oge 0914 close 09-04-14autos & auto parts: europe banking: europe food retail: europe foods...

Please see General Disclaimers on the last page of this report.

Current Environment ............................................................................................ 1

Industry Profile .................................................................................................... 20

Industry Trends ................................................................................................... 21

How the Industry Operates ............................................................................... 33

Key Industry Ratios and Statistics ................................................................... 37

How to Analyze an Oil & Gas Equipment & Services Company ................. 39

Glossary ................................................................................................................ 43

Industry References ........................................................................................... 48

Comparative Company Analysis ...................................................................... 51

This issue updates the one dated March 2014.

Industry Surveys Oil & Gas: Equipment & Services Stewart Glickman, CFA, Energy Sector Equity Analyst

SEPTEMBER 2014

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Global Industry Surveys

Airlines: Asia

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S&P CAPITAL IQ INDUSTRY SURVEYS (ISSN 0196-4666) is published weekly. Redistribution or reproduction in whole or in part (including inputting into a computer) is prohibited without written permission. To learn more about Industry Surveys and the S&P Capital IQ product offering, please contact our Product Specialist team at 1-877-219-1247 or visit getmarketscope.com. Executive and Editorial Office: S&P Capital IQ, 55 Water Street, New York, NY 10041. Officers of McGraw Hill Financial: Douglas L. Peterson, President, and CEO; Jack F. Callahan, Jr., Executive Vice President, Chief Financial Officer; John Berisford, Executive Vice President, Human Resources; D. Edward Smyth, Executive Vice President, Corporate Affairs; Charles L. Teschner, Jr., Executive Vice President, Global Strategy; and Kenneth M. Vittor, Executive Vice President and General Counsel. Information has been obtained by S&P Capital IQ INDUSTRY SURVEYS from sources believed to be reliable. However, because of the possibility of human or mechanical error by our sources, INDUSTRY SURVEYS, or others, INDUSTRY SURVEYS does not guarantee the accuracy, adequacy, or completeness of any information and is not responsible for any errors or omissions or for the results obtained from the use of such information. Copyright © 2014 Standard & Poor's Financial Services LLC, a part of McGraw Hill Financial. All rights reserved. STANDARD & POOR’S, S&P, S&P 500, S&P MIDCAP 400, S&P SMALLCAP 600, and S&P EUROPE 350 are registered trademarks of Standard & Poor’s Financial Services LLC. S&P CAPITAL IQ is a trademark of Standard & Poor’s Financial Services LLC.

INDUSTRY SURVEYS OIL & GAS: EQUIPMENT & SERVICES / SEPTEMBER 2014 1

CURRENT ENVIRONMENT

Iraqi conflicts loom large

Iraq: northern Iraq much less meaningful to export supply than southern Iraq Southern Iraq produces about 75% of the nation’s oil. According to a Bloomberg article on June 18, 2014, exports from the south of Iraq are expected to accelerate even though fighting continues in the north. Government forces battled fighters from the Islamic State and the Levant for control of the Baiji refinery in northern Iraq in June, while southern Iraq remained calm. The only infrastructure producing and supplying international markets is in the south, and according to the article, new monthly records are being set as Iraq is increasing production and export capacity. The start of a third tanker-loading point in June helped rising exports in the south, in contrast with the situation for Kirkuk crude—a light grade from the northern field—which has not been exported since March 2014, when sabotage damaged a pipeline to the Ceyhan port in Turkey. Repair work stopped in June when fighting started. According to the article, strife would hurt the investment climate of Iraq, as well as slow the pace of oil production and export growth, even though the south is safe from attacks.

Iraq is the second-largest producer of crude oil in the Organization of the Petroleum Exporting Countries (OPEC)—playing a key role as its production gains help to offset losses in supply from Libya. Iraq is targeting production of 8.4 million barrels per day (mb/d) after 2018. In June 2014, the International Energy Agency (IEA), an autonomous international agency that coordinates energy policies among its member countries, forecast that capacity would increase by 1.3 mb/d through 2019. Output surged to 3.4 mb/d in February 2014, the highest level since 2000.

Iraq part 2: Kurds try to sell their own oil, relationship between Baghdad and Kurdistan deteriorates Iraq’s central government in Baghdad has been disputing with the Kurdistan Regional Government (KRG), the official ruling body of a federated region in northern Iraq, over oil revenue and territory. Tensions increased when the Kurds started exporting crude to Turkey through a separate pipeline without approval from the central government.

In May 2014, a tanker loaded a cargo of Kurdish crude from the Turkish port of Ceyhan—Kurdistan’s first attempt to sell crude oil, despite strong opposition from Baghdad. In June, three more tankers of Kurdish oil were loaded from Ceyhan, and on July 31, the fifth cargo of one million barrels was loaded. One of the first four cargoes of Kurdish crude loaded from Ceyhan was offloaded at the Israeli port of Ashkelon, while the other three remain anchored at sea.

Among the five vessels, the United Kalavrvta is the most high profile, holding one million barrels of Kurdish crude, but it remains anchored 60 miles off the port of Galveston, Texas as of August 1. The Iraqi central government warned all lightering companies in Galveston not to offload the crude, or face legal consequences. Baghdad claims authority over all sales of crude originating within its borders, while the KRG insists on its right to sell all oil produced from its fields. However, no buyers for any of the cargoes have stepped forward yet. According to the Energy Information Administration (EIA), an autonomous international agency that attempts to coordinate energy policies among its member countries, the KRG plans to export 1.0 mb/d of crude oil by 2015 and 2.0 mb/d by 2019.

LESS CONCERN OVER MACRO ISSUES

Macroeconomic factors—such as the sluggish US economy, slowly recovering European economies, and a slowdown in growth in emerging markets—influence crude oil demand. While China, India, and other emerging markets are seeing a slowdown in growth, the developed markets are expected to improve gradually. On the supply front are concerns about Middle East politics, especially at a time when oil services companies are ramping up investment in the region. The OPEC, which is dominated by Middle Eastern countries, seems to be divided over how to handle the difficult problem of oil production in the face of

2 OIL & GAS: EQUIPMENT & SERVICES / SEPTEMBER 2014 INDUSTRY SURVEYS

sanctions against Iran by the US and the European Union (EU). In January 2014, however, the Western powers and Iran signed an interim agreement (discussed below) that should lead to increasing supplies from that country. Possible changes to offshore drilling or fracking regulations being considered in the US may also affect the supply of oil. In addition, a greater emphasis on North American shale oil allows the industry players to alter their levels of production more quickly by changing the number of operating rigs based on crude oil prices.

Iran: how quickly should the new deal with the West translate into renewed oil exports? Iran and the Western world have been in a long dispute over the former’s nuclear program. The US and its allies suspect that Iran aims to develop nuclear weapons, while Iran insists its program is for peaceful purposes such as producing energy and medical isotopes. However, an interim agreement between the two parties was signed in January 2014. Iran agreed to stop enriching uranium beyond 5% and to “neutralize” its stockpile, provide greater access to inspectors at its nuclear sites, and stop further development of the Arak plant, which could produce plutonium. In return, the US and its allies agreed to impose no new nuclear-related sanctions for six months and provide sanctions relief worth about $7 billion. Iran will receive payment in tranches over a 180-day period, provided it does not violate the agreement, with the first tranche of $550 million paid to Iran in February.

The deal will provide some relief to Iran, but it remains to be seen how quickly the country can bring its oil exports back to pre-sanction levels. In 2012, Iran’s exports were nearly half of the 2011 average of 2.2 mb/d. According to an article published in January 2014 in Business Standard, an English-language Indian daily newspaper, Asian buyers cut their purchases of Iranian crude by 15% in 2013 and shipments were expected to recover only slightly in 2014. The article noted that Asian buyers are reluctant to agree to large increases in import volumes until a final diplomatic agreement is reached. A separate, but related, issue is whether the lengthy sanctions have caused Iran to curtail spending on oilfield maintenance, which would have accelerated the oilfields’ natural decline rates (the rates at which production falls year after year).

Since 2012, sanctions have been imposed on the country to stop it from continuing its nuclear program:

In January 2012, the EU decided to impose an oil embargo on Iran (effective July 1, 2012) and to freeze the assets of Iran’s central bank.

In March 2012, the EU disconnected all Iranian banks from the Society for Worldwide Interbank Financial Telecommunication (SWIFT) network, thereby stopping all Iranian international banking transactions.

In March 2012, the US announced new sanctions (effective from July 2012) barring financial institutions that do business with Iran’s central bank from doing business in the US. Further, the US persuaded Iran’s oil customers to halt or substantially cut back oil purchases and find alternative sources.

According to the IEA, Iran lost nearly $40 billion in oil revenues in 2012 due to the sanctions imposed by the West. In January 2013, new sanctions came into effect that required countries buying oil from Iran to keep the payments in a separate account and not repatriate the amounts to Iran. This money can be used only to purchase goods from those countries.

Sanctions on Iranian oil have a big impact on world oil markets, as Iran (pre-sanctions) was the world’s third-largest crude oil exporter. According to the EIA, Iran’s total exports of crude oil and condensate fell dramatically following the implementation of sanctions, from 2.5 mb/d in 2011 to 1.5 mb/d in 2012. In 2013, Iran’s exports of crude oil and condensate fell further to 1.1 mb/d. Although the US exempted some 20 countries from the sanction, it wants them to reduce their oil imports from Iran substantially every 180 days to remain on the exemption list.

Egypt Concerns have been raised over the political turmoil in Egypt, as it could have disrupted the Suez Canal transit route, which is used extensively in the transport of oil to global markets—transporting about four million barrels of oil per day, according to an article published in July 2013 on CNNMoney, a business website. According to the EIA, Egypt produced 0.7 mb/d of oil in 2013.


The Egyptian revolution, which began in January 2011, ended the Hosni Mubarak regime; his government was dissolved in February 2012. In June 2012, presidential elections were held in Egypt, and Muslim Brotherhood candidate Mohammed Morsi was elected. At first, the situation had begun to normalize, but became unstable in November 2012, when President Morsi passed a controversial constitutional declaration that safeguarded his decrees from judicial oversight and also dismissed the prosecutor-general. This led to protests across the country and the decree was cancelled in December 2012. However, the president did not agree to protesters’ demands to cancel the referendum on a draft constitution, for which voting was held on December 16 and 22. Since then, there have been protests and violence in the country, with the protesters demanding the ouster of President Morsi.

In July 2013, the military announced the end of Morsi’s presidency and the suspension of the constitution. The military appointed Chief Justice Adly Mansour as the interim president, and charged him with forming a transitional government. In November 2013, Morsi went on trial for involvement in the killings of opposition protesters and, in December, the government declared the Muslim Brotherhood a terrorist organization. However, the pro-Morsi protests have continued, which lead to violence.

Libya: unrest continues After a civil war in 2011, Libya showed signs of recovery in 2012, but may be deteriorating again. The civil war ended in October 2011, after the death of the country’s former leader, Muammar Gaddafi, and the collapse of his 34-year-old Jamahiriya state. Libya had production of 1.6 mb/d of oil before the civil war, and returned to that level of production in late 2012. However, civil unrest since January 2013 has led to a decline in production. The EIA reported that production in 2013 was only 980,000 barrels per day (b/d). According to a Bloomberg article published in January 2014, production had fallen further to below 250,000 b/d. With some ports still held by rebels, production is not expected to regain its pre-civil war levels any time soon.

Syria The Syrian civil war, an ongoing conflict between forces loyal to the Ba’ath government and those looking to overthrow it, started in March 2011. Opposition forces are demanding the resignation of President Bashar al-Assad, whose family has held the presidency in Syria since 1971, as well as the end of Ba’ath Party rule, which began in 1963. Clashes between the two forces are taking place across the country. The US has designated the pro-Assad Shabiha militia and the al-Nusra Front as terrorist groups. In September 2013, UN weapons inspectors concluded that chemical weapons had been used in an attack in August, but did not explicitly mention who was responsible. In October, President Assad allowed international inspectors to start destroying the country’s chemical weapons following a US-Russian agreement. Then, in December, the US and Britain suspended support for rebels in northern Syria after reports that they had seized some bases of the Free Syrian Army, which is backed by the Western powers.

Syria is not a large oil producer, but the fear is that US military action against Syria could lead to turmoil across the Middle East. Production started to decline from the third quarter of 2011, when the EU imposed oil sanctions and the conflict intensified. According to the EIA, crude oil production in Syria declined to 58,000 b/d in 2013 from 145,000 b/d in 2012. Production was 350,000 b/d prior to the civil conflict that began in March 2011. The International Energy Agency (IEA) projected production to be approximately 30,000 b/d in 2014.

Demand issues The US economy is showing signs of faster growth, and Europe has come out of its recession and is slowly recovering. Conversely, the emerging markets such as China and India are experiencing a slowdown in growth. In July 2014, the International Monetary Fund (IMF), a United Nations agency that promotes international monetary cooperation, lowered its global gross domestic product (GDP) growth forecast for 2014 to 3.4% from its April 2014 forecast of 3.7%, reflecting a less optimistic outlook for some emerging markets and the effects of a weak first quarter, specifically in the US. However, IMF expects fairly strong growth in some advanced economies next year, and increased its forecast for 2015 to 4.0% from its April forecast of 3.9%.


According to the Oil Market Report published by the IEA in July 2014, global supplies were almost unchanged month-on-month in June, at 92.6 mb/d, but up 1.1% year over year. Similarly, OPEC supplies were almost unchanged in June, at 30.0 mb/d, and are forecast to decline from a projected 29.9 mb/d in 2014 to 29.8 mb/d in 2015. On the demand side, global demand for oil is expected to grow from a projected 92.7 mb/d in 2014 to 94.1 mb/d in 2015, with approximately 1.5 mb/d expected from non-Organisation for Economic Co-operation and Development (OECD) economies.

According to the IEA, the demand for crude oil in Europe in the 12-month period through May 2014 declined 2.9% to 13.3 mb/d. In July 2014, the IEA estimated crude oil demand in Europe to be 13.6 mb/d in 2014, and this is expected to fall to 13.5 mb/d in 2015.

The US is witnessing higher demand for crude oil due to improving economic conditions. According to the IEA, crude oil demand in the US increased to 18.7 mb/d in April 2014, a year-over-year growth of 0.7% and the eighth consecutive month of year-over-year growth. In July 2014, the IEA raised its oil demand forecast for the US for both 2014 and 2015 to 19.0 mb/d and 19.1 mb/d, respectively, citing strongly growing consumption as the economic recovery takes hold. US real GDP grew at an estimated rate of 1.9% in 2013, lower than the 2.8% in 2012. It should be noted that GDP grew at an estimated annual rate of 3.7% in the second half of 2013, a rate unseen since 2003.

