7 163.7 224.3 281.2

Reimbursables 278.0 53.0 81.0 112.0 112.0 25.0 - 28.0 28.0 28.0 28.0 28.0 28.0 28.0 28.0 28.0 28.0

Other revenues 462.0 194.0 102.0 420.0 420.0 10.0 (36.0) 23.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0 105.0

Total Revenues 5,282.0 4,997.0 4,297.1 3,524.8 3,762.0 1,244.0 1,078.0 1,004.0 971.1 897.2 907.4 874.7 845.5 768.2 802.5 989.4 1,201.9

Operating expenses (1,977.0) (1,938.0) (1,624.0) (1,438.7) (1,757.3) (446.0) (422.0) (374.0) (382.0) (342.7) (348.0) (373.4) (374.7) (355.9) (391.6) (469.2) (540.6)

Reimbursable expenses (257.0) (172.0) (96.7) (106.7) (106.7) (22.0) (19.0) (29.0) (26.7) (26.7) (26.7) (26.7) (26.7) (26.7) (26.7) (26.7) (26.7)

SG&A (300.0) (315.0) (234.4) (193.9) (206.9) (65.0) (61.0) (55.0) (53.4) (49.3) (49.9) (48.1) (46.5) (42.3) (44.1) (54.4) (66.1)

Depreciation (711.0) (693.0) (774.6) (804.9) (889.7) (198.0) (192.0) (192.0) (192.6) (194.7) (195.3) (202.1) (212.8) (214.9) (217.0) (228.5) (229.2)

EBIT 2,037.0 1,879.0 1,567.4 980.6 801.3 513.0 384.0 354.0 316.4 283.8 287.5 224.5 184.9 128.5 123.1 210.6 339.2

Interest Income 24.0 63.0 63.6 33.7 23.4 17.0 17.0 15.0 14.6 12.4 13.0 2.5 5.8 5.8 4.6 5.8 7.2


Results from associated companies (38.0) 89.0 155.7 112.4 110.9 32.0 115.0 (21.0) 29.7 28.1 28.0 28.2 28.1 27.6 27.7 27.8 27.8

Other financial items 214.0 (110.0) (155.0) - - (134.0) 52.0 (73.0) - - - - - - - - -

EBT 1,792.0 1,443.0 1,209.7 724.2 497.4 316.0 468.0 170.0 255.7 220.7 227.5 157.9 118.1 54.4 48.0 134.0 261.0

Income taxes (168.9) (19.0) (181.4) (108.6) (74.6) (58.0) (45.0) (40.0) (38.4) (33.1) (34.1) (23.7) (17.7) (8.2) (7.2) (20.1) (39.2)

Non-controlling Interest (133.0) (108.0) (115.1) (77.8) (59.2) (21.0) (44.0) (26.0) (24.1) (20.2) (24.8) (18.3) (14.5) (10.9) (10.3) (17.6) (20.4)

Net Income (Operating) 1,490.2 1,316.0 913.3 537.8 363.6 237.0 379.0 104.0 193.3 167.4 168.5 115.9 85.9 35.4 30.5 96.3 201.5

Asset Impairment - - (1,837.0) - - - - (1,837.0) - - - - - - - - -

Extraordinaries (after-tax) (145.0) 2,471.0 (167.0) - - - - (167.0) - - - - - - - - -

Net Income (GAAP) 2,740.0 3,979.0 (900.7) 537.8 363.6 427.0 379.0 (1,900.0) 193.3 167.4 168.5 115.9 85.9 35.4 30.5 96.3 201.5

EPS (Operating) 3.03 2.69 1.85 1.08 0.73 0.48 0.77 0.21 0.39 0.34 0.34 0.23 0.17 0.07 0.06 0.19 0.40

EPS (GAAP) 5.58 8.12 (1.83) 1.08 0.73 0.87 0.77 (3.85) 0.39 0.34 0.34 0.23 0.17 0.07 0.06 0.19 0.40

Dividend per Share 3.72 1.94 - - - - - - - - - - - - - - -



EBITDA 2,748.0 2,572.0 2,342.0 1,785.5 1,691.0 711.0 576.0 546.0 509.0 478.5 482.8 426.5 397.7 343.4 340.1 439.1 568.5



Cash From Operations (CFO) 1,719.5 1,530.8 1,849.3 1,545.8 1,474.8 492.0 407.0 591.0 359.3 405.9 419.9 370.7 349.2 289.1 286.6 385.8 513.3

Capital Expenditures (4,273.0) (2,873.0) (1,151.3) (2,845.8) (1,586.9) (567.0) (161.0) (114.0) (309.3) (92.4) (883.2) (1,378.2) (492.0) (243.2) (968.9) (76.6) (298.1)

Free Cash Flow (FCF) (2,553.5) (1,342.2) 698.1 (1,300.1) (112.1) (75.0) 246.0 477.0 50.1 313.5 (463.3) (1,007.5) (142.8) 45.9 (682.3) 309.2 215.2

Acquisitions/Divestures/Investments 1,065.0 3,163.0 941.0 - - 620.0 208.0 113.0 - - - - - - - - -

Cash From Financing (CFF) 1,245.0 (1,607.0) (1,425.6) 641.6 120.2 (473.0) (440.0) (240.0) (272.6) (255.6) (587.6) 1,342.1 142.8 (171.6) 808.0 (171.6) (344.6)

Other 669.5 (126.8) (86.0) - - - 1.0 (87.0) - - - - - - - - -

Increase (Decrease) in Cash 426.0 87.0 127.5 (658.5) 8.1 72.0 15.0 263.0 (222.5) 57.9 (1,050.9) 334.5 - (125.8) 125.8 137.6 (129.5)


Total Capital 23,083.0 23,199.0 21,295.8 22,920.7 23,796.1 23,268.0 22,640.0 21,256.0 21,295.8 21,318.0 21,009.5 22,581.1 22,920.7 22,889.4 23,817.4 23,831.7 23,796.1

Total Debt 14,881.0 12,809.0 11,156.4 11,798.0 11,918.2 12,558.0 11,481.0 11,429.0 11,156.4 10,900.8 10,313.1 11,655.2 11,798.0 11,626.4 12,434.4 12,262.8 11,918.2

Net Debt 13,403.0 11,103.0 9,667.9 10,968.0 11,080.1 11,113.0 10,013.0 9,718.0 9,667.9 9,354.4 9,817.7 10,825.2 10,968.0 10,922.1 11,604.4 11,295.2 11,080.1


Net Debt/Capital 58.1% 47.9% 45.4% 47.9% 46.6% 47.8% 44.2% 45.7% 45.4% 43.9% 46.7% 47.9% 47.9% 47.7% 48.7% 47.4% 46.6%


BVPS 16.70 21.21 20.55 22.40 23.73 21.72 22.59 19.93 20.53 21.05 21.57 21.99 22.34 22.57 22.77 23.09 23.66

TBVPS 14.25 19.98 20.55 22.40 23.73 20.50 21.45 19.93 20.53 21.05 21.57 21.99 22.34 22.57 22.77 23.09 23.66

December 15, 2015 199

Seadrill Ltd (SDRL) Valuation PRICE TARGET SCENARIOS



22.1% 4.5X $2,474 $5.00 20% Net Income 1,186.8 2,740.0 3,979.0 (900.7) 537.8 363.6 1,537.3 1,845.1 1,722.2

24.1% 4.1X $2,263 $4.60 11% Depreciation & Amortization 614.0 711.0 693.0 774.6 804.9 889.7 947.6 976.5 1,008.1


28.1% 3.6X $1,890 $3.85 (7%) Deferred Taxes (17.0) 7.0 63.0 - - - - - (130.0)

30.1% 3.3X $1,724 $3.50 (16%) Translation Adjustment Other 204.2 (2,433.5) (2,627.2) 1,858.0 220.8 169.8 235.0 240.2 448.2

32.1% 3.1X $1,572 $3.20 (23%) Operating Cash Flow (before working cap.) 1,988.0 1,024.5 2,107.8 1,731.8 1,563.4 1,423.1 2,719.9 3,061.8 3,048.6

34.1% 2.9X $1,430 $2.90 (30%) Net Cash from Investing Activities (1,445.0) (3,208.0) 290.0 (210.3) (2,845.8) (1,586.9) (903.0) (740.9) (1,015.0)

36.1% 2.8X $1,299 $2.65 (36%) Capitalized Interest - - - - - - - - -

38.1% 2.6X $1,178 $2.40 (42%) Capitalized G&A - - - - - - - - -

40.1% 2.5X $1,066 $2.15 (48%) Less: Net Capital Expenditures (before Cap Int) 1,445.0 3,208.0 (290.0) 210.3 2,845.8 1,586.9 903.0 740.9 1,015.0

Working Capital Change (398.0) 695.0 (577.0) 117.5 (17.7) 51.6 59.8 (12.5) (2.5)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 1,348.0 2,562.0 (43.0) (1,366.6) 641.6 120.2 (1,701.5) (2,258.5) (609.5)

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (407.0) (5,440.5) 3,017.8 2,770.6 (1,906.3) (335.6) 3,458.6 4,591.8 2,645.5


Debt Risk Spread 2,500 EBITDA 3,282.6








Terminal Multiple: 3.3X Terminal Value (1) (1,844.1)

Levered Free Cash Flow (2) (1,906.3) (335.6) 3,458.6 4,591.8 801.4




December 15, 2015 200











December 15, 2015 201



6G 32 67% 11,770 12,190 70% 57%

5G 8 17% 3,060 3,242 19% 6%

4G 2 3% 570 457 56% 61%

3G 0 1% 174 45 16% --

HDHE 4 8% 1,453 1,561 42% 7%

Prem 2 4% 627 639 81% 58%

Std - -- - - -- --

Low - -- - - -- --

Other - -- - - -- --




NAV 5,955 6,895


NAV/Share 16 19

Last Price 13 13

P/NAV 77% 67%

2.6X

4.7X

3.5X3.1X

2.6X2.9X

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4.3X

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39%36%

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34%

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Transocean: Buy, $19PT, Transformation- Fleet & Performance Investment Thesis

We are initiating coverage of RIG with a Buy rating and $19 price target. In the spotlight as largest offshore driller by market capitalization, RIG shares remain volatile, but we believe the market does not appreciate the transformation story underway at RIG. Post retirement of 22 rigs, roughly 2/3 of the company’s value is derived from 6G assets. The percentage of younger, higher spec assets may grow with future rig retirements, which represent little value in our forecast. Outside of market forces and retirements, new management guided 5%-6% structural OPEX improvement in 2016, as RIG picks the low lying fruit of cost savings from bloated overhead and inefficient processes from a lack of integration and consolidation of previous mergers. Resilient cash flows and ample liquidity to pay down ~$1.7 billion in debt maturities through 2017, presents less risk than current debt ratings and widening debt/EBITDA ratios suggest. With a turn in the market, and the potential to acquire distressed assets in coming quarters, our heavily discounted $19 price target (~17% WACC) may prove conservative.


• RIG has $2.2 billion in cash, may remain close to FCF breakeven in 2016, and has $3Bn of capacity under its revolver that only requires a maximum 60% debt to tangible capitalization, which the company meets comfortably. After paying its 2015 maturity (~$900 million), RIG can pay down its near term maturities ($123 million September 2016, $995 million December 2016, $642 million October 2017) and newbuild payments without tapping the debt market. Although RIG’s debt rating sits below investment grade and leverage ratios may widen at trough earnings, we do not see acute balance sheet risk.


