16 October 2012 Americas/United States Equity Research Oil & Gas Equipment & Services

Oilfield Services Research Analysts INITIATION James Wicklund 214 979 4111 [email protected] Wait 'til You See the Whites of Their Eyes Jonathan Sisto 212 325 1292 Exhibit 1: Credit Suisse’s 16-Year Aggregate Timing Model [email protected] 15.0% 8.0% Brittany Commins Large Cap 6.0% Equipment 212 325 7128 10.0% Land Rigs [email protected] 4.0% Offshore Rigs 5.0% 2.0% Mid Small Cap Offshore Service 0.0% 0.0% Seismic Workover -2.0% -5.0% Construction -4.0% Boats

-10.0% AVG -6.0% US Rig Seasonality

-15.0% -8.0% Source: Company data and Credit Suisse.

■ Our View: Oilfield service stocks generally trade sideways for the balance of the year, typically against a rising rig count. Not only is the rig count dropping but it is likely to continue dropping for at least the next four to six months. Pricing, which many thought had bottomed, has taken another step down, the extent of which was only known to management after they closed the books for the quarter. This sets up earnings disappointment and we think earnings and expectations get reset. Other than the relative safety of the equipment sector, we see no reason to chase the stocks into year-end. ■ Differentiation: We are clearly positive on the longer-term, almost “secular,” growth potential of domestic drilling. While well-to-well consistency has still eluded the industry, the ability to produce shale/tight sands is still under- appreciated. But the capex requirements for the service industry have been huge and the industry is significantly under-capitalized for the international shale boom. That continuing high capital outlay is at the expense of returns and any DCF-based valuation having a significant impact on valuation and sector multiple differentiation. Something has to give, and it is never pretty. ■ Stock Calls: North American (NAM) services are seeing falling volume and price—never a good combination. HAL and BHI are most effected, SLB next, followed by WFT, under our coverage. Althoguh a bit crowded and already popular, the equipment companies should continue to outperform, especially through year-end. We are initiating on CAM and HAL at Outperform and on BHI, FTI, SLB, and WFT at Neutral. When the market can better discount the price dynamics and the activity dynamics, we believe investors will come back to the stocks. For now, we are neutral on the sector through year-end.

DISCLOSURE APPENDIX CONTAINS ANALYST CERTIFICATIONS AND THE STATUS OF NON-US ANALYSTS. U.S. Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS BEYOND INFORMATION™ Client-Driven Solutions, Insights, and Access

16 October 2012 Oil Services Initiation Highlights We are initiating coverage of the oilfield service and equipment space with a Market Weight position.

Exhibit 2: Credit Suisse Oilfield Services & Equipment Coverage Universe 10/15/2012 Market Target Upside / Company Ticker Rating Price Cap ($MM) Price ($) Dow ns ide Jim Wicklund & Team Baker Hughes Inc. BHI Neutral $44.77 $19,679 $40 -11% Halliburton Company HAL Outperform $33.80 $31,358 $44 30% Schlumberger Limited SLB Neutral $72.19 $95,798 $66 -9% Weatherford International Ltd. WFT Neutral $12.17 $10,218 $11 -10% Cameron International Corp. CAM Outperform $53.22 $13,107 $75 41% Forum Energy Technologies Inc. FET Restricted $22.70 $1,946 FMC Technologies, Inc. FTI Neutral $44.02 $10,494 $49 11%

Source: Bloomberg, Company data, and Credit Suisse estimates. Note: CS initiated coverage of Forum Energy Technologies (FET) in May 2012. Top Idea: Cameron International (CAM). It is risky because it is difficult to predict when or how management will fail to execute, but that is about the only thing that could get in the way. The company’s market positions have improved from regulation, acquisition and organic growth and with the longer-term growth potential in all types of manufacturing, as unappreciated as is the huge shift in capital allocation by the industry, it is in a number of sweet spots. We are initiating coverage of Halliburton (HAL) with an Outperform rating, though it is a bit qualified bias. The volatility to earnings from changes in price and activity in NAM completions is huge, and they are the biggest player. When both are going down, as they are now, get out of the way. When things are going up, load the boat. “When” is the issue and we are not sure it is now. We have discounted our computed multiple for HAL to risk that exposure yet still the valuation is exceptionally compelling. The company’s ability to generate improving returns and free cash flow will be a key issue. But overall, top management, excellent technology, and geographic depth are all distinct positives. It is just that things get better much more slowly than they get worse. We are initiating coverage of FMC Technologies (FTI) with a Neutral rating. FMC is the premier subsea equipment provider in the industry—period. A now $12 billion company that is the industry leader in the most defined growth sector is an enviable position. The increased number of rigs times the increased success rates of drilling equal higher and faster growth. But no company can wait for the future so growth is taking on some different directions. A problem contract lingers. Subsea pricing improvement is quarters away from hitting the income statement. Fabulous company but our valuation framework values it neutral. We are initiating coverage of Schlumberger (SLB) with a Neutral rating. SLB has been the 900-pound gorilla in the business forever. They lead the industry in technology, reach, and culture, with a huge number of ex-SLB people populating the top ranks of other service companies. It has the least NAM onshore service business of the Big 3, offshore is doing well, they own Russia and the seismic business has the best fundamentals of the industry right now and WesternGeco is the largest. But according to our matrix of valuation multiple versus economic return, SLB near-term appears over-valued. Trading at a ~60% premium to the closest peer that has better returns is difficult to justify. SLB could accelerate its returns and boost our valuation but our analysis shows that not likely to happen in 2013. We are initiating coverage of Weatherford International (WFT) with a Neutral rating. WFT is in limbo. It is too dangerous to be long or short. Longer term, we think long but there are hurdles ahead. Unabashed growth without enough back office discipline and

Oilfield Services 2 16 October 2012 culture makes it the poster child of ramped-up capex at the expense of returns, and the ensuing crash. Fixes are being made but culture takes time. It isn’t enough to generate free cash flow, WFT has to have the processes, procedures and discipline to better manage capital. Hard to recommend without current financials. We are initiating coverage of Baker Hughes (BHI) with a Neutral rating. BHI is working on fixing a few things. When wheels come off in a slowing market, it is a double whammy. BHI will fix the pressure pumping business but first it needs some bigger customers with all that implies. Supply chain now under one roof is a big improvement. The cultural shift from product to geomarket always takes longer than expected but is well along. Martin is doing well. But the industry macro is not being BHI’s friend and while the company is right to try and gain better customers, it comes at a near-term cost. Divergence. Equipment design and manufacture overall well see excellent fundamentals for some time. The interruption of business from Macondo was longer lasting and slower coming back than had been hoped or expected. The ripple effect affected all market. Bids were lower with more concern about keeping a shop open than generating good margins. That has worked its way pretty much through the system. The consolidation has been fast and furious in the small private world. No so with service. Costs have hurt returns, low interest rates have fostered significant competition, a falling U.S. rigs count hurts. Preference. The DCFs of the equipment companies generally show significant upside from current values. Virtually all the service companies are under-water on the calculation. Different businesses have different dynamics but the DCF just looks at value from free cash flow. And that is the issue. The service companies have increased capex significantly over the past three to five years while returns have steadily dropped generating little, if any, free cash flow. The industry has changed. The capital equipment needed for the development of North American shale/tight sands reservoirs is huge. We see the well costs and think of the huge service cost inflation but much of that inflation is the service companies investing in the capital equipment they need to provide the service. And it will continue. We are significantly under-capitalized, as a service industry, for the eventual international shale boom. That is a key statement. We are going to have to do it all again for the international markets and keep it up, just like here. It is continual manufacturing that does not get to take much advantage of centralized locations. Pads versus factories? You do not get the leverage so it is a broader cost base. The risk is that free cash flow stays scarce, the intrinsic value of the company declines and the stock trades at an ever lower multiple. We will really like the service companies at some point but the market has a great deal to digest in the near term.

Exhibit 3: Credit Suisse 3Q12 Estimates versus the Consensus 3Q12E EPS 2012E EPS Company Ticker Rating TP $ Credit Suisse Street % Difference Credit Suisse Street % Difference

Baker Hughes BHI Neutral $40 $0.82 $0.84 -2.0% $3.57 $3.62 -1.3% Halliburton HAL Outperform $44 $0.65 $0.67 -3.4% $3.04 $3.10 -2.0% Schlumberger Ltd. SLB Neutral $66 $1.05 $1.06 -1.3% $4.19 $4.24 -1.2% Weatherford Int.'l WFT Neutral $11 $0.22 $0.24 -9.5% $0.93 $1.00 -7.0%

Cameron Int.'l CAM Outperform $75 $0.90 $0.88 2.0% $3.29 $3.24 1.5% FMC Technologies FTI Neutral $49 $0.57 $0.57 -0.2% $2.09 $2.08 0.3% Source: Bloomberg and Credit Suisse estimates

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Exhibit 4: Capital Expenditures ROC Indexed to 2006

400 Indexed to 350 2006, the four large cap service 300 stocks. No 250 wonder multiples have dropped 200

150

100 Capex 50 Return on Capital 0

Source: Company data, Credit Suisse estimates Timing is Everything. We have revived our Timing Model. Any time a statistical sampling as broad and deep as this generates a 16% spread in normalized 12 month period gets our interest. Exhibit 1 on page one shows the variance of the weekly stock price from its annual average rather than year-end to normalize out trend factors and isolate seasonality. It shows that for the last few months of the year, the stock trade generally sideways. The seasonality of the U.S. rig count is also shown and typically, the rig count moves up through the end of the year. But not this year. Budgets are exhausted. NGL prices dropped much farther than oil prices in May and has had a much greater impact than expected. The third quarter rig count will be below the annual average for the fourth time in 20 years, on par with 2009, 2001, and 1997. Those were not good years for the business. So with a rising rig count keeping the stock prices steady, one has to wonder what happens with a declining rig count. Pricing & Activity. Again, looking at the rig count seasonality, the rig count typically declines through the first quarter as winter weather raises the cost of operations so it is deferred and there is less urgency to spend budgets, as there usually is in the preceding fourth quarter (not this time). This means that the U.S. rig count is likely to decline for the next six months while still battling and over-capacity issue in several product lines. Difficult. Which brings us to pricing. The OFS companies are optimists and positive—pricing will hold up. They can tell you why it should, why it will, less about why they need and want it to. But in the end, pricing will do what it does. By the time the OFS managements see the quarterly pricing, the quarter is over and the quiet period has begun. So the resulting earnings announcement is a disappointment, barring a pre-announcement. We think that happened to some degree in the third quarter. A declining rig count was generally expected as it fell through the quarter but the was a great deal of optimism on pricing. We think the earnings announcements will disappoint. And while investors can calculate and discount future levels of activity with some confidence, it is difficult to do that with pricing and it has a much greater impact.

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Exhibit 5: NGL Prices Indexed to 2003

160

140

120

100

80

60 Oil

40 Ethane Liquid rich drilling gets Butane 20 negatively impacted and not alleviated soon Propane Mt Bel 0

Source: Bloomberg Rig Counts & Forecasts. We expect the U.S. rig count will be down about 4.8% in 2013, from an average of 1,930 this year to an average of 1,840 for next year. We expect the rig count to decline over the next six months before beginning to improve around the end of Q1 2013. We expect the dry gas rig count to basically stay flat, with little drilling left to shut down. We expect the oil rig count to decline slightly owing to current forward pricing expectations and continued weakness in “liquids rich” NGLs. Demonstrating the continuing rig efficiency, footage and wells drilled should, we believe, be flat in 2013 with 2012 levels. For the balance of the year, we are optimistically hoping the rig count stays flat. That means our rig count forecast is best case. Internationally, we expect a continued slow grind higher being driven primarily by new offshore rigs in both shallow and deepwater, with the total count averaging 1,200, up from 1,194 in 2012. Africa, with the recovery of activity in Libya and Algeria and increased drilling on both coasts should lead in growth.

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Exhibit 6: Rate of Change—U.S. Rig Count

Source: Company data, Credit Suisse estimates Commodity Prices. Rather than getting into endless, detailed, opinionated analysis of supply/demand models for oil and gas, we are taking a simplified approach. Swing producers are just that and the primary swing producer needs to get $97 Brent. And at $97 Brent is okay for our forecast. Regional price hubs will have wide arbitrage swings until additional infrastructure is added, but that price works and I figure that a higher price than they need isn’t something they will try and fix aggressively near term. We use the strip, which moves, but a great deal of E&P forward planning is based on the strip, which can be hedged to make their plans. So, pay attention to the strip. And then of course the Credit Suisse commodity team has a view, putting its Brent forecast at $115/barrel for 2013 and $100 for 2014.

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Exhibit 7: Credit Suisse Global Rig Count Forecast, 2006–2013E Credit Suisse Rig Count Forecasts 2006 2007 2008 2009 2010 2011 2012E 2013E United States Oil 273 289 379 275 586 980 1,363 1,335 % Chg yr/yr 41% 6% 31% -27% 113% 67% 39% -2% Gas 1,370 1,465 1,489 799 950 888 564 581 % Chg yr/yr 16% 7% 2% -46% 19% -7% -37% 3% Misc. 4 12 9 11 3 7 5 -72 Total U.S. 1,647 1,766 1,877 1,085 1,539 1,875 1,931 1,844 % Chg yr/yr 19% 7% 6% -42% 42% 22% 3% -5% % Oil 17% 16% 20% 25% 38% 52% 71% 72% % Gas 83% 83% 79% 74% 62% 47% 29% 32%

Land 1,535 1,669 1,792 1,034 1,493 1,826 1,864 1,808 % Chg yr/yr 22% 9% 7% -42% 44% 22% 2% -3% Offshore 90 77 65 44 31 32 48 57 % Chg yr/yr -4% -14% -16% -32% -30% 3% 50% 18% Inland Waters 22 20 20 7 15 17 19 19

Vertical 980 998 952 429 494 573 554 532 % Chg yr/yr 14% 2% -5% -55% 15% 16% -3% -4% Horizontal 283 393 553 454 819 1,072 1,158 1,149 % Chg yr/yr 57% 39% 41% -18% 80% 31% 8% -1% Directional 384 375 372 202 226 230 219 203 % Chg yr/yr 13% -2% -1% -46% 12% 2% -5% -7%

% Horizontal 17% 22% 29% 42% 53% 57% 60% 62%

Canada 470 343 385 223 346 423 341 409 % Chg yr/yr 3% -27% 12% -42% 55% 22% -19% 20%

North American Total 2,117 2,109 2,262 1,308 1,885 2,298 2,272 2,253 % Chg yr/yr 15% 0% 7% -42% 44% 22% -1% -1% % of Worldwide Total 70% 68% 68% 57% 63% 66% 65% 65%

Wells Drilled Oil 13,118 13,361 16,645 11,261 16,254 21,709 29,587 29,365 % Chg yr/yr 23% 2% 25% -32% 44% 34% 36% -1% Gas 32,650 32,719 32,274 18,234 16,973 14,917 10,790 9,691 % Chg yr/yr 16% 0% -1% -44% -7% -12% -28% -10% Dry 5,244 4,978 5,428 3,552 4,277 4,492 5,132 4,849 % Chg yr/yr 12% -5% 9% -35% 20% 5% 14% -6% Total Wells Drilled 51,012 51,058 54,347 33,047 37,504 41,118 45,509 43,905 % Chg yr/yr 17% 0% 6% -39% 13% 10% 11% -4%

Footage Drilled 282,764 301,453 334,442 239,491 269,374 315,502 392,146 386,544 % Chg yr/yr 18% 7% 11% -28% 12% 17% 24% -1% Footage per total wells drilled 5.55.96.27.27.27.78.68.8 % Chg yr/yr 0% 7% 4% 18% -1% 7% 12% 2%

International Europe 77 78 98 84 94 118 113 115 % Chg yr/yr 12% 1% 26% -14% 12% 26% -5% 3% Middle East 237 265 280 252 265 291 319 326 % Chg yr/yr 25% 12% 6% -10% 5% 10% 10% 2% Africa 58 66 65 62 83 78 107 114 % Chg yr/yr 16% 14% -2% -5% 34% -6% 37% 6% Latin America 324 355 384 356 383 424 432 435 % Chg yr/yr 3% 10% 8% -7% 8% 11% 2% 1% Asia Pacific 228 241 252 243 269 256 230 243 % Chg yr/yr 1% 6% 5% -4% 11% -5% -10% 5% International Total 924 1005 1079 997 1094 1167 1201 1233 % Chg yr/yr 9%9%7%-8%10%7%3%3% % of Worldwide Tota 30% 32% 32% 43% 37% 34% 35% 35%

Offshore 269 286 295 275 305 304 290 302 % Chg yr/yr 1% 6% 3% -7% 11% 0% -5% 4% % Offshore 29% 28% 27% 28% 28% 26% 24% 25% Worldwide Total 3,041 3,114 3,341 2,305 2,979 3,465 3,473 3,486 % Chg yr/yr 13% 2% 7% -31% 29% 16% 0% 0% Source: Baker Hughes, Credit Suisse estimates

Oilfield Services 7 16 October 2012 Oilfield Service & Equipment The domestic oil and gas industry is going through a mid-cycle correction, which is a bit of a misnomer since the industry is set to resume its most secular move in history, driven by the continued development of U.S. oil and gas shales and tight reservoirs The correction is being driven by lack of infrastructure and its impact on natural gas liquids (NGLs), the continued weakness in natural gas pricing, global economic concerns, and the potential impact on crude oil pricing. It is being exacerbated by an over-supply of completion equipment and the continued improvement in technical efficiency of completions techniques and technologies. We believe most of these issues will be generally resolved by mid-2013, although the historical seasonality of the sector, the concerns about E&P capital spending next year, and little impetus to increase activity through the end of the year, are keeping us generally on hold for the North American (NAM) services sector for the next few months. Offshore drilling and equipment, artificial lift, wireline, well construction, and other segments should do relatively better, while onshore rigs, pressure pumping services, and to some extent coiled tubing will remain more challenged segments. We will discuss the various technologies and geographies driving the global Oilfield Services industry in some detail; however, we want to first put the key global drivers into perspective. Hydrocarbons While we are big fans of alternative energy development, the economic reality is that fossil fuels will see increased global demand for the foreseeable future. The only question is the rate. Concerns about China’s economic landing, the EU’s stability, and global recession will still haunt commodity prices for the near term, global supply, especially outside the U.S., is in accelerating decline, which is a more definitive trend than near-term economics. While supply/demand/price arguments can rage for ages, we believe that if Saudi Arabia gets its target price for oil and the duration of LNG contracts are upheld, commodity prices will be high enough for continuing development of the resource base. Political and economic forces will continue to cause volatility in commodity prices and resulting activity but will be more likely to push long-term prices higher rather than lower. Oil & gas are political tools today and they will be used by all political parties for their benefit. Energy independence, even if not complete, improvements in balances of trade, job growth, and local manufacturing will all be hot buttons used to the overall benefit of the industry. North America The U.S. and overall NAM oil and gas business has never had such a positive outlook from a reserve and drilling perspective, and this should serve to translate the industry into the most secular growth mode seen in decades. About the only risk to a multiyear secular run by the industry is commodity price, which has always been influenced solely by changes in demand, until the most recent crash in natural gas prices, the first ever supply-induced shock to prices. Between the recent levels of natural gas drilling and completion equipment additions, the industry has proven again that it can overreact. Technology development continues to improve with increasing recovery from existing reservoirs and improving unit economics. The shale revolution sets up the perfect holy grail of interest by large oil companies: a huge resource base with incredible incremental

Oilfield Services 8 16 October 2012 returns from efficient operations and low costs of capital and reservoirs that can yield increased recovery of hydrocarbons in place over many years. The current over-capacity situation with pressure pumping equipment, coiled tubing, and other capital assets will eventually move into supply/demand balance; however, with the second tier players operating at about 70% of capacity utilization and the rig count falling, it may not be immediate. Even if the rig count stays static, from higher rig efficiency, increased pad drilling and other developments, well intensity will continue to push oilfield services revenues higher. However, the rig count currently is falling as is pricing so this could be masked for a bit. Natural Gas liquefaction is set to grow both on the U.S. Gulf Coast, as well as on the West Coast of Canada, meaning a higher price demand market awaits, eventually boosting and providing some support to domestic gas pricing. The volumes may not be large enough for a while to be a high or firm support. Some pundits warn that the high depletion rates seen in unconventional reservoirs are an over-hanging liability. These high depletion rates require continued high levels of drilling to maintain production, which is a positive for commodity pricing support and activity. But the industry has never had such a huge inventory of fairly homogeneous drilling locations, which serves to lessen the dire predictions of some observers. A number of new technologies have been developed specifically for shale development over the past few years, many of which are asset-lite, highly productive, and coming up for sale, which has interesting implications for the industry. It has allowed entrepreneurial engineers the ability to build and develop highly beneficial technologies without reliance upon the huge facilities and budgets of the major service and oil companies. International We have been waiting for international activity to ramp up for several years now. The international rig count, excluding Iraq, which just made it back into the Baker Hughes rig count this quarter, is up only 10% since the 2008 June quarter four years ago, just before the global financial meltdown. The offshore international rig count is down just over 6% over that same four-year period, even though the composition of the fleet has changed with the addition of 80 new jackups and 95 new floaters added to the rig fleet over that period. Much of the revenue growth internationally will be in deepwater, with at least 50 7,500’ additional floaters coming into the fleet over the next three years and the service intensity of these operations multiples of many international onshore operations. Saudi Arabia and Norway have historically been the leaders in new technology adaptation and we expect that to continue, moving higher technologies into the mainstream quickly due to their challenging needs and environments. Iraq is now being reported in the Baker Hughes rig count, and while we drop it out for many of our mathematical analyses owing to lack of history, it is becoming a greater focus. While security and logistical problems still abound, all of the larger service companies have a presence there and the long-term potential of the country could be meaningful. The largest service companies have been in a series of market share battles over the past two years in which there had typically been two companies battling for work, either SLB and HAL or SLB and BHI, with WFT and others involved a bit along the way. This has turned into a more intense battle between the top three in all markets, as BHI and HAL work to increase their global footprint. This is also being seen in the bidding for ultra-deepwater mega-projects that have contract durations of 5-10 years, where the future ability to upsell new technologies has made winning the contract initially a much more competitive exercise.

Oilfield Services 9 16 October 2012

Approximately 75% of all international drilling is still for oil. Gas shale potential has been identified in a broad range of countries. Royal Dutch Shell (RDS) will spend at least $1.0 billion a year on shale exploration in China. France has identified shale potential but it has a one-year renewable ban on hydraulic fracturing and is saying it will keep the ban until an alternative to fracking emerges. Australia, Argentina, Columbia, Poland, Turkey, South Africa, and Germany are just a few names on the list. Critical Points

■ The Brave New World Is Only Four Years Old: We all talk about how the shale revolution started in the mid-2000s to early 2000s, which we address later in the report. We started finding the shales, drilling horizontal wells, applying larger and larger fracs, and we can all point to Mitchell Energy in 2002 or others but that was the ground-swell. The revolution took up arms only four years ago. When the economic collapse hit in 2008, dropping the U.S. rig count at record rates, the industry had the chance to slow down and think about what we had found. As activity recovered, it was not a continuation of what had come before but a new game, a new world. The number of wells per drilling rig declined but the depth per well, because of the increasing horizontal length, exploded and is up 30% over the last four years.

■ Service Intensity Continues to Increase: More efficient rigs that walk and move quickly will better accommodate pad drilling, which will keep the bit in the hole more hours per month. More effective and efficient completion technologies will increase IPs and EURs, justifying their increase use and cost. Fewer people involved on the wellsite will reduce downtime, costs, and improve efficiencies. As we start to test the physical limitations of horizontal well lengths, increased well density and production efficiency will keep moving forward. As we move from drilling to hold acreage to drilling science projects to the efficiencies of cell manufacturing, the overall cost structure of the industry on a unit basis should continue to decline.

■ Scale Matters More than Ever: The bundled services and drilling for the 1990s concepts of the past did not fully catch on owing in part to the continuing changes in service needs as fields were discovered, drilled, completed, developed and abandoned, then started as a new cycle on the next field. The manufacturing nature of the unconventional development effort today changes the dynamic. The bigger, more integrated, with a more comprehensive supply chain, and greater worker depth companies are better positioned. The focus on optimizing localized operations while still incorporating benefits derived from other similar operations cannot be understated.

■ Capital Allocation is Increasingly Critical. Directional drilling and hydraulic fracturing that led to this Brave New World is capital intensive and expensive. Coiled tubing units, new walking rigs, additional horsepower, more pumps, water treatment are all expensive items. And instead of moving it around with drilling, the old paradigm, now we locate lots of it on one place and then need just as much in several other locations. The capital intensity is killing the returns of the OFS companies and with the expectation that the coming boom in international shale development will require a whole new area of capital equipment needs indicates that capex could be up for a long time. And like the E&P companies, those realized returns get pushed farther and farther out to the right, hurting near-term returns and multiples. We think this is the most critical issue for the industry over the next few years.

■ The growth in the offshore rig count is a correct proxy for the growth in all variables involved in the industry. More rigs means more pipe, more bits, more mud, more technology, more discoveries, more production, more subsea

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equipment, more FPSOs, more pipelines, more boats: more of everything. It is the inverse of scale. One could argue that success rates could fall, reducing the pull- through potential relative the growth in the rig count but there has been no degradation in success rates; they continue to move up, which actually grows demand faster than the nominal growth in rigs.

■ Valuation Metrics of the Past Will Probably Not Work as Well this Time: Historically, in a cyclical industry, one tries to calculate the mid-cycle or average through the cycle appropriate multiple for the group and buy the stocks when they are below that average. In a secular growth sector, especially one with a manufacturing bias, the primary drivers of valuation should be returns, on invested capital or assets, and the rate of earnings growth, metrics that were rarely applied successfully to the hyper-cyclical stocks of the sector over the past twenty years.

Exhibit 8: Exploratory Gas Well (% of Total)

Source: Energy Information Administration (EIA)

Exhibit 9: Footage Per Well

Source: Energy Information Administration (EIA) The upper chart shows the demise of exploratory drilling for natural gas. The brief respite was from the shale exploration effort early on until we went back into full development mode. That little bump up from 2004 to 2007 provided us with more natural gas reserves

Oilfield Services 11 16 October 2012 and well locations than had been discovered before. The second chart demonstrates increased footage per well, mostly horizontal. Outlook There is no question that we are positive on the outlook for the global oilfield services sector. The need to replace existing production, the continued global growth in demand, the difficulty in finding new reserves of scale, and the increasing need for technology to accomplish all the above. We have long said that at $250/barrel oil, the world has decades of supply. At $5/barrel, we will run out in no time. Somewhere in between is the economic balance and the market will find it. Timing. One thing that has always struck us is the difference in time frame between the industry and investors. “Quickly” can mean tomorrow for a hedge fund and quarters for an oil or oilfield services company. Against that backdrop, we are positive on the overall outlook but feel that for the next several months, there could be challenges. We expect the following: The U.S. rig count will continue to drift lower through the end of the year as confidence in near-term NGL, crude oil, and natural gas prices are not high enough to cause an end-of-year spending rush in NAM oil field service activity. Seasonally, the U.S. rig count fades into the first quarter, as winter weather increases operating costs and there is little urgency to spend annual budgets. Typically the rig count bottoms late in the first quarter. Thus, we expect the U.S. rig count to be flat to down through the end of the year and into 2013. As a result, we expect the year-over-year U.S. rig count to decline by 4.8% in 2013, the well count and footage to be flat but that also indicates a fairly strong recovery in the second half of next year. The nominal rig count is not the best indicator of activity with the evolution of long laterals in tight wells; therefore, we look at the well count and footage as better proxies and use an increasing rig intensity model for many of our projections.

Exhibit 10: OSX vs. 2nd Derivative of Eagle Ford Wellcount

180% $350 160% $300 140% $250 120% 100% $200

80% $150 60% 2nd Derivative $100 40% OSX $50 20% 0% $0

Source: I. Kudnt Risst and Bloomberg Drilling efficiency will continue to improve as new rigs replace older rigs and the older rigs get more upgraded. Directional drilling systems, microseismic technologies to better orient the lateral wellbore, more effective and time efficient sliding sleeve, and other completion technologies will all combine to improve the rig efficiency model and drive service intensity. The evolution towards manufacturing optimization and away from drilling should boost efficiency metrics as well.

Oilfield Services 12 16 October 2012

Canada’s anemic post-breakup recovery is well known and will likely not make a meaningful recovery through its seasonal drilling period. The recent spate of Canadian resource acquisitions should push activity there higher in the 2013 drilling cycle. On average, for the past 20 years, Canadian drilling recoveries have pushed the rig count higher by 25%. International activity will continue to grind higher with Saudi Arabia, Kuwait, Mexico, and the deepwater market of Brazil and both sides of Africa being the primary drivers. Columbia, Kuwait, the United Arab Emirates (UAE), and Saudi Arabia have all seen the largest increases in production recently. Obviously, the Middle East overall, including Iraq, is seeing a significant increase in activity and production with Latin America coming in second on a production growth momentum and efficiency basis. Our model shows the greatest rig count growth in North Africa, with the return to some level of normalcy in drilling after the Arab Spring, although the events in Libya put that recovery at risk, and the Middle East, with the return of Iraq to the rig count. The great decline comes from the Asia-Pacific area, with broad weakness in recent activity led by Indonesia. The equipment needs of the industry are getting increasingly complex as water depth, pressures, temperatures, government regulations, safety mandates and drilling and production efficiencies all move up the requirement curve. Drilling, intervention and completion, and production all have enormous sub-segments of technologies that have sprinted ahead in terms of development in the past five years. Moore’s Law has allowed the computer-aided and software operating efficiencies to be applied to oilfield equipment. Walking rigs on shore, dual activity rigs offshore, accelerating development of frac/completion technologies, 20,000 psi blowout preventers (BOPs), production in 10,000 feet of water were all dreams less than ten years ago. The capital needs of by industry of this equipment cannot be understated. The historically dominant companies have increasing competition. National Oilwell Varco (NOV) is the 900 pound gorilla in the industry whom everyone in the industry shoots against. The following chart [shows how the company has grown and consolidated the industry but also how the needs and demands of industry equipment have grown. A multitude of companies have been sharpening their knives to take on existing competition, distance themselves from rivals, vertically integrated product offerings, and to develop the next big thing.

Oilfield Services 13 16 October 2012

Exhibit 11: Relative Market Capitalization (Indexed to 2000)

Source: Bloomberg Coming Up the Curve Are an Array of Companies: Schlumberger (SLB) acquired the balance of Framo Engineering putting multiphase metering and pumping on the ocean floor, termed “an important step in the development of subsea technologies”. Cameron (CAM) buys LeTourneau, “enhancing growth opportunities in our drilling systems platform”. General Electric (GE) buys Vetco, Hydril, Sondex, and Wellstream and is starting to flex its muscles. Forum Technologies (FET) operates in six different equipment markets and has a stated acquisition strategy. Private companies are developing technologies and applications whose growth and value in a short amount of time was deemed impossible only a few years ago. The Digital Oilfield Is a Reality Now: It is said that more digital data are created every two days than the sum total that existed from the beginning of time until 2003. The oil and gas business is on the cutting edge of that. While the primary purview of geophysicists, engineers, and geologists and without the impressive size and scale of hardware equipment, the efficiencies wrought from the continued improvement in industry’s ability to find, drill, complete, test, and produce a field in a computer model and optimize all the functions along the way in order to optimize production of the reservoir is nothing less than stunning and being pursued by a broader range of companies than ever before. Offshore Activity Will Continue to Be a High Growth Focus Area: The offshore rig count has grown faster than any other geographic area in terms of rig availability or rigs working. Ultra-deepwater (UDW) drillships, which have previously been used primarily for development but are now being used more broadly for development as well due to the significantly higher deckload capacities, have doubled in number in the past four years, with another 39 UDW drillships scheduled to be delivered over the next two years. Sixth generation semisubmersibles and high-temperature, high-pressure (HPHT) and harsh- environment jackups fleets have been expanded by 1100% and 30% as well, since 2008. The service intensity or revenue/earnings potential on these rigs dwarf the potential for typical onshore wells, with the highest and most value added technologies being used to reduce the daily spread costs. While it may cost $80K-100K per day for a U.S. onshore drilling spread, a deepwater operating spread can easily cost over $2 million a day. Insuring against the cost of failure and reducing time drilling and completing the wells drive these higher revenues and oftentimes higher margins.

Oilfield Services 14 16 October 2012

Improving Subsea Equipment Pricing Dynamics: According to an industry publication, major operators are beginning to publically state how subsea equipment manufacturers are lacking the technical personnel to deliver smaller, more challenging projects due to the industry’s current focus on mega-deepwater projects. We see the issue differently and would argue that for the first time in a number of years, operators are now having to court equipment suppliers/manufacturers in order to get into the manufacturing cycle. Such a change in dynamics is a another positive datapoint for subsea equipment pricing and thus CAM and FTI (as well as GE and Aker Solutions). Brave New World The oilfield services industry in the U.S. has gone through a dramatic transformation over the past eight years. In 2004, the focus for NAM was to reduce opex and optimize production of brownfield, development in aging assets, and postpone the demise of brownfield production, maximizing the economics of tail-end production. International and deepwater had potential and the goal in the U.S. and Canada was to milk whatever you could out of an aging asset before it died, applying broadly commoditized technology throughout the entire production base to prop up the last vestiges of life. Within two years, the U.S. was becoming the technology hog of the industry. To best demonstrate what has happened, you only have to look at the capital expenditure ramp-up by the largest oilfield service companies. Capital expenditures rose by 500% since 2004 and in 2006-09, it was not to replace equipment, it was to ramp up and add more, demonstrated by the ratio of capex to depreciation. In addition, while the economic bust of 2008 slowed things down for a while, the slow of the spending recovery is steeper than ever.

Exhibit 12: Capex Trends

250% $12,000 230% $10,000 210% 190% $8,000 170% 150% $6,000

130% Billions

Cap Ex/DD&A Cap $4,000 110% 90% $2,000 70% 50% $- 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Capital Expendtures Cap Ex vs Depreciation Bloomberg: BHI, HAL, SLB, NOV, BJS Source: Company data, Bloomberg. For at least 23 years, the U.S. oil and natural gas industry was typified by continual cyclical or hyper-cyclical swings in drilling activity which drove extreme cyclical behavior in the financial operations and results of the companies involved in the business. At conferences, the topics of conversation included full cycle profitability, management of people through the cycles, normalized returns, and the hope that the word secular might one day be attached to the industry.

Oilfield Services 15 16 October 2012

Exhibit 13: Annual Change in the U.S. Rig Count

50%

30%

10%

-10%

-30%

-50%

Source: Company data, Credit Suisse estimates. In 2002, following the economic recession caused by the 9/11 World Trade Center attacks, in which natural gas fell from over $10/Mcf in January to less than $2/Mcf by September, the cycle started up again. For the next two years, the rig count struggled back to pre-9/11 levels. Then the World Changed. The seeds had been planted as early as 1979 with the introduction of the Section 29 tight sands credits which provided an economic incentive for what was then considered unconventional natural gas. In 1990, with the federal credit renewed, it is estimated that as much as one-third of drilling was for unconventional non-associated natural gas. This credit fostered significant development in pressure pumping technology to improve production from tight, low-permeability reservoirs. Also spurring interest, capital and technology was the repeal of the Powerplant & Industrial Fuel Use Act in 1987, which had made it illegal, by federal law, to use natural gas to generate electricity. George Mitchell had discovered the Barnett Shale formation in 1981 and had spent years frustratingly trying to figure out how to get it to produce. He drilled his first science project horizontal well in 1991 but it was not until 2002, after Mitchell’s acquisition by Devon Energy (DVN), that the improved technologies of horizontal drilling and hydraulic fracturing matured to the point to make the production of shales feasible. It had taken 18 years to get the first shale production to work. Up until this point, oil and gas companies looked for, drilled, and produced individual accumulations of oil and gas. When a field was produced, you had to go find another one. In addition, they were increasingly hard to find. The term wildcatting had still applied. But no more. The Barnett shale covers 5,000 square miles and is in at least 18 different counties. The Eagle Ford encompasses 5 million acres. We do not have to find anything anymore. We can now focus on production. And the Industry Entered a Brand New Age. In 2004, 86% of all U.S. drilling was for natural gas. After the Barnett, the shale boom was on and most of it was for natural gas as well. We talk about the discovery of shales but we basically already knew where they were and had for years, while drilling through them, logging them, and wishing we had the ability to produce them, and now we do. For 17 years, we had been producing the same amount of natural gas +/- 4%. While still highly cyclical, with no more than two up drilling years before at least one year of decline, the rig count had trended up; however, we were getting increasingly inefficient in

Oilfield Services 16 16 October 2012 producing natural gas. We had not slowed oil drilling to a crawl because we so loved natural gas but that economic accumulations were no longer found in the U.S. and we had gas, lots of gas. Drilling efficiency exploded. Production volumes exploded as well. We were finding new shale at a rapid pace. The technology continued to improve. Recovery rates, the holy grail of the oil and gas industry, started off in the Barnett at around 3% of the gas in place. We are now up to 17%-plus. The economic bust of 2008 caused natural gas prices to drop by 44% sequentially from Q2 to Q3. This resulted in the rig count, which takes a bit longer to move relative to prices, dropping 48% over two quarters, the most rapid drop in drilling activity in the shortest period of time in history. Natural gas production did not drop. The increased productivity of the gas shales combined with a backlog of drilled but not yet completed wells kept production flat, defying historical predictions and logic and defining the new era in domestic production. No chart or words can better explain the evolution of the domestic oil and gas business than the following (Exhibit 14), especially when keeping in mind that natural gas production has continued to rise through 2012. A rarely used technology, often used to tap a neighbor’s reserves when they were not looking, now constitutes almost 70% of all wells drilled. When natural gas prices dropped, primarily as a result of the industry’s success in producing it cheaply, drilling for unconventional oil stepped in to take its place.

Exhibit 14: U.S. Drilling 2000-2012

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

% Gas % Oil % Horizontal

Source: Baker Hughes

■ We now have decades of identified drilling locations for oil and natural gas.

■ Technology development continues to improve with increasing recovery from existing reservoirs.

■ If Saudi gets its oil price and LNG contract duration holds, pricing should stay high enough for the continued development of these reserves

■ Even if the rig count stays static, well intensity will continue to push OFS revenues higher.

Oilfield Services 17 16 October 2012

Exhibit 15: Wells Drilled - Oil and Gas

50,000 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 1973 1976 1979 1982 1985 1988 1991 1994 1997 2000 2003 2006 2009 2012 Oil Gas

Source: EIA

Exhibit 16:Historical Seasonality of the Onshore US Rig Count

Source: Baker Hughes

Oilfield Services 18 16 October 2012

Exhibit 17: U.S. Land Rigs

120% 3,500

100% 3,000 2,500 80% 2,000 60% 1,500 40% AVAILABLE 1,000

20% ACTIVE 500 UTILIZATION 0% 0

Source: Reed Rig Consensus The above chart shows how the industry ramped up rig capacity for the overall recovery in activity from 2001 to 2008. The industry recognized the need for more capable, easier moved, AC driven rigs. Utilization is still low though having recovered but the reality is that large number of conventional rigs are getting increasingly closer to retirement. The issue for the rig companies is that they are replacing fully depreciated rigs generating very generous returns with brand new expensive rigs with returns and free cash flow dropping significantly. It has to be done to remain competitive but it is destructive to overall value.

Exhibit 18: Number of US Rig Owners

Source: Reed Rig Consensus The industry actively consolidated the onshore drilling industry for years until the post- 2001 boom set off and encouraged new entrants. The US rig count went up for six straight years, one of the longest positive runs in history, giving companies an opportunity to build and get established.

Oilfield Services 19 16 October 2012

Exhibit 19: Changes in the US Land Rig Fleet 2005-2011 Changes in the US Land Rig Fleet 2005 2006 2007 2008 2009 2010 2011 Beginning Fleet 1,988 2,026 2,298 2,817 3,076 3,169 3,153 Reductions to the Fleet Removed from Service (141) (99) (77) (59) (164) (212) (315) Moved out of Country (29) (14) (14) (29) (49) (45) (16) Destroyed (3) (6) (4) 0 (5) (2) (3) Reductions (173) (119) (95) (88) (218) (259) (334) Additions to Fleet New Builds 23 238 349 202 237 131 158 Returned to Service 124 95 189 101 36 87 95 Moved in Country 6 5 5 13 30 16 6 Assembled from Parts 58 53 71 31 8 9 3 Additions 211 391 614 347 311 243 262

Net Change 38 272 519 259 93 (16) (72) Available Rigs 2,026 2,298 2,817 3,076 3,169 3,153 3,081 National Oilwell Varco Source: Reed Rig Consensus In 2006 through 2009, the industry added almost 1,150 land rigs net to the industry. With the historical and some level of continued rig efficiencies, we are likely to have an oversupply of land rigs for some time. Granted, the number of new, highly capable rigs is somewhat limited but according to the contractors, most of the new rigs built in the last four years, 728, are shale capable rigs.

Exhibit 20: Depth of U.S. Rig Capabilities vs. Rig Count Growth Depth of US Rig Capability Outpaces Growth in 300 Overall Rig Count

250 Total Land Rigs 200 13K+ Depth Rigs

150

100

50

Source: Company data, Credit Suisse estimates This is another way of looking at the improving capability of rigs. There are a large number of older rigs but rig and drilling efficiency are going to have to continue to move higher to absorb the increased supply.

Oilfield Services 20 16 October 2012

Exhibit 21: International Rigs International Land Rig Utilization 2006 2007 2008 2009 2010 2011 Europe, incl FSU 96% 97% 90% 78% 86% 80% Africa 99% 86% 85% 70% 77% 83% Middle East 88% 94% 94% 82% 90% 97% Asia, incl China 97% 95% 96% 93% 96% 96% Latin America 95% 94% 92% 84% 88% 90% Total National Oilwell Varco Source: Reed Rig Consensus International markets have been continually tighter than US markets. Virtually all rigs are on longer-term contracts, are much more capable rigs than the average US rig and rates are higher. But this is more a comment about where activity is strongest. Europe and the FSU along with Africa, primarily due to the Arab Spring interruption of business, are the weaker rig markets right now.

Exhibit 22: Regional Rig Count Growth 2Q11-2Q12 Latin America, Europe , 2% -1%

Europe Latin America Middle East, Africa , 45% 38% Middle East Far East Africa

Libya Recovery Far East, -6% Pushes Africa Higher

Source: Baker Hughes In terms of growth, Africa, which has had the lower utilization, is recovering from the disruptions of last year. Algeria, Libya and parts of West Africa are expected to come back. While the growth numbers are significant, it generally puts Africa back to where it was before the Arab Spring. The Middle East, Iraq, Saudi, Kuwait and others, are ramping up drilling activity as non-OPEC production growth has disappointed.

Oilfield Services 21 16 October 2012

Exhibit 23: International Rig Count g

Africa , Europe , 106 115

Far East, 229 Latin America, 435

Middle East, 400

Source: Baker Hughes The Seasonality of the Sector. When we first started analyzing the sector, one of the first things that struck me was how few investors thought of the seasonality of the business while working for an operating company, it was one of our major management issues. We built a model that intended to isolate the seasonality of drilling activity, a topic with which I was intimately familiar, as well as that of oil and natural gas pricing. It then occurred to me that the derivative to all these considerations, the stock prices, must discount or display seasonality as a result. In our first model, published in 1992, took in 12 years of data and showed a 16% aggregate swing from high to low on an isolated inter-year basis, statistically significant. We have run it again, incorporating obviously more data, over a longer period of time. The same and spread continue basically constant. It say that you buy OFS stocks at the beginning of the year, sell them in late spring, buy them back again mid-summer, sell again in early fall and wait for the new year to do it again. Obviously, trading stock so actively just to avoid the oftentimes questionable impact of seasonality seems too cute sometimes but with investment timeframes by many account getting increasingly shortened, we thought any tool that could benefit should be used. Broad studies have shown the market discount window to be about six months in the future and out model agrees. You can see the rig count seasonality on this chart and it is about 180 degrees out of phase with stock price performance. We do not expect the performance of the stocks to always mirror our model but has to be considered in the timing of investment at some level.