On the other hand, crude oil demand from emerging markets such as China remained subdued. According to the IEA, in May 2014, total oil consumption for China, which is the world’s second-largest consumer of oil, increased only 1.9% year over year to 10.1 mb/d. In 2013, consumption was estimated to have grown by 3.8%, year over year, the slowest growth rate since 2008. As of July 2014, the IEA forecast that demand in China would increase by 3.3% in 2014 and 4.2% in 2015, as gasoil/diesel growth regains strength and government support is expected to keep GDP growth above 7.0%.

PROLIFIC DRILLING IN NORTH AMERICA

Unconventional shale plays, initially limited to natural gas, started in North America in 2006. Essentially, horizontal drilling and hydraulic fracturing have rendered otherwise uneconomic natural gas formations commercially viable—transforming North American natural gas production, which increased 15.8% between 2006 and 2012, according to the EIA.

In 2013, marketed natural gas production in the US was estimated to have increased 1.2% from 25.3 billion cubic feet in 2012. However, the North American natural gas market is fairly regional, with little exposure to other regions. One major reason is the lack of liquefaction plants in the US that would allow liquefied natural gas (LNG) tankers to head to lucrative overseas markets. The combination of increased supply and limited markets caused natural gas prices to plummet, falling from a range of mid-$6 per million British thermal units (MMBtu) in 2006 to an average of $2.75 per MMBtu in 2012. Natural gas prices increased in 2013 to an average of $3.73 per MMBtu. As of May 2014, prices had increased to $4.58 per MMBtu due to colder than normal weather.

When shale oil drilling started to gain a foothold in the US, which was shortly after the shale gas revolution, US production of crude oil subsequently rose in 2009 for the first time since 1991, a transformative development. However, given that crude oil is a global market, not regional, we do not expect a similar glut of crude oil to depress crude oil prices. Indeed, in a global marketplace with effective spare capacity at roughly 3.0 mb/d to 4.0 mb/d (a small fraction of the total global demand of roughly 90.0 mb/d), it would take a lot of incremental crude oil, in our opinion, to transform the marketplace in the same fashion as shale gas did for gas markets. If anything, shale oil likely reduces the percentage of US crude oil demand that is sourced from foreign shores, the first such uptick in domestic exposure since perhaps the Nixon Administration.

Nevertheless, we believe that the shale oil revolution will have an adverse effect on the valuation of oil services companies, because we believe it heightens the volatility of the perceived demand for their services. Prior to shale oil (as recently as 2007), finding new domestic sources of crude oil meant going into the deepwater US Gulf of Mexico. It takes considerable time and money to drill in up to 12,000 feet of water depth, plus another 25,000 to 30,000 feet beneath the ocean floor, in the most challenging geological


conditions. Offshore drilling rigs capable of drilling these wells could easily cost $500,000 per day. Drilling and completing such wells might take months, and the time to first production could easily be one to two years. Once an operator gives the green light to proceed with such a deepwater development, it becomes a vehicle for myriad activities: the offshore rig itself; oilfield services that are conducted on the rig; offshore supply vessels that bring replacement equipment to the rig; and so on. Even if crude oil prices plummeted after a field development had been sanctioned, that work would still proceed. Thus, expected demand for oil services was largely a function of the project economics of such work. If the field was economic at $75 per barrel, for example, then as long as expected crude oil prices were north of $75 for a long enough period of time, such a project was likely to get sanctioned.

Today, shale oil onshore means the ability to drill a well in just a few weeks, not months. The time to first production is much faster: months, not years. Consequently, operators can more easily jump into or out of field development, depending on crude oil prices, which in turn affects the demand for services. Ultimately, while we believe that the oilfield services marketplace is in the midst of a secular uptick, we recognize that the inherent volatility in demand for these services has risen as well, a development that we think could weigh on relative valuation multiples to some extent, even if potential earnings power is higher. The bottom line is, to the extent that oil services companies have North American exposure, we think they are likely to see more amplitude in the peaks and valleys in demand for their services.

Pad drilling Pad drilling is a method that allows rig operators to drill groups of wells more efficiently. A drilling pad houses the wellheads for a number of horizontally drilled wells and allows operators to drill multiple wells in a shorter time than if they had just one well per site. A drilling pad allows a fully constructed rig to be lifted and moved to the next well location using hydraulic walking or skidding systems, thus saving the effort of having to disassemble a rig at the current well and reassemble it at the next well. An analysis by Bentek Energy LLC has shown that operators are achieving efficiency gains through pad drilling. According to the analysis, the average time to drill a horizontal well in the Eagle Ford Shale formation was reduced to 14 days in the first quarter of 2013, compared with 22 days a year earlier. The reduction in time to drill wells saves the producer a significant amount of money.

Are unconventional gas plays too much of a good thing? In the past, the vast majority of the US land rig count was natural gas-directed, which typically makes these rigs sensitive to natural gas prices. In addition, more independent exploration and production (E&P) companies operate in North America, and such E&Ps tend to ramp up or pull back rapidly, adjusting their capital spending on a quarter-by-quarter basis as conditions change. Indeed, over the 10 years ended 2009,

the US land rig count has averaged 80% gas rigs and 20% oil rigs, based on data from Baker Hughes Inc. However, recent trends in US land drilling point to the rising influence of oil-directed activity.

Across the US, from the West Coast to the Northeast, some 19 geographic basins are recognized sources of shale gas. Currently, significant commercial gas shale production occurs in the Barnett Shale in the Fort Worth Basin, Lewis Shale in the San Juan Basin, Antrim Shale in the Michigan Basin, Marcellus Shale and others in the Appalachian Basin, and New Albany Shale in the Illinois Basin.

Three factors could explain the high growth and majority position of gas-

Chart H12: HORIZONTAL DRILLING GAINS SHARE

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Total US rig count (left scale)

% Horizontal drilling (right scale)

HORIZONTAL DRILLING GAINS SHARE

*through July 25.Source: Baker Hughes.


directed rig count in the past. First is the economics of unconventional gas plays. The EIA said in May 2014 that shale gas accounted for about 40% of total US natural gas production in 2012 (latest available), and was expected to rise to 53% by 2040. Some of the shale plays (such as the burgeoning Haynesville Shale or Marcellus Shale) have economies of scale that work even at weak natural gas prices, given the huge production potential. Indeed, the trend toward horizontal drilling (required in shale drilling) illustrates just how much resource potential shale plays offer.

Second, after the 2008 credit crisis eased somewhat, many E&Ps formed joint ventures that, having raised capital for the purpose of developing their acreage, are now obligated to put that capital to work. Third, many gas plays have been drilled recently only because the operators needed to drill in order to maintain leaseholds. In March 2010, the CEO of Chesapeake Energy Corp.—one of the leading players in US land drilling—said that perhaps 50% of all US land drilling at the time was being done in order to retain leases. However, that phenomenon may have peaked: Chesapeake also said in May 2010 that it expected to meet its leasehold commitments by mid-2010, and to throttle back on new drilling in the latter half of the year. Other major onshore US players, such as Devon Energy Corp. and EnCana Corp., have signaled similar intentions. Drill-to-hold acreage has largely expired, and with extremely low natural gas prices lately, the opportunity cost of giving up leaseholds from inactivity has declined. We think that the overall count for both oil and gas rigs will be flat to up slightly in 2014.

However, a typical shale oil extraction process also extracts gas. This has led to much higher production of shale gas than actually intended by the contractors, which has proved even more bearish for gas prices. According to the Short-Term Energy Outlook (STEO) released by the EIA in August 2014, production of natural gas from the Lower 48 states (excluding the Gulf of Mexico) will increase further in the next two years from 65.66 billion cubic feet per day (bcf/day) in 2013 to 69.80 bcf/day in 2014 and to 71.58 bcf/day in 2015.

Henry Hub natural gas prices dropped to $4.59/MMBtu in June 2014 versus $5.24/MMBtu in January 2009. However, the price of West Texas Intermediate (WTI) crude oil rose to $106.00/barrel (bbl.) in June 2014, from $41.71/bbl. in January 2009. Thus, the spread differential between oil and natural gas prices rose to 23.1 times in June 2014, from 8.0 times in January 2009. According to the July 2014 STEO, the price of WTI is projected to average $100.98/bbl. and $95.17/bbl., respectively, in 2014 and 2015. The price of Henry Hub natural gas is expected to average $4.77/MMBtu and $4.50/MMBtu, respectively, in 2014 and 2015, resulting in an oil/natural gas price ratio of 21.2 in 2014 and 21.1 in 2015.

As of July 2014, we were projecting crude to average $100.28/bbl. and natural gas prices to average $4.49/MMBtu in 2014. As a result, we project that the oil/natural gas price ratio will average 22.3 in 2014. Thus, it appears that many factors are favoring oil in US land drilling.

The problem no one imagined 10 years ago: too much US light sweet crude Technological advancement in drilling and fracturing processes has given a long-awaited boost to the unconventional oil industry. Weak natural gas market conditions, along with lower gas prices, are pushing E&P firms to change the focus of shale drilling techniques from gas to oil.

The US has witnessed several rapidly growing unconventional oil and gas plays in the recent past, among which are the Bakken Shale (stretching down from Canada into North Dakota and Montana) and the Eagle Ford Shale in South Texas. Their fast growth is due to their heavy liquid content, high initial oil production rates, sprawling existing and proposed infrastructure, and proximity to some of the largest energy markets in North America.

In April 2011, Rigzone, an online provider of news, data, and market research on the offshore oil and gas industry, published an article noting the huge growth in Eagle Ford Play activity. It stated, “Last year, US operators expressed their intentions to step up drilling programs in the Eagle Ford Shale formation. Strong oil prices and favorable well economics, due to greater concentrations of natural gas liquids, made drilling in this part of Texas appealing. True to their word, the rig count in the Eagle Ford has nearly doubled to 154 rigs as in March 2011, versus 82 reported in March 2010. The mix shift occurring between drilling for natural gas or oil continues to move away from natural gas. A year ago, the split was 91% gas and 9% oil rigs in the Eagle Ford. As of March 2011, the mix is 60% gas and 40% oil.” As of August 1, 2014, the


active rig count in the Eagle Ford had increased to 204, more than two and half times the figure reported in 2010, resulting in a further decline in the gas-to-oil mix to 2% gas and 98% oil, according to Baker Hughes, one of the world's largest oilfield services companies.

The increasing activity in the Bakken Play can be gauged by the high active rig count in North Dakota, which stood at 177 rigs as of August 1, 2014, up from 170 rigs a year ago, according to Baker Hughes.

The increase in shale play has led to too much of light sweet crude production in the US. According to the EIA, imports of light sweet crude have declined significantly to 1.0 mb/d in 2013, from 1.7 mb/d in 2011. With new completion techniques, production of light sweet oil is expected to increase at an even faster

pace. While production is increasing, much of the US’ refining capacity was upgraded over the last decade in anticipation of greater incoming quantities of heavy/sour crude, so that simply substituting light/sweet in lieu of heavy/sour is generally not feasible on a large-scale basis. This has led to various stakeholders demanding that the US allow more exports of light crude oil. According to an article published in Bloomberg News in May 2013, the administrator of the EIA said in a conference that the US might consider exporting light, sweet crude to Mexico in exchange for heavy crude. Currently, virtually all such light crude can be exported only to Canada, and even then typically in small quantities (190,000 b/d in December 2013, the most recent available data).

HYDRAULIC FRACTURING CAUSES CONTROVERSY

To meet the growing energy requirements of the world, the use of hydraulic fracturing (or “fracking”) has expanded, resulting in a chorus of complaints from detractors. Though the process has found support from many, including the US federal government (the Energy Policy Act of 2005 specifically exempted fracking from the requirements of the Safe Drinking Water Act), it has been facing strong opposition from many others, including environmentalists.

Fracking’s potential effect on drinking water supplies and sources in particular has galvanized opponents. One issue is contamination. In regions where energy exploration and/or drilling is carried out using fracking, leakage of chemicals (including benzene, xylene, methanol, ammonium bisulfite, and many more) that are used in the process can contaminate drinking water sources and lead to health problems for people, wildlife, and livestock. Another issue is the amount of water needed. Fracking can require one million gallons of water per each frac stage, and multiple-stage wells are routine (10- to 15-stage frac jobs are not uncommon today). Thus, fracking can divert a lot of water that could otherwise be used for purposes such as irrigation or simply conserved, leading to depletion of water resources. Opposition to fracking in some communities, such as those located on or near the Marcellus Shale, has put oilfield services companies on the defensive.

At the request of environmentalists and the residents of Pavillion, Wyoming, the EPA investigated the effect of fracking on the region’s ground water over the past three years. In its draft report released in December 2011, the EPA said that fracking was likely the reason for the chemical compounds found in the ground water aquifer in the region. During its investigation, the EPA detected synthetic chemicals such as glycols and alcohols in the deepwater wells, and found traces of petroleum hydrocarbons and methane in public and private drinking water wells. After retesting the collected samples, the agency found the water quality to be below the level defined by general health and safety standards. As directed by the US Congress, the EPA has begun a national study on the impact of fracking on drinking water sources, which is expected to be

Chart H07: US Rig Count

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US land rig count (left scale) % Oil-directed drilling (right scale)

US LAND RIG COUNT

*through July 25.Source: Baker Hughes.


released for public comment and peer review in 2014. However, many localities are not waiting for the EPA report. In New York State, the cities of New York and Syracuse have banned fracking in their watersheds. The Pittsburgh City Council banned fracking within city limits, and the New Jersey legislature is considering a permanent statewide ban.

Increase in earthquakes and seismic activity in fracking areas Another controversy that has emerged related to fracking is the increase in seismic activity observed in the regions near the wells drilled using this technology. Hundreds of small earthquakes detected in places ranging from Oklahoma to Ohio have been linked to the growing use of fracking. According to a study by the US Geological Survey scientist William Ellsworth, released in July 2013, the number of earthquakes has increased dramatically over the past few years. The study noted that the central and eastern US experienced more than 300 earthquakes above a magnitude 3.0 during 2010–2012, compared with an average rate of 21 events per year observed from 1967–2000.

There has also been a surge in seismic activity in areas where wastewater from fracked oil wells has been dumped. All of the 11 earthquakes that struck Youngstown, Ohio, in 2011 were centered near the wells used for the disposal of fracking waste. The Lamont-Doherty Earth Observatory at Columbia University found that the earthquakes in Youngstown occurred at the same depth as the disposal wells. An Oklahoma geological survey report also agreed on the possibility of a direct connection between more earthquakes and the increased use of fracking.

World Oil magazine published an article in March 2012 suggesting that certain characteristics of a formation may, if injected with fluid (such as in fracking), create enough stress to cause an earthquake. One characteristic in question is the extent to which the formation has large, naturally existing stresses that are close in magnitude to the formation’s strength; a second such characteristic is whether the formation has naturally occurring weaknesses, such as natural fault planes, that are susceptible to failure with a small disturbance of equilibrium. Put both of those together in the same formation, and it is conceivable for the injection of fracking fluids to create an earthquake. According to the article, the occurrence of such an earthquake relieves stresses, thereby lowering the intensity of potential future earthquakes. However, the question is whether the lack of fracking might mean a more powerful earthquake may occur on its own in the near or more distant future.