• RIG currently has a number of idle floaters that throw wild cards into estimates (1 UDW, 2 DW, 2 HE, and 2 MW). Prolonged idle time or faster than expected contracting of these rigs may change EPS.

• A lack of desire to assume legacy debt may prevent corporate M&A, but we see the opportunity for RIG to acquire individual or packages of distressed assets, which may prove a positive catalyst.


• The company has stated that there is the potential for the retirement of 10-15 additional rigs. It appears that management continues to review the fleet rig by rig, as new retirement announcements continue to bleed out in incremental fleet status reports. We see 17 more retirements, per our rig retirement analysis. In our view, rigs that require large incremental capital expenditures may be retired.


S&P BB+ NO Downgrade Mar 2015

Moody’s Ba2 NO Downgrade Oct 2015

December 15, 2015 202

Transocean (RIG) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Contract Drilling 9,070.0 8,952.0 6,732.8 4,390.1 4,295.1 2,000.0 1,777.0 1,569.0 1,386.8 1,292.7 1,067.5 1,045.9 984.1 996.4 1,050.9 1,065.3 1,182.5

Client Reimbursable Revenues 174.3 173.0 144.0 139.4 145.1 42.0 34.0 34.0 34.0 34.3 34.7 35.0 35.4 35.7 36.1 36.5 36.8

Drilling Management and Other 229.7 49.0 74.0 - - 1.0 73.0 - - - - - - - - - -

Contract Intangible Revenue 10.0 - - - - - - - - - - - - - - - -

Total Revenues 9,484.0 9,174.0 6,950.8 4,529.6 4,440.2 2,043.0 1,884.0 1,603.0 1,420.8 1,327.0 1,102.2 1,080.9 1,019.4 1,032.2 1,087.0 1,101.7 1,219.3

Contract Drilling & Other 3,645.0 4,065.0 3,245.3 1,665.3 1,805.6 959.0 910.0 723.0 653.3 561.5 383.3 380.5 340.0 405.2 434.9 447.6 517.8

General & Administrative (261.7) (230.0) (175.6) (166.1) (159.5) (46.0) (44.0) (43.0) (42.6) (42.1) (41.7) (41.3) (40.9) (40.5) (40.1) (39.7) (39.3)

Depreciation & Amortization (1,109.0) (1,139.0) (959.4) (763.2) (777.7) (291.0) (249.0) (210.0) (209.4) (190.3) (192.2) (191.9) (188.9) (187.3) (191.0) (193.3) (206.1)

EBIT 2,274.3 2,696.0 2,110.3 736.1 868.3 622.0 617.0 470.0 401.3 329.1 149.4 147.3 110.3 177.4 203.8 214.6 272.5

Interest Income 52.0 39.0 22.1 27.0 10.4 6.0 6.0 5.0 5.1 6.6 6.8 6.8 6.8 2.2 2.4 2.7 3.1


Other, Net (19.0) (12.0) (4.0) (84.0) (84.0) 43.0 (5.0) (21.0) (21.0) (21.0) (21.0) (21.0) (21.0) (21.0) (21.0) (21.0) (21.0)

EBT 1,722.8 2,240.0 1,689.9 280.2 424.7 555.0 498.0 345.0 291.9 224.1 35.3 24.1 (3.4) 64.6 92.0 104.0 164.1

Income Taxes (371.7) (420.0) (304.5) (64.5) (97.7) (143.0) (84.0) (25.0) (52.5) (51.6) (8.1) (5.5) 0.8 (14.9) (21.2) (23.9) (37.7)

Minority Interest (4.1) 1.0 (41.1) (43.1) (41.4) (14.0) (6.0) (9.0) (12.1) (10.7) (10.9) (11.2) (10.4) (9.6) (10.1) (10.7) (11.1)

Net Income (Operating) 1,347.0 1,821.0 1,344.2 172.7 285.6 398.0 408.0 311.0 227.2 161.9 16.4 7.4 (13.0) 40.2 60.7 69.4 115.3

Discontinued Operations 1.0 (20.0) 4.0 12.0 12.0 (2.0) - 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0

Asset Impairments (44.0) (2,621.0) (4.0) - - - - (4.0) - - - - - - - - -

Extraordinaries (after-tax) (45.8) (1,095.0) (939.0) - - (879.0) (66.0) 6.0 - - - - - - - - -

Net Income (GAAP) 1,258.2 (1,915.0) 405.2 184.7 297.6 (483.0) 342.0 316.0 230.2 164.9 19.4 10.4 (10.0) 43.2 63.7 72.4 118.3

EPS (Operating) 3.73 5.03 3.70 0.47 0.78 1.10 1.12 0.85 0.62 0.44 0.04 0.02 (0.04) 0.11 0.17 0.19 0.32

EPS (GAAP) 3.48 (5.29) 1.11 0.51 0.82 (1.33) 0.94 0.87 0.63 0.45 0.05 0.03 (0.03) 0.12 0.17 0.20 0.33

Dividend per Share 1.68 2.81 1.20 - - 0.75 0.15 0.15 0.15 - - - - - - - -



EBITDA 3,383.3 3,835.0 3,069.7 1,499.3 1,646.0 913.0 866.0 680.0 610.7 519.3 341.6 339.2 299.1 364.8 394.8 407.9 478.5

Depreciation & Amortization (1,109.0) (1,139.0) (959.4) (763.2) (777.7) (291.0) (249.0) (210.0) (209.4) (190.3) (192.2) (191.9) (188.9) (187.3) (191.0) (193.3) (206.1)


Cash From Operations (CFO) 1,782.7 2,246.0 3,283.3 1,060.0 1,046.9 540.0 1,311.0 648.0 784.3 367.8 277.3 213.5 201.4 217.3 244.1 272.2 313.3

Capital Expenditures (2,238.0) (2,165.0) (2,038.0) (1,424.6) (549.1) (201.0) (195.0) (940.0) (702.0) (250.3) (256.8) (196.4) (721.1) (112.4) (115.3) (116.1) (205.3)

Free Cash Flow (FCF) (455.3) 81.0 1,245.3 (364.6) 497.8 339.0 1,116.0 (292.0) 82.3 117.5 20.5 17.1 (519.8) 104.9 128.7 156.1 108.1

Acquisitions/Divestures/Investments 381.0 337.0 36.0 - - 9.0 24.0 3.0 - - - - - - - - -

Cash From Financing (CFF) (2,224.7) (1,557.0) (1,741.0) (995.0) (642.0) (335.0) (61.0) (1,291.0) (54.0) - - - (995.0) - - - (642.0)

Other 269.6 531.0 9.9 (103.1) (101.4) 34.0 8.0 45.0 (77.1) (25.7) (25.9) (26.2) (25.4) (24.6) (25.1) (25.7) (26.1)

Increase (Decrease) in Cash (2,029.4) (608.0) (449.8) (1,462.7) (245.6) 47.0 1,087.0 (1,535.0) (48.8) 91.8 (5.3) (9.1) (1,540.1) 80.3 103.6 130.5 (560.0)


Total Capital 27,230.0 23,763.0 22,584.2 21,713.9 21,309.4 23,221.0 23,355.0 22,473.0 22,584.2 22,734.1 22,738.4 22,733.8 21,713.9 21,742.0 21,790.7 21,848.1 21,309.4

Total Debt 10,539.0 10,092.0 8,753.0 7,758.0 7,116.0 10,020.0 10,015.0 8,753.0 8,753.0 8,753.0 8,753.0 8,753.0 7,758.0 7,758.0 7,758.0 7,758.0 7,116.0

Net Debt 7,296.0 7,457.0 6,567.8 7,035.6 6,639.1 7,338.0 6,246.0 6,519.0 6,567.8 6,476.1 6,481.4 6,490.4 7,035.6 6,955.3 6,851.6 6,721.2 6,639.1


Net Debt/Capital 26.8% 31.4% 29.1% 32.4% 31.2% 31.6% 26.7% 29.0% 29.1% 28.5% 28.5% 28.5% 32.4% 32.0% 31.4% 30.8% 31.2%


BVPS 46.16 37.79 38.05 38.34 38.99 36.37 36.75 37.69 38.00 38.41 38.42 38.41 38.34 38.42 38.55 38.71 38.99

TBVPS 37.90 37.79 38.05 38.34 38.99 36.37 36.75 37.69 38.00 38.41 38.42 38.41 38.34 38.42 38.55 38.71 38.99

December 15, 2015 203

Transocean (RIG) Valuation PRICE TARGET SCENARIOS



9.3% 10.8X $9,088 $25.00 97% Net Income (216.0) 1,258.2 (1,915.0) 405.2 184.7 297.6 1,175.6 1,429.0 1,233.1

11.3% 8.9X $8,412 $24.00 89% Depreciation & Amortization 1,258.0 1,109.0 1,139.0 959.4 763.2 777.7 888.3 960.9 1,010.5


15.3% 6.6X $7,246 $20.00 58% Deferred Taxes (133.0) (9.0) (142.0) (104.0) - - - - -

17.3% 5.8X $6,744 $19.00 50% Translation Adjustment Other - - - - - - - - -

19.3% 5.2X $6,287 $18.00 42% Operating Cash Flow (before working cap.) 909.0 2,358.2 (918.0) 1,260.6 947.8 1,075.3 2,063.9 2,389.9 2,243.6

21.3% 4.7X $5,871 $17.00 34% Net Cash from Investing Activities (429.0) (1,857.0) (1,915.0) (2,002.0) (1,424.6) (549.1) (1,337.2) (1,683.6) (1,195.2)


25.3% 4.0X $5,145 $15.00 18% Capitalized G&A - - - - - - - - -

27.3% 3.7X $4,827 $14.00 10% Less: Net Capital Expenditures (before Cap Int) 429.0 1,857.0 1,915.0 2,002.0 1,424.6 549.1 1,337.2 1,683.6 1,195.2

Working Capital Change (46.0) (718.0) (494.0) (3.4) 69.0 (69.8) (105.0) (28.6) (19.3)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred (1,049.0) (1,615.0) (539.0) (1,306.0) (995.0) (642.0) - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 1,575.0 2,834.2 (1,800.0) 568.0 449.2 1,238.0 831.8 735.0 1,067.6











Levered Free Cash Flow (2) 449.2 1,238.0 831.8 735.0 10,101.4




December 15, 2015 204











December 15, 2015 205



6G 23 47% 5,433 5,453 72% 44%

5G 9 18% 2,044 1,983 46% 30%

4G (0) -0% (12) 0 -- --

3G 0 1% 67 40 33% 17%

HDHE 8 16% 1,857 1,873 42% 10%

Prem 9 17% 2,019 2,066 59% 48%

Std 0 0% 27 8 37% 32%

Low 0 1% 102 78 43% 32%

Other 0 0% 33 - 100% --




NAV 5,981 6,366


NAV/Share 26 27

Last Price 15 15

P/NAV 58% 55%

0.3X

3.9X

2.3X2.0X

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2.9X

4.2X 4.3X

3.0X

3%

27%

26%24%

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36% 37%

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ENSCO PLC, Buy, $20PT, Solid Operator, Good Value Investment Thesis We are initiating coverage of ESV of Buy rating and $20 price target. A well managed, counter cyclical valuation play, we like the risk/reward as a means to gain exposure to an offshore drilling recovery, especially for jackups. ESV termed out its debt, which leaves no maturities until 2019, reducing any near term financial risk. Internal improvements in the downturn may translate into a stronger company: 1) reduced costs with head count reductions, with 30% fewer shore based heads ($57 million annual savings) 2) changed reporting structure to consolidate regional overhead 3) reduced discretionary comp cut 15%, through reduction of a number of “premiums” in the compensation structure 4) investment automated system maintenance implemented by 1Q/16, process safety, and increased efficiency. ESV appears patient to survey the market for distressed assets, but does have the “dry powder” to take advantage of opportunities, which may prove a positive catalyst.