Oilfield Services 22 16 October 2012

Exhibit 24: Credit Suisse’s Aggregate 16 Year Timing Model 15.0% 8.0% Large Cap 6.0% Equipment 10.0% Land Rigs 4.0% Offshore Rigs 5.0% 2.0% Mid Small Cap Offshore Service 0.0% 0.0% Seismic Workover -2.0% -5.0% Construction -4.0% Boats

-10.0% AVG -6.0% US Rig Seasonality

-15.0% -8.0%

Source: Company data, Credit Suisse estimates

Exhibit 25: Years the OSX was Down - 1998, 2001, 2006, & 2011 g 40.0% Equipment 30.0% Land Rigs

20.0% Offshore Rigs

10.0% Mid Small Cap

0.0% Offshore Service

-10.0% Seismic

Workover -20.0%

Construction -30.0% Boats -40.0% AVG -50.0%

Source: Company data, Credit Suisse estimates.

Exhibit 26: Years Following Down Years Large Cap 30.0% Equipment

20.0% Land Rigs

Offshore Rigs

10.0% Mid Small Cap

Offshore Service 0.0% Seismic

Workover -10.0%

Construction

-20.0% Boats

AVG -30.0%

Source: Company data, Credit Suisse estimates.

Oilfield Services 23 16 October 2012 Valuation Our valuation methodology for the four large capitalization oilfield services companies (BHI, HAL, SLB, and WFT) reflects both the historical enterprise value to EBITDA metric, which is the most classic and historically the highest correlated metric to stock price, and the Return on Capital generated by the companies minus the weighted cost of capital. Since 2003, which the most “modern” view of the industry, following the effects of 9/11 on market variables, there is a very high correlation between the economic returns generated and the valuation reward across all companies. As the chart shows, using a logarithmic trend line and the ten year averages of the sector, we derive a 0.98 r-squared that we use to calculate the appropriate valuation multiple based on our expectation of returns on capital less the current cost of capital. Economic value added, EVA, or its many highly similar derivatives, is one of the primary control and compensation metrics used by the industry. We are a great believer that incentive drives performance and if the company managements are rewarded by increasing returns, especially in a very high capex environment, that should be reflected in both the higher earnings and improving multiple. Size does not matter as much as returns and efficiencies. While Schlumberger (SLB) has historically carried a higher multiple, primarily because it generated a higher return, we forecast the company’s ROC in 2013 to be below its historical average and as a result, carry a lightly lower multiple. Halliburton (HAL) has generated higher returns than SLB over the past two years and we expect that to continue. Rather than getting into the derivative argument of relative technical superiority, we are most concerned that the companies are able to generate a return, above their cost of capital. The doghouse. Baker Hughes (BHI) and Weatherford (WFT) are both very well established and fine companies but miss-steps in capital allocation and the lowered returns generated near-term on that capital penalizes the companies in that they are not likely to generate a positive economic return in 2013 so they trade at lower valuation multiples. Equipment companies look better. Whether it is a different capital spending cycle, higher fixed costs which provide greater leverage or generally the nature of the business, the equipment companies have generated a more stable and resilient return on capital profile that is ramping up faster and with more visibility, generating a higher price multiple. As the below chart shows, the recovery of returns is being much more rapid in the equipment names and while they do have capex requirements, they are much more fixed location assets and generally are where they need to be. All this leads to a premium valuation for the equipment companies: CAM and FTI in this report, relative to the broader service companies.

Oilfield Services 24 16 October 2012

Exhibit 27: Equipment EVA vs. Services EVA 20.0% Service EVA

Equipment EVA 15.0% Not only did Equipment returns stay higher, they are spiking more sharply, with Service returns 10.0% likely to stall for a bit

5.0%

0.0%

-5.0%

-10.0% Source: Bloomberg, Company data, and Credit Suisse estimates

Oilfield Services 25 16 October 2012

Exhibit 28: EV/EBITDA Multiples vs. EVA

8.0%

6.0% y = 0.1051ln(x) - 0.2001 R² = 0.9905 4.0%

2.0%

0.0% 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 14.0x -2.0% EconomicAdded Value(EVA)

-4.0% EV/EBITDA

ROC WACC EV/EBITDA SLB HAL BHI WFT SLB HAL BHI WFT SLB HAL BHI WFT 2003 3.5% -8.5% 3.7% 4.8% 7.5% 8.0% 7.4% 6.6% 17.3x 11.3x 12.6x 12.5x 2004 8.4% -18.8% 8.2% 6.6% 7.4% 6.7% 6.5% 6.0% 14.3x 14.4x 12.8x 12.5x 2005 17.5% 13.0% 15.4% 8.4% 9.9% 10.9% 9.8% 10.3% 14.3x 11.1x 13.0x 14.7x 2006 24.6% 29.0% 34.6% 11.9% 10.6% 10.5% 10.9% 11.0% 12.0x 8.3x 10.1x 8.9x 2007 29.4% 33.6% 26.5% 12.5% 10.8% 9.6% 10.3% 11.1% 14.2x 8.4x 9.1x 12.1x 2008 27.8% 28.2% 21.3% 12.5% 10.3% 11.5% 11.4% 11.1% 5.8x 3.8x 3.3x 5.0x 2009 17.8% 14.9% 12.1% 7.7% 10.4% 10.8% 11.3% 10.4% 11.9x 9.7x 8.8x 12.3x 2010 13.2% 11.7% 4.9% -5.6% 12.8% 13.0% 12.2% 10.4% 16.4x 9.5x 10.3x 12.7x 2011 13.9% 17.7% 9.2% 1.5% 12.8% 14.4% 12.8% 9.9% 9.7x 5.5x 5.8x 7.4x 2012 13.5% 18.4% 9.8% 3.2% 12.8% 13.3% 11.8% 10.1% 8.5x 5.6x 5.5x 5.0x 17.0% 13.9% 14.6% 6.4% 10.5% 10.9% 10.5% 9.7% 12.5x 8.8x 9.1x 10.3x

2013E 13.4% 14.3% 7.8% 6.4% 12.8% 13.3% 11.8% 10.1% 7.9x 6.5x 4.8x 5.1x Source: Bloomberg, Company data, and Credit Suisse estimates

Oilfield Services 26 16 October 2012

Exhibit 29: EV/EBITDA Multiples vs. EVA

22.0x

17.0x

12.0x

y = 21.775x + 10.818 EV/EBITDA R² = 0.8148 7.0x

2.0x -2%0%2%4%6%8%10%12%14%

Economic Value Added (EVA)

ROC WACC EV/EBITDA CAM FTI DRC NOV CAM FTI DRC NOV CAM FTI DRC NOV 2003 4.8% 13.8% 0.0% 6.8% 7.3% 7.2% 9.1% 7.4% 16.3x 10.0x 0.0x 12.4x 2004 6.5% 16.2% 5.8% 8.2% 6.1% 6.4% 6.2% 6.9% 13.7x 12.9x 0.0x 16.0x 2005 9.6% 12.8% 7.0% 9.5% 10.1% 10.4% 11.7% 11.3% 14.1x 15.5x 14.5x 18.6x 2006 14.0% 27.7% 9.4% 13.2% 11.1% 10.7% 10.6% 11.7% 9.5x 11.6x 11.4x 8.3x 2007 18.7% 27.7% 11.3% 20.5% 11.4% 10.3% 11.0% 11.4% 12.5x 16.9x 14.3x 11.2x 2008 19.1% 31.3% 18.8% 19.0% 10.3% 11.2% 13.0% 15.5% 4.1x 5.2x 4.3x 2.9x 2009 12.2% 27.3% 18.5% 10.5% 10.9% 11.1% 11.8% 13.6% 9.9x 11.3x 6.9x 5.7x 2010 11.5% 24.0% 11.9% 10.6% 12.9% 12.8% 11.3% 14.4% 11.1x 16.4x 10.7x 8.8x 2011 9.8% 22.0% 9.6% 11.5% 13.3% 12.7% 10.9% 15.0% 11.0x 19.0x 13.8x 7.4x 2012 12.6% 20.0% 12.4% 11.8% 10.9% 14.4% 12.2x 16.0x 14.4x 8.9x Avg 11.9% 22.3% 10.6% 10.5% 10.7% 12.2% 11.4x 13.5x 9.0x 10.0x

2013E 14.1% 19.0% 12.4% 11.8% 10.9% 14.4% 11.2x 12.4x Source: Bloomberg, Company data, and Credit Suisse estimates Credit Suisse’s HOLT® Analysis Credit Suisse’s proprietary valuation framework—HOLT—forecasts CFROI values and then compares them to the market’s implied CFROI. Given this framework, BHI, CAM, HAL, and WFT look to be the cheapest among the six stocks we are initiating on. Please see exhibits below for company specific representations. If you would like more detail about Credit Suisse’s HOLT valuation for energy stocks, please ask your salesperson to put you in touch with Heather Kidde, CFA—Credit Suisse HOLT Energy & Material Sector Specialist. About HOLT® HOLT® is a team within Credit Suisse that helps investors make better decisions by using an objective framework for comparing and valuing companies. HOLT helps investors gain insight into companies at every stage of their life cycle. The HOLT methodology goes beyond traditional accounting information to emphasize cash generating ability and overall potential for value creation. We offer not only a thorough analysis of a company’s performance in the past; we also provide an objective view of the company’s valuation in the future.

Oilfield Services 27 16 October 2012

Exhibit 30: Credit Suisse HOLT® Analysis—BHI 20

18

16

14

12

10

8 CFROI CFROI (%)

6

4

2

0 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts Current Market-Implied Market-implied CFROI

12

10

8

6

4

2

0

-2

-4 Spread(Forecast CFROI - MI CFROI ) -6 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts-MI Spread Source: Company data, Credit Suisse estimates.

Exhibit 31: Credit Suisse HOLT® Analysis—HAL 20

18

16

14

12

10

8 CFROI CFROI (%)

6

4

2

0 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts Current Market-Implied Market-implied CFROI

8

6

4

2

0

-2

-4

-6

-8 Spread(Forecast CFROI - MI CFROI ) -10 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts-MI Spread Source: Company data, Credit Suisse estimates.

Oilfield Services 28 16 October 2012

Exhibit 32: Credit Suisse HOLT® Analysis—SLB 25

20

15

10 CFROI CFROI (%)

5

0 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts Current Market-Implied Market-implied CFROI

6

4

2

0

-2

-4

-6 Spread(Forecast CFROI - MI CFROI ) -8 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts-MI Spread Source: Company data, Credit Suisse estimates

Exhibit 33: Credit Suisse HOLT® Analysis—WFT 18

16

14

12

10

8 CFROI CFROI (%) 6

4

2

0 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts Current Market-Implied Market-implied CFROI

7 6 5 4 3 2 1 0 -1 -2 Spread(Forecast CFROI - MI CFROI ) -3 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts-MI Spread Source: Company data, Credit Suisse estimates.

Oilfield Services 29 16 October 2012

Exhibit 34: Credit Suisse HOLT® Analysis—CAM 18

16

14

12

10

8 CFROI CFROI (%) 6

4

2

0 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts Current Market-Implied Market-implied CFROI

8

6

4

2

0

-2

-4 Spread(Forecast CFROI - MI CFROI ) -6 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts-MI Spread Source: Company data, Credit Suisse estimates.

Exhibit 35: Credit Suisse HOLT® Analysis—FTI 25

20

15

10 CFROI CFROI (%)

5

0 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts Current Market-Implied Market-implied CFROI

6

4

2

0

-2

-4

-6 Spread(Forecast CFROI - MI CFROI ) -8 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 CFROI Forecasts-MI Spread Source: Company data, Credit Suisse estimates.

Oilfield Services 30 16 October 2012

Other Industry Information

Exhibit 36: Select Oilfield Services & Equipment Market Share Data

Source: Spears & Associates.

Oilfield Services 31 16 October 2012

Capital Expenditures We updated our capital spending data file for 100-plus energy names under Credit Suisse’s equity coverage and the data show total upstream spending increasing approximately 10.5% year over year in 2012 to $533.3 billion. The last time we ran the numbers (early February 2012), total expected upstream capex for 2012 was expected to increase 7.7% year over year to $521.6 billion. Please see Exhibit 38 and Exhibit 39 for full spending details dating back to 2008.

Exhibit 37: Total Yr./Yr. Percentage Change in Upstream Capex 50%

40% 36% 38%

30% 21% 23% 19% 20% 19% 20% 17% 16% 14% 11% 11% 9% 10% 10% 8% 4% 5% 3% 2% 0%

-10% Total -11% Supermajors -20% Other Majors Canadian E&Ps Canadian European E&Ps European AP/Australia Oils Mid-large U.S. Mid-large U.S. E&Ps Small-cap U.S. E&Ps U.S. Small-cap Other Emerg. Mkt Oils

2011 Yr./Yr. 2012 Yr./Yr. Canadian &Small Mid-cap E&Ps

Source: Company data and Credit Suisse estimates. This data is in keeping with our earlier charts on OFS company capex. It is no surprise that the shale/tight sands developments cost a lot. But this is capex, not opex and obviously the capex growth has far exceeded rig count growth. “Service intensity” means we spend a lot more money on each well. But it isn’t all “service”. There is a huge amount of capital cost required to provide that “service”. It is the daisy chain to completion. We may get to the point where so much capital has been employed that there is “enough” for a while. But that presumes there is no depletion, increase in demand or new basins found. Difficult to imagine. But for the E&P industry, we have gone

Oilfield Services 32 16 October 2012

Exhibit 38: Credit Suisse Global Capex Data Total Capex (USD MM) Company Tickers 2008 2009 2010 2011 2012 '12/'11 % Chg

Supermajors BP BP 24,017 20,310 20,548 20,244 22,176 10% Chevron CVX 19,666 19,843 19,612 26,500 30,031 13% Exxon Mobil XOM 19,318 22,491 26,871 30,975 34,436 11% Royal Dutch Shell RDS.A 36,559 27,684 28,154 27,763 30,100 8% Total TOT 19,228 17,573 16,928 21,862 24,576 12% Subtotal 118,788 107,901 112,113 127,344 141,320 11%

Other Marjors/European Integrated 2008 2009 2010 2011 2012 '12/'11 % Chg BG BG.L 6,736 5,711 7,846 10,383 11,940 15% ENI E.N 15,594 18,939 17,860 18,210 17,932 -2% Hess Corporation HES 4,438 2,918 5,492 6,560 8,540 30% Marathon MRO 6,989 6,231 3,536 3,295 4,815 46% Repsol REP.N 7,451 6,304 6,775 9,749 5,868 -40% Occidental Petroleum OXY 4,664 3,581 3,940 7,518 9,547 27% Statoil STO.N 16,579 16,294 16,654 19,556 19,781 1% Subtotal 62,452 59,978 62,103 75,271 78,422 4%

U.S. E&Ps 2008 2009 2010 2011 2012 '12/'11 % Chg Anadarko APC 4,801 4,352 5,008 6,452 7,103 10% Apache APA 5,973 3,631 4,922 7,156 9,900 38% Chesapeake Energy Corp. CHK 17,770 7,523 13,513 14,450 12,344 -15% EOG Resources EOG 5,195 3,503 5,581 6,951 7,614 10% Noble Energy NBL 1,971 1,268 1,885 2,594 3,664 41% Southwestern Energy SWN 1,756 1,780 2,073 2,184 2,008 -8% Whiting Petroleum WLL 892 488 739 1,554 1,900 22% Subtotal 38,358 22,545 33,722 41,342 44,532 8%

Small-Cap E&Ps 2008 2009 2010 2011 2012 '12/'11 % Chg Berry Petroleum BRY 398 135 310 527 650 23% Comstock Resources CRK 419 350 537 573 475 -17% Kodiak Oil & Gas Corp. KOG 11 24 179 251 650 159% Penn Virginia Corp. PVA 585 239 406 446 325 -27% Swift Energy Co. SFY 628 215 354 520 700 35% GMX Resources Inc. GMXR 284 181 195 186 97 -48% PDC Energy PETD 323 143 163 334 193 -42% Rex Energy Corp. REXX 82 33 143 302 180 -40% Rosetta Resources ROSE 228 141 310 475 640 35% Carrizo Oil & Gas Inc. CRZO 571 183 348 556 599 8% Forest Oil FST 1,395 638 759 874 685 -22% Subtotal 4,925 2,283 3,702 5,045 5,194 3%

European E&Ps 2008 2009 2010 2011 2012 '12/'11 % Chg Afren Plc AFRE.L 292 192 358 510 494 -3% DNO Petroleum DNO.OL 222 34 35 75 185 146% Lundin Petroleum LUPE.ST NA NA 375 674 1,001 48% Premier Oil PMO.L 217 303 514 661 830 26% Tullow Oil TLW.L 866 1,189 1,354 1,654 2,000 21% GALP GALP.LS 2,260 1,115 1,819 1,363 1,412 4% OMV OMVV.VI 4,731 3,264 3,176 3,241 3,458 7% Cobalt CIE 611 60 36 88 600 584% Kosmos KOS NA NA 446 500 505 1% Ophir Energy PLC OPHR.L NA 64 50 67 270 303% Genel Energy PLC GENL.L 55 73 40 77 200 158% Origin Energy Limited ORG.AX 1,150 1,601 1,746 1,512 1,241 -18% Det Norske DETNOR.OL 129 167 190 259 554 114% Subtotal 10,532 8,063 10,139 10,680 12,750 19%

Source: Company data, Credit Suisse estimates.

Oilfield Services 33 16 October 2012

Exhibit 39: Credit Suisse Global Capex Data (continued) Total Capex (USD MM) Company Tickers 2008 2009 2010 2011 2012 '12/'11 % Chg Asia Pacific/Australia E&Ps/Integrateds 2008 2009 2010 2011 2012 '12/'11 % Chg Australian World Exploration AWE.AX 0 82 127 79 157 99% CNOOC 0883.HK 4,642 6,471 6,900 5,500 10,932 99% Karoon Gas KAR.AX 37 39 139 34 58 73% Oil Search Ltd. OSH.AX 194 145 1,164 1,195 1,773 48% ONGC ONGC.BO 4,467 7,828 6,113 6,786 7,880 16% PetroChina 0857.HK 33,290 36,986 42,410 43,812 47,292 8% PTT PTT.BK 2,971 4,756 3,420 6,690 7,342 10% Santos Ltd. STO.AX 1,039 937 1,467 2,776 3,686 33% Sinopec 0386.HK 16,070 16,952 17,528 20,144 27,240 35% Tap Oil TAP.AX 56 16 41 1 24 1749% Woodside Ltd. WPL.AX 3,617 4,380 2,948 2,768 1,750 -37% Subtotal 66,383 78,592 82,256 89,784 108,135 20%

Other Emerging Market E&Ps/Integrateds 2008 2009 2010 2011 2012 '12/'11 % Chg KazMunaiGas E&P KMGq.L 350 294 599 716 1,028 44% LUKOIL LKOH.RTS 10,923 6,699 6,733 8,350 13,514 62% Novatek NVTK.RTS 1,270 524 915 1,000 2,167 117% Petrobras PBR 23,300 29,841 39,691 43,979 43,900 0% Rosneft ROSN.RTS 8,779 7,348 9,071 13,500 16,065 19% Sasol Limited SOL 338 226 145 153 203 33% Sibneft SIBN.RTS 3,366 2,607 3,301 3,598 3,922 9% Surgutneftegaz SNGS.RTS 4,186 3,926 4,574 5,888 7,078 20% Transneft TRNFp.RTS 5,229 6,407 7,414 8,357 7,664 -8% YPF Sociedad Anonima YPF 2,317 1,555 2,424 3,509 3,371 -4% HRT Participacoes S.A. HRTP3 NA 34 79 328 272 -17% Subtotal 60,059 59,461 74,945 89,378 99,185 11%

Canadian E&Ps/Integrateds 2008 2009 2010 2011 2012 '12/'11 % Chg Canadian Natural Resources CNQ.TO 6,956 2,584 5,180 6,271 6,705 7% Cenovus CVE.TO 2,068 1,897 2,137 2,825 3,266 16% EnCana ECA 5,255 3,755 4,779 4,610 3,500 -24% Husky Energy HSE.TO 3,810 2,420 3,281 4,854 4,104 -15% Imperial Oil IMO.TO 1,155 2,002 3,744 3,963 5,186 31% Nexen NXY.TO 2,877 3,064 2,579 2,552 3,001 18% Suncor Energy SU.TO 7,457 3,522 5,835 6,927 7,943 15% Talisman Energy TLM 4,872 3,729 3,566 4,303 3,335 -22% Subtotal 34,450 22,973 31,101 36,306 37,040 2%

Canadian Small/Mid-Cap E&Ps 2008 2009 2010 2011 2012 '12/'11 % Chg ARC Resources ARX.TO 572 736 602 -18% Baytex Energy BTE.TO 231 373 406 9% Crescent Point Energy CPG.TO 943 1,267 1,244 -2% Enerplus Corp. ERF.TO 525 887 849 -4% Pengrowth Energy PGF.TO 324 615 622 1% Penn West Petroleum PWT.TO 1,153 1,867 1,471 -21% PetroBakken Energy PBN.TO 788 978 877 -10% Niko Resoucres Ltd. NKO.TO 366 159 166 4% Coastal Energy Co. CEN.TO 146 178 275 54% Connacher Oil & Gas CLL.TO 194 158 54 -66% Lone Pine Resources LPR 246 342 171 -50% Subtotal 5,489 7,561 6,736 -11%

TOTAL 395,947 361,797 415,571 482,709 533,314 10% Source: Company data, Credit Suisse estimates.

Oilfield Services 34 16 October 2012

Americas / United States Oil & Gas Equipment & Services

Baker Hughes Inc. (BHI) Rating NEUTRAL* [V] Price (12 Oct 12, US$) 44.77 INITIATION Target price (US$) 40.00¹ 52-week price range 60.89 - 38.13 “Hands on the Wheel, Eyes Upon the Road” Market cap. (US$ m) 19,679.01 Enterprise value (US$ m) 23,422.26 ■ We Are Initiating Coverage on Baker Hughes with a Neutral Rating: BHI is transitioning its global business through a midcycle correction, which *Stock ratings are relative to the coverage universe in each should prove positive, with improvements already underway. These analyst's or each team's respective sector. ¹Target price is for 12 months. transitions take time though, often longer than investors expect. With [V] = Stock considered volatile (see Disclosure Appendix). international geomarkets operating, global ERP system integration complete

Research Analysts and service infrastructure built, North American completions continue to be James Wicklund the near-term Achilles heel. 214 979 4111 [email protected] ■ BHI Is Going to Aggressively Add Larger and More Stable Customers to Its North American Pressure Pumping Business, which it will Jonathan Sisto 212 325 1292 accomplish mainly through price. Supply chain is well on the way to getting [email protected] fixed. The catch-up capex is basically done. International build-out is Brittany Commins basically done. Pressure pumping prices will continue to slide along with the 212 325 7128 rig count for a couple more quarters, exacerbated by sharp market share [email protected] knives. However, management, culture, and an improving market should foster a strong eventual recovery. ■ Outlook: We expect the U.S. rig count to decline year over year, by about 4-5% in 2013, with efficiencies keeping wells and footage flat, before starting a recovery in activity early in the second quarter, in which we expect the NA markets to resume its shale/tight sand, driven secular cyclical activity growth. International activity growth should continue its anemic but positive grind up, with deepwater driving growth. We are not factoring in black swan events in commodity pricing but look for major swing producers to get their price. Natural gas prices have recovered well and will contribute to cash flows but are not likely to high or sustained enough to kick off its drilling cycle until 2014. Share price performance Financial and valuation metrics

Daily Oct 13, 2011 - Oct 12, 2012, 10/13/11 = US$53.38 Year 12/11A 12/12E 12/13E12/14E 60 EPS (CS adj.) (US$) 4.20 3.57 3.91 — Prev. EPS (US$) — — — — 40 P/E (x) 10.7 12.5 11.4 — 20 P/E rel. (%) 70.2 87.9 89.4 — 0 Revenue (US$ m) 19,831.0 21,444.3 22,360.7 — Oct-11 Jan-12 Apr-12 Jul-12 EBITDA (US$ m) 4,302.0 4,121.2 4,593.6 — Price Indexed S&P 500 INDEX OCFPS (US$) 3.44 2.46 6.62 — On 10/11/12 the S&P 500 INDEX closed at 1434.2 P/OCF (x) 14.1 18.2 6.8 — EV/EBITDA (current) 5.6 5.8 5.2 — Net debt (US$ m) 3,019 3,743 2,702 — ROIC (%) 10.49 7.78 8.03 —

Quarterly EPS Q1 Q2 Q3 Q4 Number of shares (m) 439.56 IC (current, US$ m) 18,983.00 2011A 0.87 0.93 1.18 1.22 BV/share (Next Qtr., US$) 39.7 EV/IC (x) 1.1 2012E 0.86 1.00 0.82 0.89 Net debt (Next Qtr., US$ m) 3,812.4 Dividend (Next Qtr., US$) 0.15 2013E — — — — Net debt/tot cap (Next Qtr., %) 22.1 Dividend yield (%) 0.33 Source: Company data, Credit Suisse estimates.

Oilfield Services 35 16 October 2012 Investment Overview

■ Initiating Coverage of Baker Hughes with a Neutral Rating. The U.S. rig count is experiencing a midcycle correction, with a falling rig count, pricing erosion in one of BHI’s and the industry’s banner technologies, costs have escalated and may persist a bit longer than had been expected and the market has not really been expecting it. All of this will force earnings revisions down and likely cause a reduction in guidance for companies across the spectrum for the next few quarters. While the stocks have looked cheap on some historical criteria, with pricing and activity falling, the leverage to earnings is too great to know how cheap the stocks really are, or are not.

■ Pressure Pumping Is Leading the Pack (Down) and BHI Has Its Own Issues to Deal with: In the first two years after BHI closed on BJ Services, the rig count moved up, lulling management into believing that all was right with the world. Meanwhile, capital was being thrown, with both hands at adding new capacity to the market under the mistaken belief that it would all be absorbed with no pricing potholes. For BHI, supply chains were broken, accountability was lacking, and the market started to get sloppy.

■ BHI Cannot Afford to Lose: The depth of capability and knowledge of the markets has allowed BHI to improve on supply chain, financial, and operating management and information/accounting systems. However, BJ Services worked for the smaller players in the spot market. In addition, when the market was good, it won. However, when the market gets sloppy and the capacity doubles, you want a more stalwart customer. BHI will go after those customers. You cannot increase 24-hour operations if your customers do not work 24 hours. “We will win the work and show them how good we are”. The only way to win the work is to bid low enough to win. Then, the expectation is that you will raise prices when you demonstrate your capability. Sounds great but if you do not win the work first, you never know if phase two will work. You have to win the work.

■ We Do Not Expect Pressure Pumping Prices to Bottom this Year: Drilling and completion activity are not high enough to soak up the excess equipment or products such as guar, as quickly as has been expected. We understand the rig efficiency argument; however, we think those metrics, wells completed and footage drilled, will continue to outperform the rig count but in a declining rig count, that could be flat at best. Many E&P company budgets are spent for the year. Seasonally, the rig count declines at the beginning of the year, with cold weather increasing operating costs by about 10% and no urgency to spend budgets. That could mean a declining rig count for the next six months, which is not the consensus view. All of this pushes the recovery into 2Q 2013, and we all know that things get worse faster than they get better.

■ Go Big or Go Home: Capital expenditures as a percentage of revenues have doubled from 7% in 2004 to 14% this year. We have seen the trend by all of the large capitalization service companies, as well as rig and other equipment companies. The shale/tight sands plays have consumed an enormous amount of capital over the past five years, as have international and offshore operations. In addition, establishing an operating, training, or aftermarket base comes with the implicit understanding of work durability, planning to stay busy for a long time.

Oilfield Services 36 16 October 2012

Exhibit 40: BHI—Key Variables IndexedBHI Variables to 2003 Indexed to 2003 1000 900 800 700 600 500 400 300 200 100 0

Ebitda CapEx EV ROC Source: Company data, Credit Suisse estimates.

■ The Defining Issue: Exhibit 40 summarizes the evolution of the industry and BHI in particular, over that past decade. The shale plays were discovered in the 3-4 years prior to the economic collapse in mid-2008. Companies were recognizing the renewed potential in the U.S., from brownfield to shale nirvana. After the rig count dropped 57% in a quarter, the oilfield service companies went into extreme retrench mode but all realized that when business started up again, it would be the unconventional that would lead the way; however, new and more equipment was needed: more tools, more sizes, and new operating bases. Macondo hit and everyone felt the jitters but onshore unconventional never noticed. While capital expenditures went through the roof, EBITDA followed. But with no or little free cash flow, the value being created was in doubt and the returns demonstrated the problem and affected the share price and multiples, causing enterprise value to stall.

■ End of Year Surprise? A wild card is the possibility of an end-of-year replay of 2007, when E&P companies cut everyone loose for the holidays. Sounds nice and generous but Christmas this year is on a Tuesday and there is increasing anecdotal evidence that it could happen again. It could reduce fourth quarter revenues by 7-8%, with most of the costs still running. It is nice to get the last two weeks off, it is not so nice to have to lower guidance for it. This would not just be a BHI event but a North American services event.

■ BHI Has Been a Company in Transition: In August 2009, CEO Chad Deaton announced ”our new geographic organization is now in place. It has been well received by our customers and employees and is focused on new market opportunities. Our investments in infrastructure, organization and technology are positioning the company to grow share and profitability as the next cycle unfolds”. The geomarket structure was put in place and the company adopted a new operating and reporting segment structure. One month later, Baker announced the $5.5 billion acquisition of BJ Services.

■ If that Was Not Enough: While the September 2009 announcement of the acquisition occurred a year after the U.S. rig count peaked, it was still after a heady six-year run of increased drilling activity. The financial crash was to blame and the rig count started to move up again, in post-crash recovery. The deal closed eight months later, during which time BHI’s management was not allowed to be involved in operations, decisions, or planning. There was some catch-up

Oilfield Services 37 16 October 2012

capital expenditure requirements but the company appeared to be doing well and the rig count continued to move higher, lifting results and optimism.

■ BHI Had Issues: It missed earnings in the second and third quarter of 2009. Higher carrying costs for its geomarket transition, some international market share loss, and slow expense reductions in the U.S. market all contributed. Then two quarters of beating numbers until African and Latin American issues caused the second quarter 2010 to miss. The changing of structure, shifting a product culture to a more service-oriented culture, the reunion with BJ Services was all a great amount of change to deal with, and then came a management change at the top.

■ The Handoff: Chad Deaton ended his seven year run as CEO at the end of 2011, with Martin Craighead taking his place. Martin has been with BHI for 26-plus years. Chad missed earnings his last two quarters, saddling Martin with a bit of a headwind but Baker beat estimates the first two quarters this year. Macroeconomic headwinds will likely end that streak in the third quarter.

Oilfield Services 38 16 October 2012 Company Overview Baker Hughes Incorporated (BHI) is a leading supplier of oilfield services, products, technology, and systems to the worldwide oil and natural gas industry. The company provides products and services for drilling and evaluation of oil and natural gas wells, completion and production of oil and natural gas wells, and other industries, including downstream refining and process and pipeline industries, as well as reservoir development services. BHI operates its business primarily through geographic regions that have been aggregated into five reportable segments: North America, Latin America, Europe/Africa/Russia Caspian, Middle East/Asia Pacific and Industrial Services, and Other. The four geographical segments represent BHI’s oilfield operations. Within oilfield operations, the primary driver of BHI’s businesses is the company’s customers’ capital and operating expenditures dedicated to oil and natural gas exploration, field development, and production. BHI business is cyclical and is dependent upon its customers’ expectations for future oil and natural gas prices, economic growth, hydrocarbon demand, and estimates of current and future oil and natural gas production. As of December 31, 2011, Baker Hughes had approximately 57,700 employees. The company is based in Houston, Texas. Business Segments BHI is organized in two major business segments: Oilfield Products & Services and Industrial Services & Other. The Oilfield Products & Services segment is divided into Drilling and Evaluation and Completion and Production. Within Drilling and Evaluation, BHI’s drill bits, drilling services, wireline services, drilling and completion fluids are housed. Under Completion and Production are completion systems, wellbore intervention, intelligent production systems, artificial lift, tubular services, upstream chemicals, and pressure pumping. Oilfield Products & Services is also organized geographically: • North America (U.S. Land, Gulf of Mexico, and Canada):NAM • Latin America: LAM • Europe/Africa/Russia Caspian: ECA • Middle East/Asia Pacific: MEAP

Exhibit 41: BHI 2010 Geographic Revenue Exhibit 42: BHI 2011 Geographic Revenue

Middle Middle East/Asia East/Asia Pacific Pacific 16% 15%

North America Eur/Afri/Rus North America 51% Eur/Afri/Rus 18% 55% 21%

Latin America Latin America 12% 12%

Source: Company data, Credit Suisse estimates. Source: Company data, Credit Suisse estimates.

Oilfield Services 39 16 October 2012

Exhibit 43: BHI 2010 Geographic EBIT Exhibit 44: BHI 2011 Geographic EBIT

Middle Middle East/Asia East/Asia Pacific Pacific 11% 11%

Eur/Afri/Rus Eur/Afri/Rus 15% 15%

North America Latin America North America 65% 4% Latin America 70% 9%

Source: Company data, Credit Suisse estimates. Source: Company data, Credit Suisse estimates. Industrial Services and Other consists primarily of downstream chemicals, process and pipeline services, and the reservoir development services group. Downstream chemical services provide products and services that help to increase refinery production, as well as improve plant safety and equipment reliability. Process and pipeline services work to improve efficiency and reduce downtime with inspection, precommissioning and commissioning of new and existing pipeline systems and process plants. Competition BHI’s primary competitors in the oilfield service space are predominately Halliburton (HAL), Schlumberger (SLB), and Weatherford (WFT). Market & Business Drivers The operating results of BHI are primarily driven by the company’s strong presence in the deepwater arena, well service intensity, Canada, sliding sleeve technology, and upstream and& downstream chemicals, as well as the company’s geographically diverse infrastructure and support network. Ultra-Deepwater Mega Project Opportunities BHI holds a number three market share position in the ultra-deepwater (UDW) drilling market, in which mega projects last anywhere between 4 to 10 years and can total $500 million to $1.0 billion in total. Lately, the competition to win these ultra-deepwater drilling projects has become extremely aggressive, with the major oilfield service providers all jockeying to get the work. This has led to near breakeven type bids just to get some if not all of the work. These UDW projects are often not accretive at the onset but once activity ramps up, product upselling opportunities of new technologies allow for margins to improve steadily. Very specific downhole tools or high pressure, high temperature (HP/HT) drilling and logging services can generate 40-45% EBITDA margins for BHI and its peers. Statoil (STL NO), Saudi Aramco, and Petrobras (PBR) are usually clients who are most open to using new technologies. Once new technologies see successes and are proven offshore, they are generally offered onshore. With international, national, and major oil and gas companies seeking hydrocarbons in more remote locals, the UDW floating rig count swelling, and exploration successes becoming more frequent, the offshore deepwater market will continue to be a major growth driver for BHI for years to come. Credit Suisse Offshore Drilling analyst, Greg Lewis, estimates that there are currently 39 newbuild UDW Drillships and 7 UDW Semis scheduled for delivery through 2014. Currently, 16 are contracted (8 destined for the Gulf of Mexico, 2 Brazil, 3 West Africa, and 3 Other). Conversations across our energy team lead us to believe that the uncontracted

Oilfield Services 40 16 October 2012 floaters will end up primarily in Africa (50%+), Brazil (~10%); Gulf of Mexico (~10%), and Other (30%).

Exhibit 45: Geographic Rig Placement by Type

50 51

2 d Drillship Jackup Semi

68 15 26

33 Drillship Jackup Semi 142 4 1 10 Drillship Jackup Semi Drillship Jackup Semi

59 132 28 15 23 41

Drillship Jackup Semi Drillship Jackup Semi

Source: IHS Petrodata, Credit Suisse estimates. BHI just won a $508 million contract with Statoil in Norway. The two year contract applies to 25 fields in Norway and includes directional drilling (DD), measurement-while-drilling (MWD), logging-while-drilling (LWD), and mud-logging services. As one of the three mega tenders remaining in 2012 and on the horizon for the near term, this is a significant positive for BHI. Within the Gulf of Mexico (GoM), BHI operates the two largest stimulation vessels in the world; we note both are currently idle. Looking ahead, 2013 should be a good year for BHI in the GoM, as the work needed to be done next year is more developmental in nature. Mounting Well and Service Intensity Onshore As demonstrated by the increasing percentage of oil and horizontal wells being drilled in the United States ( see Exhibit 47) and around the world, the overall well and service intensity per well is increasing dramatically. For example, the U.S. horizontal rig count now represents approximately 59% of the total U.S. rig count as of 2Q12, and we estimate that this will likely build to 60% by year-end 2012. This shift to more horizontal drilling is driving demand for more downhole tools and hydraulic fracturing services (or pressure pumping), and we believe that BHI is the third largest provider of hydraulic fracturing services in the North America, with approximately 1.8 million hydraulic horsepower presently. HAL holds a number one market share position in pressure pumping in North America, with approximately 3.0 million hydraulic horsepower; SLB we estimate has approximately 2.1 million hydraulic horsepower in the United States. Overall, we estimate there will be approximately 15.0 million horsepower in the United States and another 1.6 million in Canada by year-end 2012. (See Exhibit 51)

Oilfield Services 41 16 October 2012

Exhibit 46: Historical Oil and Gas Directed Exhibit 47: Historical Oil and Gas Rig Count Horizontal Rig Count

800 700 600 500 400 # of # of Rigs 300 200 Horizontal Gas Rig Count 100 Horizontal Oil Rig Count 0 Oct-10 Apr-11 Oct-11 Apr-12 Jun-10 Jan-11 Jun-11 Jan-12 Mar-10 Aug-10 Aug-11

Source: Baker Hughes. Source: Baker Hughes. Furthermore, our colleague Ed Westlake released a report recently, titled, U.S. Oil Production Outlook: Energy Independence Day, in which we his team built a proprietary model that estimates shale well count growth in the U.S. To this end, Westlake’s base case envisages the shale well count increasing by 37% from 11,500 wells per annum in 2012 to 15,700 wells by 2020. (See Exhibit 48). The internationalization of horizontal drilling and hydraulic fracturing into countries such as Argentina, Australia, Columbia, China, Poland, and Russia is also likely to play to BHI’s strengths.

Exhibit 48: Wells Drilled in The Model’s Oil Shale Plays by Year 18,000

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

‐

Source: Company data, Credit Suisse estimates. In early 2012, the NAM pressure pumping market saw a tremendous shift in the rig count composition from being fairly evenly split between oil versus gas to currently heavily weighted to oil and liquids-rich drilling. As a result, basins such as the Haynesville became close to uneconomical and E&P companies pulled operations to other basins. It was this shift from gas to liquids-rich drilling which led to drastic declines in NAM drilling and pressure pumping activity, oversupply of equipment, and people in certain areas. Unfortunately for BHI, it was greatly affected by having much of its pressure pumping equipment tied up in gassy basins with smaller customers and newly added hands with the inability to move to other projects or basins quickly. Coupled with logistical supply deliver issues, BHI had a tough first half of 2012. Exhibit 49 depicts some of the headwinds BHI was forced to correct in the second and third quarter of 2012.

Oilfield Services 42 16 October 2012

Exhibit 49: How BHI Is Enhancing Pressure Pumping Efficiency

Source: Baker Hughes. BHI has taken great strides to rectify the situation in NAM by putting forth a reduction in force and reorganizing/building distribution centers throughout the country. The company’s second quarter NAM EBIT margins declined only 60bps sequentially, after the company had hinted at a several hundred basis point sequential decline. Currently, BHI has approximately 25% of its U.S. and Canadian pressure pumping assets working on 24-hour operations and plans to increase to 30-33% by year-end. To accomplish this, BHI will have to add more 24-hour operating E&P clients to its customer base and plans to accomplish this by increasing market share with the more active customers by price. With Halliburton seeing 50% of its domestic contract base up for renewal from Q2 and into Q1 of 2013, BHI is likely to challenge that market share on price. This aggressiveness may help BHI’s utilization and customer mix but these efforts and those of others in the same mode, coupled with continued over capacity are likely to keep the NAM pressure pumping market challenging through at least the 1Q13 and possibly longer. Anecdotally, we have heard from our industry contacts that one major pressure pumping company is taking HHP capacity out of the market to improve its negotiating position. We estimate that the U.S. pressure pumping market has 15.0 million hydraulic horsepower (HHP) and BHI has approximately 1.8 million HHP. Our U.S. Pressure Pumping Supply/Demand Model shows the U.S. market to be 11% oversupplied.

Oilfield Services 43 16 October 2012

Exhibit 50: Credit Suisse U.S. Pressure Pumping Supply/Demand Model Drilling Assumptions Frac Assumptions Frac Calcs Frac Hhp/d Demand (MM) # Frac Adj for # Frac # Wells/ hp/job Days/ frac Days/ 7 days, 12 5 days, 12 5 Days, 1/2 Basin Rig Count Days/well Stages per 1/2 24- Stages per Year w/ Frac (K) stage job hours hours 24-hr well hour Year Haynesville 16 30.0 191 31 45 0.37 12.3 9.2 5,323 0.3 0.4 0.3 Marcellus 75 10.0 2,683 18 32 0.33 7.0 5.3 43,461 1.6 2.3 1.7 Permian 406 15.0 9,682 4 20 0.25 2.0 1.5 34,854 1.1 1.5 1.1 Eagle Ford (S. Tx) 217 30.0 2,587 28 28 0.42 12.7 9.5 65,202 2.5 3.5 2.6 Barnett 41 22.0 667 10 26 0.45 5.5 4.1 6,000 0.3 0.4 0.3 Fayetteville 15 15.0 358 14 30 0.44 7.1 5.3 4,507 0.2 0.3 0.2 Woodford 8 26.0 110 10 30 0.45 5.5 4.1 991 0.0 0.1 0.1 Piceance 16 10.0 526 8 26 0.24 2.9 2.2 3,784 0.1 0.2 0.1 Uinta 30 15.0 715 4 16 0.11 1.4 1.1 2,575 0.0 0.1 0.0 Niobrara 40 18.0 795 18 35 0.50 10.0 7.5 12,877 0.8 1.1 0.8 Bakken (BHI: MT+ND) 160 18.0 3,180 34 19 0.52 18.7 14.0 97,294 3.1 4.3 3.2 Utica 10 20.0 179 10 20 0.50 6.0 4.5 1,610 0.1 0.1 0.1 Other 64 15.0 1,324 4.0 10 0.50 2.0 2.0 4,765 0.1 0.1 0.1 Total 1,098 22,995 283,243 10.2 14.2 10.7

CS Estimated U.S. Frac Hhp Capacity (MM) 15.0

Implied Utilization 118% 89%

Effective Capacity (80% of "nameplate") 12.0 12.0 Source: Company data, Spears & Associates, and Credit Suisse estimates.