International shale developments slowing on fracking concerns Hydraulic fracturing is also facing criticism in England, France, South Africa, and even in Australia. Given the increased seismic activity and the higher possibility of water contamination, environmentalists are voicing their concerns about this drilling technology. UK-based Cuadrilla Resources has met with a roadblock at the Preese Hall exploration site in northwest England after two seismic events of magnitude 2.3 and 1.4 on the Richter scale were recorded in April and May 2011, respectively. After a geomechanical study, the company concluded that fracking could well have been the reason for the two earthquakes and voluntarily postponed fracking operations. In October 2011, the Vale of Glamorgan Council in Wales rejected Coast Oil & Gas Ltd.’s application for exploratory drilling of a well near Llantwit Major, on grounds of possible groundwater contamination. The UK placed a temporary ban on fracking in 2011, but in December 2012, the government announced that it would remove the ban.

The French government revoked the three licenses granted to Total S.A. and Schuepback Energy LLC in October 2011, due to concerns over the use of fracking for drilling the wells. In July 2013, French president François Hollande said that he would not allow fracking in that country. In December 2011, New South Wales, Australia’s most populous state, extended its temporary ban on fracking, which is used there to extract coal seam gas. However, in September 2012, New South Wales lifted the ban on fracking.

In South Africa, the development of shale gas has been a matter of debate. In February 2011, the country’s government imposed a moratorium on shale gas exploration licenses in the Karoo region, where it suspected fracking had been used. Critics of fracking in South Africa (such as Treasure the Karoo Action Group, Greenpeace, and local farmers) fear contamination of the region’s water as a result of this drilling method. Companies favoring shale gas exploration in the Karoo region (including Royal Dutch Shell and Falcon Oil & Gas Ltd.) believe that the region has about 485 Tcf of gas reserves that, if developed, could reduce the


country’s dependence on energy imports. In September 2012, South Africa ended its moratorium on hydraulic fracturing.

Problems related to fracking: science or execution? A key question that remains unresolved is whether the problems associated with fracking are structural in nature, or whether the execution of frac jobs has simply been sloppy. (A third possibility also exists: namely, that the environmental problems that have been observed are actually not associated with fracking.) In other words, are frac jobs inherently dangerous, or are they dangerous only when done badly?

Despite the fact that the jury remains out on this question, we increasingly believe that poor execution could be responsible for many of the existing problems. An article in the December 2011 issue of World Oil magazine noted that methane contamination, which is frequently blamed on fracking, may actually be due to cement integrity issues, which can be inexpensively controlled. The article stated, “A number of industry studies suggest that shallow gas migration, from formations far above the fracture-stimulated shale formation, may be responsible for the occasional aquifer contamination that has been widely blamed on fracking. The inexpensive addition of a mechanical device, specifically an inflatable or swellable casing annular packer, to control annular fluid movement, after cement displacement, can improve cement integrity and greatly reduce or eliminate the possibility of annular gas migration.”

Colorado fracking restrictions On February 27, 2014, the Colorado District Court ruled in favor of the November 2013 vote results that banned fracking in Broomfield, Colorado for five years. Opponents of the ban challenged the election results following a recount that deemed the initiative to have passed by 20 votes. An automatic recount was triggered when the initial results of the election indicated the measure had passed by 17 votes. Broomfield was one of four Colorado cities where voters approved bans on fracking, which involves high-pressure injection water, sand, and chemicals deep underground to release natural gas and oil trapped in shale formations. However, on July 24, 2014, the Boulder County District Court overturned the fracking ban in Longmont City, saying that the ban, which was passed by voters in November 2012, is pre-empted by the Colorado Oil and Gas Conservation Act that gives the state primary authority over oil and gas operations. The court granted the request of the Colorado Oil and Gas Association and the state for an order to enjoin the city from enforcing the ban, but stalled the order to give the city enough time to file an appeal.

On August 4, 2014, Colorado Governor John Hickenlooper announced a compromise agreement with proponents of two ballot initiatives that would have placed restrictions on oil and gas development in the state. The agreement created a task force charged with developing recommendations that would help minimize land use conflicts, which can occur when siting oil and gas facilities near homes, schools, businesses, and recreational areas.

Will newer fracking techniques lead to cleaner technology? Hydraulic fracturing was a blip on the US land rig count 10 years ago. Today, it is ubiquitous and the most often used process for land drilling, not only of natural gas wells (where the phenomenon began), but also for crude oil extraction. Marrying the ability to drill horizontally with the ability to crack open otherwise impermeable rock, hydraulic fracturing enables energy companies to gain access to previously inaccessible reservoirs of crude oil and natural gas—those trapped in thin layers of shale rock or other so-called tight formations. Despite its huge potential, fracking has not gone over well with environmentalists. If fracking proponents can address critics’ concerns, the technology could win huge worldwide support. New versions of fracking technology seem to be doing just that.

Schlumberger’s new HiWAY flow channel fracking technology aims to improve production and efficiency at lower cost. According to Schlumberger, more than 10,000 frac stages using HiWAY have been pumped since 2010, saving over 1.2 billion pounds of proppants compared with standard fracking techniques. (Proppants are materials, such as sand, that keep the fractures open after pressure is released.)

Baker Hughes’ FracPoint openhole fracture completion system similarly aims to offer a targeted frac placement that eliminates the need for certain other oilfield services (such as cementing jobs), which can mean higher initial productivity and better return on investment.


Halliburton’s CleanSuite technology aims to reduce the environmental footprint of fracking operations. In a natural gas producing well in North Louisiana, the CleanSuite process featured a reduced need for fresh water, better control of bacteria in the water using ultraviolet light instead of additives, and faster production. We also note that Halliburton’s CleanWave product (which is one of the three legs to the CleanSuite technology) received a “Spotlight on New Technology” award at the 2011 Offshore Technology Conference.

Effect of water sourcing and usage on service companies IHS Herold Inc., an energy research and consulting firm, held a webinar in July 2013 entitled “Water Management Strategies and Water Market Opportunities.” In the webinar, what caught our interest were the potential opportunities in oil services related to water management. Those opportunities, however, are dictated to some extent by the location in which one is drilling in the lower 48 states. In parts of Texas, for example, plenty of places are available where one can dispose of wastewater used in the various fracking stages, but accessing the water in the first place is a challenge. Fleets of water trucks are typically used, but at a high cost, not just in the prices paid to bring in the water, but also on the communities in which they are drilling (e.g., increased traffic jams from a high number of trucks on the roads). In the Marcellus Shale, water is plentiful, but disposing of wastewater is difficult.

This is where oil services technology comes in. According to a report by the Natural Resources Defense Council, an environmental action group, “direct discharge of wastewater from shale gas wells to surface waters is prohibited by federal law.” Thus, disposing of water underground to an injection well is one option. However, finding a suitable injection well can require transporting the wastewater a significant distance within the Marcellus states of Ohio, Pennsylvania, and West Virginia. Treatment of wastewater is a more expensive option, but one in which we see rising potential for new solutions. A company called Nuverra Environmental Solutions (NES), for example, offers treatment, recycling, and disposal of wastewater from energy and industrial applications. NES competes with the major oilfield services companies, such as Baker Hughes or Schlumberger, as well as a host of smaller companies such as Clean Harbors Inc., R3 Treatment Inc., and Tervita Corporation. We suspect that this field will ultimately generate new solutions for wastewater management.

One such solution not commonly noted is fairly simple: if you’re concerned about too much demand for fresh water and not enough supply, then switch to brackish water. In the third-quarter 2013 issue of Upstream Technology magazine, Dr. Stephen Holditch of Texas A&M University’s petroleum engineering department noted that brackish water (which is basically naturally occurring salt water) can be used as the base fluid, which is a minor tweaking of the typical base fluid that starts with fresh water and has potassium chloride salt added.

BP TRIAL CLOSER TO COMPLETION

In January 2013, BP plc pleaded guilty to criminal charges in the US District Court (eastern Louisiana) and agreed to pay a fine of $4.0 billion for the 2010 oil spill disaster in the Gulf of Mexico. The deal would settle nearly 100,000 claims from fishermen and others affected by the oil spill. About the decision, BP said that it has resolved “a substantial majority of legitimate economic loss and property damage claims stemming from the Deepwater Horizon accident” and that it was in the best interest of all parties concerned.

Nevertheless, differences have arisen between the Deepwater Horizon Court Supervised Settlement Program (DHCSSP) and the company regarding the interpretation of the settlement. BP said that the interpretation used by the claims administrator produced a higher number and value of awards than the interpretation it used in making an initial estimate. In March 2013, the District Court rejected BP’s position relating to business and economic losses and its plea to stop the payments. However, in July 2013, the District Court appointed Judge Louis Freeh as Special Master to lead an independent investigation of the DHCSSP in connection with allegations of potential ethical violations or misconduct within the DHCSSP. BP filed a motion in the DistrictCcourt to temporarily suspend all payments from the DHCSSP until Judge Freeh completes the independent investigation, which was later rejected by the court.


In December 2013, payments were temporarily halted as BP fought to block payments over losses not directly linked to the oil spill. However, the US Court of Appeals in New Orleans ruled on March 4, 2014 that the company must resume paying millions of dollars in business-loss claims. The British oil company said it would appeal the decision, and in May, BP asked the Supreme Court to review whether it must pay businesses for economic damages without proof that the spill caused such losses.

The January 2013 agreement did not resolve the federal government’s civil claims against BP under the Clean Water Act. The company was unable to reach a settlement with federal and state governments, and a trial began in February 2013 in US District Court (New Orleans). The first phase of the trial was completed in 2013, but the Court did not reveal the findings. The trial is now in its second phase. In January 2014, both parties filed post-trial briefs reasserting arguments about the amount of oil that spilled into the Gulf of Mexico.

In August 2013, BP sued the EPA over its suspension of BP from any new federal government contracts following the company’s guilty plea to a pollution charge in the Gulf of Mexico oil spill. In November 2012, the EPA had suspended 21 BP entities and, in February 2013, had disqualified BP’s exploration and production unit from all federal contracts after that unit pleaded guilty to a misdemeanor violation of the Clean Water Act. The company has argued that the suspensions and disqualification are contrary to federal law and regulations, and exceed the EPA’s statutory and regulatory authority and limitations.

In a separate decision, US District Court (eastern Louisiana) Judge Jane Triche Milazzo approved an agreement between Transocean Ltd. and the US Justice Department under which the company will pay $400 million in criminal penalties for its role in the oil spill. Another separate proposed civil consent decree is pending before US District Court (New Orleans) Judge Carl J. Barbier. The decree would resolve the federal government’s civil Clean Water Act penalty claims against Transocean, imposing a $1 billion civil penalty.

BP had estimated that the cleanup and the compensation costs to total around $42 billion, according to an article in Reuters dated January 27, 2012. The company itself made a payment of $14 billion for such costs, including around $7 billion paid to third-party vendors who suffered losses. According to BP, it has reached agreements with Anadarko and MOEX Offshore 2007 LLC, which have agreed to pay $4 billion and $1.065 billion, respectively, as their shares of the compensatory damage claims. Anadarko will also transfer to BP its 25% interest in the MC252 lease (which covers the Macondo field) and has the right to claim 12.5% of future recoveries from insurance reimbursements that exceed $1.5 billion (up to a maximum of $1 billion). Mitsui & Co., the parent company of MOEX, received indemnity from BP against any compensatory claims, but it still would be liable for any fines and/or penalties decided during the federal trial. On February 17, 2012, MOEX reached a settlement with the federal government and the Gulf states, agreeing to pay $90 million, a total that included civil penalties and funding for coastal protection projects.

In December 2011, BP reached a settlement with Cameron International Corp., the manufacturer of the well’s blowout preventer, when Cameron agreed to pay $250 million for indemnity against any other compensatory claims. Both companies agreed to discontinue any pending litigation against each other. Earlier, in June 2011, BP reached a similar settlement with Weatherford International Ltd. on the payment of $75 million in exchange for indemnity by BP against damage claims.

ENVIRONMENTAL CONCERNS OVER OIL TRANSPORT

Several major pipeline proposals in the US and Canada that are facing opposition from environmentalists are discussed below. We also mention several train derailments in Canada that had serious consequences.

Keystone XL Keystone XL is a $7 billion project that was proposed in 2008 by TransCanada Corp. as an extension to the $13 billion Keystone Pipeline System, an existing conduit for crude oil from Canada to refineries across the US. The Keystone Pipeline System was built in two phases. Phase I connected Hardisty, Alberta, to refineries in Illinois; this pipeline became operational in June 2010. Phase II was a pipeline connecting Steele City, Nebraska, to Cushing, Oklahoma; it became operational in February 2011. The Keystone XL project was also to be completed in two phases. The first phase involved extending the pipeline from Cushing to serve


the Port Arthur and Houston markets in Texas; the second involved building another pipeline from Alberta through South Dakota and Nebraska, to join the existing pipeline in Steele City.

Keystone XL became controversial because its proposed route passes through the Ogallala Aquifer, a significant source of water for drinking and irrigation for Nebraska and several other states. The ranchers and farmers fear that in the case of an oil spill, about 1.3 million acres of wetlands would be polluted and more than a thousand land and water species living in the area would be affected. Given these concerns, in January 2012, President Barack Obama denied a permit to Keystone XL to pass through the Nebraska Sandhills, an environmentally sensitive region. However, the US administration asked TransCanada to come up with a different route for the project and reapply for the permit, a proposal that the company accepted. In response, the company submitted a new route for the northern section of the Keystone XL project, avoiding the Sandhills, but still passing over the Aquifer, where the soil is permeable and the water table is high. According to TransCanada, the new route does not cross any area where the water level is less than five feet below the surface; however, there is a 35-mile stretch where the water level is less than 20 feet below. The new route was approved in January 2013 by Nebraska Governor Dave Heineman.

Nearly 35,000 protesters marched to the White House in February 2013 to show their opposition to the pipeline, according to an article published in Bloomberg. In August 2013, President Obama said in an interview that he had reservations about the project, mainly on environmental grounds. Platts, a unit of McGraw Hill Financial, noted in September 2013 that Obama’s comments may be seen as a spur for Canadian energy regulators to adopt policies that would lower the environmental impact of the project, although Canadian officials have said that they are opposed to a carbon tax.

Nevertheless, in its final environmental review of the project in January 2013, the US Department of State concluded that the pipeline would not have a “significant” impact on carbon pollution on its own. This conclusion was drawn partly on the basis that the crude oil produced in the Canadian oil sands would still find its way to market (by rail) even if the XL project was shelved. Assistant Secretary of State Kerri-Ann Jones noted that these findings alone cannot guarantee approval of the project as the decision-making process would examine issues related to energy security, foreign policy, and economic interests, along with climate change. The final decision rests with President Obama, and we think a decision will be made in November 2014, after the midterm election.