Since ESV was able to term out its debt when it had an investment grade rating in 2014, its next long term debt maturity does not come until 2019 ($575 million), which alleviates refinancing risk. The company has not drawn from its $2.25 billion revolving credit facility that expires at the end of September 2019, which limits the total debt to capitalization to 60% (amended from 50% in March 2015). In our view, the access to the revolver leaves ESV positioned to purchase distressed assets.


• ESV has five idle floaters and seven idle jackups. We forecast idle time for idle time into 2016 for a number of rigs with contract expirations. If these rigs are recontracted/extended. In our view, these conservative assumptions have brought our estimates below consensus for 2016. Less idle time would be a positive catalyst for our estimates.


• We forecast the retirement of the ENSCO 5004 and eight jackups within our rig attrition forecast and ESV estimates.


S&P BBB+ YES -- Jan 2010

Moody’s Baa2 YES Downgrade Oct 2015

December 15, 2015 206

ENSCO PLC (ESV) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Contract Drilling 4,947.2 4,744.6 3,974.5 3,239.5 3,428.9 1,163.9 1,059.0 901.2 850.4 807.4 804.2 787.5 840.4 802.8 853.1 882.6 890.5

Total Revenues 4,947.2 4,744.6 3,974.5 3,239.5 3,428.9 1,163.9 1,059.0 901.2 850.4 807.4 804.2 787.5 840.4 802.8 853.1 882.6 890.5

Contract Drilling 2,556.1 2,507.4 2,125.5 1,511.8 1,553.3 645.6 556.4 490.7 432.8 401.6 390.0 367.0 353.3 332.5 390.0 412.4 418.5



EBIT 1,797.4 1,792.0 1,435.5 839.8 868.8 478.4 386.2 317.1 253.8 235.7 224.7 200.0 179.3 161.1 219.3 241.2 247.1

Interest Income 16.6 13.0 7.8 8.8 9.0 2.4 3.4 1.0 1.0 2.2 2.2 2.1 2.3 2.6 2.1 2.2 2.2

Net Interest (Expense) (158.8) (161.4) (217.8) (245.4) (255.0) (52.4) (51.2) (55.3) (58.9) (58.9) (58.9) (63.8) (63.8) (63.8) (63.8) (63.8) (63.8)

Other, Net (3.5) (12.5) (35.0) (2.0) (2.0) (26.4) (7.6) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5)

EBT 1,651.7 1,631.1 1,190.4 601.2 620.7 402.0 330.8 262.3 195.3 178.4 167.5 137.9 117.4 99.5 157.1 179.1 185.0

Income Taxes (218.6) (179.1) (157.6) (60.1) (62.1) (77.7) (58.0) (2.4) (19.5) (17.8) (16.7) (13.8) (11.7) (9.9) (15.7) (17.9) (18.5)

Minority Interest (9.7) (14.1) (18.2) (25.2) (25.2) (3.2) (2.4) (6.3) (6.3) (6.3) (6.3) (6.3) (6.3) (6.3) (6.3) (6.3) (6.3)

Net Income (Operating) 1,423.4 1,437.9 1,014.6 515.9 533.5 321.1 270.4 253.6 169.5 154.3 144.4 117.8 99.4 83.2 135.1 154.9 160.2

Discontinued Operations (5.0) (961.5) (45.2) (46.6) (42.1) (0.2) (10.1) (23.3) (11.6) (11.5) (11.6) (11.7) (11.8) (10.3) (10.5) (10.6) (10.7)

Extraordinaries (after-tax) 15.8 (4,408.8) 57.2 - - - - 57.2 - - - - - - - - -

Net Income (GAAP) 1,434.2 (3,932.4) 1,026.6 469.3 491.4 320.9 260.3 287.5 157.9 142.8 132.9 106.1 87.6 72.9 124.6 144.3 149.6

EPS (Operating) 6.16 6.21 4.37 2.22 2.29 1.38 1.16 1.09 0.73 0.66 0.62 0.51 0.43 0.36 0.58 0.67 0.69

EPS (GAAP) 6.21 (16.97) 4.42 2.02 2.11 1.38 1.12 1.24 0.68 0.61 0.57 0.46 0.38 0.31 0.54 0.62 0.64




EBITDA 2,409.3 2,371.7 2,008.4 1,392.3 1,423.6 615.5 526.7 462.3 403.9 373.5 361.3 337.9 319.6 299.9 357.9 379.9 385.8



Cash From Operations (CFO) 1,980.0 2,057.9 1,505.5 714.6 692.2 467.7 423.3 383.6 230.9 209.5 182.3 183.1 139.7 186.9 151.8 169.8 183.7

Capital Expenditures (1,779.2) (1,568.8) (1,647.0) (621.7) (787.9) (397.1) (516.8) (531.9) (201.2) (195.1) (38.6) (33.1) (354.9) (108.4) (115.2) (119.1) (445.2)

Free Cash Flow (FCF) 200.8 489.1 (141.5) 92.9 (95.7) 70.6 (93.5) (148.3) 29.7 14.4 143.7 150.0 (215.2) 78.5 36.6 50.6 (261.5)

Acquisitions/Divestures/Investments 45.2 (538.1) (91.3) - - - 107.3 (198.6) - - - - - - - - -

Cash From Financing (CFF) (573.1) 483.3 (175.4) (139.5) 57.1 149.5 (240.1) (49.9) (34.9) (34.9) (34.9) (34.9) (34.9) (34.9) (34.9) (34.9) 161.7

Other 5.6 64.9 (21.4) - - 2.9 (13.2) (11.1) - - - - - - - - -

Increase (Decrease) in Cash (321.5) 499.2 (429.6) (46.6) (38.7) 223.0 (239.5) (407.9) (5.2) (20.5) 108.8 115.2 (250.0) 43.6 1.7 15.7 (99.8)


Total Capital 17,558.0 14,135.4 15,053.1 15,445.8 16,057.1 14,635.3 14,676.3 14,914.4 15,053.1 15,176.7 15,290.4 15,377.4 15,445.8 15,499.5 15,604.9 15,730.1 16,057.1

Total Debt 4,766.4 5,920.4 5,903.3 5,903.3 6,099.9 6,130.8 5,925.7 5,903.3 5,903.3 5,903.3 5,903.3 5,903.3 5,903.3 5,903.3 5,903.3 5,903.3 6,099.9

Net Debt 4,600.8 4,498.3 4,818.1 4,864.6 5,099.9 4,497.7 4,627.4 4,812.9 4,818.1 4,838.6 4,729.8 4,614.6 4,864.6 4,821.0 4,819.2 4,803.5 5,099.9


Net Debt/Capital 26.2% 31.8% 32.0% 31.5% 31.8% 30.7% 31.5% 32.3% 32.0% 31.9% 30.9% 30.0% 31.5% 31.1% 30.9% 30.5% 31.8%


BVPS 55.36 35.46 39.39 41.04 42.83 36.67 37.69 38.76 39.35 39.89 40.37 40.75 41.04 41.27 41.73 42.27 42.83

TBVPS 41.19 34.26 38.20 39.86 41.64 35.48 36.50 37.57 38.17 38.70 39.19 39.56 39.86 40.09 40.54 41.08 41.64

December 15, 2015 207

ENSCO PLC (ESV) Valuation PRICE TARGET SCENARIOS



4.6% 21.6X $6,444 $28.00 87% Net Income 1,162.2 1,434.2 (3,932.4) 1,026.6 469.3 491.4 1,045.0 1,047.2 770.8

6.6% 15.1X $5,876 $26.00 74% Depreciation & Amortization 568.0 611.9 579.7 572.9 552.5 554.8 550.7 550.4 551.0

8.6% 11.6X $5,368 $24.00 60% Capitalized Interest 107.4 67.7 78.2 63.6 9.6 - - - -

10.6% 9.4X $4,912 $22.00 47% Deferred Taxes (18.0) 6.2 36.4 (66.7) (375.8) (388.0) (763.3) (765.2) (573.6)

12.6% 7.9X $4,503 $20.00 34% Translation Adjustment Other 755.3 2.9 5,447.3 19.6 62.8 62.8 62.8 62.8 62.8

14.6% 6.8X $4,134 $18.00 20% Operating Cash Flow (before working cap.) 2,574.9 2,122.9 2,209.2 1,616.0 718.5 721.0 895.1 895.2 811.0

16.6% 6.0X $3,801 $17.00 14% Net Cash from Investing Activities (1,739.9) (1,734.0) (2,106.9) (1,738.3) (621.7) (787.9) (518.8) (570.4) (578.1)

18.6% 5.4X $3,501 $16.00 7% Capitalized Interest (107.4) (67.7) (78.2) (63.6) (9.6) - - - -

20.6% 4.8X $3,229 $14.00 (6%) Capitalized G&A - - - - - - - - -

22.6% 4.4X $2,982 $13.00 (13%) Less: Net Capital Expenditures (before Cap Int) 1,632.5 1,666.3 2,028.7 1,674.7 612.1 787.9 518.8 570.4 578.1

Working Capital Change (231.5) (75.2) (73.1) (46.9) 5.8 (28.9) (116.1) 72.3 16.6

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred (172.5) (47.5) 1,186.3 (34.6) - 196.6 - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 1,346.4 579.3 (932.7) 22.9 100.7 (234.6) 492.4 252.5 216.2











Levered Free Cash Flow (2) 100.7 (234.6) 492.4 252.5 7,426.3




December 15, 2015 208











December 15, 2015 209



6G 30 79% 4,115 4,140 100% 100%

5G 3 7% 362 359 26% 0%

4G 3 8% 399 336 28% 19%

3G 1 3% 150 59 100% 78%

HDHE - -- - - -- --

Prem 1 3% 165 164 17% --

Std 0 0% 4 (12) -- --

Low - -- - - -- --

Other - -- - - -- --

Gross GFV, Current 38 5,207 5,026

Other Assets 431 387


NAV 1,877 1,956


NAV/Share 14 14

Last Price 20 20

P/NAV 147% 143%

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Diamond Offshore: Accumulate, $24PT, Needs Counter-Cyclical Investment Catalyst Investment Thesis

We are initiating coverage of DO with a Accumulate rating and $24 price target. Rig retirements dwindle DO’s earnings power over time, which weighs on valuation of the shares. Our forecast does not scrap all of the older rigs in the fleet, as an inventory of work remains for the rigs, but do believe that DO may be wary to employ capital to keep a significant portion legacy fleet alive after current contracts conclude. In order to become more constructive on the shares, DO needs to invest to add/maintain its earnings power. We can see upward revisions to our estimates and valuation, as well as a more positive view on the shares, as we better understand potential rig acquisitions. DO does have a history of value accretive, counter-cyclical rig acquisitions at low prices. Given a higher potential for distressed assets on the market at this point in the cycle, the company should be in its element, provided they time and price purchases to reflect contracting risks and costs of carry for new rigs. DO has also mentioned building 8th generation rigs, given the ability to pursue newer rig designs with greater drilling efficiencies. Progress on cost reductions, with 20% back office and corporate headcount reductions, may help add to the investment thesis as well.


DO has done a good job of spreading its maturities, with the next major maturity in 2019, after using commercial paper/revolver to pay its $250 million 2015 debt maturity in July. DO has an additional ~$900 million available on its revolver after refinancing the maturity. Its remaining payment for the Ocean Great White, for $440 million in 2Q/16, appears adequately funded by cash and the revolver. In our view DO, may have available capacity on its revolver to renew its fleet with distressed assets. If it maintains its investment grade debt ratings, DO balance sheet should support rig acquisitions.