Exhibit 51: 2012 NAM Hydraulic Horsepower Additions Projected Current "Announced" Projected 2012 Ticker/Company 2011 YE 2011 1Q12E 2Q12E 3Q12E 4Q12E YE 2012E % Change Capacity (HHP) 2012 Additions Additions Additions SPN 315,000 127,000 442,000 40,000 40,000 40,000 38,000 158,000 600,000 36% PTEN 508,000 142,000 650,000 50,000 700,000 8% # NBR 600,000 200,000 800,000 50,000 850,000 6% CFW 291,000 144,000 435,000 3,000 3,000 3,000 3,000 12,000 447,000 3% TCW 390,000 180,000 570,000 100,000 670,000 18% BAS** 236,000 - 236,000 37,500 273,500 16% FracTech 1,312,750 1,393,500 88,500 88,500 88,500 88,500 354,000 1,666,750 20% RES 495,000 90,000 585,000 55,000 43,000 98,000 683,000 17% WFT 650,000 650,000 150,000 800,000 23% CJES 172,000 38,000 210,000 25,000 32,000 18,000 15,000 90,000 300,000 43% BHI 1,450,000 1,450,000 350,000 1,800,000 24% Great White Energy 98,800 9,000 107,800 107,800 0% HAL 2,400,000 2,400,000 500,000 2,900,000 21% SLB 1,750,000 1,750,000 350,000 2,100,000 20% Chesapeake OFS, LLC 60,000 80,000 140,000 44,000 44,000 44,000 43,000 175,000 315,000 125% Platinum Energy 107,500 107,500 25,000 17,500 42,500 150,000 40% Other 375,000 375,000 300,000 675,000 80%

United States Total 11,211,050 1,010,000 12,301,800 670,500 2,146,500 15,038,050 22%

Canada Total* 1,100,000 200,000 1,300,000 300,000 1,600,000 23%

Total NAM 12,311,050 1,210,000 13,601,800 16,638,050 22% Source: Company data, Spears & Associates, and Credit Suisse estimates. Canada BHI has carved out a significant market share position in Canada mainly due to the acquisition of pressure pumping, pure-play, BJ Services in 2010, and the company’s strong directional drilling (DD) presence. Currently, the Canadian rig count is down 30% year over year (Exhibit 52) as an abnormally wet summer extended the spring break-up and depressed natural gas prices have customers sitting on project plans. The company has stated publicly that third quarter 2012 results will be negatively affected by the lack of activity in Canada. The company generated $1.7 billion in revenue in 2011 in Canada, or approximately 17% of 2011 total North American revenue.

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Exhibit 52: Canadian Rig Count 800

700 The current Canadian rig count is -30% Yr./Yr. 600

500

400

300

200

100

0 1/6/12 2/6/12 3/6/12 4/6/12 5/6/12 6/6/12 7/6/12 8/6/12 9/6/12

2009 2010 2011 2012

Source: Baker Hughes. Technology The technological gap once cited between SLB, BHI, and HAL is no longer as great as it once was. BHI today spends an equal percent of revenue on research and development as its peers and is just now beginning to rollout new technologies that are demonstrating stellar adoption rates. For example, BHI’s new sliding sleeve technology has acquired a 40% market share position in North America. Sliding sleeve is a completion device that can be operated to provide a flow path between the production conduit and the annulus. Sliding sleeves incorporate a system of ports that can be opened or closed by a sliding component that is generally controlled and operated by slickline tool string. The advent of horizontal drilling is leading to the rising use of sliding sleeve technologies. Similarly, BHI’s Auto Track Curve drilling technology system has drilled one million feet in its first year of service by the end of the second quarter. As of early September, the system has drilling close to two mission feet and the technology has not been fully rolled out to all of BHI customers yet.

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Exhibit 53: BHI AutoTrak Curve

Source: Baker Hughes. The company is also expanding the use of its electric submersible pumps (ESPs) into more unconventional fields in North America, Latin America, and deepwater.

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Exhibit 54: BHI Deepwater Subsea Boosting Systems

Source: Baker Hughes. Chemicals (Upstream, Downstream, & Specialty) Unlike its peers, BHI offers a full suite of upstream, downstream, and specialty chemical offerings. BHI’s Upstream Chemicals group includes chemicals and chemical application systems to provide flow assurance, integrity management, and production management for upstream hydrocarbon production. The downstream chemical services and technology for the worldwide pipeline, hydrocarbon processing, and petrochemical industries help you to increase your production, improve plant safety, and equipment reliability. Lastly, the Specialty Chemical division provides specialty polymers and agricultural crop protection chemicals. Goals for 2013 We expect BHI to reduce its capital spending budget in 2013, which in turn should allow the company to generate more free cash flow. With the increased free cash flow, we look for the company to be opportunistic with building out its technology and geographic portfolio. Return on Equity will also be a key focus for senior management, as returns have been lackluster in recent years. BHI Over the Years Historic Company Transactions February 2, 2005: BHI acquired the remaining 50% stake in Luna Energy for an undisclosed amount. Luna and BHI first formed a joint venture in February 2002 with a mission to develop leading-edge fiber optic technology solutions for wellbore monitoring that improved operations and enhanced oil and gas production rates.

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December 2, 2005: The company purchased Zeroth Technology Limited (Zertech), a developer of an expandable metal sealing element, for $20.3 million in cash. As a result of the acquisition, BHI recorded $9.4 million of goodwill and $10.3 million of intangible assets. Under the terms of the purchase agreement, the former owners of Zertech are entitled to additional purchase price consideration of up to approximately $14.0 million, based on the performance of the business during 2006-08. BHI owned a 50% interest in the QuantX Wellbore Instrumentation venture (QuantX) and in October 2005, BHI purchased the remaining 50% interest in QuantX for $27.2 million. The company recorded $28.4 million of goodwill, $19.6 million of intangibles and assigned $5.1 million to in-process research and development. All acquisitions above are included in the Completion and Production segment. January 2006: BHI acquired Nova Technology Corporation (Nova) for $55.4 million, net of cash acquired of $3.0 million, plus assumed debt. Nova is a supplier of permanent monitoring, chemical injection systems, and multiline services for deepwater and subsea oil and gas well applications. As a result of the acquisition, the company recorded $29.7 million of goodwill, $24.3 million of intangible assets and assigned $2.6 million to in-process research and development. Under the terms of the purchase agreement, the former owners of Nova are entitled to additional purchase price consideration of up to $3.0 million based on certain post-closing events to the extent that those events occur no later than January 31, 2016, of which $1.0 million was paid during 2007. The final cost was $70 million according to Bloomberg. January 2006: BHI acquired Nova Technology Corporation (Nova) for $55 million, net of cash acquired of $3 million, plus assumed debt. Nova is a supplier of permanent monitoring, chemical injection systems, and multiline services for deepwater and subsea oil and gas well applications. As a result of the acquisition, the company recorded $30 million of goodwill, $24 million of intangible assets, and assigned $2 million to in-process research and development. March 1, 2006: BHI sold certain assets to SCF Partners Ltd. (private equity) for $42 million. April 28, 2006: BHI sold our 30% interest in WesternGeco for $2.4 billion in cash (BHI owned 70% prior). WesternGeco also made a cash distribution of $59.6 million prior to closing. In 2005, the company received distributions of $30.0 million from WesternGeco, which were recorded as a reduction in the carrying value of our investment. BHI also received $13.3 million from Schlumberger related to the WesternGeco true-up payment, of which $13.0 million was recorded as a reduction in the carrying value of our investment and $0.3 million as interest income. On April 28, 2006, BHI sold our 30% interest in WesternGeco to Schlumberger for $2.4 billion in cash and recorded a pretax gain of $1,744 million ($1,035 million after-tax). In 2006, BHI received $46.3 million in net proceeds from the sale of certain businesses and our interest in an affiliate. Specifically, in March 2006, BHI completed the sale of Baker SPD and received $42.5 million in proceeds, and the company received $3.8 million from the release of the remaining amount held in escrow related to our sale of Petreco International. In May 2005, the company received $3.7 million from the initial release of this escrow. During 2007, the company received $9.9 million in proceeds from the sale of our equity investment in Toyo Petrolite Company Ltd. February 2008: BHI sold the assets associated with the Completion and Production segment’s Surface Safety Systems (SSS) product line and received cash proceeds of $31 million. The SSS assets sold included hydraulic and pneumatic actuators, bonnet assemblies, and control systems. BHI recorded a pretax gain of $28 million ($18 million after-tax).

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April 2008: BHI acquired two firms for our reservoir technology and consulting group: Gaffney, Cline & Associates (GCA) and GeoMechanics International (GMI) for $72 million in cash, including $4 million of direct transaction costs and net of cash acquired of $5 million. These firms provide consulting services related to reservoir engineering, technical and managerial advisory services and reservoir geomechanics. As a result of these acquisitions, BHI recorded $43 million of goodwill and $19 million of intangibles. Under the terms of the purchase agreements, the company may be required to make additional payments of up to approximately $46 million based on the performance of the businesses during 2008-10. During 2008, BHI made several other acquisitions having an aggregate purchase price of $53 million, of which $48 million was paid in cash. As a result of these acquisitions, BHI recorded $2 million of goodwill and $26 million of intangible assets through December 31, 2008. August 30, 2009: BHI and BJ Services entered into a merger agreement pursuant to which the company will acquire 100% of the outstanding common stock of BJ Services. BHI estimated the total consideration expected to be issued and paid in the merger to be approximately $6.4 billion, consisting of approximately $0.8 billion to be paid in cash and approximately $5.6 billion to be paid through the issuance of approximately 118 million shares of Baker Hughes common stock valued at the February 11, 2010 closing Baker Hughes share price of $46.68 per share. Subject to satisfaction of conditions to closing, it is anticipated that closing of the transaction will occur in March 2010; however, BHI cannot guarantee when or if the merger will be completed or if completed, it will be exactly on the terms as set forth in the merger agreement. BJ Services is a Delaware corporation formed in 1990. BJ Services is a leading provider of pressure pumping and oilfield services for the petroleum industry. BJ Services’ pressure pumping services consist of cementing and stimulation services used in the completion of new oil and natural gas wells and in remedial work on existing wells, onshore and offshore. BJ Services’ oilfield services include casing and tubular services, precommissioning, maintenance, and turnaround services in the pipeline and process business, including pipeline inspection, chemical services, completion tools, and completion fluids. According to Bloomberg, BHI paid 6.6x LTM EBITDA for BJ Services or 10.5x BJS’ 2009 EBITDA. Assuming a purchase price of $5,527.77 million. April 27, 2009: BHI purchases Helix RDS Ltd. for $25 million. April 28, 2010: BHI completed the acquisition of BJ Services, a leading provider of pressure pumping and other oilfield services for $6.9 billion in cash and stock. This acquisition provides us with a proven leader in the areas of pressure pumping, stimulation and fracturing and complements our existing product portfolio, allowing us to provide a full suite of products and services to meet the needs of our customers. For 2010, our results are inclusive of BJ Services results from the acquisition date through December 31, 2010. The acquired business represented approximately 46% of our consolidated total assets at December 31, 2010 and approximately 36% of our consolidated net income attributable to Baker Hughes for the year ended December 31, 2010. Proceeds from disposal of assets were $208 million, $163 million, and $222 million for 2010, 2009 and 2008, respectively. These disposals relate primarily to rental tools that were lost in hole, as well as machinery, rental tools, and equipment no longer used in operations that were sold throughout the year. August 30, 2010: BHI completed the sale of two stimulation vessels and certain other assets used to perform sand control services in the U.S. Gulf of Mexico, to Superior Energy Services (SPN). The company received cash of $55 million and incurred disposition costs of $16 million. The divestiture was required by the DOJ in connection with the acquisition of BJ Services. The sale was not material to our business or our financial performance.

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2008: BHI sold the assets associated with our Surface Safety Systems product line and received cash proceeds of $31 million. May 26, 2010: BHI purchased computer software company Meyer & Associates, Inc., for an undisclosed amount. June 1, 2010: BHI purchased machinery and pump company Oilpump Services, for an undisclosed amount. August 18, 2010: BHI purchased building and products (cement) company, Tanroc Equipment, for an undisclosed amount. October 7, 2010: BHI increased its ownership in JOA Oil & Gas BV to 60% from 40%, no terms disclosed. The company made no material acquisitions in 2011. On September 1, 2011, BHI purchased a minority interest in Verdande Energy AS of Norway; no financial terms disclosed. Management Team Chadwick “Chad” C. Deaton (Chairman of the Board) Mr. Deaton has served as executive chairman of the board of the company since January 2012. He was chairman of the board and chief executive officer from October 2004 to December 2011 and president of the company from 2008 to 2010. Mr. Deaton was president and chief executive officer of Hanover Compressor Company from 2002 to 2004. He was senior advisor to Schlumberger Oilfield Services from 1999 to 2001. He was also executive vice president of Schlumberger from 1998 to 1999. Mr. Deaton has been employed by the company in 2004. Martin S. Craighead (President and CEO) Mr. Craighead became chief executive officer of Baker Hughes in January 2012. Prior to that Craighead was president of the company since 2010. He was director of the company since 2011 and was chief operating officer of the company from 2009 to 2011 and senior vice president from 2009 to 2010. He was group president of drilling and evaluation from 2007 to 2009 and vice president of the company from 2005 until 2009. Mr. Craighead was president of INTEQ from 2005 to 2007 and was president of Baker Atlas from February 2005 to August 2005. He was vice president of worldwide operations for Baker Atlas from 2003 to 2005 and vice president of marketing and business development for Baker Atlas from 2001 to 2003. Mr. Craighead was employed by the company in 1986. Peter A. Ragauss (Senior Vice President and CFO) Mr. Ragauss has served as senior vice president and chief financial officer of the company since 2006. Segment controller of refining and marketing for BP plc from 2003 to 2006. He was chief executive officer of Air BP from 2000 to 2003 and assistant to the group chief executive for BP plc from 1998 to 2000. He vice president of finance and portfolio management for Amoco Energy International immediately prior to its merger with BP in 1998. Mr. Ragauss was vice president of finance for El Paso Energy International from 1996 to 1998 and vice president of corporate development for Tenneco Energy in 1996. Mr. Ragauss was employed by the company in 2006. Arthur L. Soucy (President of Global Products) Mr. Soucy is president of global products and services. He has held this role since January 2012. Previously, he was vice president of supply chain from April 2009 to December 2011. Vice president of global supply chain for Pratt and Whitney from 2007 to 2009. Sloan Fellows Program, Innovation, and Global Leadership at Massachusetts Institute of Technology from 2006 to 2007. General manager, Combustors, Augmenters and Nozzles of Pratt and Whitney from 2005 to 2006.

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Belgacem Chariag (Vice President and President Eastern Hemisphere Operations) Mr. Chariag has served as vice president of the company and president Eastern Hemisphere operations since 2009. Prior to this role, Chariag was vice president HSE of Schlumberger Limited from May 2008 to May 2009. President of Well Services, a Schlumberger product line from 2006 to 2008. Vice president of marketing oilfield services for Europe, Caspian, and Africa of Schlumberger from 2004 to 2006. Various other operational and management positions at Schlumberger from 1989 to 2008. Employed by the company in 2009. Derek Mathieson (Vice President and President Western Hemisphere Operations) Mr. Mathieson has been vice president of the company since 2008 and was president of Western Hemisphere Operations in January 2012. Mathieson was president of products and technology from May 2009 to December 2011. Chief technology and marketing officer of the company from December 2008 to May 2009. Chief executive officer of WellDynamics, Inc. from May 2007 to November 2008. Vice president of business development, technology, and marketing of WellDynamics, Inc. from April 2006 to May 2007; technology director and chief technology officer from January 2004 to April 2006; research and development manager from August 2002 to January 2004 and reliability assurance engineer from April 2001 to August 2002 of WellDynamics, Inc. Well Engineer for Shell U.K. exploration and production 1997 to 2001. Employed by the company in 2008. Valuation We are using a 4.8x EV/EBITDA multiple times our forecasted 2013 EBITDA of $4.6 billion, on revenues of $22.4 billion. We are using an EVA component in our EV/EBITDA valuation since returns and capital allocation will be two of the most critical issues going forward for the industry. The shale boom is not going away and the capital needs of the service providers should continue to be high. Without some view of capital efficiency and adequate returns on capital, companies can generate high metrics but still destroy value if one just looks at historical EV/EBITDA valuation. The world has changed. BHI completed the $5+billion acquisition of BJS services, instituted a complete corporate makeover and got caught in a mid-cycle correction going the wrong way and as a result, saw its returns on capital drop. In our model, companies that generate lower returns than their cost of capital are destroying capital and get a lower valuation multiple. We have taken the results for the past ten years of the four largest capitalization Oilfield Service companies and calculated their valuations relative to their returns and use that to forecast forward valuation multiples. Our 4.8x multiple results in a price target of $40, approximately 12% below the current share price. At present, the company is eroding its capital base and not generating meaningful levels of free cash flow. Our model does show the potential to significantly ramp up earnings, cash flows and returns from late 2013 well into the future and that would change our valuation multiple. That implies that the company needs to navigate through the choppy waters of the next 6-12 months and if successful, would rejoin the top ranks of peer valuations.

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Exhibit 55: BHI Comparables (US$ in millions, except per share data) Stock Price Market Enterprise EBIT DA EV / EBITDA EPS P / EPS Company Ticker Rating TP $ 10/15/12 Shares Value Value 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E

Halliburton Company HAL Outperform $44 $33.80 926 $31,299 $33,942 $6,075 $6,644 5.6x 5.1x $3.04 $3.12 11.1x 10.8x Schlumberger Limited SLB Neutral $66 $72.19 1,339 $96,662 $103,644 $11,164 $12,056 9.3x 8.6x $4.19 $4.58 17.2x 15.8x Weatherford International WFT Neutral $11 $12.17 769 $9,359 $17,552 $2,910 $3,221 6.0x 5.4x $0.93 $1.18 13.1x 10.3x

Mean 7.0x 6.4x 13.8x 12.3x Median 6.0x 5.4x 13.1x 10.8x High 9.3x 8.6x 17.2x 15.8x Low 5.6x 5.1x 11.1x 10.3x

Baker Hughes BHI Neutral $40 $44.77 440 $19,699 $23,948 $4,121 $4,594 5.8x 5.2x $3.57 $3.91 12.5x 11.4x Premium/(Discount) to Peer Group Average -17% -18% -9% -7% Source: Bloomberg, Company data, and Credit Suisse estimates. Investment Risks The investment risks of investing in BHI are two fold, those specific to the company and those that relate to the broader oilfield service industry. Company-specific risks include (1) the company’s ability to improve North American supply logistics and product delivery following the rapid switch from gas to liquids-rich drilling in the first-half of 2012, (2) operations in more volatile countries, (3) changes in and compliance with post-Macondo restrictions and regulations, (4) environmental, and (5) successful development and implementation of new technological advancements. In addition, industry-specific risks include (1) oil prices, (2) global oil demand, (3) global GDP, (4) global E&P capex spending, (5) interest rate risk, (6) environmental and government regulations, (7) oversupply of pressure pumping equipment, (8) increased competition, (9) inclement weather/seasonality, and (10) geopolitical risks.

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Americas / United States Oil & Gas Equipment & Services

Halliburton (HAL) Rating OUTPERFORM* Price (12 Oct 12, US$) 33.80 INITIATION Target price (US$) 44.00¹ 52-week price range 39.13 - 26.70 “So Close You Can Almost Taste It” Market cap. (US$ m) 31,357.96 Enterprise value (US$ m) 33,654.58 ■ Initiating Coverage on Halliburton with an Outperform Rating. Near-term headwinds of a falling NAM rig count, earnings revisions down, weak *Stock ratings are relative to the coverage universe in each pressure pumping pricing and utilization, envious competitors and flat-to- analyst's or each team's respective sector. ¹Target price is for 12 months. negative near-term stock price and rig count seasonality present issues, most of which should begin to be alleviated going into the new year. With all Research Analysts that, the valuation is impossible to ignore. HAL is doing an exceptional job of James Wicklund 214 979 4111 managing broad company and industry issues but faces current headwinds [email protected] out of its control. Jonathan Sisto ■ Amplified Seasonality: Many NAM independents have spent their current 212 325 1292 [email protected] year’s budgets, likely reversing the typical seasonal increase in activity. Brittany Commins Lower activity will exacerbate the equipment overcapacity, delaying the 212 325 7128 recovery in margins. With higher winter operating costs and little budget [email protected] urgency, we expect the U.S. rig count to decline through the first quarter of next year. We expect the U.S. rig count to be down 4-5% yr./yr., with increasing rig efficiency keeping footage and well count variables basically flat, with activity flat to declining for the next six months. ■ Timing Is Everything in Life: We expect the 2H13 to improve from budget and activity levels, as NGL and crude oil differentials come into better balance after significant infrastructure spends. Natural gas drilling might not pick up as quickly as many hope but higher pricing leads to higher cash flow generation, fueling upward momentum. Our Timing Model shows that OSX stocks typically move up through the first several months of the year, even with rig activity seasonally depressed, as markets anticipate the recovery.

Share price performance Financial and valuation metrics

Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = US$35.02 Year 12/11A 12/12E 12/13E12/14E 40 EPS (CS adj.) (US$) 3.35 3.04 3.12 — 30 Prev. EPS (US$) — — — — 20 P/E (x) 10.1 11.1 10.8 — 10 P/E rel. (%) 66.5 78.1 84.5 — 0 Revenue (US$ m) 24,478.6 28,691.1 31,609.5 — Oct-11 Jan-12 Apr-12 Jul-12 EBITDA (US$ m) 6,195.0 6,133.9 6,728.1 — Price Indexed S&P 500 INDEX OCFPS (US$) 4.00 3.69 3.87 — On 10/03/12 the S&P 500 INDEX closed at 1432.84 P/OCF (x) 8.6 9.1 8.7 — EV/EBITDA (current) 5.4 5.5 5.0 — Net debt (US$ m) 2,122 2,297 2,044 — ROIC (%) 21.45 17.17 15.71 —

Quarterly EPS Q1 Q2 Q3 Q4 Number of shares (m) 927.75 IC (current, US$ m) 15,320.00 2011A 0.61 0.80 0.94 1.00 BV/share (Next Qtr., US$) 21.4 EV/IC (x) 1.9 2012E 0.89 0.80 0.65 0.69 Net debt (Next Qtr., US$ m) 2,296.6 Dividend (Next Qtr., US$) — 2013E 0.63 0.75 0.83 0.92 Net debt/tot cap (Next Qtr., %) 14.7 Dividend yield (%) — Source: Company data, Credit Suisse estimates.

Oilfield Services 53 16 October 2012 Investment Overview

■ Initiating Coverage of Halliburton with an Outperform Rating: Halliburton (HAL) has done an exceptional job of managing its business over the past several years, executing well on a number of growth, quality, and technology issues. We see it as one of the primary beneficiaries of the increasingly secular activity drivers of shales/tight sand development and deepwater. But Halliburton has the greatest exposure to the North American completions market which is seeing price and activity erosion. We have risked our valuation of HAL by 20% to account for this level of volatility and still derive a 12-month price target that compels an Outperform rating.

■ HAL has significantly increased capital expenditures, along with competitors over the past several years to take advantage of the shifting emphasis in these two areas and has cemented its position as a strong and capable player against it primary rivals. Management has indicated that a $3 billion annual capex budget is appropriate for a company its size. But returns and free cash flow define valuation more than capital growth, an issue HAL will have to address.

■ Near-Term Is Challenged: Our Outperform rating comes despite our near-term outlook for earnings revisions down over the next couple of quarters, as NAM drilling activity counter-seasonally declines in the third and fourth quarter due to spent budgets by many of its customers, and the seasonal decline into the new year keeps equipment utilization, primarily completion related equipment, at levels that delay margin recovery in equipment and materials. This could result in a six- month rig count that declines or at best stays flat, which is a more negative view than what is driving the current consensus. We look for the U.S. rig count to decline by 4-5% on average, year-over-year basis with any recovery in Canada not occurring soon enough to shift the outlook.

■ Margins and Earnings Revisions Are Both Down: We expect HAL’s third-quarter NAM land margins to drop by 600-650 basis points due to working $500 million in guar purchases down, as well as continued weakness in leading- edge pressure pumping pricing. This would lead to a 1,200-basis-point decline in U.S. pressure pumping margins alone; we think higher than current expectations. The lower levels of drilling/completion activity will also drag the guar cost issues into the first-quarter of 2013. With a number of contracts up for renewal and at least one of the company’s competitors in an aggressive pricing mode to gain market share, we could see margin weakness be more persistent and take longer to recovery than current expectations.

Exhibit 56: HAL - Percentage of Revenues by Region HAL BHI WFT SLB Revenues North American 57% 53% 44% 32% Latin America 12% 12% 21% 18% Eur/CIS/Africa 16% 18% 17% 28% Mid East/Asia 15% 16% 18% 21% Source: Company data, Credit Suisse estimates

■ Contract Renewals Are Happening at a Bad Time: HAL’s NAM service contracts, which represents a high percentage of the company’s work, especially in completions, generally extend 12-18 months. As a result, some percentage is always rolling. This year, contracts are rolling a bit bunched up around the period when drilling activity is waning, over supply of equipment is still pushing pricing lower, and at least one significant competitor is trying to gain market share and

Oilfield Services 54 16 October 2012

specifically, the type of market or customer that HAL has. Higher utilization can be achieved by working 24 hours instead of only daylight hours. However, when one does not have enough concentration of customers who operate 24 hours a day, one goes and tries to work for more of those customers. While incumbent providers have an edge, price generally wins out, everything else being equal, and generally, they are.

■ The Guar Issue Will Be Resolved: The company did the right thing, insuring it had adequate capacity to serve its customer base. Expecting continued shortages and cost inflation, the company spent approximately $500 million on guar inventories, likely bidding against itself in markets. We expect better supply chain intelligence going forward but the aggressive stocking versus a decline in completion activity will keep the inventory overhang into the first quarter of 2013. Expectations of continued shale/tight sands growth, in NAM and internationally, as well as secured contracts, especially in deepwater, will keep capital expenditures high in 2013 and we expect the company to balance cash flow with capital expenditures for the year.

■ We Are Bullish Longer Term: There is little doubt that NAM is experiencing a mid-cycle correction to what had been one of the most sustained up-cycles in the oil and gas industry. The U.S. rig count has been up 8 of the last 9 years, by an average of 11.3% . The financial crash caused a 42% one-year drop in the U.S. rig count after staging a 41% recovery the following year and another spurt of 22% growth in 2011, driven primarily by the significant increase in non-vertical drilling. This year, the rig count should be up a couple of percentage points and we are forecasting down 4-5% in 2013. This translates to a typical seasonal upturn to activity from March-April through year-end, as the U.S. market gets over its mid- cycle correction and resumes what should be one of the most secular moves in a cyclical industry, than seen in years.

Oilfield Services 55 16 October 2012 Company Overview Halliburton is a one of the world’s largest providers of products and services to the energy industry. With nearly 70,000 employees in approximately 80 countries, the company serves the upstream oil and gas industry throughout the lifecycle of the reservoir, from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production through the life of the field. Founded in 1919, Halliburton today consists of two business divisions: Drilling and Evaluation (D&E) and Completion and Production (C&P). HAL’s corporate headquarters are split between Houston, Texas and Dubai, United Arab Emirates. Overview of Business Lines HAL operates under two business divisions: the Completion and Production segment and the Drilling and Evaluation segment, which represented 61% and 39% of total revenue in 2011, respectively.

Exhibit 57: Halliburton (HAL) Percentage of Revenue

39% 61%

Completion and Production Drilling and Evaluation

REVENUE: (Millions of dollars) 2011 2010 2009 2008 2007 Completion and Production$ 15,143 $ 9,997 $ 7,419 $ 9,610 $ 8,138 Drilling and Evaluation 9,686 7,976 7,256 8,669 7,126 Total Revenue$ 24,829 $ 17,973 $ 14,675 $ 18,279 $ 15,264

Source: Company data, Credit Suisse estimates.

Exhibit 58: Halliburton (HAL) Operating Income (Millions of dollars) 2011 2010 2009 2008 2007 Completion and Production$ 3,733 $ 2,032 $ 1,016 $ 2,304 $ 2,119 Drilling and Evaluation 1,403 1,213 1,183 1,970 1,565 Corporate and other (399) (236) (205) (264) (186) Total operating income$ 4,737 $ 3,009 $ 1,994 $ 4,010 $ 3,498 Total operating income (ex-Corp & other)$ 5,136 $ 3,245 $ 2,199 $ 4,274 $ 3,684 Source: Company data, Credit Suisse estimates.

Oilfield Services 56 16 October 2012

Exhibit 59: Halliburton (HAL) Percentage of North American (NAM) Operating Income1 80%

70%

60%

50%

40%

30%

20%

10% 2007 2008 2009 2010 2011

Source: Company data, Credit Suisse estimates. 1; Total operating income excludes Corporate and other. Completion and Production The Completion and Production (C&P) segment delivers cementing, stimulation, intervention, pressure control, specialty chemicals, artificial lift, and completion services. The segment consists of Halliburton Production Enhancement, Cementing, Completion Tools, Boots & Coots, and Multi-Chem. Halliburton Production Enhancement services includes stimulation services and sand control services. Stimulation services optimize oil and natural gas reservoir production through a variety of pressure pumping services, nitrogen services, and chemical processes (hydraulic fracturing, or fracking). Sand control services include fluid and chemical systems and pumping services for the prevention of formation sand production. We estimate that pressure pumping represented approximately 55% of total North American revenues currently. Cementing services involve bonding the well and well casing while isolating fluid zones and maximizing wellbore stability. Our cementing service line also provides casing equipment. Completion Tools includes subsurface safety valves and flow control equipment, surface safety systems, packers and specialty completion equipment, intelligent completion systems, expandable liner hanger systems, sand control systems, well servicing tools, and reservoir performance services. Reservoir performance services include testing tools, real-time reservoir analysis, and data acquisition services. Boots & Coots includes well intervention services, pressure control, equipment rental tools and services, and pipeline and process services. Multi-Chem includes oilfield production and completion chemicals and services that address production, processing, and transportation challenges. Drilling and Evaluation The Drilling and Evaluation (D&E) segment provides field and reservoir modeling, drilling, evaluation, and precise wellbore placement solutions that enable customers to model, measure, and optimize their well construction activities. The segment consists of Halliburton Drill Bits and Services, Wireline & Perforating, Testing and Subsea, Baroid, Sperry Drilling, Landmark Software and Services, and Halliburton Consulting and Project Management.

Oilfield Services 57 16 October 2012

Halliburton Drill Bits and Services provides roller cone rock bits, fixed cutter bits, hole enlargement, and related downhole tools and services used in drilling oil and natural gas wells. In addition, coring equipment and services are provided to acquire cores of the formation drilled for evaluation. Wireline and Perforating services include open-hole wireline services that provide information on formation evaluation, including resistivity, porosity, density, rock mechanics, and fluid sampling. Also offered are cased-hole and slickline services, which provide cement bond evaluation, reservoir monitoring, pipe evaluation, pipe recovery, mechanical services, well intervention, perforating, and borehole seismic services. Perforating services include tubing-conveyed perforating services and products. Borehole seismic services include fracture analysis and mapping. Testing and Subsea services provide acquisition and analysis of dynamic reservoir information and reservoir optimization solutions to the oil and natural gas industry utilizing downhole test tools, data acquisition services using telemetry and electronic memory recording, fluid sampling, surface well testing, subsea safety systems, and reservoir engineering services. Baroid provides drilling fluid systems, performance additives, completion fluids, solids control, specialized testing equipment, and waste management services for oil and natural gas drilling, completion, and workover operations. Sperry Drilling provides drilling systems and services. These services include directional and horizontal drilling, measurement-while-drilling, logging-while-drilling, surface data logging, multilateral systems, underbalanced applications, and rig site information systems. Our drilling systems offer directional control for precise wellbore placement while providing important measurements about the characteristics of the drill string and geological formations while drilling wells. Real-time operating capabilities enable the monitoring of well progress and aid decision-making processes. Landmark Software and Services (Landmark) is a supplier of integrated exploration, drilling, and production software information systems, as well as consulting and data management services for the upstream oil and natural gas industry. Halliburton Consulting and Project Management provides oilfield project management and integrated solutions to independent, integrated, and national oil companies. These offerings make use of all of our oilfield services, products, technologies, and project management capabilities to assist our customers in optimizing the value of their oil and natural gas assets. HAL conducts business worldwide in approximately 80 countries. The business operations of C&P and D&E are then organized around four primary geographic regions: North America (NAM), Latin America (LAM), Europe/Africa/CIS (EAC), and Middle East/Asia (MEAP). In 2011, based on the location of services provided and products sold, 58% of HAL’s revenue were from North America, while the remainder was split, 12% LAM, 16% EAC, and 14% MEAP.

Oilfield Services 58 16 October 2012

Exhibit 60: Halliburton (HAL) Percentage of Total Revenue by Geographic Region 60%

50%

40%

30%

20%

10%

0% 2007 2008 2009 2010 2011

North America Latin America Europe/Africa/CIS Middle East/Asia

Source: Company data, Credit Suisse estimates. Market and Business Drivers The operating results of HAL are primarily driven by the company’s strong presence in the U.S. land completion activity, coupled with its mounting international onshore operations and deepwater drilling and cementing markets. Mounting Well and Service Intensity Onshore As demonstrated by the increasing percentage of oil and horizontal wells being drilled in the United States (see Exhibit 61 and Exhibit 62) and around the world, the overall well and service intensity per well is increasing dramatically. For example, the U.S. horizontal rig count now represents approximately 59% of the total U.S. rig count as of 2Q12, and we estimate that this will likely build to 60% by year-end 2012. This shift to more horizontal drilling is driving demand for more downhole tools and hydraulic fracturing services (or pressure pumping), and we believe BHI is the third largest provider of hydraulic fracturing services in the North America with approximately 1.8 million hydraulic horsepower presently. HAL holds a number one market share position in pressure pumping in North America with approximately 3.0 million hydraulic horsepower; SLB we estimate has approximately 2.1 million hydraulic horsepower in the United States. Overall, we estimate there will be approximately 15.0 million horsepower in the United States and another 1.6 million in Canada, by year-end 2012. (See Exhibit 63.)

Exhibit 61: Historical Oil and Gas Directed Exhibit 62: Historical Oil and Gas Rig Count Horizontal Rig Count

800 700 600 500 400 # of # of Rigs 300 200 Horizontal Gas Rig Count 100 Horizontal Oil Rig Count 0 Oct-10 Apr-11 Oct-11 Apr-12 Jun-10 Jan-11 Jun-11 Jan-12 Mar-10 Aug-10 Aug-11

Source: Baker Hughes. Source: Baker Hughes.

Oilfield Services 59 16 October 2012

Furthermore, our colleague, Ed Westlake released a report recently entitled, U.S. Oil Production Outlook: Energy Independence Day, in which we his team built a proprietary model that estimates shale well count growth in the U.S. To this end, Westlake’s base case envisages the shale well count increasing by 37% from 11,500 wells per annum in 2012 to 15,700 wells by 2020. (See Exhibit 63.) The internationalization of horizontal drilling and hydraulic fracturing into countries such as Argentina, Australia, Columbia, China, Poland, and Russia is also likely to play to HAL’s strengths.

Exhibit 63: Wells Drilled in The Model’s Oil Shale Plays by Year 18,000

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

‐

Source: Company data, Credit Suisse estimates. In early 2012, the NAM pressure pumping market saw a tremendous shift in the rig count composition from being fairly evenly split between oil versus gas to now heavily weighted to oil and liquids-rich drilling. As a result, basins such as the Haynesville became close to uneconomical and E&P companies pulled operations to other basins. It was this shift from gas to liquids-rich drilling which led to drastic declines in NAM drilling and pressure pumping activity, oversupply of equipment, and people in certain areas. HAL has taken the appropriate steps to solidify its position in NAM. The company has approximately 50% of its domestic contract base up for renewal from Q2 and into Q1 of 2013, and BHI is likely to challenge that market share on price. This aggressiveness may help BHI’s utilization and customer mix but these efforts and those of others in the same mode coupled with continued over-capacity are likely to keep the NAM pressure pumping market challenging through at least the 1Q13 and possibly longer. Anecdotally, we have heard from our industry contacts that one major pressure pumping company is taking HHP capacity out of the market to improve its negotiating position. We estimate that the U.S. pressure pumping market has 15.0 million hydraulic horsepower (HHP) and BHI has approximately 1.8 million HHP. Our U.S. Pressure Pumping Supply/Demand Model shows the U.S. market to be 11% oversupplied.

Oilfield Services 60 16 October 2012

Exhibit 64: Credit Suisse U.S. Pressure Pumping Supply/Demand Model Drilling Assumptions Frac Assumptions Frac Calcs Frac Hhp/d Demand (MM) # Frac Adj for # Frac # Wells/ hp/job Days/ frac Days/ 7 days, 12 5 days, 12 5 Days, 1/2 Basin Rig Count Days/well Stages per 1/2 24- Stages per Year w/ Frac (K) stage job hours hours 24-hr well hour Year Haynesville 16 30.0 191 31 45 0.37 12.3 9.2 5,323 0.3 0.4 0.3 Marcellus 75 10.0 2,683 18 32 0.33 7.0 5.3 43,461 1.6 2.3 1.7 Permian 406 15.0 9,682 4 20 0.25 2.0 1.5 34,854 1.1 1.5 1.1 Eagle Ford (S. Tx) 217 30.0 2,587 28 28 0.42 12.7 9.5 65,202 2.5 3.5 2.6 Barnett 41 22.0 667 10 26 0.45 5.5 4.1 6,000 0.3 0.4 0.3 Fayetteville 15 15.0 358 14 30 0.44 7.1 5.3 4,507 0.2 0.3 0.2 Woodford 8 26.0 110 10 30 0.45 5.5 4.1 991 0.0 0.1 0.1 Piceance 16 10.0 526 8 26 0.24 2.9 2.2 3,784 0.1 0.2 0.1 Uinta 30 15.0 715 4 16 0.11 1.4 1.1 2,575 0.0 0.1 0.0 Niobrara 40 18.0 795 18 35 0.50 10.0 7.5 12,877 0.8 1.1 0.8 Bakken (BHI: MT+ND) 160 18.0 3,180 34 19 0.52 18.7 14.0 97,294 3.1 4.3 3.2 Utica 10 20.0 179 10 20 0.50 6.0 4.5 1,610 0.1 0.1 0.1 Other 64 15.0 1,324 4.0 10 0.50 2.0 2.0 4,765 0.1 0.1 0.1 Total 1,098 22,995 283,243 10.2 14.2 10.7

CS Estimated U.S. Frac Hhp Capacity (MM) 15.0

Implied Utilization 118% 89%

Effective Capacity (80% of "nameplate") 12.0 12.0 Source: Company data, Spears & Associates, and Credit Suisse estimates.

Exhibit 65: 2012 NAM Hydraulic Horsepower Additions Projected Current "Announced" Projected 2012 Ticker/Company 2011 YE 2011 1Q12E 2Q12E 3Q12E 4Q12E YE 2012E % Change Capacity (HHP) 2012 Additions Additions Additions SPN 315,000 127,000 442,000 40,000 40,000 40,000 38,000 158,000 600,000 36% PTEN 508,000 142,000 650,000 50,000 700,000 8% # NBR 600,000 200,000 800,000 50,000 850,000 6% CFW 291,000 144,000 435,000 3,000 3,000 3,000 3,000 12,000 447,000 3% TCW 390,000 180,000 570,000 100,000 670,000 18% BAS** 236,000 - 236,000 37,500 273,500 16% FracTech 1,312,750 1,393,500 88,500 88,500 88,500 88,500 354,000 1,666,750 20% RES 495,000 90,000 585,000 55,000 43,000 98,000 683,000 17% WFT 650,000 650,000 150,000 800,000 23% CJES 172,000 38,000 210,000 25,000 32,000 18,000 15,000 90,000 300,000 43% BHI 1,450,000 1,450,000 350,000 1,800,000 24% Great White Energy 98,800 9,000 107,800 107,800 0% HAL 2,400,000 2,400,000 500,000 2,900,000 21% SLB 1,750,000 1,750,000 350,000 2,100,000 20% Chesapeake OFS, LLC 60,000 80,000 140,000 44,000 44,000 44,000 43,000 175,000 315,000 125% Platinum Energy 107,500 107,500 25,000 17,500 42,500 150,000 40% Other 375,000 375,000 300,000 675,000 80%

United States Total 11,211,050 1,010,000 12,301,800 670,500 2,146,500 15,038,050 22%

Canada Total* 1,100,000 200,000 1,300,000 300,000 1,600,000 23%

Total NAM 12,311,050 1,210,000 13,601,800 16,638,050 22% Source: Company data, Spears & Associates, and Credit Suisse estimates. Ultra-Deepwater Mega Project Opportunities HAL holds a number two market share position in the ultra-deepwater (UDW) drilling market, where mega projects last anywhere between 4 to 10 years and can total $500 million to $1.0 billion in total. Lately, the competition to win these ultra-deepwater drilling projects has become extremely aggressive with the major oilfield service providers all jockeying to get the work. This has led to near breakeven type bids just to get some if not all of the work. These UDW projects are often not accretive at the onset but once activity ramps, product upselling opportunities of new technologies allow for margins to improve steadily. Very specific downhole tools or high pressure, high temperature (HP/HT) drilling and logging services can generate 4045% EBITDA margins for HAL and its peers. Statoil (STL NO), Saudi Aramco, and Petrobras (PBR) are usually clients who are most open to using new

Oilfield Services 61 16 October 2012 technologies. Once new technologies see successes and are proven offshore, they are generally offered onshore. With international, national, and major oil and gas companies seeking hydrocarbons in more remote locals, the UDW floating rig count swelling, and exploration successes becoming more frequent, the offshore deepwater market will continue to be a major growth driver for BHI for years to come. Credit Suisse Offshore Drilling analyst, Greg Lewis, estimates that there are currently 39 newbuild UDW Drillships and 7 UDW Semis scheduled for delivery through 2014. Currently, 16 are contracted (8 destined for the Gulf of Mexico, 2 Brazil, 3 West Africa, and 3 Other). Conversations across our energy team [Please verify] lead us to believe that the uncontracted floaters will end up primarily in Africa (50%+), Brazil (~10%); Gulf of Mexico (~10%), and Other (30%).

Exhibit 66: Geographic Rig Placement by Type

50 51

2 d Drillship Jackup Semi

68 15 26

33 Drillship Jackup Semi 142 4 1 10 Drillship Jackup Semi Drillship Jackup Semi

59 132 28 15 23 41

Drillship Jackup Semi Drillship Jackup Semi

Source: IHS Petrodata, Credit Suisse estimates. HAL just won a multimillion directional drilling (DD) contract with Petrobras (PBR) in Brazil. As one of the three mega tenders of 2012 and on the horizon for the near term, this is a significant positive for HAL. The other two winner-takes-all international, mega tenders were won by BHI and SLB. Key Halliburton Brands Baroid: Baroid provides drilling fluid systems, performance additives, completion fluids, solids control, specialized testing equipment, and waste management services for oil and natural gas drilling, completion, and workover operations. Boots & Coots: Boots & Coots is the premier pressure control company. Boots & Coots provides a wide variety of pressure control services to oil and gas exploration and development companies around the world. Landmark: Landmark provides solutions to E&P challenges through the continuous development and enhancement of our leading high-science software and technology services. This is most of HAL’s seismic product offering, albeit it is a desktop software application. Sales are traditionally seasonally strong in the fourth quarter and weaker in the first. With over 350 patent filings since 2001, HAL recognizes that solving your challenges of today, and those of tomorrow, requires constant innovation around everything we do. HAL’s technologies and services span every discipline in our industry

Oilfield Services 62 16 October 2012 and includes such market leaders as OpenWorks®, SeisWorks®, GeoProbe®, and AssetPlanner® applications. Pinnacle: Pinnacle provides industry-unique integration of microseismic, tilt meter, and fiber optic technologies to maximize completion efficiency and production economics. Pinnacle provides a unique combination of fracture and reservoir consulting services, award-winning fracture diagnostic and reservoir monitoring technologies, all recognized worldwide for enhancing production economics. Pinnacle’s fracture diagnostic and reservoir monitoring technologies are aligned with Halliburton’s fracturing and acidizing capabilities to provide more than data; it provides insight and a comprehensive solution to maximize reservoir yields in today’s complex assets. Pinnacle also designs, manufactures, sells, and installs fiber-optic-based pressure and temperature monitoring equipment and systems. HAL recently acquired SensorTran, a company that designs, produces, and markets the world’s most advanced fiber optic-based Distributed Temperature Sensing (DTS) systems.