Earlier, in July 2012, the southern leg of the Keystone XL project, from Cushing to Port Arthur and Houston, received final approval from the US Army Corps of Engineers to begin construction of the 485-mile stretch of the pipeline. This southern portion began operations in January 2014.

Northern Gateway Enbridge Inc.’s Northern Gateway Pipeline Project, scheduled to start in 2017, received the approval of Canada’s National Energy Board in December 2013. Enbridge must now seek approval from the federal government, which has 180 days to review the project. A number of environment groups have filed lawsuits. According to thestar.com, an online news publication, as of February 3, 2014, there were five different challenges by groups arguing that the joint review panel erred in a number of ways.

This pipeline would move crude oil from Alberta across the Rocky Mountains to Kitimat on British Columbia’s Pacific Coast. From there, it would be sent to either Asia or California. The concern is that the pipeline route is subject to seismic activity and frequent landslides, thereby making it prone to oil spills.

Enbridge said that it would be using the newest technology, thus reducing the risk of rupture, but the project seems to be going through the same fate as Keystone XL, with the same groups opposing this project. According to a November 2011 report by the Natural Resources Defense Council, Pembina Institute, and Living Oceans Society, a spill from Northern Gateway would destroy salmon habitat and adversely affect the habitat of whales, orcas, and grizzlies. Enbridge, responding to these concerns, said that it had considered other options and chose the safest route for the pipeline.

The pipeline project met a roadblock in July 2012 when, apart from the concerns of the environmentalists, the government of British Columbia (BC) announced its plan to renegotiate its share of the benefits from the


project. According to Terry Lake, BC’s Environment Minister, the province of British Columbia would get only 8% of the pipeline revenues, while assuming 100% of the marine risk for the port terminal and 58% of the land-based risk of the pipeline. Further, in May 2013, BC’s provincial government said that it will not support the Northern Gateway pipeline as presented because the project has not addressed environmental concerns. According to the Wall Street Journal in December 2012, a poll commissioned by the Gitga’at First Nation (an indigenous Indian tribe) showed that 60% of British Columbians who responded were opposed to the pipeline. Despite this opposition from BC, the pipeline project has received some support from the Northwest Territories (NWT). In August 2012, NWT premier Bob McLeod announced that he is ready to allow the shipment of crude oil from Alberta to the NWT and then to Asia.

According to an article published in the Financial Post, a Canadian newspaper, the July 2012 deal announced by China National Offshore Oil Corp. (CNOOC) to buy Nexen Inc., which owns energy resources in Canada, is a possible indication of plans to ship crude oil to China from Alberta using the Northern Gateway pipeline.

Energy East TransCanada Corp. announced in August 2013 that it was moving ahead with the Energy East Pipeline project. The 4,500-kilometer pipeline is expected to carry 1.1 mb/d crude oil from Alberta and Saskatchewan to refineries in eastern Canada. The project has the following components:

Converting an existing natural gas pipeline to an oil pipeline

Constructing new pipelines in Alberta, Saskatchewan, Manitoba, eastern Ontario, Quebec, and New Brunswick to link up with the converted pipeline

Constructing the associated facilities required to move crude oil from Alberta to Quebec, and New Brunswick, including marine facilities that enable access to other markets

The proposed starting point is a new tank terminal in Hardisty, Alberta, with three other new terminals being built, one each in Saskatchewan, Quebec City, and Saint John. The terminals in the Quebec City and Saint John areas will include facilities for marine tanker loading. The exact route will only be determined after public and regulatory review.

The project is already facing opposition, with environmentalists and indigenous activists questioning the politics around the project. Civil groups like Greenpeace and the Council of Canadians have declared that they will start political campaigns against the project. According to an article published in November 2013 by CBC News, a division of the Canadian Broadcasting Corp., the Ontario Provincial Energy Minister Bob Chiarelli has asked the Ontario Energy Board to consult citizens of the province and prepare a report on the potential benefits and drawbacks of the pipeline. In December 2013, TransCanada noted that it proposed a new route after Edmundston Mayor Cyrille Simard raised concern that the pipeline would harm his city’s watershed area. The company had planned to apply for a permit by mid-2014, according to Bloomberg.

Quebec oil train disaster On July 6, 2013, a train carrying 73 tank cars of North Dakota crude rolled driverless down a hill into the heart of Lac-Megantic, Quebec, where it derailed and exploded. According to an article published in the Guardian on July 7, 2013, 50 people were killed and a large part of the town was destroyed. The incident brought scrutiny to the safety of shipping oil by rail. In September 2013, Canada’s Transportation Safety Board noted that US and Canadian regulators should better document the transport of dangerous goods after it found that the train was carrying more flammable, gasoline-like fuel than the crude oil it was supposed to be carrying. The Board further noted that it is also looking at the safety of the rail cars that are used to move oil.

According to an article published in Bloomberg in October 2013, regulators in Canada imposed stricter labeling, which requires anyone importing or transporting crude to do tests to classify the type of fuel involved and update safety data sheets with the government. In September 2013, the US Pipeline and Hazardous Materials Safety Administration proposed making DOT-111 tank cars less prone to rupture. In order to prevent derailments and accidents similar to the disaster in Quebec, the US Federal Railroad Administration


announced on April 9, 2014 that it proposed a rule that will require two-person crews on trains carrying crude oil, and prohibit unattended freight trains or standing freight cars on main tracks or sidings.

New Brunswick train derailment On January 8, 2014, a Canadian National Railway train carrying propane and crude oil derailed and caught fire in northwest New Brunswick. According to a January 2014 Reuters article, no one was injured in the accident, but nearly 45 homes in the village of Plaster Rock were evacuated after the derailment. The article noted that the derailment, which came a little more than a week after a train carrying crude oil derailed and exploded in North Dakota, has put the surging crude-by-rail business under heavy scrutiny. On January 27, another train carrying butane in New Brunswick derailed, leading to questions about Canadian National Railway’s maintenance budget.

OFFSHORE RIG SUPPLY: TOO MUCH OF A GOOD THING

As of August 2014, Rigzone reported that there were a total of 1,495 rig fleets worldwide, including stacked and under construction rigs. Of this total, only 863 rigs were under contract, representing 57.5% total utilization. The four most competitive rig types were drill barge, with 88.9% utilization, up from 80.0% in August 2013; drillship, with 82.7% utilization, down from 86.9%; semisub, with 79.9% utilization, down from 89.8%; and jackup, with 79.6% utilization, down from 88.4%. Most rig utilizations were down year over year, according to Rigzone.

New rigs not obtaining contracts or getting short-term deals In 2013, Diamond Offshore Drilling announced that it would launch two deepwater semisubmersible rigs and four ultra-deepwater drillships over the next two years. Of the six rigs announced, only three have contracts. As of May 28, 2014, Seadrill Ltd. had 19 rigs under construction—three semisubmersibles, eight drillships, and eight jackups—but only one semisubmersible and one drillship were contracted. In June 2014, Ensco plc announced eight new rigs to be delivered through 2016—three drillships and five premium jackups—but only two drillships and one jackup obtained contracts. On July 18, 2014, Rowan Companies plc announced three new ultra-deepwater drillship contracts, with expected deliveries by July 2014, October 2014, and March 2015. Two of the rigs are contracted for three years and the other is contracted for two years.

As of July 2014, Transocean had 14 rigs under construction—seven deepwater, two ultra-deepwater, and five high-specification jackup rigs—but only the seven deepwater rigs have already obtained contracts. Also in July, Noble Corp. reported one new drillship, two new jackups, and one jackup scheduled to be completed in 2016. The company also reported one new short-term contract (from July to September 2014), and two contract extensions—one from February 2015 to February 2016, and one from April 2014 to December 2014.

On August 1, 2014, Atwood Oceanics reported that it has three ultra-deepwater rigs under construction, with delivery schedules of August 31, 2014, March 2015, and December 2015. Two of the rigs are available for contracting. As of July 2014, the total number of new rigs was 97, of which 55% had still not been contracted, according to IHS Petrodata, an independent source of market intelligence and data for the offshore oil and gas industry worldwide.

OFFSHORE DRILLERS DIVESTING OLDER RIGS

Contractors have indicated that they are entertaining divestitures and spinoffs of older units as a strategy to expand and focus on rationalizing their portfolio of drilling rigs. Transocean and Noble Corp. have been looking at divesting some operations for more than a year.

Transocean. In November 2013, Transocean announced that it would implement a Master Limited Partnership (MLP), which it concluded could complement its capital structure. The company stated that an MLP-type yield vehicle could provide additional financial flexibility and enhance the execution of its assets strategy. Transocean expects the initial public offering (IPO) of the MLP to be completed around mid-2014, with a minority interest sold at that stage. The offering is subject to the approval of the company’s Board of Directors, market conditions, and the effectiveness of a registration statement.


Noble Corp. On August 4, 2014, Noble Corp. announced that it completed its spin-off of Paragon Offshore plc, which owns most of Noble’s standard specification drilling business. Noble and Paragon are now two separate and publicly traded companies. Noble distributed to its shareholders one ordinary share of Paragon for every three ordinary shares of Noble. Shareholders who had been entitled to receiving fractional Paragon shares received cash in lieu of that fractional share. Noble plans to offer an improving mix of premium assets, consisting of high-specification rig capacity, at a time when operators’ needs are expanding.

INCREASE IN NEWBUILD ORDERS

More and more contractors are ordering new rigs, resulting in a rise in newbuilds. This indicates a trend toward greater preference for drill ships and ultra-deepwater floaters, which are equipped with technologically advanced features. The primary factors contributing to this trend could be a move toward an increasingly bifurcated vessels market with emphasis on high-quality equipment, aging of the existing offshore fleet available with the contractors, and a heightened focus on safety following the Macondo oil spill in 2010.

Contractors are ordering equipment with high specs, even when their current projects may not have high-spec rigs as a requirement. Ordering new equipment on a speculative basis reflects increased confidence on the part of the contractors. While ordering newbuilds on speculation is common for jackups, it is not so usual for floaters, so this is an interesting trend emerging in the market.

Given the Macondo spill and the uncertain global economic environment, orders of new rigs from June 2010 to December 2011 were much higher than earlier expectations, with over 100 new rigs ordered, as estimated in the World Rig Forecast released by IHS Petrodata in 2012. Most of the newbuilds ordered have

been harsh environment jackups, followed by drillships and semisubmersibles. According to HIS Petrodata, high utilization is likely to persist in 2014, but tail off in 2015 as the number of new rigs in the marketplace finally begins to outpace demand. Based on the forecast data, we see marketed rig utilization was about 90% in December 2013, and rising to 93% in December 2014. However, keep in mind that many newbuild jackups are not yet contracted, and many of those are due for delivery in 2015. Thus, we would expect the forecast demand numbers to drift upward over time, as we approach 2015. As of July 2014, there were 240 offshore rigs on order or under construction, according to HIS Petrodata, up from 211 in July 2013.

Chart H05: NUMBER OF OFFSHORE RIGS ON ORDER OR UNDER CONSTRUCTION

Chart H03: NEWBUILD FLOATERS

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Can this pace be sustained? However, all may not be well in the world of newbuilds, at least from the perspective of the shipyards where the rigs are built. A June 2012 article in Marine Log magazine opined that many Chinese shipyards may have to close. The article noted that China took in $19 billion in new shipyard orders in 2011, a fraction of the $48

billion in new orders taken by South Korean yards. Given the extremely fragmented nature of Chinese shipyards, compared with a much more streamlined industry in South Korea, we believe that some natural consolidation may occur in China, especially as the industry gravitates toward research and development (R&D) improvements in drilling rigs. Recent design innovations in offshore drilling, such as Sevan Drilling’s cylindrical hull design, have potential applications as floating, production, storage, and offloading (FPSO) vessels as well, as noted in the July 2012 issue of World Oil magazine.

According to RigBase, however, the delivery slippage of newbuilds for all rig types declined significantly in the 2009–2012 period compared with the

2005–2008 period. For jackups, delivery slippage fell to 55.6 days during 2009–2012, down from 151.3 days during the 2005–2008 period, representing an efficiency gain of 63.2%. Similarly, over the same period, delivery slippage days dropped to 55.3 days for semisubmersibles (from 253.4) and to 29.6 days for drillships (from 104.8), showing efficiency improvements of 78.2% and 71.8%, respectively.

Faster turnaround of new rigs helps projected payback periods. This encourages contractors to build new rigs so long as demand is expected to remain high, which we think appears to be the case for now. Looking at individual companies, we see that a majority of the leading contractors have their asset/equipment strategy in line with the trend. For instance, Noble Corp. stated, in January 2014, that it plans capital expenditures (capex) of around $2.6 billion for 2014,

of which it will spend around $1.4 billion on its newbuild program. We suspect that this represents the near-term high point for capital spending by Noble, but still anticipate material spending on newbuilds through 2016.

Companies with a newer fleet have generally seen their margins go up, since newer units generally have better utilization and less unplanned downtime, and thus lower unanticipated repair and maintenance costs. In addition, older rigs are more often in for repairs, even when anticipated. While newer units may use more crew and thus have higher operating costs in absolute dollars, margins are still often better because dayrates are higher as well.

LAND DRILLING NOW LESS SENSITIVE TO NATURAL GAS PRICES

In the past, a good proxy for determining trends in the oil and gas industry was land drilling activity, as measured by rig count. The rig utilization rate calculates the number of rigs being used in drilling as a percentage of the entire rig fleet available. A higher price for natural gas increases the demand for rigs, resulting in a higher utilization rate, and vice versa. This relationship weakened in 2012, when the average

Chart H04: MOBILE OFFSHORE RIGS

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Supply Demand Utilization (%)

MOBILE OFFSHORE RIGS (As of December 2013)

F-Forecast.Source: IHS-Petrodata.

Utilization (%)Number of rigs

Table B08: NUMBER OF NEWBUILDS BY PERIOD AND RIG TYPE

NUMBER OF NEWBUILDS BY PERIOD AND RIG TYPE

SEMISUB- DRILL- ALL

PERIOD JACKUP MERSIBLE SHIP TYPES

2010-2013 137 24 85 2462005-2009 116 55 46 2172001-2004 19 4 0 23

Total 272 83 131 486

Source: RigBase.


price of natural gas declined to $2.75/MMBtu from $4.00/MMBtu in 2011, but the data for land rig utilization, published in the Annual Rig Census by National Oilwell Varco, put the rate of US land rig utilization at 76% in 2012, up from 68% in 2011. The trend continued in 2013, with the average price of natural gas rising by 35.6% to $3.73/MMBtu, while the utilization rate declined by nine percentage points to 67%.

There are three main reasons for drilling becoming less sensitive to natural gas prices. First, the nature of land drilling has been turned on its head, with the operators now more focused on crude oil than on natural gas. This is clear from the rig count split between oil and gas, as reported by Baker Hughes. According to the company, as of August 8, 2014, 83.4% of the rigs were utilized for oil and 16.6% for gas, compared with nearly 21.3% for oil and 78.1% for gas in January 2009.