• Roughly, 13 rigs are currently idle or rolling off contract through 2016. Since we allow for significant downtime between contracts in our forecast, potential for faster re-contracting may be a positive catalyst for EPS forecasts and the shares.


• We forecast 6 floaters, in addition to the 12 cold stacked rigs (5 JU, and 7 floaters) may be ultimately be retired. We forecast the retirement of floaters, Ocean Patriot, Ocean Ambassador, Ocean Victory, Ocean Quest, Ocean Rover, and Ocean Guardian.


S&P BBB+ YES Downgrade Apr 2015

Moody’s Baa2 YES Downgrade Oct 2015

December 15, 2015 210

Diamond Offshore (DO) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Ultra-Deepwater 924.5 987.6 1,309.3 1,295.1 1,387.0 251.4 315.7 376.2 366.0 310.5 320.1 339.1 325.4 315.2 333.8 366.4 371.6

Deepwater 617.1 494.2 536.7 243.2 188.1 138.8 181.1 136.7 80.1 51.1 63.9 64.6 63.7 60.7 54.5 34.8 38.1

Midwater 1,197.9 1,076.8 390.9 233.2 147.2 176.4 96.9 69.5 48.2 62.8 56.4 57.0 57.0 51.8 36.1 36.5 22.7

Jackups 174.1 178.5 80.7 34.5 29.5 33.1 23.7 16.7 7.2 10.0 9.8 7.3 7.4 7.4 6.9 7.0 8.3

Revenues Related to Reimbursables 76.8 77.5 58.5 42.8 42.8 20.5 16.6 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7

Total Revenues 2,990.4 2,814.7 2,376.0 1,848.8 1,794.6 620.1 634.0 609.7 512.2 445.1 460.9 478.6 464.2 445.8 442.1 455.4 451.4

Ultra-Deepwater 408.8 434.1 651.7 628.0 675.0 96.9 154.2 220.1 180.5 138.0 158.8 172.6 158.7 151.7 159.6 179.4 184.3

Deepwater 349.3 202.2 276.9 86.2 35.5 75.1 94.6 69.0 38.1 18.9 22.6 22.8 21.9 19.6 13.0 (0.2) 3.1

Midwater 593.4 541.8 160.8 113.0 68.8 77.0 30.2 33.7 19.9 27.4 28.3 28.6 28.6 23.9 19.4 19.6 5.8

Jackups 59.0 67.3 17.3 12.0 7.0 11.5 2.9 4.2 (1.2) 4.4 4.3 1.6 1.7 1.8 1.3 1.3 2.6

Other (46.4) (48.7) (30.7) (23.7) (23.7) (11.6) (7.3) (5.9) (5.9) (5.9) (5.9) (5.9) (5.9) (5.9) (5.9) (5.9) (5.9)

Net Reimburables 1.9 1.5 1.1 0.9 0.9 0.4 0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2


Gain (Loss) on Sale of Assets 0.8 0.1 0.8 - - 0.6 0.2 - - - - - - - - - -


EBIT 913.8 659.9 513.5 227.1 174.1 95.2 135.1 186.3 96.9 32.8 62.3 76.5 55.4 42.0 39.9 48.3 44.0

Interest Income 0.7 0.8 2.4 4.4 5.9 0.6 0.6 0.6 0.6 0.9 1.3 1.6 0.6 1.0 1.3 1.6 1.9

Interest (Expense), Net (24.8) (66.2) (96.3) (126.0) (132.8) (24.0) (25.5) (21.4) (25.5) (28.2) (30.9) (33.5) (33.4) (33.3) (33.2) (33.2) (33.1)

Gain/(Loss) on Marketable Securities - 3.2 2.1 - - 5.6 (3.5) - - - - - - - - - -

Other, Net (24.2) 0.7 0.7 - - 0.2 0.3 0.2 - - - - - - - - -

EBT 865.4 598.4 422.5 105.5 47.1 77.6 107.0 165.8 72.0 5.5 32.7 44.6 22.7 9.7 8.0 16.8 12.8

Income Taxes (202.5) (163.2) (57.6) (14.8) (6.6) (10.3) (16.0) (21.2) (10.1) (0.8) (4.6) (6.2) (3.2) (1.4) (1.1) (2.3) (1.8)


Asset Impairments 1.3 (115.2) (322.4) - - (319.0) - (3.4) - - - - - - - - -

Extraordinaries (after-tax) (115.4) 67.0 (9.4) - - (4.0) (0.6) (4.8) - - - - - - - - -

Net Income (GAAP) 548.9 387.0 33.0 90.8 40.5 (255.7) 90.4 136.4 61.9 4.7 28.1 38.4 19.5 8.3 6.8 14.4 11.0

EPS (Operating) 4.77 3.17 2.66 0.65 0.29 0.49 0.66 1.05 0.45 0.03 0.20 0.28 0.14 0.06 0.05 0.10 0.08

EPS (GAAP) 3.95 2.81 0.24 0.65 0.29 (1.86) 0.66 0.99 0.45 0.03 0.20 0.28 0.14 0.06 0.05 0.10 0.08




EBITDA 1,301.9 1,116.4 1,009.9 753.7 700.8 232.5 258.4 304.4 214.5 167.2 192.9 204.2 189.4 175.9 172.1 178.5 174.2



Cash From Operations (CFO) 1,066.0 988.5 658.8 596.4 544.4 160.6 40.3 265.8 192.1 136.9 151.4 159.4 148.7 138.5 133.6 136.7 135.6


Free Cash Flow (FCF) 108.4 (1,044.3) (193.9) (135.3) 264.2 (36.5) (448.8) 193.6 97.7 64.6 (360.5) 84.5 76.1 68.9 64.6 65.6 65.1

Acquisitions/Divestures/Investments (594.5) 1,751.0 8.5 - - 4.8 - 3.7 - - - - - - - - -

Cash From Financing (CFF) 508.2 (824.0) 173.5 139.4 (70.5) (17.1) 357.8 (150.0) (17.2) (17.3) 191.5 (17.4) (17.5) (17.5) (17.6) (17.7) (17.7)

Other (10.5) 4.0 (0.0) - - (0.0) 2.1 (2.1) - - - - - - - - -

Increase (Decrease) in Cash 11.6 (113.4) (12.0) 4.1 193.7 (48.8) (88.9) 45.3 80.5 47.3 (169.0) 67.1 58.7 51.4 47.0 47.9 47.4


Total Capital 7,131.4 6,696.1 6,902.5 7,108.1 7,053.7 6,424.4 6,877.4 6,863.9 6,902.5 6,883.8 7,097.3 7,112.2 7,108.1 7,092.8 7,075.9 7,066.6 7,053.7

Total Debt 2,494.1 2,244.5 2,481.6 2,666.0 2,641.5 2,244.6 2,619.6 2,487.7 2,481.6 2,475.5 2,678.2 2,672.1 2,666.0 2,659.8 2,653.7 2,647.6 2,641.5

Net Debt 397.1 1,994.8 2,246.3 2,426.5 2,208.4 2,045.8 2,507.8 2,333.0 2,246.3 2,192.8 2,564.6 2,491.3 2,426.5 2,369.0 2,315.9 2,261.9 2,208.4


Net Debt/Capital 5.6% 29.8% 32.5% 34.1% 31.3% 31.8% 36.5% 34.0% 32.5% 31.9% 36.1% 35.0% 34.1% 33.4% 32.7% 32.0% 31.3%


BVPS 33.35 32.38 32.20 31.97 31.30 30.48 31.03 31.90 32.10 31.90 31.86 31.90 31.80 31.62 31.43 31.30 31.14

TBVPS 33.35 32.38 32.20 31.97 31.30 30.48 31.03 31.90 32.10 31.90 31.86 31.90 31.80 31.62 31.43 31.30 31.14

December 15, 2015 211

Diamond Offshore (DO) Valuation PRICE TARGET SCENARIOS



7.6% 13.2X $3,863 $29.00 44% Net Income 720.5 548.9 387.0 33.0 90.8 40.5 50.6 74.8 60.1



10.6% 9.5X $3,365 $25.00 24% Deferred Taxes (51.5) 34.1 1.5 (114.7) - - - - -

11.6% 8.7X $3,216 $24.00 19% Translation Adjustment Other 66.8 6.0 111.4 291.8 (24.5) (24.5) (24.5) (24.5) (24.5)

12.6% 8.0X $3,075 $23.00 14% Operating Cash Flow (before working cap.) 1,166.4 1,051.3 1,017.1 722.4 595.7 542.7 540.3 547.8 533.1

13.6% 7.4X $2,941 $22.00 9% Net Cash from Investing Activities (815.7) (1,552.1) (281.8) (844.3) (731.7) (280.3) (273.1) (338.6) (410.3)


15.6% 6.4X $2,693 $20.00 (1%) Capitalized G&A - - - - - - - - -

16.6% 6.0X $2,578 $19.00 (6%) Less: Net Capital Expenditures (before Cap Int) 778.0 1,477.8 221.2 828.3 728.9 280.3 273.1 338.6 410.3

Working Capital Change 182.6 88.9 32.0 (47.7) 3.6 1.7 2.6 2.0 (2.1)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred - 997.8 (250.0) 243.0 208.9 - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations 205.8 (1,513.3) 1,013.9 (301.2) (345.7) 260.7 264.6 207.3 125.0







Cost of Debt, after tax 5.0% Subtract Levered FCF from Operations for Explict Forecast 512.0

Net Debt/Total Capital 30.0% Subtract: Changes in Equity for Explict Forecast (73.5)







December 15, 2015 212











December 15, 2015 213

Atwood Oceanics, Hold, $12.50PT, Fears in Front of Capital Needs Investment Thesis We are initiating coverage of ATW with a Hold rating and $12.50 price target. ATW has a high quality fleet, but uncontracted rig exposure in 2016 leaves little earnings visibility in the near term. Newbuild funding requirements (~$200 million) in 2016 create needs for additional debt. Although, ATW renegotiated the terms of its revolver in front of likely covenant issues, risks remain. Consensus estimates look high for 2016 and we forecast a dividend cut. Under a more normalized risk parameters, our valuation suggest a $30+/share valuation, but a below investment grade rating and need for capital leads us to price heightened risk and expect greater volatility in the shares during coming quarters. Balance Sheet /Cash Flow Strength ATW leverage ratios are likely break its credit facility maximum leverage ratio covenant (4.5x Net Debt/EBITDA) in 2H/16, create volatility in the shares, and the need to raise expensive debt. The company may need to tap high yield markets to fulfill a stipulation to secure pre-negotiated amendments for its covenants. (maximum leverage ratio may be replaced with a senior secured leverage ratio of 3.0x (only the amount drawn on the revolver/EBITDA) and minimum interest expense coverage ratio may be reduced from 3.0x to 1.75x) Given much tighter high yield markets, we anticipate and interest rate into the mid-teens on new issuance. Perceived higher costs of capital from the need to issue senior notes or convertible bonds depresses valuation in our model, but suggests the equity market may already discount near term financial risks in the shares. Dilution from an equity issuance is not off the table amongst scenarios. We note ATW already attained a maturity extension to May 2019 in March 2015, which also loosened other leverage ratio covenants (maximum leverage ratio upwards to 4.50x through December 31, 2017, after which period the maximum leverage ratio may revert back to 4.00x through maturity). We continue to monitor ATW’s success in achieving further dispensations from its creditors. Near Term Availability/Catalysts • Improved visibility for contracts for the newbuilds, the Atwood Admiral & Atwood Archer, or the

exercise of further negotiated delivery delays may alleviate overhangs on the stock. • All of ATW’s jackups roll off contract by the end of 2016, which adds cash flow risk. Rig Retirements Forecast • After the disposal of the Atwood Hunter, we do not forecast any further rig retirements