Sperry Drilling: Sperry Drilling is leading the industry in drilling wells faster, safer and more accurately. Halliburton Over the Years Mono Pumps January 2003: HAL sold its Mono Pumps business to National Oilwell, Inc. (NOV). The sale price of approximately $88 million was paid with $23 million in cash and 3.2 million shares of NOV common stock, which were valued at $65 million on January 15, 2003. The company recorded a gain of $36 million on the sale in the first quarter of 2003, which was included in its Drilling and Formation Evaluation segment. Included in the gain was the write-off of the cumulative translation adjustment related to Mono Pumps of approximately $5 million. In February 2003, HAL sold 2.5 million of its 3.2 million shares of NOV common stock for $52 million, which resulted in a gain of $2 million, and in February 2004, HAL sold the remaining shares for $20 million, resulting in a gain of $6 million. The gains related to the sale of the National Oilwell, Inc. common stock were recorded in Other, net. Wellstream March 2003: HAL sold the assets relating to its Wellstream business, a global provider of flexible pipe products, systems, and solutions, to Candover Partners Ltd. for $136 million in cash. The assets sold included manufacturing plants in Newcastle upon Tyne, United Kingdom, and Panama City, Florida, as well as assets and contracts in Brazil. Wellstream had $34 million in goodwill recorded at the disposition date. The transaction resulted in a loss of $15 million, which was included in its Digital and Consulting Solutions segment. Included in the loss is the write-off of the cumulative translation adjustment related to Wellstream of approximately $9 million. Halliburton Measurement Systems May 2003: HAL sold certain assets of Halliburton Measurement Systems, which provides flow measurement and sampling systems, to NuFlo Technologies, Inc. for approximately $33 million in cash. The gain on the sale of Halliburton Measurement Systems’ assets was $24 million and was included in its Production Optimization segment. Enventure and WellDynamics First quarter of 2004: Halliburton and Shell Technology Ventures (Shell, an unrelated party) restructured two joint venture companies, Enventure Global Technology LLC (Enventure) and WellDynamics B.V. (WellDynamics), in an effort to more closely align the ventures with near-term priorities in the core businesses of the venture owners. Prior to this transaction, Enventure (part of our Fluid Systems segment) and WellDynamics (formerly part of its Digital and Consulting Solutions segment) were owned equally by

Oilfield Services 63 16 October 2012

Shell and HAL. Shell acquired an additional 33.5% of Enventure, leaving HAL with 16.5% ownership in return for enhanced and extended agreements and licenses with Shell for its Poroflex™ expandable sand screens and a distribution agreement for its Versaflex™ expandable liner hangers. As a result of this transaction, HAL changed the way it accounted for its ownership in Enventure from the equity method to the cost method of accounting for investments. HAL acquired an additional 1% of WellDynamics from Shell, giving it 51% ownership and control of day-to-day operations. In addition, Shell received an option to obtain its remaining interest in Enventure for an additional 14% interest in WellDynamics. No gain or loss resulted from the transaction. Beginning in the first quarter of 2004, WellDynamics was consolidated and is now included in its Production Optimization segment. The consolidation of WellDynamics resulted in an increase to HAL’s goodwill of $109 million, which was previously carried as equity method goodwill in “Equity in and advances to related companies.” Surface Well Testing August 2004: HAL sold its surface well testing and subsea test tree operations within its Production Optimization segment to Power Well Service Holdings, LLC, an affiliate of First Reserve Corporation, for approximately $129 million, of which it received $126 million in cash. During 2004, it recorded a $54 million gain on the sale. Subsea 7, Inc. January 2005: HAL completed the sale of our 50% interest in Subsea 7, Inc. to its joint venture partner, Siem Offshore (formerly DSND Subsea ASA), for approximately $200 million in cash. As a result of the transaction, it recorded a gain of approximately $110 million during the first quarter of 2005. It accounted for its 50% ownership of Subsea 7, Inc. using the equity method in its Production Optimization segment. Dulles Greenway Toll Road As part of HAL’s infrastructure projects at the time, the company took an ownership interest in the constructed asset, with a view toward monetization of that ownership interest after the asset has been operating for some period and increases in value. In September 2005, HAL sold its 13% interest in a joint venture that owned the Dulles Greenway Toll Road in Virginia. HAL received $85 million in cash from the sale. Because of unfavorable early projections of traffic to support the toll road after it had opened, it wrote down its investment in the toll road in 1996. At the time of the sale, its investment had a net book value of zero, and therefore, HAL recorded the entire $85 million of cash proceeds to operating income in its Government and Infrastructure segment. Ultraline Services Corporation January 2007: HAL acquired all of the intellectual property, current assets, and existing business associated with Calgary-based Ultraline Services Corporation, a division of Savanna Energy Services Corp., for approximately $177 million, subject to adjustment for working capital purposes. Ultraline is a provider of wireline services in Canada. Ultraline will be reported in HAL’s Drilling and Formation Evaluation segment. KBR, Inc. With the company’s asbestos and silica liability and affected subsidiaries clear of Chapter 11 reorganization proceedings, Halliburton began to separate KBR from Halliburton in 2006. Second quarter of 2006: HAL completed the sale of KBR’s Production Services group, which was part of its Energy and Chemicals segment. In connection with the sale, HAL received net proceeds of $265 million. The sale of Production Services resulted in an adjusted pretax gain, net of post-closing adjustments, of approximately $120 million, which is reflected in discontinued operations.

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November 2006: KBR, Inc. completed an IPO, in which it sold approximately 32 million shares of KBR, Inc. common stock, at $17.00 per share. HAL received proceeds of approximately $508 million from the IPO, net of underwriting discounts and commissions and offering expenses. As the IPO was a result of a broader corporate reorganization, the increase in the carrying amount of our investment in KBR, Inc. was recorded in Paid-in capital in excess of par value on our consolidated balance sheet at December 31, 2006. HAL now holds an approximate 81% interest in KBR, Inc., represented by 135.6 million shares of KBR, Inc. common stock, and consolidate KBR, Inc. for financial reporting purposes. February 26, 2007: HAL’s Board of Directors approved a plan under which it will dispose of its remaining interest in KBR, Inc. through a tax-free exchange with Halliburton shareholders pursuant to an exchange offer, and following the completion or termination of the exchange offer, a special pro rata dividend distribution of any and all of its remaining KBR, Inc. shares. In connection with the anticipated exchange offer, KBR, Inc. will file with the Securities and Exchange Commission (SEC) a registration statement on Form S-4 with respect to the offering, and it will file with the SEC a Schedule TO. The exchange offer will be conditioned on a minimum number of shares being tendered. Any exchange of KBR, Inc. stock for outstanding shares of Halliburton Company common stock pursuant to the exchange offer will be registered under the Securities Act of 1933, and such shares of common stock will only be offered and sold by means of a prospectus. This annual report does not constitute an offer to sell or the solicitation of any offer to buy any securities of KBR, Inc. The exchange offer and any subsequent spin-off will complete the separation of KBR, Inc. from Halliburton and will result in two independent companies. In January 2007, we received a ruling from the Internal Revenue Service that, among other things, no gain or loss will be recognized by Halliburton or its shareholders as a result of a distribution of KBR, Inc. stock by means of a pro rata dividend. HAL has requested a supplemental ruling from the Internal Revenue Service that no gain or loss will be recognized by Halliburton or its shareholders as a result of a distribution of KBR, Inc. stock by means of an exchange offer whereby holders of Halliburton stock may tender their shares and receive KBR, Inc. shares in exchange, followed by a dividend distribution of any remaining shares of KBR, Inc. stock held by Halliburton to its shareholders. The exchange offer and any subsequent distribution of KBR, Inc. stock will not be conditioned on receipt of such a supplemental ruling from the Internal Revenue Service. HAL has also obtained an opinion of counsel related to the tax-free nature of the exchange offer and any subsequent spin-off distribution. PSL Energy Services Limited July 2007: HAL acquired the entire share capital of PSL Energy Services Limited (PSLES), an eastern hemisphere provider of process, pipeline, and well intervention services. PSLES has operational bases in the United Kingdom, Norway, the Middle East, Azerbaijan, Algeria, and Asia Pacific. We paid approximately $330 million for PSLES, consisting of $326 million in cash and $4 million in debt assumed, subject to adjustment for working capital purposes. As of December 31, 2007, we had recorded goodwill of $163 million and intangible assets of $54 million on a preliminary basis until its analysis of the fair value of assets acquired and liabilities assumed is complete. Beginning in August 2007, PSLES’s results of operations are included in its Completion and Production segment. Dresser Equipment Group As a part of its sale of Dresser Equipment Group in 2001, HAL retained a small equity interest in Dresser Inc.’s Class A common stock. Dresser Inc. was later reorganized as Dresser, Ltd., and it exchanged its shares for shares of Dresser, Ltd. In May 2007, HAL sold its remaining interest in Dresser, Ltd. HAL received $70 million in cash from the sale and recorded a $49 million gain. This investment was reflected in Other assets on its consolidated balance sheet on December 31, 2006.

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WellDynamics July 2008: HAL acquired the remaining 49% equity interest in WellDynamics from Shell Technology Ventures Fund 1 B.V. (STV Fund), resulting in its 100% ownership of WellDynamics. WellDynamics is a provider of intelligent well completion technology and its results of operations are included in HAL’s Completion and Production segment. Dresser Equipment Group As a part of HAL’s sale of Dresser Equipment Group in 2001, it retained a small equity interest in Dresser Inc.’s Class A common stock. Dresser Inc. was later reorganized as Dresser, Ltd., and HAL exchanged its shares for shares of Dresser, Ltd. In May 2007, HAL sold its remaining interest in Dresser, Ltd. HAL received $70 million in cash from the sale and recorded a $49 million gain. KBR, Inc. HAL paid $417 million to the Department of Justice (DOJ) and Securities and Exchange Commission (SEC) in 2009 related to the settlements with them and under the indemnity provided to KBR, Inc. (KBR) upon separation. Foreign Corrupt Practices Act (FCPA) As a result of the resolution of the DOJ and SEC Foreign Corrupt Practices Act (FCPA) investigations, HAL will pay a total of $142 million in equal installments over the next three quarters for the settlement with the DOJ and under the indemnity provided to KBR upon separation. Multi-Chem Group, LLC In October 2011, HAL completed the acquisition of Multi-Chem Group, LLC (Multi-Chem) in an all-cash transaction. Multi-Chem is the fourth-largest provider of production chemicals in North America, delivering specialty chemicals, services and solutions. HAL paid approximately $880 million for Multi-Chem and other acquisitions in 2011. Future M&A Trican Well Services Ltd. In meeting with senior management of Halliburton in late-July, we asked where the company would consider buying a smaller domestic pressure pumping company and we were told that it could buy hydraulic horsepower at 150% of replacement cost and make such a deal accretive. Strategically, we think Halliburton could buy Trican Well Services Ltd. (TCW CN) and export TCW’s 670,000 horsepower overseas. A move that would alleviate excess capacity concerns in the North American market, while also allowing HAL to be the first to market in several overseas markets. Australia, in particular, could be such a market. Management Team David J. Lesar (Chairman, President, & CEO) Mr. Lesar has been executive chairman and chief executive officer of Halliburton since August 2000 and has been its president since May 1997. Mr. Lesar served as the chief operating officer of Halliburton from June 1997 to August 2000 and its executive vice president and chief financial officer from June 1995 to June 1996. Mr. Lesar joined Halliburton in 1993 and also served in many capacities. Prior to Halliburton, Mr. Lesar was a partner with Arthur Andersen LLP. Mr. Lesar serves as director of the American Petroleum Institute. He serves as a member of advisory board of The British-American Business Council. He served as a director of Lyondell Chemical Company since July 28, 2000. He served as a Director of GenOn Energy, Inc. (also known as Mirant Corp.), since 2000 and Cordant Technologies Inc. since August 1998. Mr. Lesar is a 1978 graduate of the University of Wisconsin where he earned his BS and MBA.

Oilfield Services 66 16 October 2012

Mark A. McCollum (Executive Vice President & CFO) Mr. McCollum has been chief financial officer and executive vice president of Halliburton since January 2008. Mr. McCollum served as chief accounting officer and senior vice president of Halliburton from August 25, 2003 to December 31, 2007. He serves on Accounting Department Advisory Council of Baylor University. Mr. McCollum is a certified public accountant in Texas, and is a member of the AICPA, the Texas Society of CPA’s, the Financial Executives Institute and the Institute of Management Accountants. Mr. McCollum received his bachelor of business administration from Baylor University. Jeff Miller (Executive Vice President & COO) Mr. Miller was promoted to executive vice president and COO of Halliburton on September 20, 2012. In his new position, Mr. Miller will be responsible for Halliburton’s global operations, as well as business development and marketing. Prior to his current role, Miller has held a number of positions at Halliburton, including most recently as senior vice president of global business development and marketing, responsible for strategic account management, sales, and marketing. He has also served as senior vice president of Halliburton’s Gulf of Mexico region, vice president of the company’s Baroid business line, country vice president for Indonesia, and country vice president for Angola. Miller holds a Bachelor of Science degree in agriculture and business from McNeese State University and has a Master of Business Administration degree from Texas A&M University. Miller is a certified public accountant and a member of the Texas A&M University Look College of Engineering Advisory Board. Timothy J. Probert (President of Strategy & Corporate Development) Mr. Probert has been president of Strategy & Corporate Development of Halliburton since January 2011. Mr. Probert served as president of Global Business Lines & Corporate Development at Halliburton from January 2010 to January 2011. He served as senior vice president of Drilling & Evaluation Digital Solutions of Halliburton Energy Services Inc. from May 2006 to December 2007. He served as president of Drilling & Evaluation division and president of Corporate Development at Halliburton from March 2009 to December 2009. He is a member of the Corporate Advisory Board of the American Association of Petroleum Geologists. Mr. Probert received a BS in geology and geography from the University of London in 1972. Valuation We are using a 6.3x EV/EBITDA multiple times our forecasted 2013 EBITDA of $6.64billion, on revenues of $31.6 billion to generate our price target of $44 per share. We are using an EVA component in our EV/EBITDA valuation since returns and capital allocation will be two of the most critical issues going forward for the industry. The shale boom is not going away and the capital needs of the service providers should continue to be high. Without some view of capital efficiency and adequate returns on capital, companies can generate high metrics but still destroy value if one just looks at historical EV/EBITDA valuation. The world has changed. In our model, the actually derived EV/EBITDA multiple from the analysis for Halliburton was 7.9x, the highest in the group. Historically, HAL has traded at a discount to SLB, the multiple leader through a period where SLB also generated the highest returns. Over the past few years, HAL has taken the lead . When we look at the group’s historical EVA to EV/EBITDA relationship, HAL’s current return profile generates a significantly higher multiple. Because HAL has more leverage to changes in the North American completion market, which is the most volatile sub-segment of the services sector, and currently both price and volume are declining, we have risked HAL’s valuation multiple rather than the earnings, especially since price erosion is extremely difficult to model. Even using this knocked down multiple, we still get the highest price target for HAL in our universe.

Oilfield Services 67 16 October 2012

The will closely watch the earnings volatility of HAL over the next several quarters to see if our discount is warranted or removed. The company is forecast to have the highest ROC of the peer group in 2013. Capex should be a bit lower in 2013 but is likely to ramp back up in succeeding years as the capital required for the international shale boom starts getting allocated. HAL currently trades at 11.2x and 10.9x times our 2012/13 EPS estimates, and 5.5x and 5.1x times our 2012/13 EBITDA estimates, respectively. On an EV/EBITDA basis, shares of HAL trade a 20% discount to the peer group’s average 2013 EV/EBITDA multiple and a 41% discount to SLB.

Exhibit 67: HAL Comparables

(US$ in millions, except per share data) Stock Price Market Enterprise EBIT DA EV / EBITDA EPS P / EPS Company Ticker Rating TP $ 10/15/12 Shares Value Value 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E

Baker Hughes BHI Neutral $40 $44.77 440 $19,699 $23,948 $4,121 $4,594 5.8x 5.2x $3.57 $3.91 12.5x 11.4x Schlumberger Limited SLB Neutral $66 $72.19 1,339 $96,662 $103,644 $11,164 $12,056 9.3x 8.6x $4.19 $4.58 17.2x 15.8x Weatherford International WFT Neutral $11 $12.17 769 $9,359 $17,552 $2,910 $3,221 6.0x 5.4x $0.93 $1.18 13.1x 10.3x

Mean 7.0x 6.4x 14.3x 12.5x Median 6.0x 5.4x 13.1x 11.4x High 9.3x 8.6x 17.2x 15.8x Low 5.8x 5.2x 12.5x 10.3x

Halliburton Company HAL Outperform $44 $33.80 926 $31,299 $33,942 $6,075 $6,644 5.6x 5.1x $3.04 $3.12 11.1x 10.8x Premium/(Discount) to Peer Group Average -21% -20% -22% -13% Source: Company data, Bloomberg, and Credit Suisse estimates. The Gulf of Mexico/Macondo Well Incident The semisubmersible drilling rig, Deepwater Horizon, sank on April 22, 2010, after an explosion and ensuing fire onboard the rig began on April 20, 2010. The Deepwater Horizon was owned and operated by Transocean Limited (RIG). The rig was drilling the Macondo exploration well in the Mississippi Canyon Block 252 in the U.S. Gulf of Mexico (GoM) for the lease operator, BP Exploration & Production, Inc. (BP). Halliburton provided several services during BP’s exploration, including cementing, mud logging, direction drilling, measurement-while-drilling, and rig data acquisition services. The explosion, fire, and final sinking of the Deepwater Horizon lead to 4.9 million barrels of oil leaking from the well and eleven fatalities. As of December 31, 2011, Halliburton has not accrued any amounts related to this matter because the company has not determined that a loss is probable and a reasonable estimate of a loss or range of loss related to Macondo cannot be made. Investment Risks The investment risks of investing in HAL are two fold, those specific to the company and those that relate to the broader oilfield service industry. Company-specific risks include (1) a significant portion of HAL’s revenue from come from North America (i.e., U.S. Land; 52% in 2011, 42% in 2010, and 30% in 2009), (2) changes in and compliance with post-Macondo restrictions and regulations, (3) environmental, (4) inability to new technologies, and (6) retention of key/skilled employees. Industry-specific risks include (1) oil prices, (2) global oil demand, (3) global GDP, (4) global E&P capex spending, (5) interest rate risk, (6) environmental and government regulations, (7) oversupply of pressure pumping equipment, (8) increased competition, (9) inclement weather/seasonality, and (10) geopolitical risks.

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Americas / United States Oil & Gas Equipment & Services

Schlumberger (SLB) Rating NEUTRAL* Price (12 Oct 12, US$) 72.19 INITIATION Target price (US$) 66.00¹ 52-week price range 80.00 - 59.67 “U Can’t Touch This” Market cap. (US$ m) 95,798.16 Enterprise value (US$ m) 100,865.50 ■ Initiating Coverage of Schlumberger with an Neutral Rating: While its valuation relative to its peers is stretched, it likely has more earnings *Stock ratings are relative to the coverage universe in each resilience over the next couple of quarters as a result of its international and analyst's or each team's respective sector. ¹Target price is for 12 months. seismic exposure. SLB is a well-run behemoth of a company, with some level of technology leadership across most of its product lines. New Research Analysts management seems to have aggressive financial performance, as one of its James Wicklund 214 979 4111 key goals. While we believe that international spending and activity will be a [email protected] slow grind up, significant exposure to Russia, the Middle East, Latin America Jonathan Sisto and deepwater, coupled with a strong technology portfolio makes it well 212 325 1292 positioned to show strong relative performance over the near term and solid [email protected] performance in the long term. Brittany Commins 212 325 7128 ■ Diversified with Other Businesses: On a percentage of revenues basis, [email protected] SLB, the second largest pressure pumping company, has half the exposure to that market than the #1 player, HAL. The company will be negatively affected by any continued weakness in drilling activity and pricing, which we think will continue into 2013 but the impact to the bottom line is mitigated by its diversity, justifying, at least on a near-term basis, the multiple premium relative to its peers. Seismic is only 8% of SLB’s revenue base but is seeing better pricing improvement than most any other business segment. ■ Valuation is the Only Issue. SLB has been rewarded over the years with a premium valuation multiple, deserved because of it higher returns. For three years now, they have ceded that return leadership and while leading technology is fabulous, the returns should be as well. So until the returns get geared up, our EVA-based EV/EBITDA valuation models says the stock is ahead of itself based on our forecast. They will continue to do a fabulous job and as their returns get more fabulous, so will our price target.

Share price performance Financial and valuation metrics

Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = US$67.2 Year 12/11A 12/12E 12/13E12/14E 80 EPS (CS adj.) (US$) 3.65 4.19 4.58 — 60 Prev. EPS (US$) — — — — 40 P/E (x) 19.8 17.2 15.8 — 20 P/E rel. (%) 130.2 120.8 123.0 — 0 Revenue (US$ m) 39,540.0 42,344.4 44,279.5 — Oct-11 Jan-12 Apr-12 Jul-12 EBITDA (US$ m) 10,098.0 11,188.3 12,101.0 — Price Indexed S&P 500 INDEX OCFPS (US$) 4.53 4.89 6.73 — On 10/03/12 the S&P 500 INDEX closed at 1434.2 P/OCF (x) 15.1 14.7 10.7 — EV/EBITDA (current) 10.0 9.0 8.3 — Net debt (US$ m) 4,770 5,067 1,133 — ROIC (%) 14.32 14.58 15.53 —

Quarterly EPS Q1 Q2 Q3 Q4 Number of shares (m) 1,327.03 IC (current, US$ m) 36,162.00 2011A 0.71 0.87 0.98 1.11 BV/share (Next Qtr., US$) 24.2 EV/IC (x) 2.6 2012E 0.98 1.05 1.05 1.11 Net debt (Next Qtr., US$ m) 6,082.0 Dividend (Next Qtr., US$) — 2013E — — — — Net debt/tot cap (Next Qtr., %) 18.7 Dividend yield (%) — Source: Company data, Credit Suisse estimates.

Oilfield Services 69 16 October 2012 Investment Overview We are initiating coverage of Schlumberger Limited (SLB) with a Neutral rating and $66 target price. SLB is 3 times the size of Halliburton, the #2 company in the sector, on the basis of market capitalization and enterprise value. The company has been the bellwether blue chip in the oilfield services universe for decades and continues in that role with a diverse and educated workforce, strong technology development, and implementation and a focus on the reservoir rather than the well.

■ North America Concerns: We feel that the U.S. markets will be challenged through year end with a declining rig count, over capacity in several key technologies including pressure pumping and completion equipment and materials. In general, with current year’s budgets almost exhausted and little certainty on commodity prices and activity next year, we think that the U.S. rig count will bottom in late Q1, or early Q2 next year and that third and fourth quarter 2012 earnings this year are too high for all North American-centric operations. We forecast that the U.S. rig count will be down 4-5% in 2013 from the 2012 average and that translates into a declining rig count over the next six months before resuming an upward trend.

Exhibit 68: Geographic Revenue Composition BHI HAL SLB WFT Re ve nue s : North America 53% 57% 32% 44% Latin America 12% 12% 18% 21% Eur/CIS/Africa 18% 16% 28% 17% Middle East/Asia 16% 15% 21% 18% Source: Company data, Credit Suisse estimates.

■ Diversity Should Help: As Exhibit 68 shows, SLB has the least amount of exposure to the North American market, with first place shares in the Middle East/Asia and Europe/CIS/Africa regions, and a strong and growing position in Latin America, aided in part by the recently awarded PBR offshore wireline contract. SLB noted that service capacity is tightening in seismic, wireline, and drilling services, three areas of market share leadership for the company. We are expecting the international rig count to be up only slightly in 2013, led primarily by offshore, with 57 rigs expected to be put into service over the next two years, which is the driver to SLB’s expected near-term growth.

■ Change in Attitude: SLB appointed Paal Kibsgaard as CEO on August 1, 2011, following the retirement of Andrew Gould, who had steered the company for eight years. Kibsgaard is a petroleum engineer from Norway who joined Schlumberger in 1997. Gould was an accountant with a degree in economic history. Gould did an excellent job in his tenure at SLB and handed over a well-oiled machine to Kibsgaard. However, we think that management styles and focus will be different this time. Paal seems more focused on the financial performance of every aspect of the company while maintaining its dominant technology position, whereas Gould was dedicated to maintaining the dominant technology position with financial performance being the result. It should be interesting. Interesting Points

■ With the continuing expansion of reach by BGP, the Chinese seismic company, land seismic operations are becoming increasingly competitive since they are manpower intensive, giving them an edge. Earlier this year, SLB had several crews operating in the Middle East displaced by BGP on price and in areas where SLB has been operating for some time. SLB made the point that it would begin to

Oilfield Services 70 16 October 2012

license its older land technology which would indicate its entry into the $1.5bn/year seismic equipment market, currently a duopoly of suppliers.

■ SLB bought the remaining interest in Framo Engineering a year ago after a fourteen year collaboration with the company. Framo is a leading supplier of multiphase subsea pumps and meters with about 500 people located in Norway. It puts SLB directly into the subsea equipment market, combining Framo’s boosting and metering business with SLBs flow assurance and surveillance capability. With SLB’s nose now firmly under the tent of subsea equipment players, it will be interesting to see what it does next, integrating reservoir and subsea equipment.

■ China is not only the fastest growing energy consumer, it also appears to have vast shale potential as well. SLB capitalized again on its collaborative efforts, buying 20% (~$100 million) of a Chinese oilfield services company, Anton Oilfield Services, founded in 1999, it had been working with for several years and forming a joint venture to offer IPM services onshore in China.

■ Pemex currently spends more capital than Brazil on its oil and gas industry and while the first try at Chicontepec did not end well for all, SLB is partnering with PetroFrac (PFC-LN) on an integrated production service contract in Mexico. PetroFrac is the lead with SLB as the sub and the initial project spend is not huge initially, expected at $17.5 million for the first two years, but for the remainder of the 30 year contract, capex will be on a per barrel basis, in an effort to incentivize better results. We do not expect SLB to make much more than a bit over its cost of capital, as it was bid aggressively; however a 30-year deal based on a fee per barrel is a landmark event in Pemex, service company relations.

■ IsoMetrix. How could we put out a report on SLB without mentioning their new marine technology that measures wavefields in four components? We just couldn’t. After at least ten years of waiting, time-lapse 3-D and multi-component 3- D, the reflected wave, the two orthogonal waves and the shear wave, are becoming real commercial applications. Instead of sonar locating the submarine, multi-component tells you how many torpedoes are on board. The potential benefits to increased reservoir drainage is significant. SLB has always enjoyed a premium multiple versus its peer group. Exhibit 69 shows, the ten-year premium versus HAL is 43% and versus BHI 34%. While the premiums today over those two companies are extreme relative to the averages, they are basically in-line with the last two and half years. SLB is trading at a narrower premium to its historical average than the next two companies but interestingly has persistently had a lower return on capital than HAL.

Exhibit 69: SLB Multiple Premium Over the Years EV/Ebitda SLB Premium Over Return on Capital SLB HAL BHI WFT HAL BHI WFT SLB HAL BHI WFT 2003 11.3x 9.7x 12.6x 13.0x 17% -10% -13% 2003 3.5% -8.5% 3.7% 4.8% 2004 13.8x 12.3x 12.2x 11.8x 12% 14% 17% 2004 8.4% -18.8% 8.2% 6.6% 2005 12.1x 10.1x 11.6x 11.5x 20% 4% 5% 2005 17.5% 13.0% 15.4% 8.4% 2006 12.0x 9.2x 10.2x 9.4x 31% 17% 27% 2006 24.6% 29.0% 34.6% 11.9% 2007 12.9x 8.3x 9.2x 10.4x 56% 39% 24% 2007 29.4% 33.6% 26.5% 12.5% 2008 10.7x 7.0x 6.4x 9.4x 54% 68% 14% 2008 27.8% 28.2% 21.3% 12.5% 2009 10.6x 7.7x 8.1x 11.7x 38% 30% -10% 2009 17.8% 14.9% 12.1% 7.7% 2010 12.2x 7.5x 7.8x 10.5x 63% 56% 16% 2010 13.2% 11.7% 4.9% -5.6% 2011 11.0x 6.5x 6.8x 8.1x 68% 61% 36% 2011 13.9% 17.7% 9.2% 1.5% 2012* 9.2x 5.3x 5.7x 12.6x 73% 61% -27% 2012 13.5% 18.4% 9.8% 3.2% 11.6x 8.4x 9.1x 10.8x 43% 34% 9% 17.0% 13.9% 14.6% 6.4% Crnt Discount from Avg -20% -36% -37% 16% * 2012 1H Ebitda annualized Source: Bloomberg, Company data, and Credit Suisse estimates.

Oilfield Services 71 16 October 2012 Company Overview Founded in 1926, Schlumberger Limited (SLB) is a leading oilfield services company supplying technology, information solutions, and integrated project management that optimize reservoir performance for customers working in the oil and gas industry. Having invented wireline logging as a technique for obtaining downhole data in oil and gas wells, Schlumberger today supplies a wide range of products and services from seismic acquisition and processing, drill bits and drilling fluids, directional drilling and drilling services, and formation evaluation and well testing to well cementing and stimulation, artificial lift and well completions, and consulting, software, and information management. Schlumberger has principal executive offices in Paris, Houston, and The Hague. As of December 31, 2011, the company employed approximately 113,000 people of over 140 nationalities working in approximately 85 countries. Business Segments Schlumberger Oilfield Services operates in each of the major oilfield service markets, managing its business through three groups: (i) Reservoir Characterization, (ii) Drilling, and (iii) Reservoir Production. Each Group consists of a number of technology-based service and product lines, or Technologies. These Technologies cover the entire life cycle of the reservoir and correspond to a number of markets in which SLB holds leading positions. The business is then also managed through 35 GeoMarket regions, which are grouped into four geographic areas: North America, Latin America, Europe/CIS/Africa, and Middle East & Asia. Quarter-by-quarter, SLB reports financial results by the aforementioned geographies; however, for the basis of presentation herein, we will provide an overview of the three business groups to offer a better view of the entire company.

Exhibit 70: SLB—Historic Revenue by geography

Source: Company data.

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SLB’s non-United States operations accounted for approximately 68% of consolidated revenue in 2011; 76% and 84% in 2010 and 2009, respectively.

Exhibit 71: SLB: Historic Income Before Taxes by Geography

Source: Company data. Note: Income before taxes prior to Eliminations & other. Reservoir Characterization Group Reservoir Characterization consists of the principal technologies involved in finding and defining hydrocarbon deposits. These include WesternGeco, Wireline, Testing Services, Schlumberger Information Solutions, and Data & Consulting Services. • WesternGeco is the world’s leading geophysical services company, providing comprehensive worldwide reservoir imaging, monitoring and development services, onshore and offshore. WesternGeco also offers an extensive multiclient data library. • Wireline provides the information necessary to evaluate subsurface formation rocks and fluids to plan and monitor well construction, and to monitor and evaluate well production. Wireline offers open-hole and cased-hole services including wireline perforating. • Testing Services provides exploration and production pressure and flow-rate measurement services at the surface and downhole. • Schlumberger Information Services provides software, consulting, information management and IT infrastructure services that support core oil and gas industry operational processes • Data & Consulting Services supplies interpretation and integration of all exploration and production data types, as well as expert consulting services for reservoir characterization, production enhancement, field development planning and multidisciplinary reservoir, and production solutions. Drilling Group SLB’s Drilling Group consists of technologies and equipment involved in the drilling and positioning of oil and gas wells and comprises Bits & Advanced Technologies, M-I SWACO, Geoservices, Drilling & Measurements, PathFinder, Drilling Tools & Remedial, Dynamic Pressure Management and Integrated Project Management (IPM) well construction projects.

Oilfield Services 73 16 October 2012

• Bits & Advanced Technologies designs, manufactures, and markets highly sophisticated drill bits. These technologies leverage proprietary modeling and simulation software for the design of application-specific bits and cutting structures. SLB’s acquisition of Smith International in 2010 propelled SLB to a number one share in drill bits. • M-I SWACO is a leading supplier of drilling fluid. The division also includes environmental solutions that safely manage waste volumes generated in drilling and production operations. SLB primarily competes against Baker Hughes and Halliburton and to some extent Newpark Resources (NR) and Tetra Technologies (TTI). • Geoservices supplies mud logging services for geological and drilling surveillance. • Drilling & Measurements and PathFinder supplies engineering support, directional-drilling, measurement-while-drilling, and logging-while-drilling for all wells. • Drilling Tools & Remedial provides a wide variety of bottom-hole assembly drilling tools. • Dynamic Pressure Management houses SLB’s managed pressure drilling and underbalanced drilling operations. Reservoir Production Group Reservoir Production consists of the principal technologies involved in the production of oil and gas reservoirs using completion techniques, artificial lift, well intervention, subsea, water services, carbon services, and production management. • Well Services includes pressure pumping, well cementing, and stimulation. • Completions supplies equipment such as packers, safety valves, and sand control screens. • Artificial Lift provides production equipment and optimization services using electrical submersible pumps and gas lift equipment onshore and offshore. The company also offers surface horizontal pumping systems. SLB’s primary competition in Artificial Lift comes from Weatherford (WFT), Baker Hughes (BHI), and Lufkin Industries (LUFK). Of note, SLB’s closest competitor Halliburton does not have an artificial lift product offering. With the proliferation of shale oil and gas drilling in North America, the demand for artificial lift offerings is growing rapidly.

• Well Intervention develops coiled tubing equipment and services and provides Coiled Tubing Mkt Share slickline services for downhole mechanical well intervention, reservoir monitoring, and downhole data acquisition. We estimate SLB has 23% market share position in coiled tubing services globally, according to Spears & Associates. SLB 23% • Subsea SLB offers subsea solutions through a joint venture with Framo Other 36% Engineering, which the company acquired the remaining interest in in 2011. HAL SLB/Framo designs and sells subsea boosting technologies, multiphase meters, 14% and water reinjection pumps to improve reservoir recovery rates with different TCW CN BHI 5% SPN 13% subsea pumps and production manifolds. Many of the company’s subsea product 9% offerings compete head on with subsea leaders, such as FMC Technologies (FTI) and Cameron International (CAM). Source: Spears & Associates. • Carbon and Water Services provides containment and handling solutions. Lastly, the oil and gas industry’s focus has begun moving toward maximizing production and estimated ultimate recovery. Integrated Project Management (IPM) is SLB’s response to this challenge and a significant growth area for the company. IPM activity is characterized by long-term relationships between the customer and the company. SLB’s IPM offers a combination of engineering, process management, and understanding of

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Schlumberger segment technologies. SLB has achieved a number of successes in IPM, in particular in Mexico. The Burgos project for example, now in its seventh year, has delivered 237 completed wells, which include the drilling of 2.3 million feet of hole. The benefits to PEMEX have included accelerated production, reduced capital expenditure and increased efficiency. Competition SLB’s primary competitors in the oilfield service space are predominately Baker Hughes (BHI), Halliburton (HAL), and Weatherford (WFT).

Oilfield Services 75 16 October 2012 Market & Business Drivers The operating results of SLB are primarily driven by the company’s strong presence in the deepwater arena, marine seismic, well service intensity, wireline, well-testing and fluids, as well as, the company’s geographically diverse infrastructure and support network. Ultra-Deepwater Mega Project Opportunities Schlumberger holds a number one market share position in the ultra-deepwater (UDW) drilling market, where mega projects last anywhere between 4 to 10 years and can total $500 million to $1.0 billion in total. SLB is also number one in Brazil, followed by HAL. Lately, the competition to win these ultra-deepwater drilling projects has become extremely aggressive with the major oilfield service providers all jockeying to get the work. This has led to near breakeven type bids just to get some if not all of the work. These UDW projects are often not accretive at the onset but once activity ramps, product upselling opportunities of new technologies allow for margins to improve steadily. Specific downhole tools or high pressure, high temperature (HP/HT) drilling and logging services can generate 40-45% EBITDA margins for SLB and its peers. Statoil (STL NO), Saudi Aramco, and Petrobras (PBR) are usually clients who are most open to using new technologies. Once new technologies see successes and are proven offshore, they are generally offered onshore. With international, national, and major oil and gas companies seeking hydrocarbons in more remote locals, the UDW floating rig count swelling, and exploration success becoming more frequent, the offshore deepwater market will continue to be a major growth driver for SLB for years to come. Credit Suisse Offshore Drilling analyst, Greg Lewis, estimates that there are currently 39 newbuild UDW Drillships and 7 UDW Semis scheduled for delivery through 2014. Currently, 16 are contracted (8 destined for the Gulf of Mexico, 2 Brazil, 3 West Africa, and 3 Other). Conversations across our energy term lead us to believe that the uncontracted floaters will end up primarily in Africa (50%+), Brazil (~10%); Gulf of Mexico (~10%), and Other (30%).

Exhibit 72: Geographic Rig Placement by Type

50 51

2 d Drillship Jackup Semi

68 15 26

33 Drillship Jackup Semi 142 4 1 10 Drillship Jackup Semi Drillship Jackup Semi

59 132 28 15 23 41

Drillship Jackup Semi Drillship Jackup Semi

Source: IHS Petrodata, Credit Suisse estimates.

Oilfield Services 76 16 October 2012

Mounting Well & Service Intensity Onshore As demonstrated by the increasing percentage of oil and horizontal wells being drilled in the United States (Exhibit 73 and Exhibit 74) and around the world, the overall well and service intensity per well is increasing dramatically. For example, the U.S. horizontal rig count now represents approximately 59% of the total U.S. rig count as of 2Q12, and we estimate that this will likely build to 60% by year-end 2012. This shift to more horizontal drilling is driving demand for more downhole tools and hydraulic fracturing services (or pressure pumping), and we believe SLB is the number two provider of hydraulic fracturing services in the North America, with approximately 2.1 million hydraulic horsepower presently. HAL holds a number one market share position in pressure pumping in North America, with approximately 3.0 million hydraulic horsepower and $11 billion in sales in 2011. Outside of North America, SLB and HAL’s pressure pumping businesses are of comparable size. Overall, we estimate there will be approximately 15.0 million horsepower in the United States and another 1.6 million in Canada by year-end 2012.

Exhibit 73: Historical Oil and Gas Directed Exhibit 74: Historical Oil and Gas Rig Count Horizontal Rig Count

800 700 600 500 400 # of # of Rigs 300 200 Horizontal Gas Rig Count 100 Horizontal Oil Rig Count 0 Oct-10 Apr-11 Oct-11 Apr-12 Jun-10 Jan-11 Jun-11 Jan-12 Mar-10 Aug-10 Aug-11

Source: Baker Hughes. Source: Baker Hughes. Furthermore, our colleague, Ed Westlake released a report recently, titled, U.S. Oil Production Outlook: Energy Independence Day, in which we his team built a proprietary model that estimates shale well count growth in the U.S. To this end, Westlake’s base case envisages the shale well count increasing by 37% from 11,500 wells per annum in 2012 to 15,700 wells by 2020 (Exhibit 75) The internationalization of horizontal drilling and hydraulic fracturing into countries such as Argentina, Australia, China, Poland, and Russia is also like to play to SLB’s strengths. By being the sole service company in many geographies, SLB will be able to carve out prominent share.

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Exhibit 75: Wells Drilled in The Model’s Oil Shale Plays by Year 18,000

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

‐

Source: Company data, Credit Suisse estimates. In addition, to the proliferation of oil and gas shale drilling domestically and internationally, SLB’ acquisition of Smith International in 2010 gave SLB a number one market share position in drill bits. SLB has said it believes that they have gained share in directional drilling (DD), measuring-while-drilling (MWD), and logging-while-drilling (LWD), as well, following the Smith acquisition. The rationale being that if SLB’s drilling products are on approximately 500 rigs a day, shifting more of that activity to Smith bits or products, is how it is gaining share. The company also believes drill bits margins in the U.S. are similar to pressure pumping margins. Seismic - WesternGeco SLB’s WesternGeco business housed in the Reservoir Characterization Group, generated $2.63 billion in revenue in 2011 according to Spears & Associates; equating to approximately 26.4% of Reservoir Characterization revenues. SLB provides comprehensive worldwide reservoir imaging onshore and offshore on a contracted basis, in addition, SLB sells data out of its multiclient seismic library. As of December 31, 2011, WesternGeco had a backlog of $1.0 billion; more recently, the segment was completely sold out for the third quarter and was already 60% booked for the fourth quarter of 2012. SLB’s proprietary Coil and Dual Coil Shooting full-azimuth seismic surveys are a differentiated product offering versus CGG Veritas (CGV), Petroleum Geo-Service ASA (PGS NO), and Fugro (FUR NA). See Exhibit 76 for 2010 and 2011 revenue share, respectively. Seismic and geophysical services are a product service lines BHI, HAL, and WFT do not offer. HAL’s seismic exposure is through its proprietary Landmark software offering.

Exhibit 76: Global Seismic Revenue Share (2010–2011)

CGG Veritas Fugro, 6% Fugro, 7%

Schlumberger Petroleum Geo‐ Petroleum Geo‐Service Service ASA, 9% CGG Veritas, 25% CGG Veritas, ASA, 9% 25% Petroleum Geo‐ Service ASA Schlumberger, 23% Schlumberger, Fugro 19%

Source: Spears & Associates. Dominance in Russia

Oilfield Services 78 16 October 2012

Among the top four oil service companies, SLB has multiples of the others market share. Historically, Russia and Saudi Arabia have been geographic strongholds for SLB, where enviable margins were common. Today, SLB has lost some of its dominance in Saudi Arabia due to increased competition from BHI and HAL, but still reigns strong in Russia. Russia is a difficult market to do work in as a western company, according to several industry checks we have done. However, more technology is beginning to be adopted in Russia. Longer laterals and more sophisticated drilling techniques are being used and small pricing negotiations are underway according to the company. We foresee Russia continuing to be a geographic region of strength for SLB in the coming years, especially with more exploration drilling done in the Artic and waters off the east coast of Russia. Performance-Based Contracts SLB is moving to sign more performance-based contract (PBCs) with its customers as a means to display the company’s superior executive and breadth. Many of these contracts are written in such a way that SLB recognizes meaningful pricing escalators if work is done more efficiently, cost effectively, or enhances estimated ultimate recovery (EUR) figures. At the Credit Suisse Vertical Tour last November in Houston, SLB’s EVP of Corporate Development, J.F. Poupeau, said that 50% of drilling and measurement-based work has some sort of performance-based item written into the contracts. Research and Development In 2011, SLB invested $1.1 billion in research and development (R&D) for its oilfield activities. According to the company, SLB invests more each year in R&D than all other oilfield service companies combined. We would argue that historically, this may have been the case but in recent years the technological gap existing between SLB and its next closest peers, HAL and BHI, has narrowed considerably. With the exception of WFT, SLB, BHI, and HAL all now offer different proprietary technologies to clients. Anecdotally, in late-July we heard from a few private equity contacts in Houston, that an asset-light, sliding sleeve technology company was being shopped around to the major oilfield service companies and WFT bid $300 million and was its bid was rejected. Therefore, it is fair to assume the technology gap between SLB and WFT has widened.

Oilfield Services 79 16 October 2012 SLB Over the Years Future Strategy Initiatives We expect to get more aggressive in the subsea space in the next twelve months. More specifically, we think SLB could form a joint-venture with Aker ASA (AKER NO) to better compete with FMC Technologies (FTI), Cameron International (CAM), and General Electric (GE) in subsea. By teaming up with Aker, SLB could leverage its now fully owned subsidiary, Framo Engineering (acquired in full in June 2011), and increase its market share position in subsea boosting and separation. At a recent competitor conference, SLB stated that there are over 200 new deepwater 11,000 estimated subsea subsea fields coming online in the next four years, and that by 2020 there will be more wells by 2020 than 11,000 subsea wells in operation worldwide. Current estimates are that the subsea equipment market is approximately $6 billion per annum. Subsea developments will therefore become more and more important to many of SLB’s major customers and SLB’s ability to help them maximize production and reserves from these assets represent a key business opportunity for SLB going forward. Similarly, SLB recently has teamed up with PetroFrac Limited (PFC LN) to form a working relationship to deliver integrated and production enhancement capabilities to customers around the world. Together this partnership was selected by PEMEX to provide integrated production enhancement services in the Panuco area, which contains four mature onshore fields. Moreover, SLB has shown an openness to partner with other industry leaders to strategically position itself in this ever-evolving industry. Liquid Robotics Oil & Gas June 21, 2012: Liquid Robotics, Inc. and Schlumberger announced the creation of Liquid Robotics Oil & Gas, a joint venture to develop services for the oil and gas industry using Wave Gliders, the world’s first wave-powered, autonomous marine vehicles. The JV will combine Liquid Robotics Wave Glider technology with Schlumberger’s oil and gas expertise and industry knowledge to integrate and deploy new solutions for customers worldwide. Liquid Robotics and SLB have equal ownership of the joint venture. Liquid Robotics will provide fleets of Wave Gliders together with relevant engineering, piloting and maintenance expertise, while Schlumberger brings its upstream technology and market leadership. The JV will be the exclusive distributor of Wave Glider products and services to oil and gas customers worldwide. Wave Gliders offers a game-changing capability to operate offshore for up to one year without requiring a crew, fuel, or a dedicated support vessel during its mission. Fleets of Wave Gliders have crossed hundreds of thousands of miles of the earth’s oceans to help scientific, defense, and industrial customers gain valuable insights into the marine environment. C.E. Franklin Ltd. May 30, 2012 -- CE Franklin Ltd. (NASDAQ: CFK) announced that it had entered into an arrangement agreement with a wholly owned National Oilwell Varco, Inc. (NOV) subsidiary, NOV Distribution Services ULC (NDS), pursuant to which, NDS has agreed to acquire all of the issued and outstanding common shares of CE Franklin for consideration of CAD$12.75 in cash per Common Share. Schlumberger was CE Franklin’s largest shareholder at the time the transaction was announced.