Second, according to Platts, natural gas liquids margins, are driving development in US shale plays, and with natural gas prices for the Henry Hub benchmark at lower levels, these wet (or high Btu) plays should continue to drive production growth. Finally, the drilling process has

become very efficient due to a number of innovations and we believe that well counts are now more informative than rig counts. According to Baker Hughes, the preliminary total US land well count to rig count ratio improved to 5.34 at the end of 2013, compared with 4.92 at the end of 2012.

E&P CAPITAL SPENDING OUTLOOK

Capital spending by major E&P players has increased sharply due to strong and stable oil prices. Chevron reported capital and exploratory expenditures of $41.9 billion in 2013, up 22.5% from $34.2 billion in 2012. Exxon Mobil reported that its capital and exploration expenditures for full-year 2013 were $42.5 billion, 7.0% higher than in 2012. The company had earlier indicated its plans to invest at the rate of $37 billion per year for the next five years to meet rising world energy demand. Other major E&P players have witnessed similar trends. Heavily weighted toward gas, US E&Ps have begun to focus on unconventional oil and natural gas liquids (NGLs). Like the shale gas frenzy several years ago, much of the activity remains focused onshore, where early drilling results have been successful at several untapped basins with high liquids content. Overall, we think a high single-digit growth rate in spending is reasonable for 2014, with double-digit growth internationally, but mid-single-digit growth in the US.

At the beginning of 2011, oil prices reached highs not seen since 2008, reflecting the disruption of exports from Libya and unrest elsewhere in the Middle East and North Africa. In our view, after a retreat caused by tempered global economic data, and with further geopolitical friction, US prices have begun to climb again. As of July 2014, using S&P estimates based on data from research and consulting firm IHS Inc. WTI spot oil prices were projected to average about $100.28 per barrel in 2014.

Increased production from onshore shale plays and a warm winter pressured spot prices for US natural gas in 2013. However, prices increased toward the end of 2013 and continued to do so into 2014, due to colder than expected winter. Prices reached $5.23 per million Btu on January 24, 2014. According to the EIA, gas working inventories on January 24, 2014, were estimated to be 16.6% below the five-year average. As of July 2014, based on data from the EIA, S&P expected Henry Hub spot prices to average $4.49 per million Btu in 2014. Year to date through July 18, 2014, the S&P Integrated Oil & Gas Index was up 3.4%, versus a 6.6% rise in the S&P 1500 Composite Index, reflecting, in our view, concerns over sluggish production

Chart H06: LAND RIG UTILIZATION VS. NATURAL GAS PRICE

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LAND RIG UTILIZATION VS. NATURAL GAS PRICE

*Includes non-land rigs, which comprise less than 4% of the total number of rigs.Sources: National Oilwell Varco; Energy Information Administration.


growth. In 2013, the index advanced 18.1%, compared with a 30.1% increase for the S&P 1500. In 2012, the index was down 0.6%, versus a 13.7% increase for the S&P 1500.

As of August 2014, our fundamental outlook for the oil and gas E&P sub-industry for the next 12 months was positive. US E&Ps are emphasizing crude oil and NGL production. For our coverage universe in 2014, S&P Capital IQ consensus estimates suggest a median increase of 13% of crude oil production, and a median increase of 10% in NGL production, as compared with 2013. This compares with more subdued natural gas production, which is expected to show a median decline of 3.2% in 2014. Our coverage universe is also anticipated to generate cash from operations amounting to 93% of projected capital spending, which we interpret to mean that companies will tap into credit facilities in order to pursue their organic growth plans. We remain cautious on US natural gas, and see the recent shift toward liquid production continuing in 2014.

INDUSTRY OUTLOOK

Year to date through July 11, 2014, the S&P Oil & Gas Drilling Index was up 4.0%, while the S&P Oil & Gas Equipment & Services Index advanced 22.1%, versus a 6.1% rise in the S&P 1500 Composite Index. In 2013, the Oil & Gas Drilling Index advanced 11.5% and the Oil & Gas Equipment & Services Index increased 30.1%, compared with a 30.1% increase for the S&P 1500. In an unusual turn, the fortunes of the two sub-industries deviated from each other in 2012. The S&P Oil & Gas Drilling Index advanced 4.2% in 2012, while the S&P Oil & Gas Equipment & Services Index declined 0.7%, compared with a 13.7% increase for the S&P 1500.

As of July 2014, our fundamental outlook for the next 12 months was neutral for the Oil & Gas Drilling sub-industry and neutral for the Oil & Gas Equipment & Services sub-industry. Energy prices are one factor in our outlook: as of July 2014, using data from independent economic forecaster IHS Inc., we were projecting that, in 2014, WTI oil prices would average $100.28per barrel. Meanwhile, the EIA projects that Henry Hub natural gas prices would average $4.49/MMBtu in 2014. Each sub-industry has its own factors, however, which we detail below.

Oil and gas drilling Our fundamental outlook for the oil and gas drilling sub-industry for the next 12 months is neutral. The April 2010 Macondo oil spill in the US Gulf of Mexico led to a drilling moratorium that was lifted in October 2010. Based on estimates from IHS Petrodata, the region should host 48 deepwater units by January 2015, up from the 33 that were working at the time of the Macondo accident. While demand is on the rise, we anticipate marketed supply to rise as well.

Longer term, we expect US deepwater exploration and development to expand, given our view of the GOM’s importance to the nation’s future energy security. Internationally, we look for continued strong demand for active ultra-deepwater units. In the shallow-water market, we see an ongoing shift in demand between high-specification and lower-spec units, as we expect the former to enjoy strong utilization while the latter category should see relatively lower utilization and dayrates, although even among lower-spec units, demand appears to be on the rise. We would not be surprised to see more divestitures or spinoffs of legacy units, such as Transocean’s November 2012 sale of 38 shallow-water rigs to Shelf Drilling, or Noble Corp.’s decision to spin off 45 of its 80 rigs (with most of the 45 being older jackups).

Onshore North American drilling activity in the second quarter of 2014 was an average count of 1,796 active units, up 5.1% from the same period in 2013. However, on a per-rig basis, the number of wells drilled (5.23) was marginally lower. With natural gas prices having recovered from a 2012 trough, we think that should spur greater interest in gas drilling, but technology improvements that enable faster drilling times should offset, resulting in land rig counts being flat to slightly up in 2014, in our view.

As of late June 2014, there were 146 jackups, 27 semisubmersibles, and 70 drillships on order or under construction. Of the 97 floaters under construction, 55% had obtained contracts, versus 14% for jackups.


Oil and gas equipment and services Our fundamental outlook for the oil and gas equipment and services sub-industry for the next 12 months is neutral. We see mid-single-digit growth in upstream capital spending in 2014. While we still view the longer-term growth rate in upstream capital spending as a secular positive, we harbor some concerns about near-term weakness outside of deepwater work. Our concerns stem in part from weakening global demand, even in emerging markets such as China; rising non-OPEC supply; and greater influence of the onshore US market, where we see oil services demand as more volatile and beset by pressures from oversupply. On the other hand, the expected influx of new deepwater rigs through 2014 should spur demand for related services, and deepwater work typically carries higher margins.

In 2013, a number of oilfield capital equipment companies struggled to manage supply chain issues, fueled in part by strong demand for offshore-related work. We think cost reduction efforts and improvements in supply chain efficiency will help margins in 2014. We also believe relatively steady WTI crude oil prices, projected to average in the $90/barrel–$105/barrel area through 2014, will help bolster customer confidence. All told, we see the best international improvements in the North Sea, Russia, and the Middle East, while we think that Brazil and Mexico are wild cards. A fundamental bear case for oilfield services (not our current view) would likely be predicated on two fronts. First are macro drivers, to the extent that concern over sovereign debt levels creates credit problems for upstream customers, placing project approvals at risk. Second are political drivers, to the extent that unrest in places such as Iraq, semi-autonomous Kurdistan, Egypt, and Libya worsens in 2014. We think cost increases will be manageable, while we expect greater regulatory oversight in the US Gulf, which, depending on the extent of any new rules, could increase the costs involved in deepwater exploration and development there, potentially dampening supply growth.


INDUSTRY PROFILE

Contract drilling companies and the oilfield services industry

The equipment and oilfield services industry is a highly diverse and still quite fragmented industry that serves to support activities of the world’s oil and gas producers. Through their two primary segments, contract drilling and oilfield services, companies within the industry offer a wide range of products and services that oil producers generally do not source in-house. Industry companies also provide technical expertise on an as-needed basis.

More than 10,000 companies operate within the industry in the US alone, according to the American Petroleum Institute, an industry association. They vary enormously in size, from Fortune 500 companies such as Schlumberger Ltd.—which had $45.3 billion in revenues in 2013 and 123,000 employees working in 85 countries—to small retailers and consultants that operate locally with only a handful of employees.

Almost all of the industry’s revenue is derived from the capital and operational spending budgets of oil and gas producers. On a worldwide basis, total upstream capital expenditures (capex) were projected at $764 billion for 2013, a 6% increase over 2012, according to the November 2013 forecast of IHS Herold Inc., an energy research and consulting firm. Further, according to its Global Upstream Performance Review, published in August 2013, IHS Herold estimated a 2.5% increase in worldwide upstream capex for 2014. According to the firm, rising costs remain a major driver of the rise in industry spending, contributing to just under half of the year-on-year rise in E&P capex seen during 2012.

PLAYERS GROW AS INDUSTRY CONSOLIDATES

The once highly fragmented oilfield services landscape has been altered dramatically by merger activity since the mid-1980s. Companies have consolidated in response to heightened competition that requires them to offer a broad range of products and services, and often have found it more efficient to acquire other companies that possess the technologies they seek than to develop them in-house. Today, many service companies participate in several market segments in order to offer a wide range of products and services. In this way, they have become total-solution providers to the oil and gas industry.

Another incentive to merge is the stock market: plunging stock prices, sometimes sparked by declining commodity prices, can make smaller companies ripe targets for larger, more financially stable players. Larger companies can also better afford to invest in new research and development (R&D) efforts, which is especially important given the growing need for high-technology solutions in oilfields around the world.

The four largest oilfield services players (ranked by market capitalization as of August 2014) are Schlumberger Ltd., Halliburton Co., National Oilwell Varco Inc., and Baker Hughes Inc., each with market caps in excess of $29 billion. The next tier of diversified oil services and oil capital equipment companies includes Cameron International, FMC Technologies, and Weatherford International Ltd. Smaller companies frequently develop expertise in particular niches of the oilfield services industry. FMC Technologies and Cameron International, for example, provide oilfield capital equipment to others in the industry and compete for lucrative subsea project awards, whereas Weatherford is a broadly diversified oil services company that competes globally, primarily with Schlumberger, Halliburton, and Baker Hughes.

With a few exceptions, such as Transocean Inc. and Noble Corp., contract drilling firms tend to be smaller than their counterparts in the oilfield services sector. Some of the important players in this subsector include Patterson-UTI Energy Inc., Nabors Industries Ltd., and Rowan Cos. Inc. Ensco joined the league of large drilling firms after acquiring Pride International Inc. in a stock-and-cash deal in May 2011. In a press release dated May 31, 2011, Ensco said that the acquisition has expanded its deepwater fleet with drillships assets, and increased its presence in the emerging markets of Brazil and West Africa. In the last lengthy industry shakeout, in 2002 and 2003, smaller players sold out to larger, better-capitalized competitors. According to


the 2010 NOV Downhole Rig Census, there were nearly 700 US rig owners in 1987; by 2003, there were just 179 rig owners, although that number rebounded to 325 owners in 2011, an increase of one versus 2010. In 2012, however, the number of owners fell by 8 to 317, according to the 2012 NOV Downhole Rig Census. In 2013, the number of owners fell to 313, according to the 2013 NOV Downhole Rig Census.

INDUSTRY TRENDS

The revenue base of the equipment and oilfield services industry relies on oil and natural gas producers’ upstream capital spending. These companies set aside significant amounts of money each year for exploration and development activities.

INCREASE IN OIL AND GAS CAPITAL SPENDING

Capital spending budgets of oil and gas companies—from which almost all revenue for equipment and service providers is derived—grew significantly in recent years. Oil companies were encouraged to invest in their expanding their own operations, largely due to tight supply conditions and rising demand for crude oil and natural gas. IHS Herold, a research and information services company, reported that total finding and development (F&D) spending and total capital spending both increased by 13% to $587.6 billion and $626.7 billion, respectively, in 2012. It also estimated that capital spending had risen 3% in 2013 and would increase 2.5% in 2014.

IMPLICATIONS OF ENHANCED REGULATORY OVERSIGHT: COSTS ON THE RISE

The regulatory environment has witnessed various changes since the Macondo oil spill in 2010. The Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), an agency within the US Department of the Interior, was reorganized and replaced by two independent entities: the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE). The two agencies introduced stricter regulations, which entail a greater number of fail-safe measures on rigs, more regular maintenance of offshore drilling equipment, and more rigorous use of tests to ensure well stability.

These regulations are adversely affecting the cost structure of the contractors. As part of the regulations, the contractors were required to get their blowout preventers (BOPs) certified, but additional measures, such as

Table B01: GLOBAL UPSTREAM PERFORMANCE

GLOBAL UPSTREAM PERFORMANCE(Based on 226 global oil and gas producers surveyed; all averages are for the years ended December 31, 2012 ʬ)

FINDING & DEVELOPMENT RECYCLE RESERVE REPLACEMENT ORGANIC RESERVE

- - - - - COSTS* ($/BOE) - - - - - - - - - RATIO (%)** - - - - - - - - - - - COSTS† ($/BOE) - - - - - REPLACEMENT‡ (%)

1- YEAR 3- YEAR 1- YEAR 3- YEAR 1- YEAR 3- YEAR 1- YEAR 3- YEAR

REGION AVG. AVG. AVG. AVG. AVG. AVG. AVG. AVG.