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6G 51 83% 3,333 3,484 92% 38%

5G - -- - - -- --

4G 1 2% 86 37 71% --

3G - -- - - -- --

HDHE - -- - - -- --

Prem 9 15% 609 662 55% 2%

Std - -- - - -- --

Low - -- - - -- --

Other - -- - - -- --


Other Assets 15 (65)


NAV (Liquidation Value) 1,712 2,110


NAV/Share 26 32

Last Price 16 16

P/NAV 63% 51%


S&P BB NO -- Jan 2012

Moody’s Ba3 NO Downgrade Oct 2015

December 15, 2015 214

Atwood Oceanics (ATW) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Contract Drilling Revenues 1,063.7 1,174.0 1,395.9 1,014.5 954.7 351.7 350.4 330.6 363.2 278.9 279.0 250.4 206.3 212.7 224.8 238.6 278.7

Total Revenues 1,063.7 1,174.0 1,395.9 1,014.5 954.7 351.7 350.4 330.6 363.2 278.9 279.0 250.4 206.3 212.7 224.8 238.6 278.7

Operating Expenses (458.9) (553.2) (559.2) (487.4) (596.9) (148.4) (139.8) (143.3) (127.7) (131.4) (118.0) (118.2) (119.7) (136.4) (146.0) (147.9) (166.6)

Other (1.0) (7.7) (0.0) - - - - (0.0) - - - - - - - - -

SG&A (56.8) (61.5) (57.2) (56.7) (50.1) (17.4) (14.7) (10.5) (14.6) (18.1) (14.6) (13.1) (10.8) (11.2) (11.8) (12.5) (14.6)

Depreciation (117.5) (147.4) (171.9) (186.3) (228.9) (44.6) (42.5) (42.5) (42.3) (43.1) (45.4) (46.0) (51.7) (52.6) (57.5) (58.7) (60.1)

EBIT 429.5 404.2 607.5 284.2 78.8 141.4 153.3 134.2 178.6 86.3 100.9 73.0 24.0 12.5 9.5 19.5 37.3


Interest Income 0.2 0.3 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Other (gain on asset sale) - 0.0 0.1 - - (0.0) - - 0.1 - - - - - - - -

EBT 404.8 362.8 555.1 204.2 (5.4) 125.9 140.5 122.5 166.1 67.3 81.9 52.0 2.9 (8.6) (11.5) (1.6) 16.3

Income Tax (54.6) (44.4) (52.0) (32.6) 0.8 (14.7) (12.3) (9.5) (15.4) (12.1) (12.3) (7.8) (0.4) 1.3 1.7 0.2 (2.4)

Net Income (Operating) 350.2 318.4 503.1 171.5 (4.6) 111.2 128.2 113.0 150.7 55.2 69.6 44.2 2.5 (7.3) (9.8) (1.3) 13.8

Income (Loss) from Discontinued Operations - - - - - - - - - - - - - - - - -

Gain (Loss) on Asset Sale - 22.4 (14.4) - - (8.9) (5.5) - - - - - - - - - -

Asset Impairment - - (56.1) - - (56.1) - - - - - - - - - - -

Extraordinaries (after-tax) - - - - - - - - - - - - - - - - -

Net Income (GAAP) 350.2 340.8 432.6 171.5 (4.6) 46.2 122.7 113.0 150.7 55.2 69.6 44.2 2.5 (7.3) (9.8) (1.3) 13.8

EPS (Operating) 5.32 4.89 7.74 2.64 (0.07) 1.71 1.97 1.73 2.32 0.85 1.07 0.68 0.04 (0.11) (0.15) (0.02) 0.21

EPS (GAAP) 5.32 5.24 6.65 2.64 (0.07) 0.71 1.89 1.73 2.32 0.85 1.07 0.68 0.04 (0.11) (0.15) (0.02) 0.21

Dividend per Share - - 0.83 0.30 0.30 0.25 0.25 0.25 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08



EBITDA 547.0 551.6 779.4 470.4 307.7 185.9 195.9 176.7 220.9 129.4 146.3 119.0 75.7 65.1 67.0 78.1 97.5



Cash From Operations (CFO) 432.1 442.6 604.3 552.8 154.7 194.8 155.0 328.6 (74.1) 207.4 134.5 116.7 94.2 40.5 21.4 50.0 42.8


Free Cash Flow (FCF) (313.1) (533.1) 156.3 (29.2) 15.2 45.7 126.9 85.7 (102.0) 191.2 (391.3) 93.3 77.7 12.9 (10.1) 14.2 (1.8)

Acquisitions/Divestures/Investments 0.1 61.5 (4.4) - - 1.3 1.2 (0.2) (6.7) - - - - - - - -

Cash From Financing (CFF) 314.6 459.2 (119.0) 166.4 (19.5) (6.1) (160.1) 93.5 (46.3) (4.9) 181.0 (4.9) (4.9) (4.9) (4.9) (4.9) (4.9)

Other 9.2 3.7 1.1 - - 0.7 0.5 (194.7) 194.6 - - - - - - - -

Increase (Decrease) in Cash 10.9 (8.7) 33.9 137.2 (4.3) 41.7 (31.6) (15.7) 39.5 186.3 (210.3) 88.4 72.8 8.0 (15.0) 9.4 (6.7)


Total Capital 3,470.6 4,297.6 4,633.1 4,982.4 4,969.7 4,349.4 4,324.5 4,529.2 4,633.1 4,686.4 4,939.6 4,981.9 4,982.4 4,973.0 4,961.2 4,957.9 4,969.7

Total Debt 1,263.2 1,742.1 1,685.9 1,871.9 1,871.9 1,741.8 1,606.5 1,716.2 1,685.9 1,685.9 1,871.9 1,871.9 1,871.9 1,871.9 1,871.9 1,871.9 1,871.9

Net Debt 1,174.5 1,662.0 1,572.0 1,620.7 1,624.9 1,620.0 1,516.3 1,641.7 1,572.0 1,385.6 1,781.9 1,693.4 1,620.7 1,612.7 1,627.6 1,618.2 1,624.9


Net Debt/Capital 33.8% 38.7% 33.9% 32.5% 32.7% 37.2% 35.1% 36.2% 33.9% 29.6% 36.1% 34.0% 32.5% 32.4% 32.8% 32.6% 32.7%


BVPS 33.52 39.26 45.32 47.90 47.71 40.11 41.78 43.19 45.39 46.21 47.25 47.90 47.90 47.76 47.58 47.53 47.71

TBVPS 33.52 39.26 45.32 47.90 47.71 40.11 41.78 43.19 45.39 46.21 47.25 47.90 47.90 47.76 47.58 47.53 47.71

December 15, 2015 215

Atwood Oceanics (ATW) Valuation PRICE TARGET SCENARIOS



11.1% 9.0X $1,240 $19.00 44% Net Income 272.2 350.2 340.8 432.6 171.5 (4.6) 185.9 304.0 174.5



17.1% 5.9X $903 $14.00 6% Deferred Taxes (1.0) (0.8) (1.3) (2.7) - - - - -

19.1% 5.2X $812 $12.50 (5%) Translation Adjustment Other 12.9 20.8 (30.8) 85.1 11.3 11.3 11.4 11.4 11.4

21.1% 4.7X $729 $11.25 (14%) Operating Cash Flow (before working cap.) 353.9 492.9 464.7 693.2 369.1 235.7 456.6 615.7 533.5

23.1% 4.3X $655 $10.00 (24%) Net Cash from Investing Activities (777.4) (745.1) (914.2) (452.4) (582.0) (139.5) (240.8) (335.4) (368.3)

25.1% 4.0X $587 $9.00 (32%) Capitalized Interest - - - - - - - - -

27.1% 3.7X $525 $8.00 (39%) Capitalized G&A - - - - - - - - -

29.1% 3.4X $468 $7.25 (45%) Less: Net Capital Expenditures (before Cap Int) 777.4 745.1 914.2 452.4 582.0 139.5 240.8 335.4 368.3

Working Capital Change (98.3) (60.8) (22.1) (88.9) 183.7 (81.0) (66.8) (1.3) 14.9

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 299.2 421.9 459.2 (70.5) 185.9 - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (624.3) (613.2) (886.6) 400.1 (582.5) 177.1 282.6 281.6 150.3















December 15, 2015 216











December 15, 2015 217

Noble Corp: Buy, $16PT, Solid Fleet & Balance Sheet Investment Thesis

We are initiating coverage of NE with a Buy rating and $16 price target. We are buyers of NE for exposure to the offshore driller group for the following reasons 1) we like its new fleet 2) share are undervalued on mid-cycle value 3) liquidation value (NAV) puts a floor under the stock 4) favorable balance sheet and cash flow profile (especially relative to the group) 5) NE has financial flexibility to acquire distressed assets at attractive prices. In our view, the PGN spin-off de-risked the story and left the company well positioned for the current downturn.


Given a higher marginal cost of debt (8.5%), the company looks well positioned. NE may be FCF positive throughout our forecast. Longer term debt maturities are largely spread out over time, but NE has ~$300 million of Senior Notes Maturing in March 2016 and another ~$300 million of Senior Notes Maturing in March 2017. The company may be able to repay both maturities with cash on hand and use of its undrawn credit facilities with capacity to $2.7 billion. The recent quarterly dividend cut to $0.15 from $0.375 may help to preserve cash for debt repayment purposes. That said, NE’s credit facilities are more than ample, with a covenant that requires a maximum of 60% debt to tangible capitalization. NE does not surpass the low 40’s% in our forecast.

In our view, NE may find itself in a position to acquire distressed assets, due to capital availability on its credit facilities.


• Contract news on floaters coming off contract (Noble Jim Day, Danny Adkins, Amos Runner, Clyde Boudreaux) and the idle Max Smith may prove a catalyst for the shares.

• Four jackups come off contract through 2016 and may prove a catalyst for the shares.


• After the spin-off of the majority of NE’s older fleet to Paragon (PGN), we see the Noble Homer Ferrington, a 4G floater that is currently stacked, and Noble Paul Romano as potential retirement candidates in NE’s floater fleet. Neither are on our larger retirement focus list. Jackups Noble Joe Beall, Noble Charles Copeland, and Noble David Tinsley are on our jackup retirement list.