Oilfield Services 80 16 October 2012

Wilson International, Inc. May 2012: SLB entered into an agreement with National Oilwell Varco, Inc. (NOV) to sell its Wilson distribution business. SLB acquired Wilson International Inc. as part of the acquisition of Smith International in 2010. Founded in 1921, Wilson is a leading distributor of pipe, valves and fittings as well as mill, tool and safety products and services to the international energy business and to other industrial customers. The company manages a distribution business of approximately 200 sales and operations locations across the United States with a growing presence in other key international geographies. Wilson employs approximately 2,500 employees as a standalone SLB business unit. Geoservices April 23, 2012: SLB completed the acquisition of Geoservices for $915 million in cash. Geoservices was a privately owned oilfield services company specializing in mud logging, slickline, and production surveillance operations. Framo Engineering AS June 29, 2011: SLB announced the acquisition of the remaining equity shares from Frank Mohn AS in Framo Engineering AS, a privately owned Norwegian company specialized in the business of developing, manufacturing, and selling products and services relating to multiphase pumps and subsea pump-systems, multiphase metering systems, and swivels and marine systems to the oil and gas industry. Framo Engineering, founded in 1983, employs approximately 500 people, mostly in Norway. The company is the leading multiphase subsea pump and meter supplier, and has focused its investments in the development of new technology for oil and gas production from subsea wells, particularly in the emerging deepwater market. Subsea multiphase boosting can enable ultra-deepwater light-oil and heavy-oil production by increasing ultimate recovery of deepwater oil and gas fields. Global Connectivity Services Second Quarter 2011: SLB completed the divestiture of its Global Connectivity Services business for approximately $385 million in cash to the Harris Corporation (HRS). Smith International, Inc. August 27, 2010: SLB acquired Smith International (SII), a leading supplier of premium products and services to the oil and gas exploration and production industry for $11 billion in an all-stock deal. When the deal was announced, SLB looked to be paying approximately 12.8 times Smith’s TTM EBITDA of $964 million . The transaction combined the complementary drilling and measurements technologies and expertise of SLB and Smith in order to facilitate the engineering of complete drilling systems which optimize all of the components of the drill string. The transaction also gave SLB a presence in manufacturing drill bits, an offering the company lacked before. Under the terms of the transaction, Smith became a wholly-owned subsidiary of SLB. Each share of Smith common stock issued and outstanding immediately prior to the effective time of the acquisition was converted into the right to receive 0.6966 shares of SLB common stock, with cash paid in lieu of fractional shares. Smith contributed revenues of $3.3 billion and net income of $160 million (including the recurring effects of purchase accounting) to SLB for the period from the closing of the transaction through December 31, 2010. Smith reported revenue of approximately $6.0 billion (unaudited) for the period from January 1, 2010 to August 27, 2010 and $8.2 billion in 2009.

Oilfield Services 81 16 October 2012

Management Team Paal Kibsgaard (Chief Executive Officer) Mr. Kibsgaard is chief executive officer of Schlumberger Limited. Prior to his most recent position, Kibsgaard held a variety of global management positions including chief operating officer, vice president of Engineering, Manufacturing and Sustaining; vice president of Personnel for Schlumberger Limited; and president of Schlumberger Drilling & Measurements. Earlier in his Schlumberger career, Kibsgaard was GeoMarket manager for the Caspian region after holding various field positions in technical sales and customer support. A petroleum engineer with a master’s degree from the Norwegian Institute of Technology, Kibsgaard began his career in 1992 working for ExxonMobil. In 1997, he joined Schlumberger as a reservoir engineer in Saudi Arabia. Simon Ayat (Executive Vice President and CFO) Mr. Ayat is executive vice president and chief financial officer of Schlumberger Limited. Prior to assuming his current role, Ayat served as the company’s vice president treasurer and previously held the position of vice president controller and business processes. Ayat’s 28-year career with Schlumberger spans a variety of management positions from Paris, Houston and Dallas to the Middle East and Far East regions. Ayat graduated from the University of San Francisco where he received a BS in business administration with an emphasis on finance and accounting.

Kjell-Erik Oestdahl (Executive Vice President of Shared Services, Infrastructure and Distribution)

Mr. Oestdahl is executive vice president Operations for Schlumberger, a position he has held since 2011. He holds responsibility for field operations worldwide. Prior to his current assignment, Kjell-Erik served as Schlumberger chief procurement officer and vice president of operations for WesternGeco.

Satish Pai (Executive Vice President of Operations)

Mr. Pai was named vice president of Operations in April 2008 and currently he is the executive vice president of operations based in Paris. He holds responsibility for the Schlumberger product groups. Pai joined Schlumberger in 1985 as a field engineer working in Thailand, Brunei, and his native India. Satish received a BS in mechanical engineering from the Indian Institute of Technology in Madras. Jean-Francois “J.F.” Poupeau (Executive Vice President of Corporate Development & Communication) Mr. Poupeau is executive vice president Corporate Development and Communication, a position he assumed in May 2012. Poupeau is responsible for corporate planning, corporate development, corporate engagement and communications. Prior to his current role, he was president of the Schlumberger Drilling Group, a position he held since the completion of the merger with Smith in 2010. Poupeau received a bachelor’s in geology and a master’s in petroleum engineering from Tulane University. He is a member of SPE and SPWLA. Valuation Consistent with the rest of our oilfield service company coverage, we are looking at shares of SLB on an EV/EBITDA and price-to-earnings basis. Furthermore, we are also looking at returns, SLB had a ROE of 15% in 2011 and we estimate it to increase to 17% and 16% in 2012-13, respectively.

Oilfield Services 82 16 October 2012

SLB currently trades at 17.3x and 15.8x our 2012/13 EPS estimates, respectively. This compares with the peer groups average multiple of 12.2x and 10.9x 2012/13 earnings. On an EV/EBITDA basis, SLB trades at 68% premium to nearest competitor, HAL, and at a 64% premium to the peer group.

Exhibit 77: SLB Comparables (US$ in millions, except per share data) Stock Price Market Enterprise EBIT DA EV / EBITDA EPS P / EPS Company Ticker Rating TP $ 10/15/12 Shares Value Value 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E

Baker Hughes BHI Neutral $40 $44.77 440 $19,699 $23,948 $4,121 $4,594 5.8x 5.2x $3.57 $3.91 12.5x 11.4x Halliburton Company HAL Outperform $44 $33.80 926 $31,299 $33,942 $6,075 $6,644 5.6x 5.1x $3.04 $3.12 11.1x 10.8x Weatherford International WFT Neutral $11 $12.17 769 $9,359 $17,552 $2,910 $3,221 6.0x 5.4x $0.93 $1.18 13.1x 10.3x

Mean 5.8x 5.3x 12.2x 10.9x Median 5.8x 5.2x 12.5x 10.8x High 6.0x 5.4x 13.1x 11.4x Low 5.6x 5.1x 11.1x 10.3x

Schlumberger Limited SLB Neutral $66 $72.19 1339 $96,662 $103,644 $11,164 $12,056 9.3x 8.6x $4.19 $4.58 17.2x 15.8x Premium/(Discount) to Peer Group Average 60% 64% 41% 45% Source: Bloomberg, Company data, and Credit Suisse estimates. Investment Risks The investment risks of investing in SLB are two fold, those specific to the company and those that relate to the broader oilfield service industry. Company-specific risks include (1) a significant portion of SLB’s revenue from come from outside the U.S. (68% in 2011, 76% in 2010, and 84% in 2009), (2) SLB conducts operations in countries including, Iran, Syria, Sudan, and Cuba, which are currently subject to trade and economic sanctions and further U.S. law enforcement bodies are conducting a grand jury investigation into operations in some of these countries, (3) changes in and compliance with post-Macondo restrictions and regulations, (4) environmental, (5) inability to maintain the company’s technology leadership over competitors, and (6) retention of key/skilled employees. Industry-specific risks include (1) oil prices, (2) global oil demand, (3) global GDP, (4) global E&P capex spending, (5) interest rate risk, (6) environmental and government regulations, (7) oversupply of pressure pumping equipment, (8) increased competition, (9) inclement weather/seasonality, and (10) geopolitical risks.

Oilfield Services 83 16 October 2012

Americas / United States Oil & Gas Equipment & Services

Weatherford International, Inc.

(WFT) Rating NEUTRAL* [V] Price (12 Oct 12, US$) 12.17 INITIATION Target price (US$) 11.00¹ 52-week price range 18.20 - 11.62 “De-Lever Me from Evil” Market cap. (US$ m) 9,243.95 Enterprise value (US$ m) 17,596.49 ■ We are initiating coverage of Weatherford International with a Neutral rating. Going too fast, for some time, with too few critical controls typically *Stock ratings are relative to the coverage universe in each results in a crash. Weatherford hit the wall in a couple of different ways. We analyst's or each team's respective sector. ¹Target price is for 12 months. think the company will survive. It is not a foregone conclusion; however, it [V] = Stock considered volatile (see Disclosure Appendix). will take time, money, lost opportunity and more time to build back trust. It

Research Analysts will also take incorporating some basic capital allocation disciplines as soon James Wicklund as possible. 214 979 4111 [email protected] ■ We believe that the company, operationally, is doing fine. The North American spending lowdown should affect them less than most due to mix, Jonathan Sisto 212 325 1292 international operations are currently drama free, and it is more [email protected] manufacturing than many realize which is doing relatively better than service. Brittany Commins Asset sales, lower capex, and improving DSOs are all being pursued to 212 325 7128 generate cash and pay down debt. The tax accounting issues are proving [email protected] expensive, time-consuming, and strain credibility but should be finalized by year end. ■ Too dangerous as a long and a short, with no second quarter filing made yet and a yet undetermined FCPA issue, our valuation multiple is highly risked.

Share price performance Financial and valuation metrics

Daily Oct 13, 2011 - Oct 12, 2012, 10/13/11 = US$13.93 Year 12/11A 12/12E 12/13E12/14E EPS (CS adj.) (US$) 0.80 0.93 1.18 — 15 Prev. EPS (US$) — — — — 10 P/E (x) 15.2 13.1 10.3 — 5 P/E rel. (%) 100.1 91.7 80.7 — 0 Revenue (US$ m) 12,990.0 15,481.8 16,256.0 — Oct-11 Jan-12 Apr-12 Jul-12 EBITDA (US$ m) 2,479.0 2,909.9 3,221.4 — Price Indexed S&P 500 INDEX OCFPS (US$) 1.10 1.43 3.09 — On 10/11/12 the S&P 500 INDEX closed at 1432.84 P/OCF (x) 13.3 8.5 3.9 — EV/EBITDA (current) 6.8 5.8 5.2 — Net debt (US$ m) 7,235 8,353 7,933 — ROIC (%) 6.03 6.35 6.99 —

Quarterly EPS Q1 Q2 Q3 Q4 Number of shares (m) 759.57 IC (current, US$ m) 16,788.00 2011A 0.08 0.14 0.26 0.30 BV/share (Next Qtr., US$) 12.6 EV/IC (x) 0.97 2012E 0.25 0.16 0.22 0.30 Net debt (Next Qtr., US$ m) 8,193.0 Dividend (Next Qtr., US$) — 2013E 0.23 0.25 0.31 0.39 Net debt/tot cap (Next Qtr., %) 84.1 Dividend yield (%) — Source: Company data, Credit Suisse estimates.

Oilfield Services 84 16 October 2012 Investment Overview We initiate coverage of Weatherford International (WFT) with Neutral rating. WFT is smallest of the four large-cap oilfield service companies, operating in over 100 countries, and employing almost 60,000 people. It is an integrated service and manufacturing company, with directional drilling and drilling rigs being the top revenue sectors. Beginning in March 2011, with a tax accounting entry made wrong years before and finally noticed, Weatherford has been pushed incredibly close to the brink. Multiple tax accounting issues arose over the subsequent several quarters which caused a complete restatement of the company’s financials at the end of 2011; however, it was not over. More Charges, More Issues: WFT is paying an accounting firm other than its auditor to help design and implement a system that has the stringent command and control systems required to satisfy Ernst & Young, after issuing a qualified opinion on Q2 numbers. As that system gets pushed down through the organization, any discrepancy gets identified meaning that virtually all of the accounting issues, so far, are related to historical erroneous tax entries, all stemming from the discovery of one $500 million tax asset that was booked wrong six years ago. This caused the CFO to be concerned about Sarbanes Oxley implications and did not sign the Q2 10-Q; therefore, the company has not filed its most recent financials and might not until November or February. Money, Money, Money: WFT is not broke but cash poor might fit. The company has been outspending cash flow for five of the last six quarters and all but four quarters since the end of 2007. The company is driven by growth, unabashed growth. 250 acquisitions in 13 years is an amazing run. It is the legacy of the company and its predecessor. However, if that is the objective, then the responsibility to shareholders is to do it well and here Weatherford fell down. Different financial systems that continued for extended periods, management turnover that saw four chief accounting officers in two years, a string of several COOs over the past several years and most damning, no systems in place to integrate these acquisitions, creating a fragile base under which further acquisitions were then loaded. Capital Discipline and Returns: WFT, at its early core, was an equipment rental company. If ever a business cried out for the need of capital discipline, this is it. If I run a store, I want to have every piece of equipment I might ever need right here in back. The way the system works, one submits and AFE, approximate financial expenditure, with a capital request. The AFE has the justification and the expected economic return. There is no measure in place to track, report or analyze those capital expenditures. If running that store, I do not have any kind of a capital charge, to discourage me from overstocking or over ordering equipment, I wouldn’t; and nowhere in the WFT organization is there any direct or indirect capital cost or allocation method to insure efficient use and deployment of capital. People act in accordance to how they are incentivized. If I am not discouraged from using inefficient capital, I will because spending other people’s money is fun. I think this is the one largest failings of the company.

Oilfield Services 85 16 October 2012

Exhibit 78: Peer Group CAPEX Spend Indexed to 2003

Source: Company data, Credit Suisse estimates We Have Them Making It: The company can and will cut capex. It hurts because any cut in capex is a reduction of potential growth but it has to happen. DSOs is a focus. Currently, at 86 days, reductions help the working capital and cash flow situation a great deal and it needs the help. Receivables from Latin America national oil companies are seeing 120- 128 day payments. New procedures are being put in place to shorten payment periods, including pro forma invoices followed by final invoice. On an annual basis, a one-day improvement in DSOs generates $30 million in cash flow. There are two $260 million debt payments due in 2013, at 4.95% and 5.15%. Currently, the company plans to pay off the two tranches, in April and November, from operating cash flow. Our model is not optimistic enough for that and while we hope it is right, we assume the debt will be rolled in the current favorable credit market. It’s a Hard Job. Seldom is a company so identified with its CEO as Weatherford. Bernard Duroc Danner built more shareholder value in the 1990’s than anyone else in the Oilfield Services sector, with the possible exception of Gene Isenberg during the same period. Bernard is more entrepreneurial than back-office accounting, more dealmaker than integrator. It would make sense that some of the financial controls required in huge global companies was not a paramount concern. I have known Bernard to be optimistic, hopeful, self-deprecating, intelligent, thoughtful, and honest. How the company comes out of the current situation will better address his qualifications as CEO. Near-Term Binary Issue. One cannot really be long the stock, with FCPA, a qualified opinion by the auditor, no current financials filed and an unclear picture on future earnings power weighing on the stock. If one large long-only holder decided not to own a company with that description, there would be few new buyers. We think it will make it but informed and educated people have ongoing concern issues with Weatherford so it cannot be completely dismissed. On the other hand, being short could be dangerous. An activist investor could take advantage of the near-term corporate issues and attract the attention of disappointed WFT shareholders, and push for a change that might be well received. So until some of these issues are resolved, we rate the stock Neutral.

Oilfield Services 86 16 October 2012

Exhibit 79: WFT—Key Variables Indexed in 2003 1000

800

600

400

200

0

-200

Ebitda CapEx EV ROC Source: Company data, Credit Suisse estimates.

Exhibit 80: WFT “SWOT” Analysis Strengths Weaknesses • Artificial lift (~20% market share) • High debt load • Standard and unconventional well completion • Accounting internal controls • Focusing on niche markets that do not directly • Exposure to markets with expected anemic growth compete with the Big 3 (i.e. Canada and pressure pumping) • Improved inventory and capital management • CAPEX allocation and lack of ROIC monitoring systems installed as a result of the accounting • Launched SAP software nine months ago to address overhaul this weakness Weatherford International

Opportunities Threats • Margin expansion in artificial lift • Lack of balance sheet flexibility • Growth in international markets • $560mm of debt is due in 2013 • Working capital management • Tax accounting issues • Have improved bill collection system which reduced • FCPA investigation accrued receivables • DSOs have improved by 11 days since 2009

Source: Company data, Credit Suisse estimates.

Oilfield Services 87 16 October 2012 Company Overview Weatherford (WFT) is a global providers of oilfield services, whose operations are levered toward onshore and oil services. The company has one of the most diverse portfolios of products/services in the industry, which is a result of 250+ strategic acquisitions over the past 13 years Their offerings include drilling, evaluation, completion, production & intervention cycles of oil and natural gas wells. Weatherford is perhaps best known for artificial lift, a market in which it holds a market share leading position. Of the revenues, 64% comes from outside the U.S., but the company is levered toward North America (52% of revenues). WFT is headquartered in Geneva, Switzerland and operates in over 100 countries. As of December 31, 2011 the company had approximately 50,000 people worldwide. Its principal customers consist of major and independent oil and natural gas producing companies. Business Segments Weatherford organizes its revenue into two categories: 1) Formation Evaluation and Well Construction, run by Senior Vice President Nick Gee and 2) Completion and Production Systems, run by Senior Vice President Dharmesh Mehta. Within these two categories there are ten service lines: (1) artificial lift systems; (2) stimulation and chemicals; (3) drilling services; (4) well construction; (5) integrated drilling; (6) completion systems; (7) drilling tools; (8) wireline and evaluation services; (9) re-entry and fishing; and (10) pipeline and specialty services.

Exhibit 81: WFT—2011 Revenue by Segment Revenues by Segment 2009 2010 2011 Artificial Lift Systems 14% 15% 17% Stimulation and Chemicals Services 8% 12% 17% Drilling Services 16% 17% 17% Well Construction 15% 14% 12% Integrated Drilling 14% 12% 11% Completion Systems 11% 8% 8% Drilling Tools 8% 8% 6% Wireline and Evaluation Services 6% 6% 6% Re-entry and Fishing 6% 6% 5% Pipeline and Specialty Services 2% 2% 1% Source: Company data, Credit Suisse estimates. Artificial Lift Systems Artificial lift systems (17% of 2011 Sales) provide production equipment and optimization services. They are installed in oil and gas wells that do not have sufficient reservoir pressure to lift the available hydrocarbons to the surface. The artificial lift market reached an estimated $8.6 billion in 2011 (22% growth YoY). WFT has been able to successfully grow this business and win share from its primary competitor in the space, Lufkin Industries, and in 2011 WFT was the market share leader. WFT was the market share winner in 2011, and is well positioned to continue to capture value in this growing market

Stimulation and Chemicals The Stimulation and Chemicals segment (17% of 2011 Sales) offers pressure pumping, chemical and associated technologies services which enhance the effectiveness of the production process. These products and services include fracturing, coiled tubing, cement services, chemical systems, and drilling fluids. Pressure pumping, services that increase access to proven reserves, represents ~80% of sales in this segment. Although WFT is a small player in the massive pressure pumping market (estimated $42 billion in 2011), it

Oilfield Services 88 16 October 2012 has been able to steadily gain share since its entrance in 2002. In 2011, WFT gained an estimated 100 bps of share as the market grew 61%. Drilling Services WFT’s Drilling Services business includes directional drilling, well testing, as well as surface logging systems. ~50% of sales in this service line are derived from directional drilling. • Directional drilling allows drilling of horizontal wells and penetration of multiple reservoir pay zones from a single wellbore. • Surface logging systems, often referred to as mud logging, is a well−site service that uses fluid and gas samples along with drilling cuttings to evaluate the geology and geochemistry of the formation. The derived data and interpretation is used to help geologists and drillers ensure that the well is placed in the most productive formation to maximize ultimate well productivity. Weatherford launched its logging services product lines with the acquisition of International Logging in August 2008. • Well testing services provides exploration and production pressure and flow-rate measurement services at the surface and downhole Well Construction The Well Construction line includes the primary services and products required to construct a well and spans tubular running services, cementing products, liner systems, swellable products, solid tubular expandable technologies, and inflatable products. Integrated Drilling Weatherford has the ability to offer project management services, in which it provides a number of products and services needed to drill and complete a well, including the rig. All of its land drilling rigs are located outside of North America. Completion Systems This business segment comprises of a comprehensive line of completion tools, sand screens, and reservoir optimization technologies. Drilling Tools Weatherford designs and manufactures patented tools used in drilling oil/natural gas wells, including drilling jars, under reamers, rotating control devices and other pressure−control equipment. It establishes leasing contracts for drilling tools with operators and drilling contractors. Wireline and Evaluation Services Wireline provides the information necessary to evaluate subsurface formation rocks and fluids to plan and monitor well construction, and to monitor and evaluate well production. When combined with geosciences consulting, this integrated capability provides the data and interpretation to reduce reservoir uncertainty and ultimately optimize production and maximize recovery. Re−entry and Fishing WFT’s re−entry, fishing and thru−tubing services repair wells that have mechanical problems or that need work to prolong production of oil and natural gas reserves. Pipeline and Specialty Services Pipeline and Specialty Services provides a range of services throughout the life cycle of pipelines and process facilities, onshore and offshore.

Oilfield Services 89 16 October 2012 Market & Business Drivers With new innovations such as horizontal drilling and hydraulic fracturing the oilfield services sector has become an increasingly vital component to the oil/gas production process. With these new developments, service intensity has increased allows for greater revenue opportunities for OFS companies. The need to replace existing production, the continued global growth in demand, the difficulty in finding new reserves of scale, and the increasing need for technology has spurred growth for oilfield service companies. WFT operates in most OFS service lines, but is able to most effectively operate in niche markets that don’t directly compete with the “Big 3” (HAL, SLB, and BHI). Artificial lift and pressure pumping are important markets for WFT.

Exhibit 82: WFT Revenue by Region

North America Total 52% Latin America 11% United States Europe/West 36% Africa/FSU 18%

Middle East/North Africa/Asia 19% Mexico 6% Canada 10%

Source: Company data, Credit Suisse estimates.

Oilfield Services 90 16 October 2012

Exhibit 83: WFT Product Lines

Revenues by Product Line 2007 2008 2009 2010 2011 Artificial Lift Systems 1,410 1,632 1,236 1,738 1,949 Stimulation and Chemicals Services 470 672 706 1,738 1,559 Drilling Services 1,175 1,536 1,412 1,738 2,208 Well Construction 1,253 1,440 1,324 1,226 1,819 Integrated Drilling 392 576 1,236 1,124 1,559 Completion Systems 783 960 971 818 1,039 Drilling Tools 940 1,056 706 613 1,039 Wireline and Evaluation Services 627 768 530 613 779 Re-entry and Fishing 627 672 530 511 779 Pipeline and Specialty Services 157 288 177 102 260 Total 7,832 9,601 8,827 10,221 12,990

Yr-Yr Growth Artificial Lift Systems 16% -24% 41% 12% Stimulation and Chemicals Services 43% 5% 146% -10% Drilling Services 31% -8% 23% 27% Well Construction 15% -8% -7% 48% Integrated Drilling 47% 115% -9% 39% Completion Systems 23% 1% -16% 27% Drilling Tools 12% -33% -13% 69% Wireline and Evaluation Services 23% -31% 16% 27% Re-entry and Fishing 7% -21% -4% 53% Pipeline and Specialty Services 84% -39% -42% 154% Total 23% -8% 16% 27% Source: Company data, Credit Suisse estimates Artificial Lift Weatherford is the market share leader in artificial lift, a process which increases the pressure in a reservoir to improve flow rate of a well. WFT primarily competes with Lufkin (LUFK) in the space and is likely gaining share and improving margins as Lufkin is currently dealing with manufacturing problems. There has been a cultural shift within the company in the last two years. From 2003-2010 WFT had no acquisitions in artificial lift, and from 2011-12 it has made five. WFT is focusing on building out the markets in which is does not compete with the Big 3. The small acquisitions in lift have been paying off, but one drag on this business line has been its 38% acquisition of Borets, which focuses on ESP (electric submersible pumps) in Russia. ESPs represent about one-half the spend for lift, but other segments such as rod lift are growing faster. WFT entered this deal in an attempt to gain a presence in the ESP market but has still gained little traction. This stake may become a divestiture target as WFT begins to tighten its balance sheet. been its Russian lift performance. Pressure Pumping North American pressure pumping margins have been tough across the board, especially for smaller players who lack the capacity to service high utilization customers. Weatherford has clearly been feeling brunt of the pressure pumping margin squeeze, which has been exacerbated by the decline in rig activity in North America. We estimate that ~14% of revenues were driven by pressure pumping in 2011, ~2/3 of which came from North America, which leaves a significant amount for revenues exposed to this worsening market. In 2Q11 pressure pumping comprised 20% of North American EBIT, which significantly declined to 9% in 2Q12. Although we believe the advent of horizontal drilling has created promising long-term prospects for pressure pumping and unconventional oil/gas services, near-term pricing pressure will create a highly competitive landscape, which will make it difficult for smaller players to win share against the Big 3 dominating the market: Halliburton (HAL), Schlumberger (SLB), and Baker Hughes (BHI). We note that Weatherford has performed well in the large pressure pumping market (~$42B in 2011),

Oilfield Services 91 16 October 2012 which has experienced double-digit growth 8 out of the past 10 years. Having launched operations in 2002, WFT is a nascent player compared with its major competitors, but has been able to steadily gain share through last year and boasts an estimated ~750,000 hydraulic horsepower (HHP). However, with the recent shift in market dynamics we expect WFT’s share to decrease as the market declines, which will be a drag on earnings through the rest of the year. For now, WFT has begun to strategically bundle pressure pumping with well completion services, an area in which it is exceling. Challenges Ahead Accounting Issues - Overview Weatherford disclosed in March 2011 that it had uncovered an accounting issue that would require it to restate historical financials. Since the announcement, the stock price has plummeted by over 40%, causing the market cap to drop from ~17B to ~10B in the last year and a half. The lion share of the problem is due to a mistake with one entry (occurring 2007-2010) that failed to appropriately account for uncertain tax positions, in accordance with Fin 48. Fin 48 is an official interpretation of the U.S. GAAP accounting rules that became effective in 2007 and dictates that a business may recognize an income tax benefit only if it is more likely than not that the benefit will be sustained. This original mistake eventually lead to a cumulative $500mm adjustment of mostly non-cash tax items. The total restated adjustments reached over $600 as of year-end 2011. We believe that WFT is almost out of the woods, with its tax accounting issues and that the company will be able to close its books by February 2012. A material weakness can only be closed out at year end when the company submits its 10-K Accounting Issues - The Bottom Line $274 million in total reserves have been set aside for the accounting issues. Although this is a drag on WFT’s cash-poor balance sheet, the cost of the cumulative accounting adjustments will likely not exceed this amount. $92 million in cash taxes are owed thus far (which is a result of a small number of incidences in specific jurisdictions). The company’s original estimate of zero cash tax impact did not play out. Weatherford’s accounting issues have been extensive and revealed a systemic problem within the company which have made investors wary. However, in the end it appears that the problem is contained and the blow to the balance sheet and income statement is manageable. The company has several large accounting firms on retainer and paying them enough that one must assume a great deal of work is being done. Playing catch-up is hell but needs to be done. Timing wasn’t good but never is. Internal disciplines still need work. Investors will be skittish and wary stepping back into the stock but once the qualified opinion gets lifted and audited financials are filed, this issue should go away.

Oilfield Services 92 16 October 2012

Accounting Issues - Timeline

Exhibit 84: Timeline of WFT’s Accounting Issues (Feb. 2011–Present) Feb 2011: Internal Feb 2011 (4Q12 Earnings 1Q12: An additional issue is audit uncovers an Call): Management expects error in accounting for uncovered resulting in a another ~$250mm in $24mm error. The issue uncertain tax benefits. adjustments and states that Aug 2011: John relates to accounting in 1 The problem began there are no cash tax Briscoe is hired as jurisdiction and is not in 2007 (3 years) implications to the WFT’s new CFO systemic restatements

March 2011 June 2012

March 2011: Filed March 2012: Adjustments in 2Q12 Release: 10-K late with WFT’s 10-K total $256mm. WFT’s new internal restatement of controls uncovers 6-8 historical income tax additional mistakes expense totaling resulting in a $41mm $360mm error

Source: Company data. February 2011: The company’s internal audit group found one incorrect entry: a deferred tax asset was recorded, even though there was no foreseeable value for the asset. The mistake was made once each year since 2007 (three years total), which cumulated to $500 million. March 2011, File 10-K late: Financial statements include the restatement of the deferred tax assets. Income tax expense was understated by $154mm in 2007, $106mm in 2008, and $100mm in 2009. WFT admits to a material weakness in its accounting procedures. August 2011: John Briscoe joins WFT as CFO as part of the effort to rebuild the internal controls system February 2012, 4Q11 conference call: Management expected further restatement of the historical financials to be $225-250 million. It also stated that there are no historical tax, cash implications as a result of the adjustments March 2012 WFT filed its 10K late: Restatement of historical results aggregates to $256mm. These errors resulted in an understatement of income tax expense, in addition to the previous restatement by $41mm in 2010, $50 million in 2009, and $165mm for 2008 and prior. First Quarter 2012: An additional issue was uncovered, totaling $24mm, which was related to one entry in one jurisdiction. The problem was not systemic. Second Quarter 2012: The company’s improved internal controls uncover 6-8 new issues related to an uncertain tax position that collectively equaled $41mm. Management is hopeful that it will be able to close the books by the third quarter of 2012, but will not do so until it is certain that all problems have been uncovered. WFT cannot receive an unqualified opinion from its auditors until it files its 10-K at year end. Balance Sheet Inflexibility - Overview

Oilfield Services 93 16 October 2012

High capital expenditures has resulted in negative free cash flow since 2008. With ~$550mm in debt coming due in 2013, WFT has been tightening its belt to remain solvent. The company plans to fund the repayments through internally raise cash, which if it is able to do would be an impressive feat. One of WFT’s best hopes for increase cash flow is its capital management initiative. It has been able to improve DSOs by 11 days since 2009, and with each day equaling ~$35mm this improvement represents approximately $385mm in cash. WFT will next be targeting inventory deployment efficiencies, which it began to tackle in 1Q12 with its company-wide launch of SAP software. WFT will also likely have to turn to divestitures of certain businesses; however, in the current midcycle conditions, finding buyers could prove difficult. Although WFT’s hopes to pay down its debt due in 2013 with internally generated cash flow is a noble goal, we believe that refinancing is a more feasible option. The company has been able to pull in the reigns of the working capital and admirably reduced sales outstanding by ~$385 dollars, but now there isn’t too much additional cash that can be squeezed out of working capital efficiencies. DSOs are in line with peers, and days payable hovers at the high end of the group. The last place WFT could look for cash in working capital is inventory. Days of inventory on hand remains higher than peers. And with one day of inventory equaling ~$30mm, WFT can significantly increase its cash availability with improved inventory management. However, we believe the types of internal changes required to realize this benefit will take a few years to show in the balance sheet.

Exhibit 85: WFT - DSOs and DSIs LUFK HAL BHI WFT SLB CAM FTI Days Sales Outstanding69768485889296 Days Inventory on Hand 73 42 70 109 50 151 59 Days Payable 22 37 48 166 100 202 51 Source: Company data, Credit Suisse estimates. In the short run, refinancing appears to be the best option. Given the current environment of zero percent interest rates, WFT will likely be able to refinance the debt at the same rate or lower. There will be no shortage of funds available for WFT in the bond market because the company’s debt offers an appealing yield while still remaining two notches above junk with the credit rating agencies. WFT has the highest credit spread in the entire energy sector, which means two things 1) fixed income investors view this company as the riskiest in the sector and 2) these bonds have the highest return in energy. Despite the market’s view of the bond’s high risk, WFT is rated Baa2 (two notches above junk) at Moody’s and BBB (two notches above junk) at S&P; however, WFT was placed on negative outlook recently at both of the rating agencies due to its tax accounting issues. We note that our deep dive into the accounting problems lead us to believe that the issue is contained and manageable. Although WFT appears to be performing well operationally, one issue of note is its high leverage position. For instance, at the end of Q2, WFT’s LTM debt/EBITDA ratio was 2.9 versus 1.2 for BHI and 0.7 for HAL. We note that WFT’s leverage has improved since the beginning of 2011. As of March 31, 2011, the company’s LTM debt/EBITDA ratio was 3.6 and has gradually improved to 2.9 currently primarily due to improved operating results. We would like to highlight that the absolute debt level on WFT’s balance sheet has steadily increased over the last few quarters. With regards to the delayed 10-Q filings, WFT was able to receive all of the required consents from its lenders and as a result, the company has not violated any of its covenants.

Oilfield Services 94 16 October 2012

Exhibit 86: WFT Debt Schedule Carrying Amount (In millions) 5.15% Senior Notes due 2013 (March) $296 4.95% Senior Notes due 2013 (October) $251 5.50% Senior Notes due 2016 $356 6.35% Senior Notes due 2017 $613 6.00% Senior Notes due 2018 $498 9.625% Senior Notes due 2019 1,029 5.125% Senior Notes due 2020 $799 6.50% Senior Notes due 2036 $596 6.80% Senior Notes due 2037 $298 7.00% Senior Notes due 2038 $499 9.875% Senior Notes due 2039 $247 6.75% Senior Notes due 2040 $598 Source: Company data, Credit Suisse estimates. Balance Sheet Inflexibility —The Bottom Line WFT’s balance sheet will be able to survive with the combination of improved working capital management and divestitures. The company’s goal is to become more capital efficient and no longer fund CAPEX intensive growth projects. WFT plans to pay down its 2013 debt (Exhibit 86) with cash flow from operations. FCPA and Sanctioned Countries Investigations—Overview WFT has had two major investigations by the DOJ one dealing with its operations in sanctioned countries and the other FCPA issues in connection to its work with the Oil for Food program in Iraq in 2005. In the 2Q12 earnings conference call WFT announced that it had settles the sanctioned country issue for $100mm and commented that the FCPA investigation is smaller in scope. FCPA and Sanctioned Countries Investigations —Bottom Line Through December 31, 2011, the company incurred $40 million for costs in connection with the exit from certain sanctioned countries and incurred $123 million for legal and professional fees in connection with complying with and conducting these on-going investigations. Although the FCPA investigation is ongoing, the commentary in the 2Q12 conference call seemed to reduce the possibility of an extreme outcome.

Oilfield Services 95 16 October 2012 WFT Over the Years The current Weatherford International, Ltd was created in 1998 upon the merger of Weatherford Enterra and EVI (Energy Ventures Inc., a vertically integrated oil services and production company). Bernard Duroc-Danner became Chairman of the Board, and CEO, both positions he continues to serve. By November 1999, the number of acquisitions made since Weatherford Enterra and EVI merged in 1998 had reached 16, with a total expenditure of about $500 million. Since this time, WFT has made several large acquisitions to expand its global reach and diversify its product/service platform; in recent years the company has engaged in a number of smaller strategic acquisitions. While WFT works on balancing its budget in preparation for the ~$550mm of long term debt due in 2013, it seems like the near term M&A activity will focus on divestitures. Large Acquisitions Precision Drilling—Contract Drilling In 2005, Weatherford acquired Precision Drilling Corporation’s Energy Services and International Contract Drilling divisions for $2.1 billion. The acquisition included 48 total rigs, 19 heavy duty land drilling rigs and 29 light and medium drilling rigs. These rigs operate in Kuwait, Saudi Arabia, Oman, Egypt, India, Mexico, the Persian Gulf, Australia, and Venezuela. Precision Drilling’s business was chosen as a key market expansion opportunity into the Middle East. The company had been established in the area for 40 years and offered the potential for future bundling with WFT’s Evaluation Drilling & Intervention Services Division products and services for national oil companies. TNK-BP—Oilfield Services July 27, 2009: WFT acquired TNK-BP’s Oilfield Services business and assets for US$471 million. The business acquired provides drilling, sidetracking, well intervention and workover, cementation, and required support services in Russia International Logging, Inc. August 2008: Weatherford acquired International Logging, Inc., a provider of surface logging, and provides formation evaluation and drilling related services at the well site through its team of more than 1,200 graduate field geologists serving customers in more than 55 countries from over 30 offices globally. With the acquisition of ILI, Weatherford adds a new service to its portfolio, which is already one of the broadest in the industry. V-Tech International In 2008, Weatherford completed its acquisition of V-Tech International, a pioneer in the development of mechanical power tong systems in the North Sea to improve rig safety. Strategic Acquisitions Petrowell Limited May 31, 2012: WFT announced plans to acquire Petrowell Ltd, based in Aberdeen, Scotland, for an undisclosed sum. Petrowell manufactures oil and gas completion tools. Petrowell is known for its completion, intervention, open hole, and articular lift products that provide solutions for challenging operating environments. CygNet Software May 19, 2011: WFT announced the acquisition of CygNet Software, the leading Enterprise Operations Platform (EOP) provider, delivering SCADA and operational applications. The acquisition builds on WFT’s oil and gas optimization business and will expand its presence to over 350,000 wells. Dharmesh Mehta, vice president of Production Systems for Weatherford commented, “We can now provide a complete optimization solution to all

Oilfield Services 96 16 October 2012 shale producers around the world as well as provide integrated optimization to CygNet’s existing clients.” Isotech Laboratories June 7, 2011: Weatherford Laboratories, a WFT subsidiary, announced the acquisition of Isotech Labs for an undisclosed amount. The company conducts isotope testing for the oil and gas industry and employed 42 people at the time of acquisition. Oiltracers LLC March 3, 2010: WFT announced the acquisition of Oiltracers LLC for a deal valued at $3 million. OilTracers LLC, a company dedicated to providing the petroleum industry with Charge Risk evaluation of individual prospects, as well as solving field development challenges through integration of petroleum geochemistry, geology, and engineering data. OilTracers’ premier offerings include a proprietary tool that provides quantitative allocation of commingled production, considered the current gold standard in the industry. Impact Solutions Group June 30, 2009: WFT acquired Impact Solutions Group Ltd from Freebird Partners LP for an undisclosed amount. Impact Solutions Group provides technical solutions for drilling wells. Its products include drilling, completion, and work over fluids. The company also provides pressure drilling and secure drilling technology.

Oilfield Services 97 16 October 2012

Management Team

Exhibit 87: WFT Management Team Name Age Position Bernard J. Duroc-Danner 58 Chairman of the Board, President and Chief Executive Officer John H. Briscoe 54 Senior Vice President and Chief Financial Officer Peter T. Fontana 65 Senior Vice President and Chief Operating Officer Nicholas W. Gee 49 Senior Vice President — Formation Evaluation and Well Construction Dharmesh B. Mehta 46 Senior Vice President — Completion and Production Systems Joseph C. Henry 41 Senior Vice President, Co-General Counsel and Corporate Secretary William B. Jacobson 43 Senior Vice President, Co-General Counsel and Chief Compliance Officer Source: Company data. Bernard J. Duroc-Danner PhD (Chairman & Chief Executive Officer) has served as the president, CEO, and chairman of the board since 1998. He joined EVI, Inc., Weatherford’s predecessor company, at its inception in May 1987 and served as president and CEO of EVI from 1990 until 1998 when he was elected CEO of Weatherford International (the EVI and Weatherford Enterra merged entity). Dr. Duroc-Danner holds an M.B.A. and a Ph.D. in economics from Wharton (University of Pennsylvania). Prior to the start-up of EVI, he held positions at Arthur D. Little Inc. and Mobil Oil Inc. John H. Briscoe joined the company in August 2011 as vice president and chief accounting officer and was appointed senior vice president and chief financial officer in March 2012. Mr. Biscoe was brought onto the management team in light of the company’s severe accounting oversights. From 2005 to August 2011, Mr. Briscoe was in senior management at Transocean Ltd., and was vice president and controller from October 2007 to August 2011. Prior to joining Transocean, Mr. Briscoe held senior accounting positions with Ferrellgas Inc. and Dresser Industries Inc. Mr. Briscoe also has seven years of public accounting experience with the firms of KPMG and Ernst & Young. Mr. Briscoe is a certified public accountant and holds a BBA from the University of Texas. Peter T. Fontana was appointed senior vice president and chief operating officer in December 2010, and was senior vice president of Western Hemisphere from July 2009 to December 2010. Prior to his joining the company in 2005 , he held leadership positions with Baker Hughes, Forasol/Foramer and The Western Company of North America. Mr. Fontana has an MBA from Southern Methodist University. Nicholas W. Gee was appointed senior vice president of Formation Evaluation and Well Construction in October 2011. Mr. Gee rejoined Weatherford in April 2009 as vice president investor relations. He graduated with a first-class honors degree in chemical engineering from the University of Birmingham, and holds an MBA with distinction from Warwick Business School. Dharmesh B. Mehta was appointed senior vice president of Completion and Production Systems in October 2011. Mr. Mehta joined the company in 2001 and prior to his tenure at Weatherford, he gained ten years of experience in the software and oil and gas industries. Mr. Mehta received a bachelor’s degree from the University of Houston and a master’s degree from the University of Wisconsin.

Oilfield Services 98 16 October 2012 Financials Forecasts & Key Assumptions We are modeling revenue growth in 2012 of 19% to $15.5 billion, and then revenue growth of 5% in 2013 to $16.3 billion, driven by recent acquisitions and WFT’s artificial lift business. Our EPS forecasts are $0.93 in 2012 and $1.18 in 2013, and our EBITDA forecasts are $2.9 billion in 2012 and $3.2 billion in 2013. Balance Sheet/Liquidity The most recent balance sheet WFT has release was in 1Q12. At the end of the first quarter, WFT had $371 million in cash and equivalents on its balance sheet. Net debt totals $7.55 billion. We are modeling to the company to be free cash flow negative in 2012 before reducing capital expenditures in 2013 and producing a positive free cash flow in 2013 and beyond. WFT is highly leveraged with company’s 1Q12 debt-to-capitalization ratio of 43%. We are modeling a slight leverage increase to 45% for FY 2012. Valuation Consistent with the rest of our oilfield service company coverage, we are looking at shares of WFT on an EV/EBITDA and price-to-earnings basis. Furthermore, we are also looking at returns, WFT had a ROE of 2.8% in 2011 and we estimate it to increase to 5.8% and 8.6% in 2012-13, respectively. We believe that WFT’s best comparable group consists of Baker Hughes (BHI), Halliburton (HAL), and Schlumberger (SLB), given the products manufactured, customers serviced, and geographic end markets. WFT currently trades at 10x and 5.4x times our 2013 EPS and EBITDA estimates, respectively, which is an a -14% discount to the average peer group EV/EBITDA multiple of 6.3x on 2013 estimates.