Africa/Middle East 28.30 22.79 263.7 284.0 27.60 21.89 89 103Latin America 18.37 20.22 335.3 272.5 18.41 19.91 105 114Russian-Caspian 3.96 4.31 531.4 507.0 3.85 3.99 263 214Asia-Pacif ic 33.72 24.49 150.6 194.8 33.51 23.95 100 115Canada 20.92 17.85 140.5 157.4 20.57 17.47 196 222US 44.97 23.51 102.2 173.2 32.33 20.21 158 248Europe 51.36 23.45 135.2 245.1 44.24 21.86 56 88

Worldw ide 21.90 18.78 220.1 244.8 20.35 17.27 146 161*F&D costs incurred (total costs incurred minus proved acquisition costs) divided by oil and gas additions (oil and gasrevisions plus extensions and discoveries plus improved recovery). **Recycle ratio is a Standard & Poor's calculation; itrepresents netback of oil and gas (revenues less production and transportation costs, before SG&A) divided by reservereplacement costs. †RRC represents total costs incurred (exploration plus development plus proved and unprovedacquisitions) divided by oil and gas additions (revisions plus extensions and discoveries plus improved recovery pluspurchases). ‡ORR represents oil and gas revisions plus extensions and discoveries plus improved recovery, divided bytotal production. ʬ Latest available.Sources: IHS Herold Inc.; S&P Capital IQ.


requiring extra sets of shear rams on these BOPs, could be taken. In its 2012 first-quarter report, Transocean mentioned that enhanced regulations have affected revenues, costs, and out-of-service time, and

it was unable to predict with certainty the magnitude of enhanced regulation going forward. Atwood Oceanics Inc., in its first quarter ended March 2012, stated that the cost for its Vicksburg rig had increased due to increased equipment costs related to a planned regulatory inspection.

In April 2012, Rigzone, an offshore drilling industry research and information site, published that the amount exploration and production (E&P) companies are paying for insurance is 20% higher than the pre-Macondo level. The article states that

one of the reasons for the higher cost is the extra expense companies have to pay to regain control of the well. In the “Big Spenders” survey conducted by the Economist Intelligence Unit in 2012, 82% of the directors and policy makers surveyed said that they either strongly or somewhat agree that regulatory issues have become more important in the post-Macondo period. More than 30% of respondents regarded increasing regulation as the main challenge for their companies in the next 12 months.

NEED FOR IMPROVED TECHNOLOGY FUELING MORE M&A ACTIVITY IN OILFIELD SERVICES…

Ecolab Inc., the largest provider of chemicals and services for water and wastewater treatment, acquired closely held Champion Technologies Inc., a specialty chemical company catering to the upstream and midstream oil and gas markets, for $2.2 billion in cash and stock in April 2013. With this acquisition, Ecolab believes it is the largest oilfield chemicals supplier in North America. This is the second purchase by Ecolab of a company that makes energy-related chemicals. In 2012, Ecolab completed the acquisition of Nalco Holding Co., a maker of chemicals used in water treatment, pollution control, and energy conservation.

In February 2013, National Oilwell Varco Inc. completed its acquisition of Robbins & Myers Inc. for $2.5 billion. Schlumberger acquired Tesco’s Casing Drilling division for $45 million in April 2012. Schlumberger president Jean-Francois Poupeau said that Casing Drilling’s technology would enable it to construct wells where the use of conventional technology has proven difficult.

The single largest deal in 2011 was Ensco’s acquisition of Pride International for about $9 billion, slightly lower than the $11.0 billion deal in 2010 where Schlumberger acquired Smith International. A variety of M&A transactions occurred in the oilfield services sector in 2011, primarily by large players in the industry. The transactions focused mainly on oilfield capital equipment and related services. For example, in early 2011, Acergy S.A. completed its $3 billion merger with Subsea 7, which we think was driven by interest in subsea projects.

Also in 2011, General Electric Co. was involved in two oilfield capital equipment deals. In one deal, a GE subsidiary, Vetco Gray, spent $1.4 billion to acquire Wellstream Holdings to help grow its industrial business product lines. In the second deal, GE acquired the well support division of John Wood Group for $2.8 billion. GE believes that the acquisition will enhance its high-specification product and service offerings in unconventional oil sources. Using downhole pump “artificial lift” technology for brownfield expansion, GE can now cater to oil demands from mature oil fields.

…while some companies divest to focus on core capabilities Core capabilities have started to be the focus for companies in the sector. In its fourth-quarter 2013 conference call in February 2014, Weatherford International said that it had identified five core business lines related to well construction, formation evaluation, as well as completion and production work, where it would continue to invest, but that non-core businesses would be made available for divestitures. In May 2012, Schlumberger sold its Wilson distribution business to National Oilwell Varco. It had acquired the Wilson business as part of the acquisition of Smith International in 2010. 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.

Table B14: AVERAGE BUILD COST

AVERAGE BUILD COST(In millions of dollars)

DRILL- SEMISUB-

PERIOD SHIP JACKUP MERSIBLE

2013-2016 692 225 5802009-2012 723 201 5792005-2008 709 156 5812001-2004 360 130 521Source: RigBase.


LATEST TECHNOLOGY DEVELOPMENTS: OIL SANDS…

There have been some recent developments in technology in Canadian oil sands—both for in-situ development (whereby the raw product, the bitumen, is brought to the surface but the sand is left behind) and for mining. According to the Spring 2013 issue of Energy Focus, a UK-based trade publication, 51% of oil sands production comes from mining techniques, with the other 49% being in-situ. Mining the oil sands results in the creation of tailings (i.e., the residue comprised of water, sand, silt, fine clay particles, and residual hydrocarbons after the bitumen is removed), and the size of tailings ponds can be significant. Syncrude Canada Ltd., for example, is experimenting with a technique called thin-lift drying. Under this technique, the tailings (which, if left alone, would have the consistency of a milkshake), are pushed into thin layers, after which sunlight will dry them out and help the company reclaim the land.

On the other hand, in-situ development is conducted with steam. The bitumen is heated up with steam, and achieving a low steam-to-oil ratio (SOR) is considered desirable. There are two main technologies that drive such development: cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD). As noted in Energy Focus, newer technologies are being evaluated. One such technology involves injecting heated solvent vapor into the reservoir, heating it up, dissolving the bitumen, and making the extraction process faster. A second technique is called Toe-to-Heel Air Injection, whose goal is to reduce greenhouse gas emissions and water use. In this process, air is injected prior to combustion, which creates the heat to melt the bitumen.

…and water usage Challenges with water management are high, because horizontal drilling in shale plays results in multiple barrels of produced water for every barrel of produced oil. A new water treatment approach, which Baker Hughes experimented with in the Permian Basin, was highlighted in the November 2012 issue of World Oil. In this pilot project, Baker tested the viability of reusing produced water and flowback water from its operations. With electrocoagulation technology, an electric current is introduced to the water, which destabilizes suspended, emulsified, or dissolved contaminants in the water (such as suspended solids or heavy metals). In this pilot project, virtually all of the suspended solids and heavy metals were removed, preventing potential formation damage when that water is reused in fracking fluids.

WILD CARDS: BRAZIL AND IRAQ

The extent to which Brazil and Iraq significantly ramp up their capital spending on energy projects is the biggest indeterminate factor for oil services demand. In our view, both countries have enough work on the drawing board to make a major impact on demand and, thus, on pricing of services.

Brazil: vast unexploited reserves Massive oil discoveries in recent years have made Brazil the world’s 11th largest oil producer. In addition, discoveries in the subsalt layer of the Santos Basin have indicated the huge potential for unexploited reserves.

Tupi, the Brazilian ultra-deepwater field in the Santos Basin, was heralded in November 2007 as having potentially recoverable volumes of crude oil and natural gas in the range of five billion to eight billion barrels of oil equivalent. In December 2010, Petróleo Brasileiro S.A. (Petrobras), Brazil’s state-owned oil company, mentioned that the Lula field in the Tupi area has 6.5 billion barrels of recoverable oil and equivalents, and the Cernambi field at Iracema holds 1.8 billion barrels, which was in the range of its previous expectations. According to the January 2014 Brazil Oil & Gas Report from Business Monitor International (BMI), a market research firm, Brazil’s production of oil and other liquids will increase to 3.9 million barrels per day by 2022, compared with 2.3 million barrels per day in 2013. According to the US Energy Information Administration (EIA), a statistical agency in the US Department of Energy, Brazil’s proved estimated oil reserves stood at 140 billion barrels as of October 2013 (latest available).

Petrobras believes that it may double domestic output to 4.9 million barrels of oil equivalent a day before 2020 if it adds output from Carioca and other discoveries. Additionally, the company has made two new oil and gas discoveries in Brazil’s Espírito Santo basin that are 115 km offshore and around 1,900 meters deep. According to data from the World Rig Forecast released by IHS Petrodata in January 2012, Petrobras has cancelled its 21-rig newbuild tender that was to be built in Brazil and has decided to negotiate directly with


the two participants, Ocean Rig and Sete Brasil Participações S.A. In November 2012, Petrobras cancelled the order for five drill ships which it had agreed to lease from Ocean Rig Group in February 2012, due to better-than-expected production from existing wells in the Santos Basin. Petrobras accounts for about 22% of the world’s deepwater production. Such discoveries in the homeland are likely to give the company an edge in becoming a leader in the deepwater market, tapping the deepwater discoveries in other regions like Africa with its expertise.

These discoveries could boost to Brazil’s output, but they pose significant challenges to oil and gas operators. These reservoirs lie below a layer of salt more than one mile thick, with temperatures exceeding 500 degrees Fahrenheit, in waters that are as deep as 10,000 feet. As the costs of overcoming these hurdles are likely to be considerable, it is not yet clear whether the obstacles will serve to discourage development. These demand highly advanced and specific technologies to meet different requirements.

In addition, strict preventive measures must be developed to avoid the prospect of another Macondo-like disaster. Even relatively minor leaks are fraying governmental nerves. One example is the November 2011 incident at an appraisal well operated by Chevron. That well, which was being drilled at the Campos Basin’s Frade field at a depth of about 1,184 meters, resulted in oil leakage of about 200–300 barrels per day (less than 1% of the estimated flow rate from Macondo). Although the company managed to contain the leak, it is having a hard time dealing with the Brazilian government, which has strict rules and regulations for its oil exploration activities. In November 2012, Chevron offered to pay $150 million to settle the lawsuit. The prosecutors had initially asked for nearly $20 billion in damages, but they now seem to agree on the amount offered by Chevron. The incident raised concerns in the country regarding drilling operations in its waters and zero tolerance for adverse events, especially given the huge investments that the government will be putting forth in development of the resource base.

Petrobras has already planned to invest about $236.5 billion to develop deepwater offshore fields through 2016. As the subsalt discoveries continue, the government is taking steps to restructure the industry to get most of the benefits of the new developments. The Petrobras stock sale in September 2010 increased the government’s stake in the company to 48% from 40%. The government has developed a new production-sharing agreement for subsalt areas, under which Petrobras has been made legal operator for all the fields and owns a minimum 30% in all new projects. The government formed Pré-Sal Petróleo, a state enterprise that will own all subsalt reserves and represent the government in all decisions related to subsalt ventures. The government is also forcing operators to make equipment purchases from the domestic market when they are much cheaper to purchase abroad, and is imposing strict requirements on the subsalt projects; both of these actions are likely to hinder the company in achieving its optimistic targets.

The government of Brazil intends to increase the contribution of the oil and gas supply chain to the economy, which currently is around 10%. It expects Petrobras and its suppliers to create jobs within the nation, but a tight labor market is making it difficult for these companies to do that. Further, the local-content requirement of the government is slowing the pace of development in Brazil. Production in newly found reserves need sophisticated technologies, and Brazilian oil services companies are struggling to meet the demand. According to a study by Booz & Co., Brazilian players in the oil services industry charge 55% more than their international counterparts do. This is due to a higher tax burden, higher borrowing costs, and infrastructure bottlenecks. These reasons have led Petrobras to forecast no production growth in 2013, in spite of the country having 14.0 billion barrels of oil equivalent (BOE) in proven reserves. Irrespective of the challenges, we believe that the trend of subsalt discoveries will boost the oil production of the country as and when they materialize and will place Brazil among the top oil-producing countries, consequently opening up a huge market for oilfield service providers.

Iraq: promise and challenges Iraq has been one of the most promising spots for oil services companies over the past few years, and the country’s government has signed contracts with E&P majors for oilfield development. According to industrywide estimates, Iraq’s oil production capacity is likely to increase multiple times provided the country manages to overcome the many challenges that threaten its expansion plans. However, as Iraq’s


terms and conditions were not economically favorable, the response from foreign companies to the May 2012 Iraqi oil and gas auctions was lukewarm.

In the past 30 years, three wars, neglect, and investment restrictions by the United Nations have left Iraq’s oil infrastructure severely damaged and badly in need of repair, modernization, and expansion. The security concerns in the country, coupled with political tensions, have raised questions regarding the production targets set for the country. Further, there has been growing tension between Kurdistan and the central government. Kurdistan, an autonomous state since 1970, is independently developing its own oil resources, and is wooing major oil companies by providing lucrative production-sharing contracts. In January 2013, Kurdistan’s Natural Resources minister said that the state was in talks with several major oil companies to operate oilfields. In November 2011, Baghdad had blacklisted ExxonMobil from bidding in Iraq after the company gained the rights to six concessions in Kurdistan.

Chevron. In July 2012, Chevron moved into Iraq by buying 80% interests in the Sarta and Rovi blocks from Reliance Industries of India. Further, Total of France bought 35% of the Harir and Safen blocks from Marathon Oil, while Gazprom of Russia farmed the Garmian block operated by Canadian company Western Zagros.

ExxonMobil. In April 2011, ExxonMobil awarded a contract to Halliburton to provide drilling services for 15 wells in the West Qurna oil field in southern Iraq utilizing three drilling rigs. In August 2010, ExxonMobil received a letter of intent from Royal Dutch Shell to develop the Majnoon field in southern Iraq, one of the world’s largest oilfields, and to serve as project manager with Nabors Drilling (a unit of Nabors Industries) and Iraq Drilling.

Baker Hughes. In 2010, Baker Hughes announced it signed a three-year agreement with Iraq’s South Oil Co. (SOC) to supply wireline technologies to SOC and other Iraqi oil and gas producers and help develop local Iraqi wireline logging capabilities. In its fourth-quarter 2011 conference call, the company said that it was in the process of finalizing a contract with Eni SpA, Italy’s biggest energy company by market value, to drill 60 wells and manage four rigs in the Zubair oilfield. According to the company, this contract, worth an estimated $640 million, would be the biggest award to date for the company in Iraq. Earlier, in August 2011, the company received a contract from LUKOIL, Russia’s largest crude producer, for providing drilling and completion services for 23 wells in the West Qurna field.

Weatherford International. This company also provides various oilfield services at the South and North Rumaila Fields in Basra; the Buzurgan Field in Missan; and at other oil and gas locations in Iraq. In October 2011, Weatherford won a deal worth about $200 million to set up initial production facilities at the Garraf oil field in southern Iraq, according to the Wall Street Journal on October 19, 2011. As a part of the deal, Weatherford would construct a degassing facility with two trains, each having a capacity of 50,000 barrels per day. The work would also include the construction of storage tanks and other infrastructure. Earlier in 2011, the company won a deal worth around $52 million to drill 11 wells in the same field.

Schlumberger. In May 2011, Schlumberger received a contract from a group headed by ExxonMobil to drill wells in the oilfield in West Qurna, Iraq. In June 2011, Russia’s Gazprom Neft, the oil arm of Gazprom, awarded Schlumberger a three-year contract to drill the first wells at its Badra oil project in Iraq.