6G 24 72% 5,929 5,945 80% 58%

5G 1 3% 230 261 24% --

4G 0 1% 72 89 10% --

3G 0 1% 105 63 97% --

HDHE 6 18% 1,465 1,482 69% 37%

Prem 1 4% 350 309 100% 36%

Std 0 1% 103 95 100% 98%

Low - -- - - -- --

Other - -- - - -- --




NAV 2,497 2,614


NAV/Share 10 11

Last Price 12 12

P/NAV 116% 110%

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S&P BBB Y Downgrade Dec 2014

Moody’s Baa3 Y -- Jun 2013

December 15, 2015 218

Noble Corp (NE) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Contract Drilling Services 4,052.1 4,004.6 2,998.7 2,454.1 2,419.4 779.4 771.3 736.8 711.2 636.2 582.7 622.5 612.8 579.8 615.7 613.3 610.6

Labor Contract Drilling Services 52.2 16.4 - - - - - - - - - - - - - - -

Other 0.1 0.0 - - - - - - - - - - - - - - -

Revenues Related to Reimbursables 111.9 104.1 92.9 91.1 91.1 25.0 22.2 22.9 22.8 22.8 22.8 22.8 22.8 22.8 22.8 22.8 22.8

Total Revenues 4,216.3 4,125.1 3,091.5 2,545.2 2,510.5 804.3 793.6 759.7 734.0 659.0 605.5 645.2 635.5 602.6 638.5 636.1 633.3

Contract Drilling Services 2,027.6 2,089.6 1,741.4 1,322.1 1,243.3 457.6 452.1 433.7 397.9 355.9 312.4 331.7 322.0 305.0 317.9 311.8 308.7

Labor Contract Drilling Services 15.6 3.9 - - - - - - - - - - - - - - -

Net Reimburables 26.3 23.9 19.5 20.0 20.0 4.8 4.6 5.1 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0



EBIT 1,072.1 1,181.9 1,042.9 666.1 535.0 284.4 275.1 263.0 220.4 196.2 155.4 161.9 152.5 138.9 137.0 131.0 128.0

Interest Income 3.2 (0.2) 10.3 10.8 12.7 6.6 - 0.9 2.8 1.9 3.2 4.4 1.3 2.0 2.8 3.7 4.1


Other, Net 1.3 - (0.4) - - - (0.4) - - - - - - - - - -

EBT 970.3 1,026.5 836.2 440.0 297.7 241.9 217.3 209.2 167.8 139.3 105.5 103.8 91.3 78.4 77.4 72.2 69.6

Income Taxes (162.0) (182.7) (120.8) (101.2) (65.5) (43.4) (39.4) (12.8) (25.2) (32.0) (24.3) (23.9) (21.0) (17.3) (17.0) (15.9) (15.3)

Noncontrolling Interests (67.7) (74.8) (76.8) (61.1) (62.8) (20.0) (18.8) (22.0) (15.9) (16.2) (14.8) (15.0) (15.0) (15.5) (15.7) (15.8) (15.8)


Discontinued Operations - (35.2) - - - - - - - - - - - - - - -

Asset Impairments (33.0) (713.0) - - - - - - - - - - - - - - -

Extraordinaries (after-tax) 75.1 (12.3) 144.2 - - - - 144.2 - - - - - - - - -

Net Income (GAAP) 782.7 8.5 782.8 277.7 169.4 178.4 159.0 318.7 126.8 91.0 66.4 64.9 55.3 45.7 44.7 40.5 38.5

Earnings Allocated to Unvested Shares (9.1) (6.4) - - - - - - - - - - - - - - -

EPS (Operating) 2.89 3.01 2.62 1.15 0.70 0.72 0.66 0.72 0.52 0.38 0.27 0.27 0.23 0.19 0.18 0.17 0.16

EPS (GAAP) 3.05 0.01 3.22 1.15 0.70 0.72 0.66 1.32 0.52 0.38 0.27 0.27 0.23 0.19 0.18 0.17 0.16




EBITDA 1,951.5 2,010.6 1,681.0 1,269.0 1,188.0 438.5 434.3 423.6 384.6 344.5 299.2 317.4 308.0 291.9 303.7 297.7 294.7



Cash From Operations (CFO) 1,702.3 1,778.2 1,581.6 982.9 880.5 368.6 399.3 484.3 329.3 292.8 251.4 210.3 228.4 230.7 205.7 222.9 221.1


Free Cash Flow (FCF) (785.2) (294.7) 1,129.8 85.6 350.5 279.3 318.3 374.6 157.6 136.6 (258.0) 96.8 110.2 112.7 74.2 85.6 78.0

Acquisitions/Divestures/Investments (5.9) - 2.5 - - - - 2.5 - - - - - - - - -


Other (102.9) (233.5) (102.9) - - (31.2) (9.6) (62.1) - - - - - - - - -

Increase (Decrease) in Cash (167.6) (45.9) 217.2 (36.3) 205.3 13.7 165.5 (83.3) 121.3 100.3 (271.0) 60.5 73.9 76.4 37.9 49.3 41.7


Total Capital 13,878.8 11,433.7 11,449.2 11,605.1 11,629.3 11,411.8 11,469.3 11,358.7 11,449.2 11,504.0 11,557.4 11,586.1 11,605.1 11,614.5 11,622.9 11,627.1 11,629.3

Total Debt 5,556.3 4,869.0 4,488.7 4,512.1 4,512.1 4,862.4 4,838.5 4,488.7 4,488.7 4,488.7 4,512.1 4,512.1 4,512.1 4,512.1 4,512.1 4,512.1 4,512.1

Net Debt 5,441.8 4,800.5 4,203.0 4,262.6 4,057.3 4,780.2 4,590.9 4,324.3 4,203.0 4,102.7 4,397.1 4,336.6 4,262.6 4,186.2 4,148.4 4,099.1 4,057.3


Net Debt/Capital 39.2% 42.0% 36.7% 36.7% 34.9% 41.9% 40.0% 38.1% 36.7% 35.7% 38.0% 37.4% 36.7% 36.0% 35.7% 35.3% 34.9%


BVPS 32.83 25.95 28.59 29.31 29.41 26.41 27.40 28.39 28.77 28.99 29.12 29.23 29.31 29.35 29.39 29.40 29.41

TBVPS 32.83 25.95 28.59 29.31 29.41 26.41 27.40 28.39 28.77 28.99 29.12 29.23 29.31 29.35 29.39 29.40 29.41

December 15, 2015 219

Noble Corp (NE) Valuation PRICE TARGET SCENARIOS



5.8% 17.1X $5,340 $22.00 85% Net Income 522.3 782.7 8.5 782.8 277.7 169.4 328.8 420.4 348.2



11.8% 8.4X $4,137 $17.00 43% Deferred Taxes (20.1) (16.0) 22.6 (67.6) (13.2) (6.0) (10.1) (12.5) (10.6)

13.8% 7.2X $3,813 $16.00 34% Translation Adjustment Other 239.4 168.9 885.2 190.0 61.1 62.8 63.7 66.7 64.6

15.8% 6.3X $3,520 $14.50 22% Operating Cash Flow (before working cap.) 1,636.3 1,930.1 1,792.1 1,568.4 941.0 879.2 1,046.3 1,138.5 1,066.1

17.8% 5.6X $3,255 $13.50 13% Net Cash from Investing Activities (1,788.6) (2,532.5) (2,072.9) (449.3) (897.3) (530.0) (685.9) (713.5) (645.3)


21.8% 4.6X $2,796 $11.50 (3%) Capitalized G&A - - - - - - - - -

23.8% 4.2X $2,597 $10.50 (12%) Less: Net Capital Expenditures (before Cap Int) 1,652.6 2,417.5 2,025.8 424.2 884.9 530.0 685.9 713.5 645.3

Working Capital Change (118.5) (112.8) 33.2 38.3 54.3 1.2 (56.8) 15.1 18.0

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 551.4 921.3 1,022.9 (396.8) 23.3 - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (449.2) (1,296.0) (1,289.8) 1,502.7 (21.6) 348.0 417.3 410.0 402.8















December 15, 2015 220











December 15, 2015 221



6G 21 51% 2,662 2,518 100% 63%

5G - -- - - -- --

4G - -- - - -- --

3G - -- - - -- --

HDHE 14 34% 1,754 1,706 52% 25%

Prem 4 9% 485 518 50% 41%

Std 3 6% 320 263 77% 75%

Low - -- - - -- --

Other - -- - - -- --




NAV 1,758 1,991


NAV/Share 14 16

Last Price 18 18

P/NAV 124% 110%

Rowan Cos., Buy, $25PT, Value Play, More Jackup Exposure Investment Thesis

We are initiating coverage of RDC with a Buy rating and $25 price target. RDC screens well on value, remains conservatively run, and offers balanced floater/jackup exposure, without credit issues. Management seems content to reduce costs (lowered shore-based headcount by 20%) and ride out the downturn, with a stable dividend. A higher premium jackup mix proves RDC may seek opportunities to acquire assets, but don’t seem anxious to actively pursue transactions, given questions around the timing of recovery. RDC offers a compelling story, but we would like to see the company use the downturn to add rigs to its nascent ultra-deepwater floater fleet and gain scale.


RDC’s credit facility requires a debt to book capital ratio under 60%, which does not pose an issue under our forecast. The company does have ~$400 million Senior notes that mature in September 2017, but we are assume the debt may be refinanced or paid down with cash without issue. The company has no further newbuild rig payments in the future.


• Contracts for the four idle jackups would be welcome. We are assuming a few quarters of idle time, at lower operating costs, but longer uncontracted periods may lead to negative revisions to our estimates. Cold stacking these rigs may prove positive for our estimates, as costs may come down.

• The new/extended contracts for the drillships remain a question, as contracts begin to roll off in 2017. In our view, the floaters may roll off into the beginning of a market recovery, so poise to carry risk and hold out for better dayrates may determine if new contracts are positive or negative catalysts.


• Over the next few years, we forecast the jackups, Cecil Provine, Rowan California, Rowan Middletown, Charles Rowan, and Arch Rowan may retire.

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S&P BBB- Y Upgrade Jul 2009

Moody’s Baa3 Y New Aug 2015

December 15, 2015 222

Rowan Companies (RDC) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Contract Drilling 1,579.3 1,824.4 2,103.1 1,774.4 1,569.4 547.0 508.7 545.4 502.0 451.3 434.6 444.3 444.2 418.3 389.4 384.5 377.2

Total Revenues 1,579.3 1,824.4 2,103.1 1,774.4 1,569.4 547.0 508.7 545.4 502.0 451.3 434.6 444.3 444.2 418.3 389.4 384.5 377.2

Contract Drilling 727.8 832.3 1,122.4 985.1 737.6 291.3 254.8 297.8 278.5 257.0 245.5 241.3 241.3 220.9 179.8 172.2 164.7



EBIT 325.4 383.8 612.8 520.9 251.5 174.0 128.2 164.0 146.6 141.4 131.8 123.8 123.9 102.3 57.4 49.7 42.1


Interest Income 0.4 - - - - - - - - - - - - - - - -

Gain on Disposals (0.2) (1.0) (2.6) - - - (0.3) (2.3) - - - - - - - - -

Other, Net 2.0 - (56.3) - - 0.5 - (56.8) - - - - - - - - -

EBT 258.5 279.7 404.7 355.3 85.9 140.9 97.4 62.0 104.4 100.0 90.4 82.4 82.5 60.9 16.0 8.3 0.7

Income Tax (Expense) (14.3) (16.3) 7.1 (53.3) (12.9) (17.2) (9.4) 49.4 (15.7) (15.0) (13.6) (12.4) (12.4) (9.1) (2.4) (1.2) (0.1)


Discontinued Operations - 4.0 - - - - - - - - - - - - - - -

Asset Impairments - (438.4) (273.8) - - - - (273.8) - - - - - - - - -

Extraordinaries (after-tax) 9.6 55.9 (80.3) - - - (3.3) (77.0) - - - - - - - - -

Net Income (GAAP) 253.8 (115.1) 57.7 302.0 73.0 123.7 84.7 (239.4) 88.7 85.0 76.8 70.0 70.1 51.7 13.6 7.1 0.6

EPS (Operating) 1.96 2.11 3.29 2.42 0.58 0.99 0.70 0.89 0.71 0.68 0.62 0.56 0.56 0.41 0.11 0.06 0.00