Exhibit 88: WFT Comparables (US$ in millions, except per share data) Stock Price Market Enterprise EBIT DA EV / EBITDA EPS P / EPS Company Ticker Rating TP $ 10/15/12 Shares Value Value 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E

Baker Hughes BHI Neutral $40 $44.77 440 $19,699 $23,948 $4,121 $4,594 5.8x 5.2x $3.57 $3.91 12.5x 11.4x Halliburton Company HAL Outperform $44 $33.80 926 $31,299 $33,942 $6,075 $6,644 5.6x 5.1x $3.04 $3.12 11.1x 10.8x Schlumberger Limited SLB Neutral $66 $72.19 1,339 $96,662 $103,644 $11,164 $12,056 9.3x 8.6x $4.19 $4.58 17.2x 15.8x

Mean 6.9x 6.3x 13.6x 12.7x Median 5.8x 5.2x 12.5x 11.4x High 9.3x 8.6x 17.2x 15.8x Low 5.6x 5.1x 11.1x 10.8x

Weatherford International WFT Neutral $11 $12.17 769 $9,359 $17,552 $2,910 $3,221 6.0x 5.4x $0.93 $1.18 13.1x 10.3x Premium/(Discount) to Peer Group Average -13% -14% -4% -18% Source: Bloomberg, Company data, and Credit Suisse estimates. Investment Risks The investment risks of investing in WFT are two fold, those specific to the company and those that relate to the broader oilfield service industry. Company-specific risks include (1) the company’s internal accounting weakness, (2) the ongoing FCPA investigation, (3) operations in countries including, Iran, Syria, Sudan, and Cuba, which are currently subject to trade and economic sanctions and further U.S. law enforcement bodies are conducting a grand jury investigation into operations in some of these countries, (4) changes in and compliance with post-Macondo restrictions and regulations, and (5) environmental topics. Industry-specific risks include (1) oil prices, (2) global oil demand, (3) global GDP, (4) global E&P capex spending, (5) interest rate risk, (6) environmental and government regulations, (7) oversupply of pressure pumping equipment, (8) increased competition, (9) inclement weather/seasonality, and (10) geopolitical risks.

Oilfield Services 99 16 October 2012

Americas / United States Oil & Gas Equipment & Services

Cameron International Corp. (CAM) Rating OUTPERFORM* Price (12 Oct 12, US$) 53.22 INITIATION Target price (US$) 75.00¹ 52-week price range 58.99 - 38.91 Right Place, Right Time - Top Pick Market cap. (US$ m) 13,106.89 Enterprise value (US$ m) 13,597.89 ■ Initiating coverage with an Outperform rating. We are initiating coverage of CAM with an Outperform rating and a $75 target price. Relative to the *Stock ratings are relative to the coverage universe in each other subsegments within oilfield services, we believe offshore equipment analyst's or each team's respective sector. ¹Target price is for 12 months. manufacturers are the one of the best place for investors to be positioned in the later-half of 2012. With a far more diverse revenue stream than its Research Analysts closest peer, CAM offers exposure to the secular growth trends such as James Wicklund 214 979 4111 subsea, separation onto FPSOs, offshore and onshore rig equipment, valves [email protected] and measurement solutions to U.S. midstream projects, and U.S. frac rental Jonathan Sisto tree and manifold opportunities. Only 32% of CAM’s 2011 revenue came 212 325 1292 from offshore/deepwater arenas. [email protected] Shining Star. Our only reservation in recommending CAM is that it is one of Brittany Commins ■ 212 325 7128 the most consensus ratings in the sector with 23 of 25 analysts rating it a [email protected] buy. It’s crowded. But we don’t see the stock as over-priced, while we have some concerns about activity levels over the next several months, clearly global manufacturing will outperform North America related services, and management has been executing well. The former Natco businesses as wells as the Letourneau and TTS Group drilling businesses have all required a bit of work to optimize and the company isn’t there yet so there is further upside potential to returns and earnings. ■ Wind at their back. CAM’s backlog at Q2 was a record $7.5 billion, up 35% year-over-year and up 10% sequentially, demonstrating the momentum of the business. Revenues grew in every segment in Q2 as well. Drilling & Production Services makes up about 70% of the backlog and includes subsea and surface equipment as well as the expanded drilling equipment segment. Its frac tree/manifold rental business has been its fastest growing business and while we expect frac services in general to slow down, Cameron along with FMC and GE, are aggressively taking share from regional “moms & pops” as capital becomes more critical and a competitive advantage. Share price performance Financial and valuation metrics

Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = US$47.99 Year 12/11A 12/12E 12/13E12/14E EPS (CS adj.) (US$) 2.84 3.29 4.36 — 40 Prev. EPS (US$) — — — — P/E (x) 18.7 16.2 12.2 — 20 P/E rel. (%) 123.4 113.6 95.2 — 0 Revenue (US$ m) 7,000.0 8,221.3 9,162.0 — Oct-11 Jan-12 Apr-12 Jul-12 EBITDA (US$ m) 1,165.6 1,382.6 1,738.6 — Price Indexed S&P 500 INDEX OCFPS (US$) 0.84 2.33 5.45 — On 10/03/12 the S&P 500 INDEX closed at 1434.2. P/OCF (x) 58.8 22.8 9.8 — EV/EBITDA (current) 11.9 10.1 8.0 — Net debt (US$ m) 262 491 -557 — ROIC (%) 15.61 14.65 18.94 —

Quarterly EPS Q1 Q2 Q3 Q4 Number of shares (m) 246.28 IC (current, US$ m) 4,969.80 2011A 0.64 0.66 0.78 0.77 BV/share (Next Qtr., US$) 21.2 EV/IC (x) 2.3 2012E 0.57 0.74 0.90 1.08 Net debt (Next Qtr., US$ m) 662.1 Dividend (Next Qtr., US$) — 2013E 0.99 1.08 1.12 1.17 Net debt/tot cap (Next Qtr., %) 12.6 Dividend yield (%) — Source: Company data, Credit Suisse estimates.

Oilfield Services 100 16 October 2012 Investment Overview We are initiating coverage on shares of Cameron International Corporation (CAM) with an Outperform weighting and $75 target price. We view CAM as the best way for investors to play the diversified oilfield service equipment manufacturers.

■ With such rapid increases in the number of offshore rigs and seismic and other technologies improving the success rate of drilling, subsea development equipment will be a major benefactor. Particular pieces of CAM equipment that will benefit from increased subsea development are subsea trees and manifolds though the company is constantly pursuing complementary technologies and organic development to expand its offering. The company is slated for a huge 2H12 and 2013 subsea order rate.

■ Since the BP Macondo well disaster in 2010, the oil and gas industry has seen an increase in government oversight and regulation. Increased regulation, inspections, and equipment redundancies of oilfield service equipment, such as blowout preventers (BOPs) is becoming the new norm. In fact, dual BOPs are already sold-out for 2013 with 2014 and 2015 approaching similar levels. OEM maintenance and repair are the industry standard now. Greater complexity of equipment reduces market encroachment. All of this is proving a strong net positive for Cameron.

■ The shift to more horizontal drilling of oil and liquids-rich wells is driving demand for more high pressure, high temperature (HPHT) pieces of oilfield equipment such as blowout preventers (BOPs), wellheads, production systems, controls, and valves from DPS’ Surface Systems (SUR). CAM is also benefiting from increased demand for more connection type valves, as producing wells need to be connected to mid-stream infrastructure such as pipelines. CAM’s “Enterprise” initiative is focused on providing broader solutions rather than discrete equipment and the shale development “manufacturing” mentality fits that effort well.

■ The increase in use of floating production storage and offloading vessels, called FPSOs, primarily in Brazil but proliferating, provides another growth platform for CAM especially in the separation, valve, and measurement solutions business lines, with revenue potential reaching $200+ million. While the adoption rate has been slow over the past few years, the increases in discoveries in remote locations bodes well for its future growth.

■ Historically, CAM’s market share of offshore rigs (1974-2011) has been 47% for semis and drillships and 52% for jackups. With the addition of Letourneau in the third quarter 2011 and TTS Group in the second quarter of 2012, the revenue potential per rig is now approaching $250 million each and as one of only a few companies with such a broad offering, should be able to generate decent margins once the businesses are fully integrated.

■ Expect to see reduced capital expenditure levels in 2013 as CAM looks to offer more investor friendly actions (share repurchase, special dividend, or dividend). Recall, the dividend was suspended in and around the Macondo well incident in 2010. With many growth opportunities in its sights, we would expect CAM to go the “dating” route of stock buybacks rather than the “commitment” of a significant dividend. Both will be behind growth as the primary use of free cash flow.

■ Right Place, Right Time. Mid-cycle slowdown considered, CAM is in one of the best positions with the needed products. While crowded, there is significant upside. Execution remains the key.

Oilfield Services 101 16 October 2012 Company Overview Cameron International Corporation (CAM), based in Houston, TX, provides flow equipment products, systems and services to worldwide oil, gas and process industries through three business segments, Drilling and Production Systems (DPS), Valves & Measurement (V&M) and Process & Compression Systems (PCS). Cameron’s origin dates back to 1833 with the founding of the Cooper foundry (later Cooper Industries) in Mt. Vernon, Ohio, a manufacturer of steam engines that powered industrial plants and textile and rolling mills. With the discovery of oil and gas in the late 1800’s, Cameron’s predecessor businesses became more focused on machinery and equipment used in the exploration and production of oil and gas. Cooper Industries’ oilfield business grew by the founding or acquisition of Ajax Iron Works (compressors), Superior (engines and compressors), Bessemer Gas Engine Company (gas engines and compressors) and much later Joy Petroleum Equipment (valves, couplings and wellheads) and Joy Industrial Compressor Group. Cameron Iron Works (blowout preventers, ball valves, control equipment, McEvoy-Willis wellhead equipment and choke valves) was founded in 1920 in Houston, Texas and was acquired by Cooper Industries in 1989. Cameron operated as a wholly-owned subsidiary of Cooper Industries, Inc. until June 30, 1995, when it was spun-off as a separate stand-alone company and renamed Cooper Cameron Corporation, combining the former Cooper and Cameron oil and gas-related product businesses. The Company subsequently changed its name to Cameron International Corporation in May 2006. Since becoming a stand-alone Company, Cameron has continued its acquisition strategy, having made numerous acquisitions, including the 1996 acquisition of Ingram Cactus Company, the 1998 acquisition of Orbit Valve International, Inc., 2004’s acquisition of Petreco International, Inc., the purchase of substantially all of the businesses within the Flow Control segment of Dresser, Inc. in 2005, the acquisition of NATCO Group Inc. ( NATCO ) in 2009 and the purchase of LeTourneau Technologies, Inc. in 2011. Today, Cameron is a Fortune 500 company with annual revenues of $7 billion and a workforce of approximately 22,500 employees in more than 200 legal entities spanning more than 50 countries worldwide. Business Segments CAM is organized into three main business segments, from which ten operating divisions are managed. The three business segments are described and outlined below. For a more visual representation of CAM’s business segment, operating divisions, and end markets, please see Exhibit 92and Exhibit 93. Drilling & Production Systems (DPS) The Drilling & Production Systems segment includes businesses that provide systems and equipment used to control pressures and direct flows of oil and gas wells. DPS’ products are utilized in a wide variety of operating environments including basic onshore fields, highly complex onshore and offshore environments, deepwater subsea applications and ultra-high temperature geothermal operations. Some of the most well know products designed, produced, and serviced by the DPS segment are; onshore and offshore blowout preventers (BOPs), high pressure, high temperature (HPHT) wellheads and valves, as well as subsea wellheads and manifolds. In late-2011, CAM purchased Le Tourneau from Joy Global Inc. (JOY) to complement its existing Drilling Systems product line within DPS. As Exhibit 89 represents, 58.4% of CAM’s 2011 total revenues were derived from the DPS segment. Valves & Measurement (V&M)

Oilfield Services 102 16 October 2012

The Valves & Measurement segment includes business divisions that provides valves and measurement systems used to control, direct, and measure the flow of hydrocarbons moving from the wellhead through flow lines, gathering lines and transmission pipelines to end market users like refineries, petrochemical plans and other industrial users. Predominantly, the equipment manufactured and sold by CAM’s V&M division meets the standards set by the American Petroleum Institute (API) and the American Society of Mechanical Engineers. Key products produced and sold by the V&M segment include, gate valves, ball valves, butterfly valves, double black & bleed valves, actuators, and chokes. In addition, aftermarket parts and services are provided by the a team of sales, marketing, and engineering specialists. The segment is a beneficiary of the rising oil and gas drilling activity taking place in North America currently. More oil and gas production are leading to greater demand for valves on pipelines and other support equipment. In 2011, V&M represented 23.9% of CAM’s total revenue and 26.8% of total company income before income taxes. Process & Compression Systems (PCS) The Process & Compression Systems segment includes the business divisions that produces standard and custom engineered process packages for separation and treatment of impurities within oil and gas and compression equipment. Integrally geared centrifugal compressors are used by customers around the world in a variety of industries, including air separation, petrochemical, chemical and process gas. PCS products include oil and gas separation equipment, heaters, dehydration and desalting units, gas conditioning units, membrane separation systems, water processing systems, integral engine-compressors, separable reciprocating compressors, two and four-stroke cycle gas engines, turbochargers, integrally-geared centrifugal compressors, compressor systems and controls. Aftermarket services include spare parts, technical services, repairs, overhauls and upgrades. CAM’s acquisition of NATCO (discussed in more detail later) in 2009 expanded the size, product offerings and global reach of the company separation and processing business. Today, CAM’s PCS segment equates to 17.7% of the company’s 2011 total revenues and 10.6% of its total income before income taxes.

Exhibit 89: CAM—Total Revenues by Segment (2009, 2010, and 2011)

PCS, PCS, 17.6% 18.6% PCS, 17.7%

DPS, DPS, V&M, DPS, V&M, V&M, 60.6% 58.4% 22.9% 59.6% 20.8% 23.9%

Source: Company data. Furthermore, 44% of CAM’s 2011 total revenue came from North America and no one customer represented more than 10% of CAM’s revenue.

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Exhibit 90: CAM - Total Revenues by Geographic Region 2009 2010 2011 North America $2,033 $2,491 $3,084 % of total 39% 41% 44% South America 504 525 648 % of total 10% 10% 12% Asia, including Middle East 1,042 1,178 1,271 % of total 20% 23% 24% Africa 685 1,182 1,002 % of total 13% 23% 19% Europe 790 655 754 % of total 15% 13% 14% Other 170 103 200 % of total 3% 2% 4%

Total $5,223 $6,135 $6,959 Source: Company data. Deepwater Revenue Exposure Given the secular growth trends in the oil and gas sectors over the last several years, it is important to point out that CAM generated approximately 32% of its 2011 revenue from offshore, deepwater markets.

Exhibit 91: CAM - EBIT by Segment (2009, 2010, & 2011) 70% 67.6% 62.6% 61.6% 60%

50%

40%

26.8% 30% 22.6% 19.1% 15.8% 20% 13.4% 10.6% 10%

0% DPS V&M PCS

2009 EBIT 2010 EBIT 2011 EBIT

Source: Company data. Revenue Recognition CAM recognizes revenue on a completed contract basis within its valves, compression, separation, and surface businesses. For highly engineered and long build time orders in subsea and drilling, CAM uses the unit completion method of percentage of completion. Similarly, CAM’s measurement business (nuclear power plant content) uses percentage of completion as well. Competitors In the oil and gas production equipment markets that CAM sells to, CAM competes against the lies of Aker Solutions, Balon Corp., Circor International, Inc., Dover Corp., Dril-Quip, Inc., Emerson Process Management, FlowServ Corp., FMC Technologies, Inc., GE Oil &

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Gas, National Oilwell Varco, Robbins & Meyers Fluid Management group (now owned by NOV), Oil States International (OIS), Tyco International Ltd., and Weatherford, Ltd.’s artificial lift business. In the compression equipment market, CAM competes again Ariel Corp., Atlas-Copco AB, CECO, Deman, Dresser-Rand Company, FS-Elliott Company LLC, Hoerbiger Group. CAM prides itself on delivering a broad-base of high quality products around the world that are honored by its reputation and excellent services and repair capabilities. From an investment standpoint, the primary competitors investors should include are; FMC Technologies, National Oilwell Varco, Forum Energy Technologies, Dril-Quip, and Dresser-Rand.

Oilfield Services 105

Oilfield Services Exhibit 92: Cameron Corporate Structure

16 October 201

Source: Cameron International. 10 6 2

Oilfield Services Exhibit 93: Cameron End Markets

16 October 201

Source: Cameron International. 10 7 2

16 October 2012 Market & Business Drivers Among the key industry growth trends that will affect CAM’s businesses are offshore oil and gas development, North American drilling activity, original equipment manufacturer service work, and drilling equipment replacements.

Increasing Offshore & Subsea Development As the oil and gas industry continues on its quest to discover hydrocarbons in more remote locations, capital expenditures toward subsea, deepwater equipment and fields is expected to increase to approximately $22 billion by 2017, according to Quest Offshore (Exhibit 94). With the increasing number of offshore, deepwater drilling rigs coming into the global market, the number of potential reservoir discoveries is increasing at a rapid rate. Credit Suisse’s offshore drilling analyst Gregory Lewis estimates that the total number of offshore drilling rigs, jackups, and semi-submersible rigs could total 953 by 2015; split, 152 drillships, 565 jackups, and 236 semis-submersibles. With such rapid increases in the number of rigs work offshore and discover rates becoming more successfully due to advances in seismic technology, subsea development equipment will be a major benefactor. Particular pieces of CAM equipment that will benefit from increased subsea development are subsea trees and manifolds. As represented in Exhibit 98 below, we think there are 606 subsea trees are likely to be awarded in 2012 globally from subsea projects. CAM has a number two market share position behind FMC Technologies (FTI) in the market for subsea trees and manifolds. More specifically, from 2007 through 2011, FTI achieved 47% market share of subsea system orders; a market that totaled $35.2 billion during the aforementioned time period. Cameron (CAM), FTI’s biggest competitor, secured 21% market share during the same time period, while GE Oil & Gas (GE) earned 15%, Aker Solutions (AKSO) had 10%, and Dril-Quip (DRQ) managed 7% share. In 2011, 32% of CAM’s total revenue was classified as from deepwater.

Exhibit 94: Worldwide Subsea Capex (2012E–2017E) $25,000 900 $MM ‐ subsea production umbilicals installed

$MM ‐ subsea manifolds 800

$20,000 $MM ‐ tree control pkg (flying leads, jumper, MCS, HPU, UTA, J‐Plate) 700 $MM ‐ subsea trees & control pod: (chokes, sensor pkg.)

No. subsea trees (well completions) by onstream year 600 Startups

$15,000 Km ‐ subsea production umbilicals installed $MM

500 Tree

or

SPU 400 Subsea

of

$10,000 of

KM 300

200 Number $5,000

100

$0 0 2004 2005 2006 2007 2008 2009 2010 2011 2012e 2013e 2014e 2015e 2016e 2017e Startup Year

Source: Quest Offshore. The subsea tree market is limited by the manufacturers own manufacturing capacity. We estimate that 775 trees can be manufactured during any given year. More specifically, we

Oilfield Services 108 16 October 2012 have heard from our contacts that GE Oil & Gas (GE) can manufacture seven subsea trees/month at the company’s Aberdeen facility only (84 trees/year). We then assume this global manufacturer has the capabilities to produce another thirty-six other trees globally and that FMC Technologies, the market leader, can produce 45% of the trees each year.

Exhibit 95: Subsea Tree Manufacturing Capacity

Dril-Quip 4% Aker 10%

Vetco (GE) FMC Technologies 16% 45%

Cameron 25%

Theoretical Capacity: 775

Source: Credit Suisse estimates. Improving Subsea Equipment Pricing Dynamics: According to an industry publication, major operators are beginning to publically state how subsea equipment manufacturers are lacking the technical personnel to deliver smaller, more challenging projects due to the industry’s current focus on mega-deepwater projects. We see the issue differently and would argue that for the first time in a number of years, operators are now having to court equipment suppliers/manufacturers in order to get into the manufacturing cycle. Such a change in dynamics is a another positive datapoint for subsea equipment pricing and thus CAM and FTI (as well as GE and Aker Solutions). Mounting Well & Service Intensity As demonstrated by the increasing percentage of horizontal wells being drilled in the United States and elsewhere, the overall well and service intensity per well is increasing dramatically. According to Baker Hughes, the U.S. horizontal rig count now represents approximately 62% of the total U.S. rig count at the end of Q3, and we estimate that this will likely build to 66% by year-end 2012. This shift to more horizontal drilling of oil and liquids-rich wells is driving demand for more high pressure, high temperature (HPHT) pieces of oilfield equipment such as blowout preventers (BOPs), wellheads, production systems, controls, and valves from DPS’ Surface Systems (SUR). CAM’s frac rental tree and manifold business has grown exponentially over the last few years. More specifically, the rental business generated $100 million in revenue in 2010 and $500 million in 2011. CAM is also benefiting from increased demand for more connection type valves, as producing wells need to be connected to mid-stream infrastructure like pipelines. To meet customer demand specifically in North America, CAM has opened several new sales and aftermarket facilities in the Marcellus, Eagle Ford, Haynesville, and the Bakken. The company also has surface operations in Brazil and Iraq, currently.

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Exhibit 96: Historical Oil and Gas Directed Exhibit 97: Historical Oil and Gas Rig Count Horizontal Rig Count

800 700 600 500 400 # of # of Rigs 300 200 Horizontal Gas Rig Count 100 Horizontal Oil Rig Count 0 Oct-10 Apr-11 Oct-11 Apr-12 Jun-10 Jan-11 Jun-11 Jan-12 Mar-10 Aug-10 Aug-11

Source: Baker Hughes. Source: Baker Hughes. The Beneficial “Macondo Effect” Following the BP Macondo well disaster in 2010, the oil and gas industry has seen an increase in government oversight and regulation. Increased regulation, inspections, and equipment redundancies of oilfield service equipment, such as blowout preventers (BOPs) is becoming the new norm. For example, the general counsel of an offshore drilling company can no longer allow his or her company to opt for a lower cost non-original equipment manufacturer (OEM) repair and maintenance work due to the liability president set by Macondo. Furthermore, with offshore rig dayrates pushing $600,000/day or more, rig operators and oil companies cannot afford unnecessary downtime due to equipment repair or inspection. Equipment redundancies and strategically located back-ups are no becoming the industry norm. Therefore, BOP OEMs such as CAM, National Oilwell Varco (NOV), and GE Oil & Gas (GE) are likely to be beneficiaries of this increased equipment demand, aftermarket service and recertification work. We fully expect CAM to expand its aftermarket service offering by adding roofline and skilled labor, while quietly increasing prices over the next several years, but not to egregious levels that would impair the company’s long-term customer relationships in the process. Year-to-date, CAM’s aftermarket drilling bookings in the first-half of 2012 have totaled $400 million and exceed all of 2010, or any year prior. CAM booked five subsea BOP stacks and five jackup BOP stacks in the second quarter of 2012; four of the stacks were sold as backups on existing rigs. The recently announced Rowan Drilling (RDC) drillships being built by the Hyundai Heavy Industry shipyard will have dual-BOPs and we believe the BOPs will be CAM’s. Furthermore, our checks tell us that dual-BOP stacks are sold- out for 2013 and are close to being sold-out for 2014 and 2015 already. Swelling Demand for Valves With more oil and gas production being done offshore via floating production storage and offloading vessels called FPSOs, CAM’s measurement, valves, produced water, treating, and actuators are primed to see increased demand. CAM has noted in the past that the company’s V&M segment has revenue opportunities of $50-100 million per FPSO coming online in the next few years. The division of CAM is primarily trying to sell separation technology and equipment onto FPSOs. And, Quest Offshore estimates there will be 145 FPSOs in use in the next five years. The repair and maintenance of existing refineries is calling for more V&M work in the U.S., Russia, and Brazil. Through the acquisitions the company has made of the years (i.e., Dresser in 2005), CAM has been very successful in gaining operating and economic efficiencies that we argue allows CAM to delivery higher ROIC than its peers. Rig Replacement and Upgrade Cycle

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Given the aging onshore drilling rig fleet in North America (NAM) and the increasing demands on those rigs through increased drilling for unconventional resources, the industry is undergoing a swift transition to next-generation, AC-powered drilling rigs. CAM’s DPS business segment and its newly acquired Le Tourneau and TTS Drilling Technologies, Inc. operations should benefit from selling more elevating systems, skidding systems, cranes, top drives, rotary tables, draw works, mud pumps and rig control and power systems. Le Tourneau also provides drilling equipment and rig designs and components to offshore rigs as well, which as stated throughout this report is seeing an amount of newbuild construction an international oil and gas companies are seeking hydrocarbons in remote regions of the globe, like the Artic, East and West Africa, Southeast Asia, and need new, quality, reliable equipment to match their demands and goals. Historically, CAM’s market share of offshore rigs (1974-2011) has been 47% for semis and drillships and 52% for jackups.

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Exhibit 98: Credit Suisse’s Estimate of Major Subsea Projects

Project/Field Name Country/Region Operator # of Trees Likely Supplier Timing Status

North America (NAM) Panyu 34‐1/35‐1/35‐2GoM (USA) CNOOC 6 FTI, CAM Pending Mad Dog South GoM (USA) BP 33 CAM, FTI Bidding Appomattox GoM (USA) Shell 14 FTI Bidding Hadrian North GoM (USA) ExxonMobil 16 All Bidding Julia GoM ExxonMobil 10 FTI Bidding Beaufort Sea Amauligak Canada ConocoPhillips 10 Bidding PONY GoM Hess 14 FTI Bidding Vito GoM Shell 14 FTI Bidding Total 117

Africa / Middle East (AFM) Block 15/06 Angola ENI 10 GE Bidding Erha North Phase 2 Nigeria ExxonMobil 10 CAM 3Q12 Pending Egina Nigeria Total 48 FTI Late‐3Q12 Pending T.E.N. (Tweneboa) Ghana Tullow 16 FTI 4Q12 Bidding Lucapa Angola Chevron 18 Aker, CAM, GE, FTI, DRQ Bidding Block 31, Phase 2 Angola BP 40 CAM 3Q12 Letter of Intent Chissonga (Block 16) Angola Maersk 44 All 1Q12 Bidding Greater Plutonio Infill (Block 18) Angola BP 10 FTI Bidding Lukoil Ghana Ghana Lukoil 20 FTI Bidding Agbami Phase 2 Nigeria Cheveron 26 2Q12 Bidding Block 32 Angola Total 64 FTI 2013 Bidding Kizomba Satellites Phase 2 Angola ExxonMobil 16 CAM, GE, Aker 2Q12 Bidding Moho North Phase 2 Congo Total 17 2Q12 Bidding North Alex Phase 1 Egypt BP 18 CAM 3Q12 Bidding WDDM Phase Ixb Egypt BG 12 CAM 4Q12 FEED Western Hub Angola ENI 11 ALL 1Q12 Bidding Azeri Subsea Azerbaijan BP 6 FTI, CAM Bidding Total 386

Asia / Pacific R‐Series/Satellites India Reliance 21 FTI Bidding Sunrise Australia Woodside 12 FTI Bidding Gendalo / Gehem Indonesia Chevron 18 All 2H12 Bidding Total 51

North Sea Linnorm Norway Shell 6 FTI Bidding Kraken U.K. Enquest 24 FTI Bidding Rosebank U.K. Chevron 14 FTI 2013 Aasta Hansteen (Luva) Norway Statoil 8 Aker, FTI Bidding Total 52

OVERALL TOTAL (ex‐South America) 606 Source: Quest Offshore, Company data, and Credit Suisse estimates.

Oilfield Services 112 16 October 2012 Cameron Over the Years The Cameron originally founded in Ohio and then built by Shel Ericson is not the Cameron of today. Over the last several years, current CEO Jack Moore has taken the build blocks assemble by his predecessors and turned Cameron into a global oilfield service and equipment company offering best-in-class products and service. Below, we discuss many of the main acquisitions and mergers executed by CAM since 2009; discussing pricing multiples and business operations where applicable. TTS Energy June 6, 2012 - CAM closed on its purchase of the drilling equipment business of TTS Energy Division from TTS Group ASA, a Norwegian company, for a cash payment of $248.1 million, net of cash acquired. TTS provides high performance drilling equipment, rig packages and rig solutions for both onshore and offshore rigs to the international energy industry and its financial results have been included in the Drilling & Production Systems (DPS) segment since the date of acquisition. As of June 30, 2012, preliminary goodwill recorded from this transaction was $235.3 million. We view the bolt-on acquisition as a nice complement to CAM’s existing DPS segment and the newly acquired Le Tourneau business purchase in fall-2011. Elco Filtration and Testing, Inc. During the first quarter of 2012, CAM acquired 100% of the outstanding stock of Elco Filtration and Testing, Inc. (Elco), for a total purchase price of $61.5 million, net of cash acquired. Elco was purchased to strengthen CAM’s existing wellhead product and service offerings and has been included in the DPS segment since the date of acquisition. Le Tourneau Technologies, Inc. October 24, 2011 - CAM closed its the acquisition of Le Tourneau Technologies, Inc. (LTI), a wholly-owned subsidiary of Joy Global Inc. (JOY), for $375.0 million in cash, or about 10.3x 2010 estimate-EBITDA of $34.0 million. Of note, Rowan Drilling (RDC) sold Le Tourneau to JOY on May 16, 2011 for $1.1 billion in cash. LeTourneau provides drilling equipment as well as rig designs and components for both the land and offshore rig markets and its results of operations have been included in the Company’s DPS segment from the date of acquisition. In 2010, LTI generated total revenues of approximately $515 million, split between two divisions, (i) Drilling Systems - $233 million and (ii) Offshore Products - $282 million. Drilling Systems featured products include complete jackup rigs, rig kits and component packages, primary drilling equipment such as mud pumps, draw works, top drives and rotary tables, and electrical components such as variable-speed motors and drives. LTI’ Products serve applications onshore and in shallow water. Offshore Products division offers a full line of rig components including elevating structures, cranes, drill packages, skidder systems, anchor winches, BOP-handling units. LTI’s components can be utilized on offshore jackup rigs and on land-based rigs as well. The addition of LeTourneau’s products meaningfully expands CAM’s offshore equipment market. We expect CAM to position LTI (and its legacy BOP and riser businesses) as a competitive alternative to National Oilwell Varco (NOV) and Aker’s Maritime Hydraulics. LTI’ operations include 800 employees and manufacturing facilities in Texas and Mississippi. We understand that Joy will retain ownership of the LeTourneau’s steel mill but CAM has established a supply agreement with LeTourneau for several years, which should combat against any near-term supply disruptions. Le Tourneau EBITDA margins to date from with CAM’s DPS segment have been somewhat lackluster. We believe CAM management has/is taking the appropriate steps to

Oilfield Services 113 16 October 2012 relocate manufacturing facilities, right-size employee count, and find additional synergies for cost savings and revenue growth. To this end, on the second quarter conference call, management stated that LTI margins will “exit this year [with] upper-single digit” and “exit next year [with margins] that look alike a traditional Cameron margin. Also during 2011, CAM acquired the stock of four other businesses for a total cash purchase price, net of cash acquired, of $46.9 million. The first, Vescon Equipamentos Industriais Ltda. was acquired to strengthen CAM’s surface product offerings in the Brazilian market and has been included in the DPS segment. Second, the remaining interest in Scomi Energy Sdn Bhd., previously a Cameron joint venture company, was acquired in order to strengthen process systems offerings in Malaysia. Thirdly, TS- Technology AS, a Norwegian company, was acquired to enhance the company’s water treatment technology offerings. Lastly, Industrial Machine and Fabrication (IMF) was acquired to enhance the Company’s rotating compression aftermarket offerings. All four acquisitions have been included into CAM’s PCS segment. During 2010, CAM acquired the assets or capital stock of two businesses for a total cash purchase price of $40.9 million. These relatively small business were acquired to enhance the Company’s product offerings or aftermarket services in the DPS and V&M segments. During 2009, the Company acquired the NATCO Group Inc. (NATCO) by issuing common stock valued at $971.6 million. According to CAM CEO Jack Moore at the time of the transaction, NATCO’s “revenues in 2008 exceeded $650 million”, which means CAM paid approximately 1.5x 2008 sales. NATCO had a backlog at the end of the first quarter of $314 million and over 400,000 square feet of manufacturing capacity, and proprietary CO2 membrane technology that could be leverage out of southeast Asia (Malaysia) and into other subsea development areas like sub-salts of offshore Brazil, where CO2 separation is needed. NATCO’s operations were included in the PCS segment. NATCO was one of the leading process systems companies in the world with a well- earned reputation for leading edge technology, quality products and a responsive service organization. Combined with Cameron, the new entity created a transformational step change in our separation and process capabilities. NATCO services onshore, offshore, and deep water markets. Operating in three segments, (i) Standard and Traditional (S&T), which is their oil, gas, and water separation technology focused on the onshore markets with smaller standardized processing equipment, including a very strong presence in the shale plays, (ii) Automation and Controls (A&C), which is focused on subsea well automation, platform monitoring, and process sampling, handling systems, and they are very big in Angola and the Gulf of Mexico, and then there is Integrated Engineered Solutions Group (IES). IES competed directly with Cameron’s Petreco division (acquired in 2004). IES is where NATCO has heavily invested in new technology like the Cynara Membrane technology used in CO2 capture, which is gaining wider use around the world and has a solid aftermarket story. Management Jack B. Moore (Chairman, President & CEO) Mr. Moore has been president chief executive officer of Cameron since April 2008 and became Cameron’s chairman of the board in May 2011. He joined Cameron’s Drilling & Production Systems group in July 1999 as vice president and general manager, Western Hemisphere, and was named president of this group in July 2002. He became president and chief operating officer in January 2007 and has been a director of Cameron since 2007. Prior to joining Cameron, Moore held various management positions with Baker Hughes Incorporated where he was employed for 23 years. Moore received a BBA from the University of Houston and is a graduate of the Advanced Management Program at

Oilfield Services 114 16 October 2012

Harvard Business School. He serves on the boards of directors of KBR, American Petroleum Institute (API), and National Ocean Industries Association (NOIA). Charles M. Sledge (Senior Vice President & CFO) Mr. Sledge joined Cameron in July 2001 as corporate controller and was named to his current position in April 2008. Sledge had previously been with Stage Stores Inc. since 1996, serving most recently as senior vice president-finance and treasurer. Prior to joining Stage, he was with Price Waterhouse LLP from 1989 to 1996. Sledge received a BS in accounting from Louisiana State University and is a certified public accountant. He is also a graduate of The Advanced Management Program at Harvard Business School. John D. Carne (Executive Vice President, COO) Mr. Carne was named chief operating officer of Cameron in August 2010. Carne has also served as executive vice president of Cameron since April 2010. Carne joined Cameron’s Compression Systems business in 1971 and subsequently held positions as systems designer; manager, technical services; area manager, aftermarket services; regional manager, Far East; and director of operations, U.K. and Norway. In 1996, he became manager of the Subsea Systems division’s manufacturing facility in Leeds, England and was named operations director, Eastern Hemisphere for the Drilling & Production Systems group in 1999. In April 2002, Carne became president of Cameron’s Valves & Measurement group and a vice president of the corporation. In January 2007, Carne became President of Cameron’s Drilling & Production Systems. James E. Wright (Senior Vice President, President Valves & Measurement) Mr. Wright was named president of Cameron’s Valves & Measurement group in January, 2007. Wright has also served as senior vice president of Cameron since April 2010. Wright joined Cameron in 1979 and has previously served as president, Distributed and Process Valves divisions and vice president and general manager, Distributed Products, as well as in numerous domestic and international management positions in Cameron’s valve businesses. Wright received a BA in English from the University of British Columbia. Joseph H. Mongrain (Vice President, President Process & Compression Systems) Mr. Mongrain is president of Cameron’s Process & Compression Systems Group. Mongrain joined Cameron in June 2006 as vice president, human resources and was responsible for the Company’s worldwide human resources programs. Mongrain was previously with Schlumberger, where he began his career as a Field Engineer in the Gulf of Mexico. He then moved to the Middle East where he held management positions in multiple locations and functions. He moved into a human resources management role in 1995, serving most recently as Director, Human Resources for one of the firm’s global divisions in Houston, and prior to that, as Director, Human Resources for Schlumberger’s North and South America region. He received a BS in ocean engineering from the Florida Institute of Technology.

Oilfield Services 115 16 October 2012 Financials Forecast & Key Assumptions We are modeling revenue growth in 2012 of 17% to $8.2 billion, and then revenue growth of 11% in 2013 to $9.16 billion. Our total company EBIT margin estimates are 13.7% in 2012 and 16% in 2013 versus 13% in 2011, as we expect the Le Tourneau and TTS Energy acquisitions to be brought up to speed and improved, coupled with improving margins in DPS and V&M. Our EPS forecasts are $3.29 in 2012 and $4.36 in 2013, and our EBITDA forecasts are $1.383 billion in 2012 and $1.739 billion in 2013. Balance Sheet/Liquidity At the end of the second-quarter CAM had $1.25 billion in cash and equivalents on its balance sheet. Net debt totals $789.1 million. We are modeling the company to generate about $1.0 billion in free cash flow in 2012 before reducing capital expenditures in 2013 and producing a significant amount of free cash flow in 2013 and beyond. The company’s current net debt-to-capitalization ratio of 11% is under-leveraged in our opinion in such a low rate environment but acquisitions are still a top priority, giving CAM plenty of dry powder. Orders & Backlog CAM’s total company book-to-bill ratio has been greater than 1 for much of the five-half years as depicted in the chart and thus CAM sales and marketing teams have done a good job getting more than enough orders in the door. Currently, CAM’s overall book-to- bill ratio stands at 1.3x. Obvious incoming orders for CAM and its peers were materially impacted by the global financial crisis of 2008 and 2009, hence the sharp drop off in orders and the book-to-bill ratio in 4Q08.

Exhibit 99: CAM—Orders by Segment and Book-to-Bill

3,000 2.0

DPS V&M P&C Book-to-Bill 1.8 2,500 1.6

1.4 2,000 1.2

1,500 1.0

$ millions 0.8 1,000 0.6

0.4 500 0.2

0 0.0 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12

Source: Company data, Credit Suisse estimates. CAM’s total backlog has been rising for each of the last seven quarters and now currently states at $7.5 billion. The current backlog is composed of 69% of the backlog from DPS, and 15% respectively from V&M and PCS, as of the end of second quarter 2012.

Oilfield Services 116 16 October 2012

Exhibit 100: CAM—Backlog by Segment

8,000 DPS V&M P&C 7,000

6,000

5,000

4,000 $ millions 3,000

2,000

1,000

0 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12

Source: Company data, Credit Suisse estimates. Valuation Our valuation is based on the historical relationship between the economic value added by the company and its resulting EV/EBITDA valuation multiple. If the return on capital exceeds the cost of capital, value is created and reflected in the stock price. We have taken a group of peer oilfield equipment manufacturing companies and correlated their EVA vs. EV/EBITDA multiples and forecasted the multiple for 2013 using our derived ROC. We then use that EV/EBITDA multiple, for CAM at 11.2x our expected 2013 EBITDA to derive a price target of $75. Our price target $75 is a 12-month price target and there is a great deal of volatility in the OFS universe. We are expecting the US rig count to decline over the next 5-6 months, counter-seasonally in the 4th quarter and returning to its normal 1st quarter seasonal decline in 2013. While a lesser amount of CAM’s revenue base is related to the near-term rig count, it will be effected and the sentiment of the group could affect the stock price. Our Timing Model shows that the best entry point for OFS stocks is typically in January but we would expect CAM to out-perform more North American centric service stocks at least through the end of the year. Comparables We believe CAM’s best comparable group consists of FMC Technologies (FTI), National Oilwell Varco (NOV), Forum Energy Technologies (FET), Oceaneering (OII), and Oil States International (OIS), given the products manufactured, customers serviced, and geographic end markets. Currently, shares of CAM are trading at 12.4x and 7.6x our 2013 earnings per shares (EPS) and EBITDA estimates, respectively. On an EBITDA-basis, shares of CAM are trading at a 2% discount to the peer group on 2013 numbers, while against earnings shares are trading at a 8% discount to the same peer group.

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Exhibit 101: CAM Comparables

(US$ in millions, except per share data) Stock Price Market Enterprise EBIT DA EV / EBIT DA EPS P / EPS Company Ticker Rating TP $ 10/15/12 Shares Value Value 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E

Forum Energy Technologies FET Restricted - $22.70 90 $2,038 ------FMC Technologies FTI Neutral $49 $44.02 242 $10,631 $11,572 $836 $1,027 13.8x 11.3x $2.09 $2.64 21.1x 16.7x National Oilwell Varco NOV NC - $78.22 427 $33,363 $32,997 $4,428 $5,082 7.5x 6.5x $5.97 $6.92 13.1x 11.3x Oceaneering Int.'l OII NC - $51.75 108 $5,586 $5,623 $594 $698 9.5x 8.1x $2.65 $3.23 19.6x 16.0x Oil States Int.'l OIS NC - $73.37 55 $4,028 $5,066 $919 $948 5.5x 5.3x $8.10 $8.22 9.1x 8.9x

Mean 9.1x 7.8x 15.7x 13.2x Median 8.5x 7.3x 16.3x 13.7x High 13.8x 11.3x 21.1x 16.7x Low 5.5x 5.3x 9.1x 8.9x

Cameron International CAM Outperform $75 $53.22 248 $13,183 $13,358 $1,383 $1,739 9.7x 7.7x $3.29 $4.36 16.2x 12.2x Premium/(Discount) to Peer Group Average 7% -1% 3% -8% Source: Company data, Credit Suisse estimates. Risks Macroeconomic and Commodity Exposure Demand for most of the CAM’s products and services, and therefore its revenue, depends to a large extent upon the level of capital expenditures related to oil and gas exploration, production, development, processing and transmission. Declines, as well as anticipated declines, in oil and gas prices could negatively affect the level of these activities, or could result in the cancellation, modification or rescheduling of existing orders. Goodwill Impairments A deterioration in future expected profitability or cash flows could result in an impairment of the CAM’s existing goodwill on the balance sheet. Total goodwill approximated $1.6 billion at December 31, 2011, a large portion of which was allocated to the Company’s PCS segment, which includes the majority of the NATCO operations acquired in 2009. As a result of competitive pressures during the economic downturn that began prior to the acquisition of NATCO, the backlog of the Custom Process Systems business within the PCS segment carried an unusually low margin. If the Company is unable to improve the margins on this portion of the PCS segment over time, an impairment of goodwill might be required. Goodwill associated with the Custom Process Systems business was approximately $566.3 million at December 31, 2011. Execution of Subsea Systems Projects CAM is a significant participant in the subsea equipment and systems market. This market is significantly different from most of CAM’s other markets since the subsea systems projects are much larger in scope and complexity, in terms of both technical and logistical requirements. Subsea projects typically involve long lead times, are larger in financial scope, require substantial engineering resources to meet the technical requirements of the project, and often involve the application of existing technology to new environments and, in some cases, may require the development of new technology. If CAM experiences unplanned difficulties in meeting the technical and/or delivery requirements of a project, CAM’s earnings, margins, or liquidity could be negatively impacted. Of note as well is that CAM uses percentage-of-completion (POC) accounting on it projects and cannot book any revenue until customers have taken full delivery of a part or piece of equipment. Foreign Currency In recent years, CAM has established multiple “Centers of Excellence” facilities for manufacturing such products as subsea trees, subsea chokes, subsea production controls and BOPs. These production facilities are located in the United Kingdom, Brazil and other European and Asian countries. To the extent CAM sells these products in U.S. dollars, the company’s profitability is eroded when the U.S. dollar weakens against the British pound, the euro, the Brazilian real and certain Asian currencies, including the Singapore dollar. Alternatively, profitability is enhanced when the U.S. dollar strengthens against these same currencies.

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Other The company is currently undergoing a multi-year effort to upgrade its SAP business information systems in the DPS and V&M business segments (implementation in the PCS segment concluded in the third quarter of 2011). The company encounter difficulties with the implementation that could impact operational execution.