Amid continuing conflict and internal political unrest in Iraq, it is difficult to measure its oil reserves, which are estimated to range from 115 billion proven barrels (according to the EIA) to 143 billion barrels (according to the Organization of Petroleum Exporting Countries, or OPEC). The country’s oil reserves are considered to be the fifth largest in the world, after Saudi Arabia (267 billion barrels), Venezuela (211 billion barrels), Canada (174 billion barrels), and Iran (151 billion barrels).

While we think some of the world’s largest oilfield services companies could earn billions of dollars from contracts in Iraq, above-ground problems in the region since the emergence of the ISIS organization are superseding the below-ground potential, and timeline for resumption of normal activities is impossible to say.


THE MOVE TO THE EASTERN HEMISPHERE IS ONGOING

In a move to increase its business in the Eastern Hemisphere, Halliburton opened its corporate office in Dubai in 2007. The company said, “The Eastern Hemisphere is a market that is more heavily weighted toward oil exploration and production opportunities and growing our business here will bring more balance to Halliburton’s overall portfolio.” In 2010, Halliburton revealed its plans to increase its manufacturing production in the Eastern Hemisphere. Baker Hughes stated in its 2010 annual report, “We also are investing in manufacturing capacity in the Eastern Hemisphere to produce products in Asia and the Middle East, closer to our customers.”

The industry feels strongly that the Eastern Hemisphere will offer abundant opportunities for growth and open new unexplored markets. For instance, the revenues for Schlumberger, Baker Hughes, and Halliburton in 2013 for the Eastern Hemisphere grew by 14.6%, 14.3%, and 16.8%, respectively, year over year, whereas their Western Hemisphere revenue growth during the same period was up 2.6%, down 0.4%, and down 2.93%, respectively. For the same period, year over year, the operating margins for Eastern Hemisphere operations grew by 27.0%, 16.6%, and 21.5%, respectively, for Schlumberger, Baker Hughes, and Halliburton. Their Western Hemisphere margins in the same period were down by 4.9% for Schlumberger, down by 29.4% for Baker Hughes, and down by 12.7% for Halliburton.

OLDER OFFSHORE WELLS REACHING MIDDLE AGE

Oil and gas wells tend be to more productive in their initial years, when they generate greater output without requiring much maintenance. However, with the passage of time, it becomes increasingly harder to maintain the same pace of productivity. Unexpected downtime becomes more common, and multiple problems crop up one after the other. The upstream companies that own these wells are constantly searching for new ways to replace production. One such way is to find and develop new wells, but another way is to maximize the lifecycle production of an existing well. These operators have been drilling on land for decades, but drilling offshore (and particularly in deep water) is a more recent phenomenon. With aging wells, production problems are likely to be on the rise, and we think companies that help offer solutions in this regard will see an uptick in demand in 2014.

One such technique is rigless well intervention, in which a services provider brings in a dynamically positioned (DP) vessel to provide tools and services to boost production, without the need for a more expensive (and scarcer) deepwater drilling rig. Forgoing a drilling rig can save considerable time and money since the DP vessel is considerably cheaper to rent, requires a smaller crew than a drilling rig, and can be on and off the job faster than a drilling rig. Services providers such as FMC Technologies Inc., Helix Energy Solutions Group Inc., and Superior Energy Services Inc. all perform such tasks. In July 2012, Helix Energy Solutions Group entered into an agreement with Transocean to acquire the Discoverer 534 drillship for $85 million. Helix converted the drillship into a well intervention vessel in Singapore, after which it joined its intervention fleet in the Gulf of Mexico.

Another area of expertise relates to aftermarket servicing. In our view, the companies that install the original subsea equipment, such as FMC Technologies and Cameron International, should see an uptick in aftermarket demand. In the post-Macondo oil spill world, we think customers will see an advantage to having the manufacturer of their subsea equipment also service that equipment. The US deepwater aftermarket business ebbed in 2011 following the 2010 oil spill, but Gulf of Mexico deepwater drilling rose in 2012, increasing demand for aftermarket services.

Finally, new subsea innovations such as subsea separation should see rising demand. The ability to separate seawater from hydrocarbons at the seafloor helps producers in two ways: first, it gives their platforms more capacity to handle the flow of hydrocarbons; and second, it relieves some of the downward pressure on the well (since water is heavier than oil), which can also boost flow rates. FMC Technologies’ Marlim project offshore Brazil is the world’s first deepwater subsea water/oil separation project. Finally, given the water depths that all of this work is being done in (well above the limits for human divers), we see increased


demand for remote-operated vehicles (ROVs) that players such as FMC Technologies and Helix Energy provide. Overall, we think the aging deepwater population bodes well for the oil services space.

US Lower 48 shale plays shifting into crude oil, and out of natural gas As crews move out of natural gas and into crude oil, services companies are encountering temporary utilization problems. Schlumberger, in its first-quarter 2012 results, said that the transition of services activities from gas-rich to liquids-rich basins in North America affected its results as its fleet utilization was reduced. Baker Hughes, the third-largest oilfield services company, warned in March 2012 that it expected its pretax operating profit margin to fall sequentially in the first quarter of 2012, as North American explorers shifted to liquids from natural gas leading to higher costs and lower utilization. Baker Hughes’ pretax operating margin did drop 390 basis points in that quarter, sequentially, to 13.4%, before rebounding 10 basis points in the second quarter to 13.5%.

The rising demand for high-specification equipment will also be of benefit to services companies, with operators moving to harsher terrain forced by the low utilizations in Gulf. Companies are also investing in advanced technology and product development, as well as acquisitions to provide better services. For instance, Baker Hughes has developed a new line of drill bits that have six times the abrasion resistance of earlier bits, which will increase their productivity in harsh terrain areas where one might get a mere three or four runs out of a drill bit before having to replace it.

SHRINKING DEEPWATER LEARNING CURVE

Deepwater test drilling technology In their never-ending quest for new hydrocarbon resources, oil and gas producers have been searching in ever-deeper parts of the ocean for the large, long-life fields that have become increasingly rare in shallow waters and onshore.

Most offshore drilling takes place in relatively shallow water of 400 feet or less, but much of the undiscovered oil and gas resources are believed to be in waters of more than 3,000 feet, requiring deepwater-capable drilling rigs. A third generation of deepwater drillships is now under construction—ships that can drill as much as 40,000 feet below the seabed, in water that is 12,000 feet deep, using state-of-the-art technology.

At the same time, the high cost of drilling deepwater wells—a single deepwater well may cost $100 million or more—is driving innovations that minimize costs by cutting operating times. Transocean Ltd. patented its “dual activity” technology, in which drillships are equipped with two drilling stations inside a single derrick, allowing two drilling tasks to take place simultaneously instead of sequentially. Baker Hughes commercialized the MaxCor drilling technology, which involves a large diameter sidewall-coring tool that works in extreme environments and acquires larger core volume in less time.

New communication systems and fiber-optic sensors are under development that can help companies cope with both the harsh weather conditions of the North Sea and hurricanes in the Gulf of Mexico. BP plc created a 1,100-mile-long broadband fiber-optic communications network linking seven deepwater production facilities in the Gulf of Mexico with its offices in Houston; the company can expand the network to 64 different production platforms. The network is designed to help the company reduce the time that hurricanes force them to shut down production facilities. The network has been in operation for three years and is the most significant undersea investment to date.

Subsea well intervention goes rigless Producing wells require maintenance (e.g., to help avoid producing too much water and not enough oil and gas). Unfortunately, in high water depths, the cost of bringing in a floating rig to perform well maintenance (also called well intervention) can be so high—easily $400,000 per day or more—that the economics of well intervention do not make sense for the operator. Consequently, oilfield services companies that perform the interventions have a vested interest in finding a more economical method. As noted in the May 2010 issue of Marine Technology magazine, Schlumberger has introduced a rigless subsea well intervention system. The new system relies on reentering a subsea well to perform through-tubing work without a rig, while still enabling coiled tubing and wireline operations. According to the article, this procedure extends well


intervention capability to 3,000 meters (approximately a 9,000-foot water depth). The former BJ Services (now part of Baker Hughes) developed a similar Rigless Intervention System (RIS). RIS enables several well intervention operations, such as abandonments, conductors pre-installations, and workovers without support of a rig, thus considerably saving the rig time and cost.

Independence Project: small fields become economically viable In July 2007, the Independence Hub (I-Hub) platform, the Independence Subsea operation, and the gas pipeline known as Independence Trail began production. These three operations, known collectively as the Independence Project, have the capacity to gather, process, and transport about one billion cubic feet per day of gas, plus significant condensate production from 10 fields that lie in the east-central Gulf of Mexico. On an individual basis, these smaller deepwater fields would be cost-prohibitive to develop; the Independence Project ties them together, turning the entire group into an economically viable project.

The Independence Project is a hub-and-spoke project centered 110 miles southeast of the Mississippi River Delta. The “wheel” around the spokes covers a rectangular area of about 1,800 square miles. The completed project allowed five independent exploration companies to develop multiple deepwater natural gas/condensate discoveries in depths ranging from 7,800 feet to 9,000 feet. Deepwater fields traditionally require significant undiscovered volumes to justify the high costs of production.

By linking smaller fields, the Independence Project enables the participating companies to pursue recovery of two trillion cubic feet of gas reserves—10% of US gas supply from the Gulf of Mexico, or 2% of total US gas production—while keeping costs at manageable levels. The Independence Project features the world’s deepest suction pile installations, the world’s deepest subsea structure for future pipeline inline tie-in, and the world’s largest monoethylene glycol reclamation unit. Anadarko, the operator of Independence Hub, said in April 2013 that the Hub produced 206 million cubic feet per day (mmcf/d), net of royalties, in the first quarter of 2013, up from 191 mmcf/d in the fourth quarter of 2012; these numbers compare with approximately 0.9 mmcf/d produced back in June 2011.

Is subsea separation and compression a potential technological breakthrough? Subsea separation is an emerging technology in which oil and natural gas are separated from each other (and from non-hydrocarbons, such as rock cuttings and water) on the ocean floor, thereby eliminating the costly practice now in use of bringing crude oil and natural gas from deepwater wells to the surface for separation. This saves time and the cost of constructing flow lines to and from the surface—potentially, a two-mile journey—and improves overall recovery from the field.

In addition to subsea separation, the ability to compress natural gas at the seabed is something that, though not yet truly commercialized, could significantly improve the economics of deepwater drilling. Currently, natural gas is brought to the surface before being compressed; compression can be necessary when a reservoir’s natural pressure declines, thus reducing the flow of gas out of the reservoir. In March 2007, the partners in the immense Ormen Lange development in the North Sea announced plans to spend 2.5 billion Norwegian kroners (about US$416 million) to develop a subsea compression station to be placed on the ocean floor at a depth of 860 meters. The station would enable the partners to halve their operating costs over a 20-year period, versus compression performed on a platform at the surface. In November 2009, the partners opened the new subsea compression station.

Early results from subsea separation have been promising. Royal Dutch Shell applied subsea separation in its BC-10 project offshore Brazil, separating gas from liquids. According to an undated article on Rigzone.com, the BC-10 project was developed with 13 wells, six subsea separators and boosters, and a floating, production, storage & offloading vessel (FPSO), and began producing heavy oil in July 2009. Similarly, Total’s Pazflor project offshore in West Africa employed a gas/liquid separation system. According to the Journal of Petroleum Technology, this project produced first oil in August 2011, less than 44 months after sanctioning, and generated total production of 13.7 million barrels in 2011, versus an initial forecast of 5.3 million barrels. Finally, Shell’s Perdido deepwater project in the US Gulf of Mexico (moratorium notwithstanding) is expected to use subsea separation technology. Key providers of such technology include FMC Technologies Inc., Cameron International Corp., GE Oil & Gas, and Expro International Group Ltd.


Brazilian discoveries: high potential, but challenging In November 2007, the Brazilian ultra-deepwater field known as Tupi in the Santos Basin was heralded as having potentially recoverable volumes of crude oil and natural gas in the range of five billion to eight billion BOE. In May 2008, Petrobras estimated first production from this field by the end of 2010. The Carioca field, a similar find within the Santos Basin, was first believed to contain even bigger quantities of hydrocarbons, but Petrobras said in April 2008 that it was premature to comment on reserve potential from this latter play. In February 2010, the company reaffirmed estimated recoverable oil volume of five billion to eight billion barrels from Tupi, but also noted that its ongoing extended well test, once completed, would yield greater clarity on the number of platforms needed to develop and produce the field.

The estimated size of the Tupi field alone is large, but both the Tupi and Carioca fields offer significant challenges to oil and gas operators. The reservoirs lie below a layer of salt more than one mile thick, with temperatures exceeding 500 degrees Fahrenheit, in waters that are as deep as 10,000 feet. Because the costs of overcoming these hurdles are likely to be considerable, it is not yet clear whether the obstacles will serve to discourage development. It is estimated that the Santos Basin could require 200 to 300 wells to be drilled, with each well potentially requiring a $100 million investment. One of the major uncertainties in developing the Basin is the projected volume of hydrocarbons to ultimately be recoverable, and with infrastructure requirements dependent, in many respects, on volumes, planning is a major challenge. Logistically, a pipeline from the Tupi field may need to be 18 inches in diameter, but run 200 kilometers from shore; projects may require floating and onshore liquefied natural gas (LNG) facilities as well.

Petrobras announced in 2010 that it had contracted 20 rigs to commence work on these pre-salt plays in 2011 and 2012, and planned to construct 28 rigs in domestic shipyards by 2014. However, the company cancelled the tender and is now negotiating directly with two players, Ocean Rig and Sete Brasil. We believe that the focus on using domestic shipyards may need to be modified to include foreign construction, given that Brazil’s deepwater shipyard industry is relatively less developed compared with the shipbuilding heavyweights in Asia-Pacific. A December 10, 2013 article in Upstream magazine noted that “Existing Brazilian shipyards such as Brasfels are already working at full capacity. On the other hand, new facilities such as Estaleiro Rio Grande and Estaleiro Atlântico Sul are struggling to overcome teething problems while coping with a flood of orders for tankers, floating production, storage and offloading vessels and—assuming the current rig tender results in at least one major award—drillships.”

Rig design developments According to a paper presented at the Deep Offshore Technology 2010 industry conference, and noted in the industry publication Offshore, the INTECSEA/WorleyParsons Group has developed a deepwater semisubmersible platform that could cut design costs for new semis. The four columns of the semisubmersible, which support the “topsides” structure, are designed to have free-flooding inner chambers. The added mass from the water within the columns suppresses the motion of the semisubmersible, and enables the construction of the hull of the rig with 33% less steel. Given the high impact of steel costs on rig construction costs, this new design could enable rig contractors to reduce construction costs.

Offshore Source magazine noted in August 2009 that the COSCO shipyard in China had succeeded in completing the construction of the first circular drilling rig. Named the Sevan Driller, the rig is capable of drilling through 12,500 feet of water, and can drill wells of nearly 40,000 feet.