EPS (GAAP) 2.04 (0.92) 0.46 2.42 0.58 0.99 0.68 (1.92) 0.71 0.68 0.62 0.56 0.56 0.41 0.11 0.06 0.00




EBITDA 596.5 706.5 1,004.2 880.4 638.4 263.7 223.6 268.1 248.8 228.7 218.7 215.8 217.1 196.4 155.1 147.3 139.5





Free Cash Flow (FCF) 17.2 (1,535.2) 128.0 587.3 395.8 (269.5) 101.8 151.7 144.0 172.0 146.5 131.8 137.1 133.6 100.5 83.4 78.2

Acquisitions/Divestures/Investments 44.6 22.0 8.0 11.4 11.4 1.7 0.6 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8

Cash From Financing (CFF) 5.7 755.0 (50.4) (49.9) (50.0) (12.6) 37.3 (62.7) (12.5) (12.5) (12.5) (12.5) (12.5) (12.5) (12.5) (12.5) (12.5)

Other 1.4 4.5 - - - (2.0) 2.0 - - - - - - - - - -

Increase (Decrease) in Cash 68.8 (753.7) 85.7 548.8 357.2 (282.4) 141.8 91.9 134.3 162.3 136.9 122.1 127.5 124.0 90.8 73.8 68.6


Total Capital 6,902.5 7,498.7 7,527.9 7,780.0 7,803.0 7,613.5 7,745.0 7,451.6 7,527.9 7,600.4 7,664.8 7,722.3 7,780.0 7,819.2 7,820.3 7,814.9 7,803.0

Total Debt 2,008.7 2,807.3 2,806.7 2,806.7 2,806.7 2,807.1 2,856.9 2,806.7 2,806.7 2,806.7 2,806.7 2,806.7 2,806.7 2,806.7 2,806.7 2,806.7 2,806.7

Net Debt 915.9 2,468.1 2,381.9 1,833.1 1,475.9 2,750.3 2,658.3 2,516.2 2,381.9 2,219.5 2,082.7 1,960.6 1,833.1 1,709.1 1,618.3 1,544.5 1,475.9


Net Debt/Capital 13.3% 32.9% 31.6% 23.6% 18.9% 36.1% 34.3% 33.8% 31.6% 29.2% 27.2% 25.4% 23.6% 21.9% 20.7% 19.8% 18.9%


BVPS 39.32 37.61 37.76 39.84 40.01 38.42 38.98 37.22 37.83 38.41 38.92 39.38 39.83 40.15 40.15 40.10 40.01

TBVPS 39.32 37.61 37.76 39.84 40.01 38.42 38.98 37.22 37.83 38.41 38.92 39.38 39.83 40.15 40.15 40.10 40.01

December 15, 2015 223

Rowan Companies (RDC) Valuation PRICE TARGET SCENARIOS



5.4% 18.6X $4,034 $33.00 89% Net Income 185.7 253.8 (115.1) 57.7 302.0 73.0 19.8 123.2 183.5


9.4% 10.6X $3,475 $28.00 60% Capitalized Interest 34.1 48.7 41.3 16.2 - - - - -

11.4% 8.8X $3,236 $26.00 49% Deferred Taxes (4.6) (33.6) (182.5) 4.5 17.8 4.3 1.2 7.2 10.8

13.4% 7.5X $3,019 $25.00 43% Translation Adjustment Other 23.7 37.6 53.6 419.5 65.0 65.0 65.0 65.0 65.0

15.4% 6.5X $2,822 $23.00 31% Operating Cash Flow (before working cap.) 486.6 577.6 119.9 889.4 744.3 529.2 473.1 588.4 651.5

17.4% 5.8X $2,643 $22.00 26% Net Cash from Investing Activities (674.8) (562.8) (1,936.2) (749.7) (173.2) (151.8) (145.7) (261.7) (376.3)

19.4% 5.2X $2,480 $20.00 14% Capitalized Interest (34.1) (48.7) (41.3) (16.2) - - - - -

21.4% 4.7X $2,331 $19.00 9% Capitalized G&A - - - - - - - - -

23.4% 4.3X $2,195 $18.00 3% Less: Net Capital Expenditures (before Cap Int) 640.6 514.1 1,894.9 733.5 173.2 151.8 145.7 261.7 376.3

Working Capital Change (58.8) 95.5 344.4 12.4 27.6 29.8 (1.5) (24.0) (2.5)

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 866.5 - 792.7 - - - - - -

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (961.7) (32.0) (2,912.1) 143.5 543.5 347.5 328.9 350.6 277.7















December 15, 2015 224











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6G 14 100% 3,077 52% 19%

5G - -- - -- --

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Gross GFV, Current 14 100% 3,077

Other Assets 265

Liabilities & Dividends (2,916)

NAV 427

Shares Outstanding 211

NAV/Share 2.03

Last Price 0.97

P/NAV 48%

Pacific Drilling: Hold, $3PT, High Risk, High Return Investment Thesis

We are initiating coverage of PACD with a Hold rating and $3 price target. Our Hold rating overrides the valuation parameters of our ratings framework, as we consider PACD a special situation with heightened risk. We look for more near term clarity on new contracts and credit issues to review our ratings exception. Under the assumption that PACD survives the downturn, we see significant upside in the shares, especially de-risked from our current ~32% WACC. That said, balance sheet concerns and fleet utilization risks, as all but two rigs roll off contract by the end of 2016, drive our Hold rating, overriding our valuation discipline. Without new contracts, we see PACD likely to break recently adjusted covenants. Potential suitors may be attracted to the top quality fleet, but may not want to assume PACD’s debt and cost of carry for uncontracted rigs. Thus, we see a lower probability of a positive catalyst for the company as an acquisition target.


PACD debt trades above a 20% yield to worst, as the company carries a 50%+ net debt to capital and other deteriorating leverage ratios We forecast the company remains cash flow positive, but our forecast remains at risk as contracts roll off in the challenging market. The cancellation of the Pacific Zonda saves the payment of $381.5 million remaining for the rig, which helps the cash flow profile. The current negotiations/arbitration process for the recovery of $181 million paid for the Zonda may take up to two years to conclude. Likewise, access to $500 million under 2013 Revolving Credit Facility remains positive, as the facility was increased from $300 million and Total Debt / EBITDA ratio covenants were stepped up to between 5-6X over the course of 2016-2017. If PACD is not able to find contracts for idle rigs and those running off contract, the revised covenants may be breached. We see the next debt maturity for the $500 million of Senior Secured Notes on December 2017, too far off to pose a near term risk to the shares.


• Idle rigs, Pacific Mistral and Pacific Meltem, and roll off of contracts for the Pacific Khamsin, Pacific Bora, and Pacific Scirocco through 2016 remain an overhang on PACD shares. We assume all but one are working by the beginning of 2017.

• Negative news of contract cancellations, etc. may severely impact the cash flow outlook for the company.

Retirements Forecast

• We do not expect retirements from PACD’s 6G floater fleet.


S&P B- NO -- Nov 2015

Moody’s Caa2 NO Downgrade Oct 2015

December 15, 2015 226

Pacific Drilling (PACD) Model Income Statement ($ Millions) 2013 2014 2015 2016 2017 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17

Contract Drilling Revenues 745.6 1,085.8 1,079.4 766.8 910.2 283.4 273.9 260.2 261.9 193.2 193.2 185.1 195.3 197.0 202.7 246.6 264.0

Total Revenues 745.6 1,085.8 1,079.4 766.8 910.2 283.4 273.9 260.2 261.9 193.2 193.2 185.1 195.3 197.0 202.7 246.6 264.0

Operating Expenses (337.3) (459.6) (429.6) (366.4) (488.3) (117.7) (110.4) (98.3) (103.2) (87.2) (87.7) (89.0) (102.4) (113.2) (115.1) (129.6) (130.4)

SG&A (48.6) (57.7) (55.7) (37.4) (44.4) (16.4) (13.3) (13.2) (12.8) (9.4) (9.4) (9.0) (9.5) (9.6) (9.9) (12.0) (12.9)

Depreciation (149.5) (199.3) (243.9) (272.8) (284.9) (57.1) (57.2) (61.5) (68.1) (68.1) (68.2) (68.2) (68.3) (74.0) (68.6) (73.8) (68.6)

EBIT 210.2 369.2 350.2 90.2 92.6 92.3 92.9 87.2 77.9 28.5 27.8 18.9 15.1 0.1 9.1 31.2 52.2


Other (gain on asset sale) (1.6) (5.2) (3.3) (1.8) (1.8) (2.1) (0.3) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5)

EBT 114.6 233.9 190.5 (90.8) (85.9) 53.5 59.4 50.3 27.3 (16.8) (17.4) (26.5) (30.1) (45.0) (35.8) (13.2) 8.1

Income Tax (22.5) (45.6) (31.3) (23.3) 15.9 (1.8) (12.3) (9.3) (7.8) (5.9) (5.9) (5.6) (6.0) 8.4 6.6 2.5 (1.5)

Net Income (Operating) 92.1 188.3 159.3 (114.1) (69.9) 51.7 47.1 41.0 19.4 (22.7) (23.3) (32.1) (36.1) (36.7) (29.1) (10.8) 6.6

Extraordinaries (after-tax) (66.6) - - - - - - - - - - - - - - - -

Net Income (GAAP) 25.5 188.3 159.3 (114.1) (69.9) 51.7 47.1 41.0 19.4 (22.7) (23.3) (32.1) (36.1) (36.7) (29.1) (10.8) 6.6

EPS (Operating) 0.42 0.86 0.75 (0.54) (0.33) 0.24 0.22 0.19 0.09 (0.11) (0.11) (0.15) (0.17) (0.17) (0.14) (0.05) 0.03

EPS (GAAP) 0.12 0.86 0.75 (0.54) (0.33) 0.24 0.22 0.19 0.09 (0.11) (0.11) (0.15) (0.17) (0.17) (0.14) (0.05) 0.03




EBITDA 359.7 568.5 594.1 363.0 377.5 149.4 150.2 148.6 146.0 96.6 96.0 87.1 83.4 74.1 77.6 105.0 120.8

Depreciation & Amortization 0.2 0.2 0.2 0.4 0.3 (0.2) (0.2) (0.2) (0.3) (0.4) (0.4) (0.4) (0.3) (0.4) (0.3) (0.3) (0.3)



Capital Expenditures (876.1) (1,136.2) (167.6) (16.0) (20.0) (57.5) (44.6) (41.2) (24.3) (6.5) - - (9.5) (5.1) (5.0) (5.0) (4.9)

Free Cash Flow (FCF) (645.6) (739.8) 302.4 168.6 145.4 90.4 16.0 112.7 83.3 76.4 45.1 39.8 7.2 19.1 32.9 29.7 63.7

Acquisitions/Divestures/Investments 161.2 12.9 - 181.1 - - - - - - - - 181.1 - - - -


Other (265.9) (12.8) (0.6) (0.7) (0.8) (0.0) (0.4) (0.0) (0.1) (0.1) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2)

Increase (Decrease) in Cash (401.8) (36.3) 43.1 71.6 59.2 (34.9) (27.6) 45.8 59.8 52.6 21.0 15.3 (17.4) (2.0) 11.5 8.0 41.7


Total Capital 4,830.8 5,729.1 5,629.1 5,417.9 5,261.7 5,651.8 5,659.8 5,633.1 5,629.1 5,582.6 5,535.2 5,478.6 5,417.9 5,360.1 5,309.6 5,277.1 5,261.7

Total Debt 2,477.6 2,821.8 2,864.7 2,587.0 2,512.2 3,042.2 3,004.6 2,938.0 2,914.6 2,891.0 2,867.0 2,842.8 2,637.2 2,616.3 2,595.1 2,573.5 2,551.7