Oilfield Services 119 16 October 2012

Americas / United States Oil & Gas Equipment & Services

FMC Technologies, Inc. (FTI) Rating NEUTRAL* Price (12 Oct 12, US$) 44.02 INITIATION Target price (US$) 49.00¹ 52-week price range 54.36 - 37.68 “I Feel the Need for Speed” Market cap. (US$ m) 10,493.69 Enterprise value (US$ m) 10,773.29 ■ Initiating Coverage with a Neutral Rating. Relative to the other sub- segment within oilfield services, we believe offshore equipment *Stock ratings are relative to the coverage universe in each manufacturers are the best place for investors to be positioned in the later- analyst's or each team's respective sector. ¹Target price is for 12 months. half of 2012. Considered by many in the industry to be the perennial manufacturer of subsea systems in the world, FTI is well positioned to Research Analysts benefit from one of the strongest secular growth segments in the oil and gas James Wicklund 214 979 4111 industry while expanding its onshore and shale business exposure. [email protected] ■ Improving Subsea Dynamics: 311 subsea trees were awarded in 2011. Jonathan Sisto Year to date, 270 trees have been awarded and the industry is on pace to 212 325 1292 [email protected] see 450-500 subsea awarded in 2012 as projects are finally coming to Brittany Commins fruition and NOC and IOCs are looking to increase their depletion rates. FTI 212 325 7128 has stated publically that they expect to see $4-$5 billion in subsea orders in [email protected] 2012 if the key projects they are tracking hit on time.

■ Longstanding Frame Agreements: FTI has forged frame agreements with many of the largest offshore oil and gas customers. It is these frame agreements which are FTI’s competitive advantage versus other subsea equipment manufacturers. These agreements give FTI greater visibility about long-term project opportunities and allow them to adjust staff levels and procure raw materials. Also, by working with customers over and over again, FTI can develop a level of standardization for its customers. How Pure? The Pure Energy Services (TSX: PSV) acquisition in late-August was intended to complement the existing frac equipment rental and sales business (12% of 2011 revenues); with the acquisition done closer to the bottom of the market than the top and at an EBITDA multiple far less than where the company currently trades, we are unsure how pure the acquisition may be. Share price performance Financial and valuation metrics

Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = US$42.14 Year 12/10A 12/11E 12/12E12/13E EPS (CS adj.) (US$) 1.50 1.58 2.09 2.64 40 Prev. EPS (US$) — — — — P/E (x) 29.4 27.8 21.1 16.7 20 P/E rel. (%) 193.7 195.3 164.8 145.1 0 Revenue (US$ m) 4,125.6 5,099.0 6,211.9 6,916.1 Oct-11 Jan-12 Apr-12 Jul-12 EBITDA (US$ m) 636.8 656.9 836.0 1,026.6 Price Indexed S&P 500 INDEX OCFPS (US$) 0.80 0.68 -0.02 0.83 On 10/03/12 the S&P 500 INDEX closed at 1434.2 P/OCF (x) 55.8 64.9 -1,828.9 52.8 EV/EBITDA (current) 16.5 16.0 12.6 10.3 Net debt (US$ m) 48 280 1,026 1,075 ROIC (%) 27.18 23.44 17.74 17.81

Quarterly EPS Q1 Q2 Q3 Q4 Number of shares (m) 238.38 IC (current, US$ m) 1,370.10 2010A 0.39 0.38 0.32 0.40 BV/share (Next Qtr., US$) 6.2 EV/IC (x) 6.2 2011E 0.31 0.38 0.49 0.40 Net debt (Next Qtr., US$ m) 193.6 Dividend (Next Qtr., US$) — 2012E 0.41 0.46 0.57 0.64 Net debt/tot cap (Next Qtr., %) 12.8 Dividend yield (%) — Source: Company data, Credit Suisse estimates.

Oilfield Services 120 16 October 2012 Investment Overview We are initiating coverage on shares of FMC Technologies, Inc. (FTI) with an Neutral weighting and $49 target price. FTI is considered by many to be leading manufacturer of subsea systems in the world, and we believe that equipment is one of the more attractive ways for investors to play the ongoing subsea/deepwater secular industry trends.

■ Activity and success in deepwater drilling drives the future market for subsea equipment. The number of deepwater rigs (5,000’+) has increased by 115% over the past five years and with current new-build ordered, will have nearly doubled by 2015 from 2007 levels with deepwater drilling success rates continuing to rise. Subsea equipment installations are considered one of the strongest secular growth segments of the oil and gas industry. There are three primary competitors in most of FTI’s businesses including Cameron International (CAM), the Oil & Gas division of GE (GE) and Aker Solutions (AKSO:NO). With such identified secular trends, we expect aggressive acquisition of complementary technologies by the four to maintain their dominance.

■ FTI’s has led the pack for some time. Of the $35.2 billion in subsea system orders awarded between 2007-2011, FTI earned a 47% share while its nearest competitor, Cameron International (CAM), achieved 21%. With 64% of the company’s 2011 revenues coming from the Subsea Technology segment and possessing frame agreements with financially/geographically major and independent oil and gas companies, FTI has tremendous long-term visibility and market dominance its competitors lack. 2,500 engineers have been added over the past two years with increases in roof line and manufacturing capacity around the world as training of people and efficiency in manufacturing is planned and executed well in advance of orders.

■ A confluence of factors including strong order flow, high utilization and deflation of input costs led to FTI reporting record margins in 2010. Investors continue to hope for a return to those margins levels which we believe will be more difficult this go- around. That, combined with order interruptions from the Macondo incident and delivery/installation issues in West Africa, has caused a decline in subsea margins, which we believe are near a bottom and should begin to improve through 2013. Post-spill businesses levels are back, oil prices are high enough to deep deepwater development projects on track and troubled projects are rare and mostly finished. Execution remains the key.

■ FTI uses percentage of completion accounting which delays the recognition of improving pricing on the income statement. That improved pricing may not be seen in reported numbers until late 2013 but comments about improved pricing on backlog orders will likely move the stock before then. There are still issues and concerns on the delivery/installation of subsea systems in and around the CLOV project in Angola. The recent Pure Energy acquisition seems to demonstrate some change in strategy for the company. It more than doubles the field employment in North America and adds a wireline segment in which the company has little interest. All of these are concerns for a stock that has typically traded at a premium multiple to its peer group.

■ The Pure Energy Services Ltd. (TSX: PSV) acquisition in late-August was intended to complement the existing frac equipment rental and sales business of the company (12% of 2011 revenues); with the acquisition done closer to the bottom of the market than the top. Only about half of Pure’s business, frac flowback, fits as strategic and it is not typically seen as a premium valuation business about is a critical part of what has been the fastest growing segment of the company over the past two years..

Oilfield Services 121 16 October 2012

■ The recent hiring of Doug Pferdehirt as Executive Vice President and Chief Operating Office, with responsibility for all three operating segments, complements what has been a very deep and strong management bench at the company and we view as a very positive move. Bob Potter, with the company since 1973, being promoted to President is positive and well deserved as well.

Oilfield Services 122 16 October 2012 Company Overview During the fourth quarter of 2011, FTI changed its reporting segments based on the strategic priorities and the manner in which the company’s chief operating officer reviews and evaluates operating performance to make decisions about resources to be allocated to the segment. This was followed by the hiring of Doug Pferdehirt as EVP and COO from Schlumberger and the acquisition, for $285 million, of Canada-based Pure Energy Services. FMC Technologies, Inc., based in Houston, TX, is a global provider of technology solutions for the energy industry. FTI designs, manufactures and services technologically sophisticated systems and products, including subsea production and processing systems, surface wellhead production systems, high pressure fluid control equipment, measurement solutions and marine loading systems for the energy industry. As of December 31, 2011, the company employed approximately 14,200 full-time employees, with approximately 32% of those employees working in the United States. Less than 3% of FTI’s U.S. employees are represented by labor unions. Business Segments FTI is organized and reports the results of operations in the three main segments: (i) Subsea Technologies, (ii) Surface Technologies, (iii) and Energy Infrastructure.

Exhibit 102: FTI—Historic Revenue by Segment

2010 2011 2009

Subsea $503 Technologies $400 $454

Surface $498 Technologies $954 $1,311 $2,731 Energy $3,022 Infrastructure $3,288

Source: Company data, Credit Suisse estimates.

Oilfield Services 123 16 October 2012

We believe the best way to represent FTI’s businesses is by discussing the company’s exposure to different industries. Exposure to Subsea Activity Subsea Technologies designs and manufactures products and systems and provides services used by oil and gas companies involved in deepwater exploration and production (E&P) of crude oil and natural gas. At the core of FTI’s Subsea Technologies segment is the company’s technology, reliability, execution, and engineering expertise of production systems, which control the flow of oil and gas from producing subsea wells. FTI’s subsea systems produces subsea Christmas trees and manifolds, which are used in the offshore production of crude oil and natural gas. These systems are placed on the sea Key Customer Relationships floor and control the flow of crude oil and natural gas from the reservoir to a host processing facility, such as a floating production facility (like a FPSO), a fixed platform or an onshore facility. The systems are designed to withstand exposure to the extreme hydrostatic pressure that deepwater environments present, as well as, internal pressures of up to 15,000 psi and temperatures in excess of 350 degrees Fahrenheit. Within, Subsea Technologies, FTI also designs and manufactures multiphase meters (MPMs). These meters deliver high accuracy to optimize oil and gas recovery. Generally, FTI’s customers within the Subsea Technologies segment include major integrated oil or independent exploration and production companies. The mix of FTI’s customer base is also one of its competitive advantages versus it competitors; because of the extremely long lead times and substantial capital investments needed to get a subsea, deepwater project underway and producing, FTI has strived to establish alliances with its key customers to ensure timely and reliable subsea and other energy-related systems. These alliances, or frame-agreements provide FTI with a tremendous amount of orders but most importantly visibility into market cycles. FTI’s alliances do not contractually commit customers to purchase subsea systems and services, but they have historically led to, and the company expects that they will continue to result in, such purchases in the future. Some of FTI’s key customer relationships are list herein. In 2011, Statoil (STL NO) and Total S.A. (TOT) represented 12% and 11% of FTI’s total revenue, respectively. As a business segment, Subsea Technologies, represented approximately 64%, 66%, and 70% of FTI’s total revenues in 2011, 2010, and 2009, respectively. Subsea Technologies is also the best proxy for FTI’s subsea or deepwater revenue exposure. Source: FMC Technologies, Inc.

Exhibit 103: FTI—Subsea Technologies’ Historic Revenue Percentage of total

70%

65%

60% 2009 2010 2011

Source: Company data, Credit Suisse estimates. FTI’s subsea systems are regarded to be some the best, if not the best in the industry. Because of FTI’s expertise in manufacturing such high-end pieces of equipment, FTI often receives advance and progress payments from its customers in order to fund initial development and its working capital requirements. Many subsea systems are ordered one to two years prior to installation.

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FTI boosts having 47% market share of subsea system orders, which totaled $35.2 billion during 2007 to 2011. Cameron (CAM), FTI’s biggest competitor, secured 21% market share during the same time period, while GE Oil & Gas (GE) earned 15%, Aker Solutions (AKSO) had 10%, and Dril-Quip (DRQ) managed 7% share. Looking at subsea systems market share on a number of trees delivered basis, between 2007 and 2011, and FTI’s share falls to 41%, while CAM’s increases to 31%. GE, Aker, and Dril-Quip held market share positions of 14%, 12%, and 2%, respectively. From a manufacturing standpoint, we estimate overall subsea tree manufacturing capacity to be 775 trees per year (See Exhibit 105). Individually, FTI can produce approximately 350 subsea trees per year, whereas CAM can only produce approximately 195 trees according to our estimates. The ability to secure and retain highly skilled subsea engineers is the predominant reason why industry capacity is held at or around 775 trees. Please see the Risks section below for more information about employee retention. Looking Ahead The company expects total inbound orders to be between $4.0 - $5.0 billion in 2012. If one or two big project moves, this inbound order number could vary some and push into early- 2013. On July 5th, FTI won a $200 million subsea tree order with Statoil (STO.LN) to manufacture and supply subsea production equipment to support Statoil’s Gullfaks South field. Generally speaking subsea tree pricing is improving as industry backlogs have tightened considerably in recent months. Much has been made this year about a large competitor being very aggressive on price in the early part of 2012 but we are confident from a high level the competitive or technological landscape has not shifted in any way. According to an industry publication, major operators are beginning to publically state how subsea equipment manufacturers are lacking the technical personnel to deliver smaller, more challenging projects due to the industry’s current focus on mega-deepwater projects. We see the issue differently and would argue that for the first time in a number of years, operators are now having to court equipment suppliers/manufacturers in order to get into the manufacturing cycle. Such a change in dynamics is a another positive datapoint for subsea equipment pricing and thus CAM and FTI (as well as GE and Aker Solutions). The CLOV project is approximately 50% complete and while some risk remain many of the engineering and procurement risks have passed. The challenge now for FTI on the second 50% is making sure internal and external fabricated parts are delivered on time into FTI’s manufacturing plants in the East Region.

Oilfield Services 125 16 October 2012

Exhibit 104: 2012E Global Subsea Manufacturing Capacity

Dril‐Quip 4% Aker 10%

Vetco (GE) FMC Technologies 16% 45%

Cameron 25%

Theoretical Capacity: 775

Source: Company data, Quest Offshore, and Credit Suisse estimates. Deepwater Intervention FTI has three intervention vessels operating in the North Sea. Two vessels are contracted with Statoil, while the other is working of BP. FTI primarily competes with Island Offshore, a private Norwegian player, who also has three vessels. One built in 2004 and the others in 2008. Deepwater intervention work is definitely an area of growth potential for FTI and given its existing subsea tree installed base and frame agreements, FTI will have a tremendous advantage in wining intervention work from its peers. In order to further expand its intervention service offering, we could envision FTI looking to buy Superior Energy’s (SPN) Hallin Marine’s newbuild semi-submersible, the CSS Derwent, or its multi-purpose vessels (MPSVs) win moon-pools to execute deepwater well intervention. Exposure to Onshore Activity

Exposure to Hydraulic Fracturing Fluid control business designs and manufacturers flowline products, under the Weco® and Chiksan® trademarks, and pumps and valves used in well completion and stimulation activities by major oilfield services companies. FTI’s flowline products (i.e., fluid ends, pumps, frac arms, and manifolds) are used in/on equipment that pumps proppant and fracking fluids down into a well during the hydraulic fracturing process. FTI’s reciprocating pump product line includes Duplex, Triplex, and Quintuplex pumps. These pumps, fluid ends, pieces of treating iron compete directly against comparable products produced by Weir Oil & Gas (WEIR LN), Gardner Denver (GDI), Forum Energy Technologies (FET), and the vertically assembled operations of Halliburton (HAL). Surface Technologies designs and manufactures products and systems and provides services used by oil and gas companies involved in land and offshore exploration and production of crude oil and natural gas. FTI also designs, manufactures and supplies technologically advanced high pressure valves, pumps and fittings used in stimulation activities for oilfield service companies.

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Exhibit 105: FTI—Surface Technologies’ Historic Revenue Percentage of total 30%

25%

20%

15%

10%

5%

0% 2009 2010 2011

Source: Company data, Credit Suisse estimates.

Exhibit 106: FTI Articulating Frac Arm Manifold Trailer

Source: Company data. Given the rising horizontal rig count in North America and technological advances in hydraulic fracturing (pressure pumping) in recent years, the demand for heavier-duty pumps and fluid ends has grown tremendously. Increased demand has made it easier for private equity money to enter the market which led to excess capacity of equipment and parts in the market in later-2011 and early-2012, coupled with E&P companies focusing their drilling budgets to oil and liquids-rich wells, utilization of pressure pumping assets deteriorated drastically in late 1Q12 and 2Q12. FTI and its competitors are currently working down inventory levels and waiting for activity levels to stabilize. On August 20, 2012, FTI announced plans to acquire Pure Energy Services Ltd. (TSX: PSV) of Calgary for US$285 million); a 40% premium over the prior day’s closing price. Pure is a leading provider of frac flowback services and an established wireline services provider operating in both Canada and the United States. Pure employs approximately 1,300 employees—FTI’s existing North American surface division employees approximately 1,000 workers. FTI paid ~4.8x 2013 consensus EBITDA which is significantly less than its current 11x multiple, which is some concern in terms of valuation dilution.

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FTI’s CEO John Gremp stated that the Pure acquisition is consistent with [the company’s] strategy to grow shale related businesses…[and] expanding into flowback services which complements the existing products and services of [the company’s] Surface Technologies segment”, which is no real surprise considering everyone wants to chase shale exposure and it wasn’t a “top of the market” purchase. FMC plans to run (keep?) the existing wireline business but has no plans to invest or expand it. The frac flowback business, 55% of total revenues, is the strategic part and will be the main growth vehicle, to which, the company argues it can bundle with its existing frac rental tree and manifold business in the United States and expand it into Canada, where Pure generated 58% of its revenues. We expect FTI to allocate a fair amount of capital to Pure . Fluid control represents 12% of Surface Technologies’ 26% revenue contribution to all of FTI in 2011. Exposure to Surface Equipment FTI’s surface wellhead business is piece of the Surface Technologies segment, the other being fluid control. The surface wellhead business provides a full range of surface wellheads and production systems, or trees, for both standard and service critical service applications. FTI supports its customers through engineering, manufacturing, field installation, aftermarket services. In addition, the FTI’s integrated shale services include hydraulic fracturing manifolds and trees and flow back equipment. Surface wellheads represent 14% of Surface Technologies’ 26% revenue contribution to all of FTI in 2011. Exposure to FPSOs & Offshore Development FTI is very actively bidding on equipment onto the topsides of floating production, storage and offloading (FPSO) vessels, especially in Brazil. The company does not disclosure what the overall revenue opportunity is per FPSO because the company looks at the business opportunity on a business unit basis. That being said, FTI does provide production manifolds, meters, separation, loading, and offloading capabilities onto FPSOs. FTI’s largest competitor in the subsea space has historically said its revenue opportunity is $250 million per FPSO and that they have approximately $1 billion in bids outstanding—as a point of reference. Similarly, FTI is very competitive in FLNG because of its patented loading and offloading technologies. The company also won a contract for Shell’s Prelude project to utilize this technology. Exposure to Infrastructure FTI’s last and smallest business segment, Energy Infrastructure, consistently represents between 10% to 11% of total revenue since 2009. The segment provides various solutions and systems to the energy industry, such as, Measurement Solutions, Loading Systems, Material Handling Solutions, Blending and Transfer Systems, Separation Systems, and Direct Drive Systems (DDS). No one customer accounted for more than 10% of Energy Infrastructures revenue in the last several years.

Oilfield Services 128 16 October 2012 Market & Business Drivers The operating results of FTI’s core businesses are primarily driven by exploration and production spending levels of international and independent oil and gas companies, which simplistically are dictated by commodity prices. The Subsea Technologies business will be primarily affected by offshore oil and gas development trends, North American and international onshore drilling activity, and other energy infrastructure needs. Increasing Offshore & Subsea Development

As the oil and gas industry continues on its quest to discover hydrocarbons in more remote locations, the capital expenditures focused on subsea, deepwater equipment and fields is expected to increase to approximately $22 billion by 2017, according to Quest Offshore. (See Exhibit 107).

Exhibit 107: Subsea Tree Growth In-line with Deepwater Exploration Plans 900

800 767 5Yr. CAGR (2011 ‐ 2016E) = 20% 704 700 640 648 600 570 462 500 438 452 432 374 400 318 311 300

Number of Subsea Trees 200

100

0 2005 2006 2007 2008 2009 2010 2011 2012E 2013E 2014E 2015E 2016E

Source: Quest Offshore Resources, Inc. At the core of FTI’s Subsea Technologies segment is subsea Christmas trees (“tree” or “subsea tree”) and manifolds, which are vital in the offshore production of crude oil and natural gas. These systems are placed on the sea floor and control the flow of crude oil and natural gas from the reservoir to a host processing facility, such as a floating production facility (like a FPSO), a fixed platform or an onshore facility. FTI has a number market share in this business. In 2011, 311 subsea trees were awarded (see Exhibit 108), of which FTI received 53%, or 165 trees. According to industry source, Quest Offshore Resources (“Quest”), the number of subsea trees is expected to grow to 798 trees by 2016; representing a 21% compounded annual growth rate. Year-to-date, 279 subsea trees have been awarded and FTI has secured 37%. Quest estimates that 570 subsea trees will be awarded in 2012 and on the second quarter 2012 conference call, FTI CEO John Gremp expressed his optimism of seeing “almost $5 billion” in subsea inbound orders in 2012 if certain large orders the company is tracking hit. To this end, FTI publishes a major subsea project opportunity list in each of its quarterly investor presentations—currently FTI foresees 435 subsea trees that it has a good chance of winning in the next fifteen months. We estimate through a number of other sources and channel checks that there are close to 606 subsea tree awards that could be awarded over the next fifteen to eighteen months, spread between FTI, CAM, GE, Aker, and DRQ. (See Exhibit 109.)

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Exhibit 108: Worldwide Subsea Capex (2012E–2017E) $25,000 900 $MM ‐ subsea production umbilicals installed

$MM ‐ subsea manifolds 800

$20,000 $MM ‐ tree control pkg (flying leads, jumper, MCS, HPU, UTA, J‐Plate) 700 $MM ‐ subsea trees & control pod: (chokes, sensor pkg.)

No. subsea trees (well completions) by onstream year 600 Startups

$15,000 Km ‐ subsea production umbilicals installed $MM

500 Tree

or

SPU 400 Subsea

of

$10,000 of

KM 300

200 Number $5,000

100

$0 0 2004 2005 2006 2007 2008 2009 2010 2011 2012e 2013e 2014e 2015e 2016e 2017e Startup Year

Source: Quest Offshore Resources, Inc. Furthermore, the increasing number of offshore/deepwater drilling rigs coming into the market will enable FTI’s key customers the ability to expand their capacity to develop subsea hydrocarbon deposits around the world. We view the increasing number of potential reservoir discoveries as leading indicator for subsea equipment manufacturers like FTI. Credit Suisse’s offshore drilling analyst Gregory Lewis estimates that the total number of offshore drilling rigs, jackups, and semi-submersible rigs could total 953 by 2015; split, 152 drillships, 565 jackups, and 236 semis-submersibles.

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Exhibit 109: Upcoming Major Subsea Projects ($150mm+)

Source: Company data as of June 30, 2012. While FTI sees major subsea projects calling for approximately 435 trees, we estimate there to be 606 trees.

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Exhibit 110: Credit Suisse’s Estimate of Major Subsea Projects # of Project/Field Name Country Operator Likely Supplier Timing Status Trees

Upcoming Projects Panyu 34‐1/35‐1/35‐2GoM (USA) CNOOC 6 FTI, CAM Pending Block 15/06 Angola ENI 10 GE Bidding Mad Dog South GoM (USA) BP 33 FTI Bidding Erha North Phase 2 Nigeria ExxonMobil 10 CAM, Aker, FTI 3Q12 Pending Egina Nigeria Total 48 Aker, CAM, FTI 4Q12 Bidding Azeri Subsea Azerbaijan BP 6 FTI, CAM Bidding T.E.N. (Tweneboa) Ghana Tullow 16 FTI 4Q12 Bidding Lucapa Angola Chevron 18 All Bidding Block 31 Phase 2 Angola BP 40 CAM 3Q12 Letter of Intent Chissonga (Block 16) Angola Maersk 44 All 1Q12 Bidding Greater Plutonio Infill (Block 18) Angola BP 10 FTI, CAM Bidding Linnorm Norway Shell 6 FTI Bidding Kraken U.K. Enquest 24 FTI Bidding Rosebank U.K. Chevron 14 FTI 2013 Sunrise Australia Woodside 12 FTI Bidding Appomattox GoM (USA) Shell 14 FTI Bidding Aasta Hansteen (Luva) Norway Statoil 8 Aker, FTI Bidding Hadrian North GoM (USA) ExxonMobil 16 All Bidding Julia GoM ExxonMobil 10 FTI Bidding Gendalo / Gehem Indonesia Chevron 18 All Bidding Beaufort Sea Amauligak Canada ConocoPhillips 10 Bidding PONY GoM Hess 14 FTI Bidding Lukoil Ghana Ghana Lukoil 20 FTI Bidding Agbami Phase 2 Nigeria Cheveron 26 2Q12 Bidding Vito GoM Shell 14 FTI Bidding R‐Series/Satellites India Reliance 21 FTI Bidding Block 32 Angola Total 64 FTI 2013 Bidding Kizomba Satellites Phase 2 Angola ExxonMobil 16 CAM, GE, Aker 2Q12 Bidding Moho North Phase 2 Congo Total 17 2Q12 Bidding North Alex Phase 1 Egypt BP 18 CAM 3Q12 Bidding WDDM Phase Ixb Egypt BG 12 CAM 4Q12 FEED Western Hub Angola ENI 11 ALL 1Q12 Bidding Potential Total by YE2012 606 Source: Quest Offshore Resources, Inc., Company data, and Credit Suisse estimates. Orders & Backlog

FTI ended the second quarter of 2012 with total inbound orders in the quarter of $1.4 billion and a company-wide backlog of $5.2 billion. Subsea orders totaled $878.2 million and Subsea Technologies backlog stood at $4.3 billion. Directionally since the lows of 2008, subsea inbound orders have been trending in the right direction and now leaves FTI’s subsea systems’ book-to-bill at 0.9x.

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Exhibit 111: FTI—Subsea Inbound Orders and Subsea Book-to-Bill $2,500 3.5x

3.0x $2,000 2.5x

$1,500 2.0x

1.5x $1,000

1.0x $500 0.5x

$0 0.0x

Source: Company data, Credit Suisse estimates. Mounting Well & Service Intensity As demonstrated by the increasing percentage of horizontal wells being drilled in the United States (see Exhibit 112), the overall well and service intensity per well is increasing dramatically. The U.S. horizontal rig count now represents approximately 60% of the total U.S. rig count, and we estimate that this will likely become the new norm.

Exhibit 112: U.S. Horizontal Rig Count

100%

90%

80%

70%

60%

50%

40%

30%

20%

10%

0%

% Gas % Oil % Horizontal

Source: Baker Hughes. This shift to more horizontal drilling of oil and liquids-rich wells is driving demand for more high pressure, high temperature (HPHT) pieces of oilfield equipment such as surface wellheads and fluid control equipment, such as fluid ends, frac arms, frac manifolds, treating iron, and aftermarket services. The latter are sold under the trademarks Weco™ and Chiksan™. Both brands are highly correlated to pressure pumping market dynamics (capacity levels, utilization, well intensity, and fracs per stage). With the addition of Pure Energy Services in August, FTI will begin delivering frac flowback units and service, along with, wireline services. However, given the declining drilling activity levels in North America and the weakening pricing environment we expect FTI’s fluid end businesses, Weco and Chiksan, to decline approximately 25% in the second-half of 2012 from first-half levels as customers continue destocking fluid end inventories and delay replacement purchases.

Oilfield Services 133 16 October 2012 FMC Over the Years Pure Energy Services Limited August 20, 2012 - FTI announced plans to acquire Pure Energy Services Ltd. (TSX: PSV) of Calgary for C$11.00 per share in cash, or approximately C$282 million ($285 million); a 40% premium over the prior day’s closing price. Pure is a leading provider of frac flowback services and an established wireline services provider operating in multiple field locations in both Canada and the United States. Pure employs approximately 1,300 employees. FTI paid approximately 4.8x 2013 consensus EBITDA of C$58.5 million. Given the composition of Pure’s business, this multiple does not seem overly expensive but is much less than the subsea/deepwater premium multiple FTI has historically commanded. FTI’s CEO John Gremp stated that the Pure acquisition is consistent with [the company’s] strategy to grow shale related businesses…[and] expanding into flowback services which complements the existing products and services of [the company’s] Surface Technologies segment. In further conversations with FTI management, we learned that the company plans to run the existing wireline business but has no plans to invest or expand on it. The frac flowback business will be FTI’s main growth vehicle, to which, the company argues it can bundle with its existing frac rental tree and manifold business in the United States. Pure’s investor presentation, dated June 2012, states that Pure has 127 frac flowback units and 84 wireline units. In 2011, 55% of Pure’s total revenue came from Frac Flowback services, while the remaining 45% came from Wireline. Geographically, 58% of 2011’s revenue was derived from Canada. Schilling Robotics, LLC April 25, 2012 - FTI closed the acquisition of the remaining 55.0% interest in Schilling Robotics, LLC., a joint venture between FTI and Schilling. Schilling is a leading a supplier of advanced robotic intervention products, including a line of remotely operated vehicle systems (ROVs), manipulator systems and subsea control systems. The acquisition of the remaining interests in Schilling will give FTI the ability to growing in the subsea space, where demand for ROVs and the need for maintenance activities of subsea equipment is expected to increase. The cost of the remaining portion of Schilling cost FTI $281.4 million. Recall, FTI invested $121.3 million in 2008 for 45.0% share in Schilling. Upon the closing of this transaction, FTI will own 100.0% of Schilling which is included among the consolidated subsidiaries reported in the Subsea Technologies segment. Control Systems International, Inc. April 30, 2012 - FTI acquired Control Systems International for $486.7million (includes cash of $331.8 million). Control Systems will be included in FTI’s Energy Infrastructure segment and enhance FTI’s automation and controls technologies. Direct Drive Systems, Inc. October 2009 - FTI acquired California-based Direct Drive Systems, Inc. (DDS), a leader in the development and manufacture of high-performance permanent magnet motors and bearings for the oil and gas industry for $120.2 million, net of cash acquired. Multiphase Meters AS October 2009 - FTI acquired Norway-based Multi-Phase Meters AS (MPM) a leader in the development and manufacture of high-performance multiphase flow meters, to further enhance and expand the company’s portfolio of subsea technologies for $32.4 million, net of cash acquired. FoodTech and Airport Systems

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July 31, 2008- FTI spun-off its FoodTech and Airport Systems business, which are now known as John Bean Technologies Corporation (NYSE: JBT), through a tax-free dividend to shareholders of 0.216 share of JBT common stock for every share of FTI stock outstanding as of the close of business on July 22, 2008. John Bean Technologies Corporation is a technology solutions provider to the food processing and air transportation industries. The company designs, manufactures, tests and services systems and products for global industrial food processing customers through its FoodTech segment and for domestic and international air transportation customers through its AreoTech segment. Management Team John T. Gremp (Chairman & Chief Executive Officer) Mr. Gremp is chairman and chief executive officer for FMC Technologies, Inc. Prior to assuming these duties in 2011, Mr. Gremp served as Chief Operating Officer of the company since 2010 and executive vice president of Energy Systems since 2007. Mr. Gremp served as vice president of Energy Production Systems in 2004 after serving as general manager of Energy Production Systems. Mr. Gremp’ s leadership expertise stems from management positions held throughout his more than 30 years with the company including general manager of Fluid Control Division in 1995 and as general manager of the Asia Pacific and Middle East region during the early 1990s. He also has held various plant, operations and regional manager positions since joining the company in Chicago as a financial analyst in 1975. Mr. Gremp earned his bachelor’s degree in business from Lewis and Clark College and an MBA from the University of California in Berkeley. He serves on the board of directors of Joy Global, the Petroleum Equipment Suppliers Association, API, and the Offshore Technology Conference. Maryann T. Seaman (Senior Vice President & Chief Financial Officer) Ms. Seaman is senior vice president and chief financial officer for FMC Technologies. Ms. Seaman became senior vice president and chief financial officer in December of 2011. She was previously appointed vice president and deputy chief financial officer in April 2010. She was treasurer through November 2011. She held the position of vice president of administration from 2007 through 2010 and was responsible for Human Resources, Executive Compensation, Health, Safety and Environment and Corporate Communications. She also served as the Secretary to the Compensation and the Nominating and Governance Committees of the board of directors. In 2005, Ms. Seaman became responsible for Corporate Communications in addition to holding the position of director of Investor Relations and Corporate Development, which she held since 2003. Before joining FMC Corporation in 1986, Ms. Seaman served as finance manager for Sheller-Globe Corporation. She received a bachelor’s degree in accounting and an MBA from Rider University in Lawrenceville, New Jersey. Robert L. “Rob” Potter (President)

Mr. Potter is president of FMC Technologies, Inc. Prior to assuming this role in August 2012, Mr. Potter served as executive vice president of Energy Systems since April 2010. Mr. Potter had also served as senior vice president of Energy Processing and Global Surface Wellhead at FMC Technologies, Inc., since 2007, and vice president of Energy Processing beginning in 2001. Mr. Potter joined FMC Technologies in 1973 as a sales representative for the Wellhead Equipment Division and held several sales management positions over the years. Mr. Potter is a graduate of Rice University with a bachelor’s degree in commerce. He serves on the executive committee for the Petroleum Equipment Suppliers Association, is a member of the board of directors of the National Ocean Industries Association and is a

Oilfield Services 135 16 October 2012 member of the American Petroleum Institute. Mr. Potter also serves on the advisory board of Spindletop Charities. Douglas J. Pferdehirt (Executive Vice President & Chief Operating Officer)

Mr. Pferdehirt is executive vice president and chief operating officer for FMC Technologies. Mr. Pferdehirt was named to the position on August 1, 2012, and is responsible for all three of the company’s operating business segments. Mr. Pferdehirt has an extensive background in the oil and gas industry. Before joining FMC Technologies, he worked for Schlumberger Limited (SLB) for 26 years in a number of leadership positions, including executive vice president of Corporate Development and Communication, and president of the Schlumberger Reservoir Production Group. Tore Halvorsen (Senior Vice President, Subsea Technologies)

Mr. Halvorsen is the senior vice president of Subsea Technologies at FMC Technologies, Inc. Previously, Mr. Halvorsen was the senior vice president of Global Subsea Production Systems since 2007. Prior to this, he served as vice president, Subsea Production Systems with responsibility for Europe, Africa, Canada, and Asia Pacific. He served as managing director of FMC Kongsberg Subsea AS in 1994 following his promotion to director of Subsea Systems when FMC Technologies purchased Kongsberg Offshore in 1993. Mr. Halvorsen joined Kongsberg Offshore AS in 1980 as Technical Manager, Subsea Systems. Mr. Halvorsen received a master’s degree in mechanical engineering in 1980 from the Norwegian Institute of Technology in Trondheim, Norway. Johan Pfeiffer (Vice President, Surface Technologies)

Johan Pfeiffer is vice president of Surface Technologies for FMC Technologies Inc. Prior to assuming this role in January of 2012, Mr. Pfeiffer was vice president of Global Surface Wellhead since June 2010. Before his role as vice president, Mr. Pfeiffer was general manager for Subsea activities in Europe, Africa, and the Common Wealth of Independent States (CIS), as well as managing director of FMC Kongsberg Subsea AS since 2007. He joined the company in 1993 as a business analyst in Philadelphia. Mr. Pfeiffer is a graduate of the Swiss Institute of Technology where he received a degree in Material Sciences. In 1993, Johan earned a master’s degree in International Studies from the University of Pennsylvania’s Lauder Institute and an MBA from the University of Pennsylvania’s Wharton School. He is a member of the board and a district chairman for the Petroleum Equipment Suppliers Association. He is also on the board of directors of the Awty International School in Houston and a member of the executive leadership team of the American Heart Association. Barry Glickman (Vice President, Energy Infrastructure)

Barry Glickman is vice president of Energy Infrastructure for FMC Technologies, Inc. Mr. Glickman joined FMC Technologies in January 2012. Before joining FMC, Mr. Glickman held a number of senior level leadership positions at GE and Dresser, Inc., including Integration Leader for the Wood Group Well Support Acquisition at GE Oil and Gas, president for Dresser Flow Technologies, president for Dresser Waukesha, CEO for GE Jenbacher and was also general manager for GE Distributed Power. Prior to joining GE, Mr. Glickman was a consultant at McKinsey & Co., where he specialized in strategy and operations for U.S. energy companies. Mr. Glickman received his MBA in finance and accounting from the University of Pennsylvania’s Wharton School. He received a BA in economics/political science from the University of California at Berkeley.

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Executive Compensation FTI’s executive compensation is divided into short and long term, where some elements are fixed, while others are variable. The long term portion is greater in weight, all equity based, restricted stock only (no options anymore) with two-thirds being performance based. 2007 was the last year FTI awarded stock options (ten year life). The last third is time based and has cliff vesting. Performance is based on total shareholder return from December to December, return on investment (debt and equity), and EBITDA growth versus eleven industry peers. The short term component of compensation is 50% equity, 50% cash, and 30% personal objectives. Employees FTI has approximately 16,000 employees globally. Within Subsea Technologies there are approximately 9,000 employees—2,000 of which were added in 2011. FTI has and is continuing to add skill labor in 2012, especially within Subsea. The company prides itself on training the best subsea engineers and given the demand outlook for subsea trees over the next five years, FTI is hiring and training staff now in order to meet future demand requirements. Retention of key and highly skilled and trained employees has always been a risk for FTI and will continue to be (See Investment Risks below). As an example Brazilian turnover rates were tremendously high two years ago, today they are less than 5%.

Oilfield Services 137 16 October 2012 Financials Forecasts & Key Assumptions We are modeling revenue growth in 2012 of 22% to $6.2 billion, and then revenue growth of 11% in 2013 to $6.9 billion, driven mainly by the Subsea Technology segment. Our total company EBIT margin estimates are 13.2% in 2012 and 14.2% in 2013 versus 12.1% in 2011, as we model Subsea Technology margins to improve through year-end and into 2013 as better pricing equipment hits the P&L. Our EPS forecasts are $2.09 in 2012 and $2.64 in 2013, and our EBITDA forecasts are $836 million in 2012 and $1.03 billion in 2013. Balance Sheet/Liquidity During the third quarter, FTI issued $800 million of senior unsecured notes composed of $300 million, 2.00% senior notes due in 2017 and $500 million, 3.45% senior notes due in 2022. These are very attractive rates for FTI, which is rated BBB. To put the 2017 notes in better perspective, Schlumberger (SLB) for example, which is rated A+, issued $500 million in senior unsecured 2017 notes at 1.25% in late-July. FTI intends to use the net proceeds from the senior note offering to repay outstanding commercial paper obligations issued in the second quarter and other indebtedness under its current revolving credit facility. FTI's long-term debt balance at the end of the second quarter equaled $1.14 billion and we expect this amount to moderate from current levels over the next several quarters. Valuation The company continues to generate superior returns which is the primary reason for the premium valuation. Our valuation metrics compares the economic value, return on capital minus the weighted cost of capital, to the Enterprise Value to EBITDA multiple. The risk over time to FTI’s stock price is that acquisitions and new business growth could still be justified as well above the company’s cost of capital but below the current returns, diluting the premium multiple derived. We expect that management weighs incremental dollars rather than just overall margins and growth is a stated goal. Our price target of $49 for FTI is based on our forecasted return on capital less the calculated weighted cost of capital, correlated with the historical regression with a 0.82 r-square and multiplied times our forecasted EBITDA. Our price target is a 12-month price target. We are concerned that the attainment of our price target may be more back-end weighted than linear due to historical seasonality of the rig count and stock prices. While not as effected by the current rig count as most OFS companies, sentiment for the group is an issue so we do expect the stock to outperform on a relative basis near-term. Comparables We believe FTI’s best comparable group consists of Cameron International Corporation (CAM), National Oilwell Varco (NOV), Gardner Denver (GDI), General Electric (GE), Weir Oil & Gas (WEIR LN), Forum Energy Technologies (FET), Oceaneering (OII), and Oil States International (OIS), given the products manufactured, customers serviced, and geographic end markets. Currently, shares of FTI are trading at 16.6x and 11.2x 2013 earnings per shares (EPS) and EBITDA estimates, respectively. On an EBITDA-basis, shares of FTI are trading at a 30% premium/discount to the peer group on 2013 numbers, while against earnings shares are trading at a 40% premium to the same peer group.

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Exhibit 113: FTI Comparables

(US$ in millions, except per share data) Stock Price Market Enterprise EBIT DA EV / EBIT DA EPS P / EPS Company Ticker Rating TP $ 10/15/12 Shares Value Value 2012E 2013E 2012E 2013E 2012E 2013E 2012E 2013E

Cameron International Corp. CAM Outperform $75 $53.22 248 $13,183 $13,358 $1,383 $1,739 9.7x 7.7x $3.29 $4.36 16.2x 12.2x Forum Energy Technologies FET Restricted - $22.70 90 $2,038 ------Gardner Denver Inc. GDI Outperform $65 $57.55 49 $2,818 $3,067 $419 $445 7.3x 6.9x $5.39 $5.58 10.7x 10.3x General Electric Co. GE Outperform $25 $22.48 10,559 $237,363 $533,932 $27,480 $30,319 19.4x 17.6x $1.54 $1.75 14.6x 12.8x National Oilwell Varco NOV NR - $78.22 427 $33,363 $32,997 $4,428 $5,082 7.5x 6.5x $5.97 $6.92 13.1x 11.3x Oceaneering International OII NR - $51.75 109 $5,623 $5,623 $594 $698 9.5x 8.1x $2.65 $3.23 19.6x 16.0x Oil States International OIS NR - $73.37 55 $4,054 $5,066 $919 $948 5.5x 5.3x $8.10 $8.22 9.1x 8.9x Weir Group WEIR LN Outperform GBP 1,850 GBP 1,729 2 GBP 3,674 GBP 4,519 GBP 519 GBP 527 8.7x 8.6x GBP 146 GBP 148 11.8x 11.7x

Mean 9.7x 8.7x 13.6x 11.9x Median 8.7x 7.7x 13.1x 11.7x High 19.4x 17.6x 19.6x 16.0x Low 5.5x 5.3x 9.1x 8.9x

FMC Technologies, Inc. FTI Neutral $49 $44.02 242 $10,631 $11,572 $836 $1,027 13.8x 11.3x $2.09 $2.64 21.1x 16.7x Premium/(Discount) to Peer Group Average 43% 30% 56% 40% Source: Bloomberg, Company data, and Credit Suisse estimates. Risks Product and Service Demand Is Dependent on Oil and Gas Industry Activity and Capital Spending Levels FTI is substantially dependent on conditions in the oil and gas industry, including the level of exploration, development and production activity, and the corresponding capital spending levels of major oil and natural gas companies. Any substantial or extended decline in these expenditures by FTI’s large customers could result in reduced discovery and development of new oil and gas reserves and the reduced exploitation of existing wells, which could adversely affect demand for the company’s systems and services and, in certain instances, result in the cancellation, modification or rescheduling of existing orders. These factors could have an adverse effect on the company’s revenue and profitability. Overall, the level of exploration, development and production activity is directly affected by trends in oil and natural gas prices, which, historically, have been volatile. Highly Engineered Products Could Prove to Be Faulty or Work Incorrectly, Which Could Materially Impact the Company’s Go-Forward Business Because of the highly engineered nature of the equipment FTI manufactures, there is the possibility that the equipment could have defects, malfunctions and failures, be misused or be altered by a natural disaster, which could result in the uncontrollable flows of natural gas and crude oil. To protect against such cases, FTI has implemented numerous checks and balances in the manufacturing process but also obtained insurance against any and all of these risks. Fixed-Price Contracts Exposure As is customary for the types of business in which FTI operates, the company often agrees to provide products and services under fixed-price contracts. Therefore, FTI is responsible for cost overruns, which could result from unforeseen technical and logistical challenges, longer than expected lead times, and/or rising raw material prices. Variations thus could materially impact the company’s operating results. Sources and Availability of Raw Materials FTI’s business segments purchase carbon steel, stainless steel, aluminum and steel castings and forgings both domestically and internationally. The company does not use a single source supplier for the majority of its raw material purchases to alleviate risks. FTI believes the available supplies of raw materials are adequate to meet its current needs. Frame Agreements—A Double-Edge Sword As noted above, FTI enters into large, long-term contracts, or ‘frame agreements’ with its key customers which collectively provides FTI with a great amount of revenue visibility but also present a risk if a relationship is damaged or lost. For example, FTI has a frame agreement with Statoil, from which it generated approximately 12% of its revenue in 2011.

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These agreements, if terminated or breached, may have a larger impact on FTI’s operating results or financial condition than shorter-term contracts due to the value at risk. If FTI were to lose several key alliances or agreements over a relatively short period of time the company could experience a significant adverse impact on its financial condition, results of operations or cash flows. Key Employee Retention FTI depends heavily on its senior executive officers and other key personnel (subsea engineers). The loss of any of these officers or key employees could adversely impact the company’s business if we are unable to implement key strategies or transactions in their absence. In addition, competition for qualified employees from peer companies that rely heavily on engineering and technology is intense. The loss of qualified employees or an inability to attract, retain and motivate additional highly-skilled employees required for the operation and expansion of its business could hinder FTI’s ability to conduct research activities successfully and develop marketable products and services. Approximately, 3% of FTI’s U.S. employees are represented by labor unions.

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Baker Hughes Inc. BHI Price (12 Oct 12): US$44.77, Rating: NEUTRAL [V], Target Price: US$40.00 Income statement (US$ m) 12/11A 12/12E 12/13E 12/14E Per share data 12/11A 12/12E 12/13E 12/14E Sales revenue 19,831 21,444 22,361 — No. of shares (wtd avg) 438 440 440 — EBITDA 4,302 4,121 4,594 — CS adj. EPS (US$) 4.20 3.57 3.91 Depr. & amort. (1,321) (1,555) (1,766) — Prev. EPS (US$) — — — — EBIT (CS) 2,985 2,566 2,827 — Dividend (US$) 0.60 0.59 0.59 — Net interest exp. (221) (256) (200) — Dividend payout ratio 14.18 16.60 15.11 — Associates — — — — Free cash flow per share (2.18) (3.91) 0.25 Other adj, (4) — — — PBT (CS) 2,760 2,310 2,627 — Key ratios and 12/11A 12/12E 12/13E 12/14E Income taxes (919) (737) (906) — valuation Profit after tax 1,841 1,573 1,721 — Growth(%) Minorities — — — — Sales 37.6 8.1 4.3 — Preferred dividends — — — — EBIT 89.3 (14.0) 10.2 (100.0) Associates & other — — — — Net profit 98.6 (14.6) 9.4 (100.0) Net profit (CS) 1,841 1,573 1,721 — EPS 78.9 (14.9) 9.4 — Other NPAT adjustments (102) — — — Margins (%) Reported net income 1,739 1,573 1,721 — EBITDA margin 21.7 19.2 20.5 — EBIT margin 15.1 12.0 12.6 — Cash flow (US$) 12/11A 12/12E 12/13E 12/14E Pretax margin 13.9 10.8 11.7 — EBIT 2,985 2,5662,827 — Net margin 9.3 7.3 7.7 — Net interest (221) (256) (200) — Valuation metrics (x) Cash taxes paid — — — — EV/sales 1.1 1.1 1.0 — Change in working capital (1,433) (1,697) (655) — EV/EBITDA 5.6 5.8 5.2 — Other cash & non-cash items 176 468 938 — EV/EBIT 7.6 9.1 7.9 — Cash flow from operations 1,507 1,081 2,911 — P/E 10.7 12.5 11.4 — CAPEX (2,461) (2,800)(2,800) — P/B 1.2 1.1 1.0 — Free cash flow to the firm (954) (1,719) 111 — Asset turnover 0.80 0.78 0.77 — Acquisitions — — — — ROE analysis (%) Divestments 306 203 — — ROE stated-return on 11.3 9.2 9.1 — Other investment/(outflows) 264 — — — ROIC 10.5 7.8 8.0 — Cash flow from investments (1,891) (2,597) (2,800) — Interest burden 0.92 0.90 0.93 — Net share issue/(repurchase) — — — — Tax rate 33.3 31.9 34.5 — Dividends paid (261) (261) (260) — Financial leverage 0.25 0.28 0.19 — Issuance (retirement) of debt 183 39 — — Credit ratios (%) Other (386) 1,012 1,191 2,702 Net debt/equity 18.9 20.0 13.3 — Cash flow from financing (464) 790 931 2,702 Net debt/EBITDA 0.70 0.91 0.59 — Effect of exchange rates 8 2 — — Interest coverage ratio 13.5 10.0 14.1 — Changes in Net Cash/Debt (840) (724) 1,042 2,702 Net debt at start 2,179 3,019 3,743 2,702 Quarterly data 12/11A 12/12E 12/13E 12/14E Change in net debt 840 724 (1,042) (2,702) EPS for Q1 0.87 0.86 — — Net debt at end 3,019 3,743 2,702 — EPS for Q2 0.93 1.00 — — EPS for Q3 1.18 0.82 — — Balance sheet (US$ m) 12/11A 12/12E 12/13E 12/14E EPS for Q4 1.22 0.89 — — Assets Cash and cash equivalents 1,050 1,289 1,139 — Accounts receivable 4,878 5,137 5,587 — Source: Company data, Credit Suisse estimates. Inventory 3,222 3,770 4,096 — Other current assets 647 865 865 — Total current assets 9,797 11,061 11,688 — Total fixed assets 7,415 8,657 9,691 — Daily Oct 13, 2011 - Oct 12, 2012, 10/13/11 = U Intangible assets and goodwill 7,099 7,033 7,033 — Investment securities — — — — 60 Other assets 536 597 597 — 40 Total assets 24,847 27,348 29,008 — Liabilities 20 Accounts payable 1,810 1,938 2,060 — Short-term debt 224 1,191 — — 0 Other short term liabilities 1,468 321 1,390 — Oct-11 Jan-12 Apr-12 Jul-12 Total current liabilities 3,502 3,450 3,450 — Price Indexed S&P 500 IN Long-term debt 3,845 3,841 3,841 — Other liabilities 1,536 1,351 1,351 —

Total liabilities 8,883 8,6428,642 — On 10/12/12 the S&P 500 INDEX closed at 1432.84 Shareholders' equity 15,746 18,706 20,366 — Minority interest 218 — — — Total equity & liabilities 24,847 27,348 29,008 — Net debt (US$ m) 3,019 3,743 2,702 —

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Halliburton HAL Price (11 Oct 12): US$33.97, Rating: OUTPERFORM, Target Price: US$44.00 Income statement (US$ m) 12/11A 12/12E 12/13E 12/14E Per share data 12/11A 12/12E 12/13E 12/14E Sales revenue 24,479 28,691 31,609 — No. of shares (wtd avg) 921 926 926 — EBITDA 6,195 6,134 6,728 — CS adj. EPS (US$) 3.35 3.04 3.12 Depr. & amort. (1,359) (1,663) (1,984) — Prev. EPS (US$) — — — — EBIT (CS) 4,836 4,471 4,744 — Dividend (US$) — — — — Net interest exp. (263) (313) (316) — Dividend payout ratio — — — — Associates — — — — Free cash flow per share 0.79 (0.25) 0.63 Other adj, (25) (24) (25) — PBT (CS) 4,548 4,133 4,403 — Key ratios and 12/11A 12/12E 12/13E 12/14E Income taxes (1,458) (1,287) (1,452) — valuation Profit after tax 3,090 2,846 2,951 — Growth(%) Minorities (5) (35)(56) — Sales 36.2 17.2 10.2 — Preferred dividends — — — — EBIT 58.1 (7.6) 6.1 (100.0) Associates & other (246) (206) — — Net profit 54.6 (8.2) 11.1 (100.0) Net profit (CS) 2,839 2,605 2,895 — EPS 61.8 (9.3) 2.9 — Other NPAT adjustments 246 206 — — Margins (%) Reported net income 3,085 2,811 2,895 — EBITDA margin 25.3 21.4 21.3 — EBIT margin 19.8 15.6 15.0 — Cash flow (US$) 12/11A 12/12E 12/13E 12/14E Pretax margin 18.6 14.4 13.9 — EBIT 4,836 4,4714,744 — Net margin 11.6 9.1 9.2 — Net interest (263) (313) (316) — Valuation metrics (x) Cash taxes paid — — — — EV/sales 1.4 1.2 1.1 — Change in working capital (649) (1,152) (1,290) — EV/EBITDA 5.5 5.5 5.0 — Other cash & non-cash items (240) 416 448 — EV/EBIT 7.0 7.6 7.1 — Cash flow from operations 3,684 3,421 3,586 — P/E 10.1 11.2 10.9 — CAPEX (2,953) (3,651)(3,000) — P/B 1.8 1.6 1.4 — Free cash flow to the firm 731 (230) 586 — Asset turnover 1.0 1.1 1.0 — Acquisitions (880) — — — ROE analysis (%) Divestments — — — — ROE stated-return on 20.1 15.0 13.7 — Other investment/(outflows) 643 292 — — ROIC 21.4 17.2 15.7 — Cash flow from investments (3,190) (3,359) (3,000) — Interest burden 0.94 0.92 0.93 — Net share issue/(repurchase) 117 — — — Tax rate 32.1 31.1 33.0 — Dividends paid (330) (334) (333) — Financial leverage 0.27 0.24 0.22 — Issuance (retirement) of debt 978 — — — Credit ratios (%) Other (928) 99 — 2,044 Net debt/equity 16.1 14.7 11.2 — Cash flow from financing (163) (235) (333) 2,044 Net debt/EBITDA 0.34 0.37 0.30 — Effect of exchange rates (27) (2) — — Interest coverage ratio 18.4 14.3 15.0 — Changes in Net Cash/Debt 304 (175) 253 2,044 Net debt at start 2,426 2,122 2,297 2,044 Quarterly data 12/11A 12/12E 12/13E 12/14E Change in net debt (304) 175 (253) (2,044) EPS for Q1 0.61 0.89 0.63 — Net debt at end 2,122 2,297 2,044 — EPS for Q2 0.80 0.80 0.75 — EPS for Q3 0.94 0.65 0.83 — Balance sheet (US$ m) 12/11A 12/12E 12/13E 12/14E EPS for Q4 1.00 0.69 0.92 — Assets Cash and cash equivalents 2,698 2,523 2,776 — Accounts receivable 5,084 5,562 6,592 — Source: Company data, Credit Suisse estimates. Inventory 2,570 3,273 3,884 — Other current assets 1,225 1,691 1,691 — Total current assets 11,577 13,050 14,943 — Total fixed assets 8,492 10,491 11,507 — Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = US$35.02 Intangible assets and goodwill 1,776 1,986 1,986 — Investment securities — — — — 41 Other assets 1,832 1,552 1,972 — Total assets 23,677 27,079 30,408 — 36 Liabilities 31 Accounts payable 1,826 2,215 2,565 — Short-term debt — — — — 26 Other short term liabilities 2,295 2,658 3,079 — Oct-11 Jan-12 Apr-12 Jul-12 Total current liabilities 4,121 4,873 5,644 — Price Indexed S&P 500 INDEX Long-term debt 4,820 4,820 4,820 — Other liabilities 1,520 1,750 1,750 —

Total liabilities 10,461 11,44312,214 — On 10/03/12 the S&P 500 INDEX closed at 1432.84 Shareholders' equity 13,198 15,636 18,195 — Minority interest — — — — Total equity & liabilities 23,659 27,079 30,409 — Net debt (US$ m) 2,122 2,297 2,044 —

Oilfield Services 142 16 October 2012

Schlumberger SLB Price (11 Oct 12): US$72.42, Rating: NEUTRAL, Target Price: US$66.00 Income statement (US$ m) 12/11A 12/12E 12/13E 12/14E Per share data 12/11A 12/12E 12/13E 12/14E Sales revenue 39,540 42,344 44,279 — No. of shares (wtd avg) 1,361 1,340 1,339 — EBITDA 10,098 11,188 12,101 — CS adj. EPS (US$) 3.65 4.19 4.58 Depr. & amort. (3,280) (3,487) (3,620) — Prev. EPS (US$) — — — — EBIT (CS) 6,818 7,701 8,481 — Dividend (US$) — — — — Net interest exp. (254) (285) (240) — Dividend payout ratio — — — — Associates — — — — Free cash flow per share 1.58 1.54 4.04 Other adj, — — — — PBT (CS) 6,564 7,416 8,241 — Key ratios and 12/11A 12/12E 12/13E 12/14E Income taxes (1,577) (1,775) (2,060) — valuation Profit after tax 4,987 5,641 6,180 — Growth(%) Minorities (16) (24)(45) — Sales 18.1 7.1 4.6 — Preferred dividends — — — — EBIT 36.4 13.0 10.1 (100.0) Associates & other — — — — Net profit 34.0 13.0 9.2 (100.0) Net profit (CS) 4,971 5,617 6,135 — EPS 35.9 14.8 9.3 — Other NPAT adjustments (193) 8 — — Margins (%) Reported net income 4,778 5,625 6,135 — EBITDA margin 25.5 26.4 27.3 — EBIT margin 17.2 18.2 19.2 — Cash flow (US$) 12/11A 12/12E 12/13E 12/14E Pretax margin 16.6 17.5 18.6 — EBIT 6,818 7,7018,481 — Net margin 12.6 13.3 13.9 — Net interest (254) (285) (240) — Valuation metrics (x) Cash taxes paid — — — — EV/sales 2.6 2.4 2.2 — Change in working capital (2,045) (2,417) (793) — EV/EBITDA 10.0 9.0 8.3 — Other cash & non-cash items 1,650 1,561 1,560 — EV/EBIT 14.8 13.1 11.5 — Cash flow from operations 6,169 6,560 9,007 — P/E 19.8 17.3 15.8 — CAPEX (4,016) (4,501)(3,600) — P/B 3.1 2.8 2.4 — Free cash flow to the firm 2,153 2,059 5,407 — Asset turnover 0.72 0.71 0.70 — Acquisitions — — — — ROE analysis (%) Divestments — — — — ROE stated-return on 15.2 16.9 16.4 — Other investment/(outflows) 106 155 — — ROIC 14.3 14.6 15.5 — Cash flow from investments (3,910) (4,346) (3,600) — Interest burden 0.96 0.96 0.97 — Net share issue/(repurchase) (2,545) (576) — — Tax rate 24.0 23.9 25.0 — Dividends paid (1,300) (1,437) (1,473) — Financial leverage 0.31 0.30 0.24 — Issuance (retirement) of debt 1,892 538 (1,000) — Credit ratios (%) Other (2,720) (1,865) 1,000 1,133 Net debt/equity 15.2 14.4 2.8 — Cash flow from financing (4,673) (3,340) (1,473) 1,133 Net debt/EBITDA 0.47 0.45 0.09 — Effect of exchange rates — — — — Interest coverage ratio 26.8 27.0 35.3 — Changes in Net Cash/Debt (2,029) (297) 3,934 1,133 Net debt at start 2,741 4,770 5,067 1,133 Quarterly data 12/11A 12/12E 12/13E 12/14E Change in net debt 2,029 297 (3,934) (1,133) EPS for Q1 0.71 0.98 — — Net debt at end 4,770 5,067 1,133 — EPS for Q2 0.87 1.05 — — EPS for Q3 0.98 1.05 — — Balance sheet (US$ m) 12/11A 12/12E 12/13E 12/14E EPS for Q4 1.11 1.11 — — Assets Cash and cash equivalents 4,827 5,407 8,341 — Accounts receivable 9,500 10,303 11,372 — Source: Company data, Credit Suisse estimates. Inventory 4,700 5,022 5,371 — Other current assets 1,512 1,983 1,983 — Total current assets 20,539 22,715 27,067 — Total fixed assets 12,993 14,328 14,308 — Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = U Intangible assets and goodwill 19,036 19,520 19,520 — Investment securities — — — — 79 Other assets 2,633 2,764 2,764 — 74 Total assets 55,201 59,327 63,659 — 69 Liabilities Accounts payable 7,579 7,578 8,203 — 64 Short-term debt 1,041 2,521 2,521 — 59 Other short term liabilities 1,918 1,583 1,583 — Oct-11 Jan-12 Apr-12 Jul-12 Total current liabilities 10,538 11,682 12,307 — Price Indexed S&P 500 IN Long-term debt 8,556 7,953 6,953 — Other liabilities 4,715 4,567 4,567 —

Total liabilities 23,809 24,20223,827 — On 10/03/12 the S&P 500 INDEX closed at 1432.84 Shareholders' equity 31,392 35,125 39,832 — Minority interest — — — — Total equity & liabilities 55,201 59,327 63,659 — Net debt (US$ m) 4,770 5,067 1,133 —

Oilfield Services 143 16 October 2012

Weatherford International, Inc. WFT Price (11 Oct 12): US$12.31, Rating: NEUTRAL [V], Target Price: US$11.00 Income statement (US$ m) 12/11A 12/12E 12/13E 12/14E Per share data 12/11A 12/12E 12/13E 12/14E Sales revenue 12,990 15,482 16,256 — No. of shares (wtd avg) 760 768 768 — EBITDA 2,479 2,910 3,221 — CS adj. EPS (US$) 0.80 0.93 1.18 Depr. & amort. (1,137) (1,189) (1,316) — Prev. EPS (US$) — — — — EBIT (CS) 1,465 1,830 2,036 — Dividend (US$) — — — — Net interest exp. (454) (474) (480) — Dividend payout ratio — — — — Associates — — — — Free cash flow per share (0.91) (1.26) 0.55 Other adj, (107) (80) (80) — PBT (CS) 904 1,277 1,476 — Key ratios and 12/11A 12/12E 12/13E 12/14E Income taxes (280) (460) (517) — valuation Profit after tax 624 817 960 — Growth(%) Minorities (16) (31)(55) — Sales 27.1 19.2 5.0 — Preferred dividends — — — — EBIT 55.2 24.9 11.2 (100.0) Associates & other — — — — Net profit 391.8 29.3 15.0 (100.0) Net profit (CS) 608 786 905 — EPS 381.1 16.3 26.4 — Other NPAT adjustments (346) (215) — — Margins (%) Reported net income 262 572 905 — EBITDA margin 19.1 18.8 19.8 — EBIT margin 11.3 11.8 12.5 — Cash flow (US$) 12/11A 12/12E 12/13E 12/14E Pretax margin 7.0 8.2 9.1 — EBIT 1,465 1,8302,036 — Net margin 4.7 5.1 5.6 — Net interest (454) (474) (480) — Valuation metrics (x) Cash taxes paid — — — — EV/sales 1.3 1.1 1.1 — Change in working capital (891) (655) 150 — EV/EBITDA 6.8 5.8 5.2 — Other cash & non-cash items 713 397 665 — EV/EBIT 11.3 9.7 8.5 — Cash flow from operations 833 1,099 2,370 — P/E 15.4 13.2 10.5 — CAPEX (1,524) (2,067)(1,951) — P/B 0.98 0.94 0.86 — Free cash flow to the firm (691) (969) 420 — Asset turnover 0.61 0.67 0.67 — Acquisitions (166) (156) — — ROE analysis (%) Divestments — — — — ROE stated-return on 2.8 5.8 8.6 — Other investment/(outflows) 16 2 — — ROIC 6.0 6.3 7.0 — Cash flow from investments (1,674) (2,221) (1,951) — Interest burden 0.62 0.70 0.73 — Net share issue/(repurchase) — 65 — — Tax rate 30.9 36.0 35.0 — Dividends paid — — — — Financial leverage 0.80 0.85 0.78 — Issuance (retirement) of debt 798 926 — — Credit ratios (%) Other (843) (987) — 7,933 Net debt/equity 75.7 82.6 72.0 — Cash flow from financing (45) 4 — 7,933 Net debt/EBITDA 2.9 2.9 2.5 — Effect of exchange rates — 1 — — Interest coverage ratio 3.2 3.9 4.2 — Changes in Net Cash/Debt (886) (1,118) 420 7,933 Net debt at start 6,349 7,235 8,353 7,933 Quarterly data 12/11A 12/12E 12/13E 12/14E Change in net debt 886 1,118 (420) (7,933) EPS for Q1 0.08 0.25 0.23 — Net debt at end 7,235 8,353 7,933 — EPS for Q2 0.14 0.16 0.25 — EPS for Q3 0.26 0.22 0.31 — Balance sheet (US$ m) 12/11A 12/12E 12/13E 12/14E EPS for Q4 0.30 0.30 0.39 — Assets Cash and cash equivalents 371 221 641 — Accounts receivable 3,235 3,888 4,025 — Source: Company data, Credit Suisse estimates. Inventory 3,158 3,303 3,303 — Other current assets 819 1,053 1,053 — Total current assets 7,583 8,465 9,022 — Total fixed assets 7,283 8,101 8,735 — Daily Oct 13, 2011 - Oct 11, 2012, 10/13/11 = U Intangible assets and goodwill 5,133 5,245 5,245 — 19 Investment securities — — — — Other assets 1,186 1,382 1,095 — 17 Total assets 21,185 23,193 24,097 — 15 Liabilities 13 Accounts payable 1,567 1,832 2,119 — Short-term debt 1,320 1,263 1,263 — 11 Other short term liabilities 1,326 1,328 1,041 — Oct-11 Jan-12 Apr-12 Jul-12 Total current liabilities 4,213 4,423 4,423 — Price Indexed S&P 500 IN Long-term debt 6,286 7,311 7,311 — Other liabilities 1,133 1,351 1,351 —

Total liabilities 11,632 13,08513,085 — On 10/12/12 the S&P 500 INDEX closed at 1432.84 Shareholders' equity 9,532 10,087 10,991 — Minority interest 21 21 21 — Total equity & liabilities 21,185 23,193 24,097 — Net debt (US$ m) 7,235 8,353 7,933 —

Oilfield Services 144 16 October 2012

Cameron International Corp. CAM Price (11 Oct 12): US$54.09, Rating: OUTPERFORM, Target Price: US$75.00 Income statement (US$ m) 12/11A 12/12E 12/13E 12/14E Per share data 12/11A 12/12E 12/13E 12/14E Sales revenue 7,000 8,221 9,162 — No. of shares (wtd avg) 249 248 247 — EBITDA 1,166 1,383 1,739 — CS adj. EPS (US$) 2.84 3.29 4.36 Depr. & amort. (207) (251) (270) — Prev. EPS (US$) — — — — EBIT (CS) 959 1,130 1,469 — Dividend (US$) — — — — Net interest exp. (84) (88) (86) — Dividend payout ratio — — — — Associates — — — — Free cash flow per share 0.36 1.60 Other adj, — 2 — — PBT (CS) 875 1,044 1,383 — Key ratios and 12/11A 12/12E 12/13E 12/14E Income taxes (167) (229) (304) — valuation Profit after tax 708 814 1,079 — Growth(%) Minorities — — — — Sales 14.1 17.4 11.4 — Preferred dividends — — — — EBIT 11.8 17.8 30.0 (100.0) Associates & other — — — — Net profit 18.3 15.1 32.5 (100.0) Net profit (CS) 708 814 1,079 — EPS 17.6 15.7 32.7 — Other NPAT adjustments (185) (15) — — Margins (%) Reported net income 522 800 1,079 — EBITDA margin 16.7 16.8 19.0 — EBIT margin 13.7 13.7 16.0 — Cash flow (US$) 12/11A 12/12E 12/13E 12/14E Pretax margin 12.5 12.7 15.1 — EBIT 959 1,1301,469 — Net margin 10.1 9.9 11.8 — Net interest (84) (88) (86) — Valuation metrics (x) Cash taxes paid — — — — EV/sales 1.9 1.7 1.4 — Change in working capital (535) (525) — — EV/EBITDA 12.1 10.2 8.1 — Other cash & non-cash items (132) 61 (34) — EV/EBIT 14.2 12.2 8.7 — Cash flow from operations 208 578 1,348 — P/E 19.0 16.5 12.4 — CAPEX (118) (182)(1,348) — P/B 2.9 2.4 2.0 — Free cash flow to the firm 91 396 — — Asset turnover 0.75 0.78 0.79 — Acquisitions — — — — ROE analysis (%) Divestments — 22 — — ROE stated-return on 11.5 15.6 17.8 — Other investment/(outflows) (825) (310) — — ROIC 15.6 14.7 18.9 — Cash flow from investments (1,213) (789) (300) — Interest burden 0.91 0.92 0.94 — Net share issue/(repurchase) 19 (5) — — Tax rate 19.1 22.0 22.0 — Dividends paid — — — — Financial leverage 0.34 0.36 0.30 — Issuance (retirement) of debt 46 (45) — — Credit ratios (%) Other 158 39 — (557) Net debt/equity 5.6 8.9 (8.4) — Cash flow from financing 222 (11) — (557) Net debt/EBITDA 0.23 0.36 (0.32) — Effect of exchange rates (20) (6) — — Interest coverage ratio 11.4 12.9 17.1 — Changes in Net Cash/Debt (802) (229) 1,048 (557) Net debt at start (540) 262 491 (557) Quarterly data 12/11A 12/12E 12/13E 12/14E Change in net debt 802 229 (1,048) 557 EPS for Q1 0.64 0.57 0.99 — Net debt at end 262 491 (557) — EPS for Q2 0.66 0.74 1.08 — EPS for Q3 0.78 0.90 1.12 — Balance sheet (US$ m) 12/11A 12/12E 12/13E 12/14E EPS for Q4 0.77 1.08 1.17 — Assets Cash and cash equivalents 1,322 1,497 2,545 — Accounts receivable 1,757 1,824 1,824 — Source: Company data, Credit Suisse estimates. Inventory 2,400 2,650 2,650 — Other current assets 349 359 359 — Total current assets 5,829 6,330 7,378 — Total fixed assets 1,500 1,806 1,836 — Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = U Intangible assets and goodwill 1,615 1,967 1,967 — 58 Investment securities — — — — Other assets 418 428 428 — 53 Total assets 9,362 10,531 11,609 — 48 Liabilities Accounts payable 2,670 2,621 2,621 — 43 Short-term debt — — — — 38 Other short term liabilities 11 22 22 — Oct-11 Jan-12 Apr-12 Jul-12 Total current liabilities 2,680 2,643 2,643 — Price Indexed S&P 500 IN Long-term debt 1,574 1,966 1,966 — Other liabilities 400 395 395 —

Total liabilities 4,654 5,0045,004 — On 10/03/12 the S&P 500 INDEX closed at 1432.84 Shareholders' equity 4,707 5,527 6,605 — Minority interest — — — — Total equity & liabilities 9,362 10,531 11,609 — Net debt (US$ m) 262 491 (557) —

Oilfield Services 145 16 October 2012

FMC Technologies, Inc. FTI Price (11 Oct 12): US$44.18, Rating: NEUTRAL, Target Price: US$49.00 Income statement (US$ m) 12/10A 12/11E 12/12E 12/13E Per share data 12/10A 12/11E 12/12E 12/13E Sales revenue 4,126 5,099 6,212 6,916 No. of shares (wtd avg) 245 243 241 242 EBITDA 637 657 836 1,027 CS adj. EPS (US$) 1.50 1.58 2.09 2.64 Depr. & amort. (101) (108) (139) (151) Prev. EPS (US$) — — — — EBIT (CS) 534 567 696 859 Dividend (US$) — — — — Net interest exp. (9) (8) (23) (26) Dividend payout ratio — — — — Associates — — — — Free cash flow per share (0.07) (0.10) (0.07) Other adj, 1 (18) 1 16 PBT (CS) 527 541 674 850 Key ratios and 12/10A 12/11E 12/12E 12/13E Income taxes (160) (157) (170) (212) valuation Profit after tax 367 384 504 637 Growth(%) Minorities — — — — Sales — 23.6 21.8 11.3 Preferred dividends — — — — EBIT (470.3) 6.0 22.9 23.4 Associates & other — — — — Net profit (218.2) 4.7 31.1 26.6 Net profit (CS) 367 384 504 637 EPS 221.1 5.6 31.9 26.5 Other NPAT adjustments — 9 — — Margins (%) Reported net income 367 393 504 637 EBITDA margin 15.4 12.9 13.5 14.8 EBIT margin 13.0 11.1 11.2 12.4 Cash flow (US$) 12/10A 12/11E 12/12E 12/13E Pretax margin 12.8 10.6 10.8 12.3 EBIT 534 567696 859 Net margin 8.9 7.5 8.1 9.2 Net interest (9) (8) (23) (26) Valuation metrics (x) Cash taxes paid — — — — EV/sales 2.6 2.1 1.9 1.7 Change in working capital (457) (389) (739) (587) EV/EBITDA 16.6 16.1 12.7 10.3 Other cash & non-cash items 127 (5) 60 (45) EV/EBIT 19.8 19.1 16.6 13.5 Cash flow from operations 195 165 (6) 201 P/E 29.5 27.9 21.2 16.7 CAPEX (212) (189)(10) (201) P/B 8.2 7.5 5.6 4.2 Free cash flow to the firm (17) (25) (16) — Asset turnover 1.1 1.2 1.1 1.1 Acquisitions — — — — ROE analysis (%) Divestments — — — — ROE stated-return on 30.2 28.5 30.1 28.6 Other investment/(outflows) 3 0 (327) — ROIC 27.2 23.4 17.7 17.8 Cash flow from investments (109) (274) (677) (250) Interest burden 0.99 0.95 0.97 0.99 Net share issue/(repurchase) (162) (113) (21) — Tax rate 30.3 29.0 25.3 25.0 Dividends paid — — — — Financial leverage 0.27 0.43 0.64 0.48 Issuance (retirement) of debt (20) 1 69 — Credit ratios (%) Other 8 (7) (112) — Net debt/equity 3.6 19.4 53.8 42.3 Cash flow from financing (174) (119) (64) — Net debt/EBITDA 0.1 0.4 1.2 1.0 Effect of exchange rates (0) (4) 0 — Interest coverage ratio 60.7 69.1 30.7 33.6 Changes in Net Cash/Debt (88) (232) (747) (49) Net debt at start (41) 48 280 1,026 Quarterly data 12/10A 12/11E 12/12E 12/13E Change in net debt 88 232 747 49 EPS for Q1 0.39 0.31 0.41 0.56 Net debt at end 48 280 1,026 1,075 EPS for Q2 0.38 0.38 0.46 0.65 EPS for Q3 0.32 0.49 0.57 0.67 Balance sheet (US$ m) 12/10A 12/11E 12/12E 12/13E EPS for Q4 0.40 0.40 0.64 0.76 Assets Cash and cash equivalents 316 344 190 141 Accounts receivable 1,103 1,342 1,759 1,993 Source: Company data, Credit Suisse estimates. Inventory 567 712 990 1,203 Other current assets 360 390 402 402 Total current assets 2,345 2,788 3,341 3,739 Total fixed assets 609 768 1,160 1,259 Daily Oct 13, 2011 - Oct 03, 2012, 10/13/11 = U Intangible assets and goodwill 415 394 808 808 Investment securities — — — — 52 Other assets 275 321 170 418 Total assets 3,644 4,271 5,478 6,224 47 Liabilities 42 Accounts payable 344 547 543 683 Short-term debt 12 588 102 102 37 Other short term liabilities 1,139 1,099 1,192 1,192 Oct-11 Jan-12 Apr-12 Jul-12 Total current liabilities 1,495 2,233 1,837 1,977 Price Indexed S&P 500 IN Long-term debt 351 36 1,114 1,114 Other liabilities 475 564 621 589

Total liabilities 2,322 2,833 3,572 3,680 On 10/03/12 the S&P 500 INDEX closed at 1432.84 Shareholders' equity 1,322 1,438 1,906 2,543 Minority interest — — — — Total equity & liabilities 3,644 4,271 5,478 6,224 Net debt (US$ m) 48 280 1,026 1,075

Oilfield Services 146 16 October 2012

Companies Mentioned (Price as of 12 Oct 12) Baker Hughes, Inc. (BHI, $44.65, NEUTRAL, TP $40.00) Cameron International Corp. (CAM, $54.09, OUTPERFORM, TP $75.00) Devon Energy Corp. (DVN, $61.61, OUTPERFORM, TP $78.00) FMC Technologies, Inc. (FTI, $44.18, NEUTRAL, TP $49.00) Forum Energy Technologies, Inc. (FET, $22.82, RESTRICTED [V]) General Electric (GE, $22.51, OUTPERFORM, TP $25.00) Halliburton (HAL, $33.97, OUTPERFORM, TP $44.00) National Oilwell Varco (NOV, $78.22) Schlumberger (SLB, $72.42, NEUTRAL, TP $66.00) Weatherford International, Inc. (WFT, $12.31, NEUTRAL, TP $11.00)

Disclosure Appendix Important Global Disclosures I, James Wicklund, certify that (1) the views expressed in this report accurately reflect my personal views about all of the subject companies and securities and (2) no part of my compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report. See the Companies Mentioned section for full company names. 3-Year Price, Target Price and Rating Change History Chart for BHI BHI Closing Target 93 Price Price Initiation/ 90 88 Date (US$) (US$) Rating Assumption 85 1/27/10 47.6 55 80 77 3/3/10 50 58 75 76 O 8/4/10 42.83 46 65 66 10/25/10 46.58 49 62 11/1/10 48.37 55 58 55 55 55 56 1/11/11 57.76 66 54 1/27/11 66.67 76 49 45 46 4/8/11 71.57 88 O NC 4/27/11 77.28 90 US$35 7/13/11 74.83 93 11/2/11 55.13 80 12/19/11 44.93 77 1/25/12 48.16 62 Closing Price Target Price Initiation/Assumption Rating 3/23/12 43.71 56 O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered 4/27/12 42.91 54 5/30/12 42.57 NC

Oilfield Services 147 16 October 2012

3-Year Price, Target Price and Rating Change History Chart for CAM CAM Closing Target Price Price Initiation/ 73 74 71 71 Date (US$) (US$) Rating Assumption 69 66 11/3/09 38.38 44 12/23/09 42.09 45 61 60 58 2/10/10 39.25 48 56 O 8/4/10 38.98 47 51 11/5/10 46.13 49 48 49 46 47 NC 2/3/11 56.99 58 44 45 4/28/11 52.17 60 41 8/1/11 54.88 73 O 36 9/12/11 49.3 74 US$31 10/28/11 51.78 71 2/3/12 55.83 69 5/30/12 46.45 NC Closing Price Target Price Initiation/Assumption Rating

O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered

3-Year Price, Target Price and Rating Change History Chart for FTI FTI Closing Target

Price Price Initiation/ 53 Date (US$) (US$) Rating Assumption 48 49 49 10/29/09 27.795 27 47 47 2/18/10 27.395 28.5 45 45 43 4/30/10 33.845 32.5 42 NC 7/27/10 29.99 34.5 38 10/6/10 34.85 35 36 35 35 11/5/10 39.03 36 33 33 11/24/10 42.13 42 28 29 2/16/11 45.58 45 27 4/28/11 45.96 47 US$23 7/27/11 44.61 49 10/27/11 47.17 45 2/17/12 51.38 49 4/25/12 47.09 47 Closing Price Target Price Initiation/Assumption Rating 5/30/12 41.15 NC O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered

3-Year Price, Target Price and Rating Change History Chart for HAL HAL Closing Target 66 Price Price Initiation/ 66 62 63 63 Date (US$) (US$) Rating Assumption 61 60 5958 59 58 12/31/09 30.09 36 56 54 1/26/10 30.88 41 51 50 3/3/10 31.7 43 46 45 46 4/20/10 33.31 42 43 41 41 42 7/20/10 30.27 45 10/25/10 34.28 50 36 36 1/11/11 39.38 59 31 NC 1/27/11 43.17 58 26 4/8/11 48.13 60 US$21 4/19/11 49.01 62 7/13/11 52.62 63 7/18/11 53.12 66 9/23/11 31.67 63 Closing Price Target Price Initiation/Assumption Rating 10/18/11 35.29 59 O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered 12/19/11 30.8 58 1/24/12 36.36 54 4/19/12 33.98 46 5/30/12 30.36 NC

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3-Year Price, Target Price and Rating Change History Chart for SLB SLB Closing Target 117 Price Price Initiation/ 111 Date (US$) (US$) Rating Assumption 110 110

10/26/09 64.3 72 101 100 98 99 11/22/09 64.63 76 O 92 1/25/10 65.81 80 91 86 3/3/10 63.23 79 83 83 81 80 80 79 78 4/26/10 72.69 86 76 7/26/10 58.85 80 7172 9/7/10 57.13 78 O NC 10/25/10 68.53 83 61 1/11/11 82.26 98 US$51 1/27/11 85.98 100 4/8/11 90.85 110 7/25/11 94.7 117 10/4/11 59.11 110 Closing Price Target Price Initiation/Assumption Rating 10/24/11 69.88 99 O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered 1/23/12 74.16 92 4/23/12 71.19 83 5/30/12 64.18 NC

3-Year Price, Target Price and Rating Change History Chart for WFT WFT Closing Target Price Price Initiation/ 27 27 Date (US$) (US$) Rating Assumption 25 25 25 10/20/09 20.06 23 24 23 23 11/23/09 16.3 21 22 3/3/10 17.07 20 21 21 21 20 20 20 7/12/10 14.27 18 19 19 7/20/10 15.56 19 18 17 N 17 10/25/10 17.09 20 N 1/11/11 22.74 27 15 13 3/3/11 21.28 24 NC 4/8/11 21.8 25 US$11 7/13/11 18.72 23 7/27/11 22.05 25 10/26/11 15.28 22 12/19/11 13 20 Closing Price Target Price Initiation/Assumption Rating 2/22/12 16.39 21 O=Outperform; N=Neutral; U=Underperform; R=Restricted; NR=Not Rated; NC=Not Covered 4/27/12 14.53 17 5/30/12 12.54 NC

The analyst(s) responsible for preparing this research report received compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities. As of October, 2 2012 Analysts’ stock rating are defined as follows: Outperform (O): The stock’s total return is expected to outperform the relevant benchmark* by at least 10-15% or more, (depending on perceived risk) over the next 12 months. Neutral (N): The stock’s total return is expected to be in line with the relevant benchmark* (range of ±10-15%) over the next 12 months. Underperform (U): The stock’s total return is expected to underperform the relevant benchmark* by 10-15% or more over the next 12 months. *Relevant benchmark by region: As of 2nd October 2012, U.S. and Canadian as well as European ratings are based on a stock’s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. For Latin American, Japanese, and non-Japan Asia stocks, ratings are based on a stock’s total return relative to the average total return of the relevant country or regional benchmark; Australia, New Zealand are, and prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock’s absolute total return potential to its current share price and (2) the relative attractiveness of a stock’s total return potential within an analyst’s coverage universe. For Australian and New Zealand stocks, 12-month rolling yield is incorporated in the absolute total return calculation and a 15% and a 7.5% threshold replace the 10- 15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholds replace the +10-15% and -10- 15% levels in the Neutral stock rating definition, respectively. Restricted (R): In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other circumstances. Volatility Indicator [V]: A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward.

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Analysts’ sector weightings are distinct from analysts’ stock ratings and are based on the analyst’s expectations for the fundamentals and/or valuation of the sector* relative to the group’s historic fundamentals and/or valuation: Overweight: The analyst’s expectation for the sector’s fundamentals and/or valuation is favorable over the next 12 months. Market Weight: The analyst’s expectation for the sector’s fundamentals and/or valuation is neutral over the next 12 months. Underweight: The analyst’s expectation for the sector’s fundamentals and/or valuation is cautious over the next 12 months. *An analyst’s coverage sector consists of all companies covered by the analyst within the relevant sector. An analyst may cover multiple sectors. Credit Suisse’s distribution of stock ratings (and banking clients) is: Global Ratings Distribution Outperform/Buy* 44% (53% banking clients) Neutral/Hold* 39% (48% banking clients) Underperform/Sell* 14% (43% banking clients) Restricted 2% *For purposes of the NYSE and NASD ratings distribution disclosure requirements, our stock ratings of Outperform, Neutral, and Underperform most closely correspond to Buy, Hold, and Sell, respectively; however, the meanings are not the same, as our stock ratings are determined on a relative basis. (Please refer to definitions above.) An investor's decision to buy or sell a security should be based on investment objectives, current holdings, and other individual factors. Credit Suisse’s policy is to update research reports as it deems appropriate, based on developments with the subject company, the sector or the market that may have a material impact on the research views or opinions stated herein. Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to Credit Suisse's Policies for Managing Conflicts of Interest in connection with Investment Research: http://www.csfb.com/research-and-analytics/disclaimer/managing_conflicts_disclaimer.html Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannot be used, by any taxpayer for the purposes of avoiding any penalties. See the Companies Mentioned section for full company names. Price Target: (12 months) for (BHI) Method: Our 12-month target price of $40 per share is based on 4.8x our 2013 EBITDA estimate. Hhistorical EBITDA multiple ranges from 3.3x to 13.0 since 2003. Risks: Risks to our $40 target price for BHI include infrastructure development requirements domestically and in countries in which BHI is expanding and execution of more multi-product, and therefore more complicated, programs. Price Target: (12 months) for (CAM) Method: Our 12-month target price of $75 per share for CAM is based on 11.2x our 2013 EBITDA estimate. CAM's historical EBITDA multiple ranges from 4.1x to 16.3x since 2003. Risks: Risks to our $75 target price for CAM include are a slowdown in the pace of subsea development and aftermarket requirement, rising costs, and a slowdown in North American land frac rental market. General risks include (1) gas and oil prices (2) non accretive or ill-timed acquisitions (3) loss of customers (4) environmental and government regulations (5) geopolitical risks. Price Target: (12 months) for (FTI) Method: Our 12-month target price of $49 per share for FTI is based on 12.4x our 2013 EBITDA estimate. FTI's historical EBITDA multiple ranges from 5.2x to 19.0x since 2003. Risks: Risks to our $49 target price for FTI include slowdown in development pace of subsea development, further strengthening of the U.S. dollar, competitive pressure on pricing, and pressure pumping equipment demand. General risks include (1) gas and oil prices (2) non accretive or ill-timed acquisitions (3) loss of customers (4) environmental and government regulations (5) geopolitical risks. Price Target: (12 months) for (HAL) Method: Our 12-month target price of $44 per share for HAL is based on 6.5x our 2013 EBITDA estimate. HAL's historical EBITDA multiple ranges from 5.5x to 14.4x since 2003. Risks: Risks to our $44 target price for HAL are over-build of hydraulic fracturing capacity, inability to sell a greater concentration of services internationally, increased competition in key product lines, and ongoing financial settlements of the 2010 Macondo well disaster. General risks include (1) gas and oil prices (2) non accretive or ill-timed acquisitions (3) loss of customers (4) environmental and government regulations (5) geopolitical risks. Price Target: (12 months) for (SLB) Method: Our 12-month target price of $66 per share for SLB is based on 7.9x our 2013 EBITDA estimate. SLB's historical EBITDA multiple ranges from 5.8x to 17.3x since 2003. Risks: Risks to our $66 target price for SLB are relative performance perhaps particularly stemming from Integrated Project Management results; international onshore sluggishness due to the uncertain oil demand outlook, and demand for seismic data. General risks include (1) gas and oil prices (2) non accretive or ill-timed acquisitions (3) loss of customers (4) environmental and government regulations (5) geopolitical risks. Price Target: (12 months) for (WFT) Method: Our 12-month target price of $11 per share for WFT is based on 5.1x our 2013 EBITDA estimate. WFT's historical EBITDA multiple ranges from 5.0x to 14.7x since 2003. Risks: Risks to our $11 target price for WFT include are Foreign Corrupt Practices Act (FCPA) investigation outcome, internal financial controls, and the pace of recovery and/or growth in various large markets including Mexico, Algeria, and Iraq. General risks include (1) gas and oil prices (2) non accretive or ill-timed acquisitions (3) loss of customers (4) environmental and government regulations (5) geopolitical risks.

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Please refer to the firm's disclosure website at www.credit-suisse.com/researchdisclosures for the definitions of abbreviations typically used in the target price method and risk sections.

See the Companies Mentioned section for full company names. The subject company (BHI, CAM, FTI, HAL) currently is, or was during the 12-month period preceding the date of distribution of this report, a client of Credit Suisse. Credit Suisse provided investment banking services to the subject company (BHI, CAM, FTI, HAL) within the past 12 months. Credit Suisse provided non-investment banking services, which may include Sales and Trading services, to the subject company (BHI, HAL) within the past 12 months. Credit Suisse has managed or co-managed a public offering of securities for the subject company (HAL) within the past 12 months. Credit Suisse has received investment banking related compensation from the subject company (CAM, HAL) within the past 12 months. Credit Suisse expects to receive or intends to seek investment banking related compensation from the subject company (BHI, CAM, FTI, HAL, SLB) within the next 3 months. 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Oilfield Services 152 16 October 2012 Americas / United States Equity Research

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