Net Debt 2,226.7 2,982.4 2,703.8 2,354.8 2,210.2 2,909.3 2,899.3 2,787.0 2,703.8 2,627.5 2,582.6 2,543.0 2,354.8 2,335.9 2,303.2 2,273.7 2,210.2


Net Debt/Capital 46.1% 52.1% 48.0% 43.5% 42.0% 51.5% 51.2% 49.5% 48.0% 47.1% 46.7% 46.4% 43.5% 43.6% 43.4% 43.1% 42.0%


BVPS 11.05 11.83 12.83 13.20 12.86 12.21 12.58 12.79 12.89 12.78 12.67 12.51 13.20 13.02 12.89 12.83 12.86

TBVPS 11.05 11.83 12.83 13.20 12.86 12.21 12.58 12.79 12.89 12.78 12.67 12.51 13.20 13.02 12.89 12.83 12.86

December 15, 2015 227

Pacific Drilling (PACD) Valuation PRICE TARGET SCENARIOS



23.8% 4.2X $638 $3.10 220% Net Income 34.0 25.5 188.3 159.3 (114.1) (69.9) 150.8 197.6 157.7

25.8% 3.9X $634 $3.10 220% Depreciation & Amortization 127.7 149.5 199.3 243.9 272.8 284.9 283.5 286.4 289.3

27.8% 3.6X $630 $3.00 209% Capitalized Interest - 2.1 9.0 35.7 - - - - -

29.8% 3.4X $626 $3.00 209% Deferred Taxes (3.8) (2.5) 18.7 1.3 - - - - -

31.8% 3.1X $620 $3.00 209% Translation Adjustment Other (5.8) 46.0 16.0 (30.1) - - - - -

33.8% 3.0X $615 $3.00 209% Operating Cash Flow (before working cap.) 152.1 220.6 431.3 410.0 158.7 215.0 434.3 484.0 447.1

35.8% 2.8X $608 $2.90 199% Net Cash from Investing Activities (245.2) (715.0) (1,123.3) (167.6) 165.1 (20.0) (192.4) (245.9) (301.8)

37.8% 2.6X $602 $2.90 199% Capitalized Interest - (2.1) (9.0) (35.7) - - - - -

39.8% 2.5X $595 $2.90 199% Capitalized G&A - - - - - - - - -

41.8% 2.4X $588 $2.80 189% Less: Net Capital Expenditures (before Cap Int) 245.2 712.8 1,114.3 131.9 (165.1) 20.0 192.4 245.9 301.8

Working Capital Change 32.9 12.1 (25.9) 95.8 25.9 (49.5) (27.1) 7.6 2.3

Weighted Average Cost of Capital (WACC) Change in Debt/Preferred 578.7 176.3 710.6 (237.0) (277.4) (85.5) (100.8) (65.8) (29.2)

Notional Tax Rate 35.0% Levered Free Cash Flow from Operations (704.7) (680.5) (1,367.7) 419.4 575.3 330.0 369.8 296.3 172.1








Net Debt/Total Capital 25.0% Subtract: Changes in Equity for Explict Forecast (0.8)


Terminal Multiple: 3.1X Terminal Value (1) (1,229.0)

Levered Free Cash Flow (2) 575.3 330.0 369.8 296.3 (1,056.8)




December 15, 2015 228











December 15, 2015 229

IMPORTANT DISCLOSURES

Rating System

Risk FactorsMacro:

Sustained weakness in commodity prices. Persistent weakness in commodity prices may negatively impact oilfield service company returns. This risk is magnifiedfor companies with weaker balance sheets and higher near term liabilities.

Access to capital markets: The ability of many oilfield service companies to withstand the downturn hinges on their access to capital. If capital markets beginto close off to the industry it would be difficult for many companies to maintain their existing operating plans.

Foreign exchange volatility. The sector’s international component leaves earnings exposed to foreign exchange volatility.

Climate change regulation. The increased attention on climate change and greenhouse gas (GHG) emissions could lead to new regulations aimed at limitingfuture GHG emissions. If enacted these regulations could impose additional costs for both operators and service providers.

Company Centric:

Contracting risk: The new and rolling contracts across the oil services business may perpetuate lower dayrates and falling contract pricing, even if renegotiationsoccur during the initial phases of a recovery.

Continued oversupply in rig market: Day rates could remain depressed if the rig market remains oversaturated resulting from fewer rig retirements thanforecasted.

Rig productivity gains: If onshore rigs continue to achieve new productivity gains, the demand for onshore rigs could continue to deteriorate, particularly inthe lower end of the onshore rig market. Greater levels of efficiency and productivity gains may

Lumpy Cash Flows: The lumpy nature of the equipment & manufacturing industry could cause a significant lag between the recovery in the oil and gas industryand the improvement in the equipment & manufacturing industry’s cash flow position.

Cost Escalation: Fixed price long term contracts common in the oilfield equipment & manufacturing leave industry participants particularly vulnerable to costincreases. This risk could be magnified for contracts entered into during a low price environment.

Adoption of new technologies: Many proppant providers are relying on new technologies to improve margins. However, there is a risk that the industry maycontinue to prefer lower cost options. Alternatively, the industry could select a single new technology winner with the losers going the way of the Beta Max video.

Other Companies Mentioned in this ReportC&J Energy Services, Ltd.(CJES) - Rating: Buy; Price Target: 7.50; Price: 4.56Core Laboratories N.V.(CLB) - Rating: Buy; Price Target: 155.00; Price: 116.03CARBO Ceramics Inc.(CRR) - Rating: Hold; Price Target: 15.25; Price: 16.10Diamond Offshore Drilling Inc(DO) - Rating: Accumulate; Price Target: 24.00; Price: 20.87Forum Energy Technologies Inc(FET) - Rating: Buy; Price Target: 19.00; Price: 12.40Franks International NV(FI) - Rating: Buy; Price Target: 23.00; Price: 15.69Fairmount Santrol Holdings Inc(FMSA) - Rating: Hold; Price Target: 2.30; Price: 2.43FMC Technologies, Inc.(FTI) - Rating: Buy; Price Target: 43.00; Price: 29.18Halliburton Company(HAL) - Rating: Accumulate; Price Target: 46.00; Price: 36.55Helmerich & Payne, Inc.(HP) - Rating: Buy; Price Target: 78.00; Price: 51.96Nabors Industries Ltd.(NBR) - Rating: Buy; Price Target: 13.00; Price: 8.63National-Oilwell Varco, Inc.(NOV) - Rating: Buy; Price Target: 52.00; Price: 33.56Newpark Resources Inc(NR) - Rating: Buy; Price Target: 7.25; Price: 4.83Oil States International, Inc.(OIS) - Rating: Buy; Price Target: 43.00; Price: 29.11Patterson-UTI Energy, Inc.(PTEN) - Rating: Buy; Price Target: 23.00; Price: 14.72Schlumberger Limited.(SLB) - Rating: Buy; Price Target: 105.00; Price: 70.02U.S. Silica Holdings Inc(SLCA) - Rating: Hold; Price Target: 20.00; Price: 20.04Superior Energy Services, Inc.(SPN) - Rating: Buy; Price Target: 21.00; Price: 13.52Weatherford International Plc(WFT) - Rating: Accumulate; Price Target: 10.25; Price: 8.73Dril-Quip, Inc.(DRQ) - Rating: Accumulate; Price Target: 75.00; Price: 58.24ENSCO PLC(ESV) - Rating: Buy; Price Target: 20.00; Price: 15.19Flotek Industries Inc(FTK) - Rating: Buy; Price Target: 14.50; Price: 10.92Noble Corp plc(NE) - Rating: Buy; Price Target: 16.00; Price: 11.99Oceaneering International(OII) - Rating: Accumulate; Price Target: 49.00; Price: 37.60Pacific Drilling SA(PACD) - Rating: Hold; Price Target: 3.00; Price: 0.94Rowan Companies PLC(RDC) - Rating: Buy; Price Target: 25.00; Price: 18.02Transocean LTD(RIG) - Rating: Buy; Price Target: 19.00; Price: 12.64Seadrill Ltd(SDRL) - Rating: Reduce; Price Target: 3.50; Price: 4.00Atwood Oceanics, Inc.(ATW) - Rating: Hold; Price Target: 12.50; Price: 12.20

December 15, 2015 230

For ratings and price target history please visit http://www.klrgroup.com/research/disclosure/.

Distribution of RatingsIB Serv./Past 12 Mos.

Rating Count Percent Count PercentBuy 55 69.62 0 0Accumulate 9 11.39 0 0Hold 10 12.66 0 0Reduce 1 1.27 0 0Sell 4 5.06 0 0

Additional DisclosuresKLR Group, LLC is a member of FINRA and SIPC and a registered U.S. Broker-Dealer.

Investment Banking services include, but are not limited to, acting as a manager/co-manager in the underwriting or placement of securities, acting as financialadvisor, and/or providing corporate finance or capital markets-related services to a company or one of its affiliates or subsidiaries within the past 12 months.

Analyst CertificationI, Darren Gacicia, hereby certify that the views expressed in this research report accurately reflect my personal views about the subject company(ies) and its(their) securities and that no part of my compensation was, is, or will be, directly or indirectly, related to the specific recommendations or views expressedby me in this research report.The Firm and/or its affiliates intend(s) to seek compensation from Atwood Oceanics, Inc., C&J Energy Services, Ltd., Core Laboratories N.V., CARBO CeramicsInc., Diamond Offshore Drilling Inc, Dril-Quip, Inc., ENSCO PLC, Forum Energy Technologies Inc, Franks International NV, Fairmount Santrol Holdings Inc,FMC Technologies, Inc., Flotek Industries Inc, Halliburton Company, Helmerich & Payne, Inc., Nabors Industries Ltd., Noble Corp plc, National-Oilwell Varco,Inc., Newpark Resources Inc, Oceaneering International, Oil States International, Inc., Pacific Drilling SA, Patterson-UTI Energy, Inc., Rowan Companies PLC,Transocean LTD, Seadrill Ltd, Schlumberger Limited., U.S. Silica Holdings Inc and Superior Energy Services, Inc. for investment banking services within threemonths, following publication of the research report.

Any opinions expressed herein are statements of our judgment as of the date of publication and are subject to change without notice.

Reproduction without written permission is prohibited.

The closing prices of securities mentioned in this report are as of Dec 14 2015. Additional information is available to clients upon written request.For completeresearch report on Atwood Oceanics, Inc., C&J Energy Services, Ltd., Core Laboratories N.V., CARBO Ceramics Inc., Diamond Offshore Drilling Inc, Dril-Quip,Inc., ENSCO PLC, Forum Energy Technologies Inc, Franks International NV, Fairmount Santrol Holdings Inc, FMC Technologies, Inc., Flotek Industries Inc,Halliburton Company, Helmerich & Payne, Inc., Nabors Industries Ltd., Noble Corp plc, National-Oilwell Varco, Inc., Newpark Resources Inc, OceaneeringInternational, Oil States International, Inc., Pacific Drilling SA, Patterson-UTI Energy, Inc., Rowan Companies PLC, Transocean LTD, Seadrill Ltd, SchlumbergerLimited., U.S. Silica Holdings Inc and Superior Energy Services, Inc., please call (713) 654-8080.

Readers are advised that this report is issued solely for informational purposes and is not to be construed as an offer to sell or the solicitation of an offer to buy.The information contained herein is based on sources which we believe to be reliable but is not guaranteed by us as being accurate and does not purport tobe a complete statement or summary of the available data. Past performance is no guarantee of future results.

December 15, 2015 231

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