Developments in reducing nonproductive time It should come as no surprise that different oilfield services providers and oil capital equipment manufacturers are taking different approaches to solving nonproductive time (NPT). One such problem relates to directional drilling.

An April 2012 article in World Oil magazine featuring drilling technology, highlights some of the tradeoffs in directional drilling. Generally speaking, operators can use one of two basic approaches to directionally drilling a well: use either a positive displacement motor (PDM) or a rotary steerable system (RSS). The PDM has the attractive feature of being able to handle torturous changes in drill path better than RSS, but rate of penetration tends to be relatively low. This is because the drillstring stops rotating while a change in


direction is being prepared, and when the drillstring is not moving, there is increased risk of equipment becoming stuck in place. The RSS has the attractive feature of being able to maintain a relatively higher rate of penetration, but often can’t handle significant changes in the path being drilled, which leads to “sliding” and, again, potentially a loss of equipment in the hole. Thus, in either case, operators facing difficult wells (often the case in shale plays) are exposed to high risk of equipment failure.

A new tool called the PowerDrive Archer has been developed by Schlumberger to help resolve this problem. The new system has a “high build rate RSS” feature to it, which allows all external parts of RSS to rotate, helping with difficult changes in drilling angle. Similarly, Weatherford has come out with a new approach it calls “MotarySteerable directional control system”, which combines a PDM with a new steering technique called “targeted bit speed” that Weatherford believes can handle more difficult well paths, such as J-shaped or S-shaped well designs.

Efforts to reduce NPT are not limited to directional drilling. National Oilwell Varco Inc. has rolled out a new computerized application it calls Videometrix Motion Detection, which makes the life of a crane operator considerably easier. Typically, an offshore oilrig or producing platform requires regular supplies—such as replacement equipment, fluids used in drilling or production, and food—that are often loaded and offloaded via a crane from a neighboring offshore supply vessel. Such cranes might be in use every day, or even several times a day, for a given project. When winds pick up and ocean waves follow suit, this simple procedure can become tricky, raising the risk of an accident (e.g., if the crane operator misjudges the vertical distance between the deck and the item being lifted), or perhaps an increase in lost time as the operator waits until the waves are sufficiently tame.

National Oilwell’s new system provides the crane operator with real-time instructions on when an item can be put on the deck, and where, based on the motion of the waves. Ostensibly, this reduces time waiting for equipment to be deployed, which means reduced NPT. When customers are routinely spending upwards of $300,000 per day for deepwater developments (and, in some cases, as much as $500,000 per day), numerous small reductions in NPT can add up to a lot of money saved.

Developments in drilling technology for harsh terrain Baker Hughes has developed a line of drill bits called the Quantec Force PDC. According to the company, these drill bits have six times the abrasion resistance of earlier bits. We believe these kinds of bits will be attractive as rentals for operators in harsh terrain areas like East Texas, where one might get a mere three or four runs out of a drill bit before having to replace it. Fewer trips to remove a spent drill bit can translate into reduced NPT, which can translate into fewer days needed to drill a well.

Early warning system for well workovers FMC Technologies has introduced a Self-Configuring Multiphase Meter (MPM), which was acknowledged at the 2010 Offshore Technology Conference held in May 2010 in Houston as one of this year’s “Spotlight Recipients” for products that are new, innovative, have broad appeal for the industry, and make a significant impact. MPMs in general are designed to measure the intake of multiple flows (e.g., of oil and of gas) into the same pipe; benefits include early identification of a change in the health of an older field, which could suggest a workover is needed. The key benefits of this new offering, in our view, are enhanced accuracy of measurement, through higher-resolution image technology, as well as faster delivery of flow rates throughout the pipe. We would anticipate growing interest in this device in subsea applications.

RFID technology for downhole drilling According to an article in the November 2010 issue of World Oil magazine, common technological device called radio-frequency identification (RFID) is making its way to the oilfield. RFID tags are commonly used to track inventory in logistics and goods movement across the country. Now, RFID is being used to track assets downhole, which can help prevent the loss of expensive equipment. It can also be used to prevent breakdowns. For example, RFID can be used to detect internal pipeline corrosion, giving an advance warning so that the operator has time to address the corrosion before an accident occurs.


HIGH RISK, HIGH POTENTIAL IN ARCTIC DRILLING

Given the advanced age of much of the world’s mature oilfields—the US Gulf of Mexico being a prime example—it is probably fair to say that the vast majority of the “low-hanging fruit”—the relatively easy-to-extract oil and gas resources—are dwindling. Replacing those resources with new finds will be increasingly challenging for operators. The challenge may be both political (in terms of access to the resources) as well as geological (in terms of the problems presented by the terrain).

According to a study by the US Geological Survey (USGS), a scientific agency for natural sciences, 25% of the world’s undiscovered crude oil and natural gas resources are located in the Arctic and other cold regions. Given natural rates of decline at existing oilfields, this potential resource base appears important for the future. The USGS estimated that the Arctic might hold 90 billion barrels of undiscovered oil, with one-third of that amount in Alaskan territory.

Notwithstanding these large estimates, the technological challenges of Arctic conditions are immense. Various environmental, logistical, and political issues would need to be addressed. The cold temperatures of the Arctic create numerous problems. They can encourage the formation of hydrates (ice crystals) in the pipes, creating potential blockages for the flow of hydrocarbons to the surface. The presence of sea ice creates challenges when drilling. Health and safety issues arise: how does one evacuate a drilling rig if a major safety issue occurs when it is –35 degrees Celsius and there is little or no visibility outside?

Loop currents—oceanographic events where ocean flows change direction and loop around themselves—are unpredictable and can damage pipes or other oilfield equipment. When loop currents occur, which sometimes happens in the US Gulf of Mexico, operators sometimes cease work until the normal currents are restored.

Logistics considerations take on greater importance. Arctic operations are typically very far from existing infrastructure, and, if a part breaks, how long will it take to get the spare needed to replace it? Further, repair and maintenance work is likely to take longer to complete, even with a ready supply of spare parts.

Lastly, there may be political obstacles to developing Arctic potential as well. Last year, Russia’s claim to an exclusive Arctic zone prompted protests from Canada, the US, Norway, and Denmark. To the extent that ownership rights in the Arctic are contested by multiple nations, developments may be delayed.

In a report published on June 23, 2011, the USGS presented the independent evaluation of the perceived challenges in developing oil and gas resources in the Arctic. The key areas of concern identified in the study included climatic changes, effective oil spill risk assessment, preparedness, and response. However, the development of a comprehensive, quantitative, cumulative effects analysis for the Arctic Outer Continent Shelf (OCS), combined with the lack of available foundational geospatial data for the Arctic remained the major challenges to a complete understanding of the region.

SEISMIC TECHNOLOGY HELPFUL FOR HYDRAULIC FRACTURING

Tight gas, low-permeability natural gas formations (such as the shale plays discussed in the “Current Environment” section of this Survey) often require significant fracturing work to gain access to the resource base. In such formations, “frac jobs” are used to crack open the rock, hopefully enabling natural gas to flow from the reservoir. Hydraulic fractures create flow pathways, and then proppants (e.g., sand, fluids, slurries, etc.) are sent down to hold the new fractures open. There’s one problem: it’s not always easy to ascertain whether the proppants are doing their job, keeping the pathways open, or whether the pathways close down after the frac work.

In 2009, Mark Willis, a researcher at the Massachusetts Institute of Technology, discussed a new approach. In order to gauge the quality of frac jobs, one can utilize seismic data on the fractures. Since open fractures scatter seismic waves to a greater degree than closed fractures do, a review of the scattering of seismic waves may give some indication of the success of the frac jobs. Given that frac work is going to be increasingly needed as development of shale plays continues, interest in gauging frac job quality is likely to grow.


This microseismic technology is useful in other ways as well. According to World Oil magazine (March 2012), improving microseismic technology is helping to eliminate the guesswork when it comes to fracture placement. This, in turn, is helping reduce the risk of a vertical fracture growth into a freshwater aquifer.

OILFIELD SERVICES GROWTH FUELED BY TECHNOLOGY

Because of accelerating decline rates in mature reservoirs around the world, oil and gas producers are facing a difficult enough job just to maintain existing production, let alone to expand it. In addition, potential new reservoirs often are located in challenging geological conditions that may make it arduous to complete wells. Thus, advances in technology are critical to generating future production gains and maximizing recovery from existing fields.

In US land drilling, one of the greatest detriments to fully maximizing land rig capacity is the time needed to transport the rig to its new drilling location and “rig up” (prepare the rig to start drilling). National Oilwell Varco Inc.’s Rapid Rig was created to solve this problem: it was built for speed of transport and rigging up, with the capability of drilling in shallow to moderate well depths. The company also introduced its Drake rig, designed as a fit-for-purpose drilling rig for the Marcellus Shale plays, where the terrain demands a rig with a relatively small footprint.

The need to optimize reservoir performance and maximize recovery from producing fields is an issue affecting all producers. Core Laboratories NV employs patented and proprietary technologies to analyze rock samples for porosity and permeability, and provides products and services to minimize formation damage and maximize production. Another unit of the company leverages the data gained from its initial work to design and carry out production-enhancement projects to solve reservoir issues. On average, an oilfield produces only 40% of its total reserves through conventional techniques. Core Laboratories aims to lift that figure to 45%–47% by using its technologies. In an April 2009 interview in Marine Technology magazine, FMC Technologies noted that for a subsea field, only 30%–35% of the in-place oil is recovered, so new technologies that can improve reservoir utilization should create attractive value propositions for operators.

NEW RIG CONSTRUCTION COSTS MAY FINALLY SEE SOME RELIEF

The offshore drilling industry has steadily been increasing new rig construction since 2004 in order to meet demand as utilization rates spiked, especially for deepwater equipment. The cost of building a rig rose as well since there was a corresponding increase in demand for key raw materials such as steel. However, the recent pullback in upstream demand may provide some relief on construction costs. In February 2010, Diamond Offshore noted that a fully equipped floater, which at the peak of the market might cost $750 million to build, could likely be had for roughly $650 million.

How significant is the order book for future offshore rig supply? As of July 2014, the order book totaled 240 rigs, according to IHS Petrodata. However, there are two points worth noting. First, some companies that have yet to begin construction on new rigs (particularly companies with liquidity problems) may choose to walk away from their investments, and simply cancel the orders. Second, if rig demand drops significantly, contractors may respond to the current downturn by retiring some of the older rigs—something not seen to any great extent in years.

Many offshore rigs are nearing the end of their useful lives. There are a considerable number of older-technology rigs out there (mainly jackups and semis) that could be taken permanently off the market and, by doing so, better balance rig supply and demand fundamentals.

In 2010, total marketed supply was up about 1.3%, nearly matching the 1.5% increase in demand. In 2011, supply rose 4.7%, but demand increased 12.2%. In 2012, total marketed supply was up about 6.7%, slightly more than the 9.5% increase in demand. For 2013, marketed supply rose 6.9%.

Aging crew, lack of new blood The lack of “new blood” to replace veterans close to retirement is one of the longer-term problems facing the oilfield services industry. At the May 2010 Offshore Technology Conference, Schlumberger noted that


data from the Society for Petroleum Engineers indicated that the industry was still aging by more than 1.0 year every year, suggesting an insufficient number of new arrivals to the industry. This has long-term ramifications for job safety, in our view, because eventually there will be more inexperienced workers and fewer veterans to mentor them.

HOW THE INDUSTRY OPERATES

Drilling for oil and gas is a unique enterprise that requires experienced personnel and specialized equipment. Most oil and gas producers find it more cost-effective to hire expertise and source drilling equipment from outside contractors and suppliers than to maintain them in-house, giving rise to an ancillary services and equipment industry that fills the varying needs of the producers.

OFFSHORE, ONSHORE EQUIPMENT & SERVICES

There are four major types of equipment and services businesses: offshore oil rigs, onshore oil rigs, drilling equipment, and services. Drilling companies provide the rigs and operate them, either on a project or long-term contract basis. Typically, land drillers operate under varying types of contracts, with rates charged either by the day, foot drilled, or on an all-inclusive or “turnkey” basis. Offshore drilling contracts are mostly written on a daywork basis, with an occasional turnkey contract. (Contracts are discussed further in the “How to Analyze an Oilfield Equipment & Services Company” section of this Survey.)

Oilfield service companies provide the tools and services required to expedite the drilling of the well. These companies manufacture equipment or build it on site, maintain it once in operation, and provide related products and services, including geological evaluations. Their customers may include oil and gas producers, as well as drilling companies. Service providers encompass the group of companies that provide ancillary services (often of a highly technical nature) to the actual drilling.

Offshore rigs Offshore drillers own and operate rigs known as mobile offshore drilling units (MODUs) that are used to drill for oil and gas in coastal or inland waters of varying depth. These rigs are highly complex structures, with large work crews that often live on board, and the companies that own them tend to specialize in that specific task rather than offering onshore drilling rigs as well.

Offshore rigs are classified according to their maximum operating depth, with some rigs designed for drilling in shallow coastal waters (up to 550 feet), while others work in intermediate waters (550 feet to 5,000 feet); recently, rigs have been drilling more in deepwaters (5,001 feet to 7,500 feet) and ultradeepwaters (7,501 feet and deeper). The deepest water where drilling activity is currently taking place is about 10,000 feet. The target reservoir may be as much as 30,000 feet below the sea floor. (Drilling rigs are distinct from offshore production platforms, which are stationed above a group of wells that have begun producing. These platforms are mostly owned by the oil and gas producing companies, not by the oilfield services companies, and therefore are not discussed in much detail in this Survey.)

Rigs are also defined by their mechanism of support, either from the bottom (submersible or jackup) or floating (semisubmersible or drill ship).

Jackup rigs. The jackup is a very popular type of offshore rig, generally operating in shallow waters less than 400 feet deep. (Rowan Cos. Inc.’s Gorilla jackups, however, can operate in depths down to 550 feet.) Jackups are further categorized based on their support system (mat-supported versus independent leg-supported) and on the position of the drilling system on the rig (slot versus cantilever). The modern independent-leg jackup rigs have three legs on a triangular-shaped barge hull; others have four or more legs on rectangular hulls. Once the hull is positioned on the drilling site, the legs are lowered until they reach the ocean floor. The legs are then used to raise (or “jack up”) the hull above the height of the highest anticipated waves.

Semisubmersible rigs. These rigs are used in intermediate water to ultra-deepwater. Semisubmersibles typically have two or more air-filled steel floats (pontoons) on which the rig sits, held in place by massive


anchors. Because the pontoons usually are submerged a few feet below the water’s surface, such rigs offer the highly stable drilling platform needed to drill in very deep water. A semisubmersible can be moved to a new drill site by towboats. Some semisubmersibles, however, are self-propelled, housing built-in power units that can move them from one site to another.

Drill ships. These vessels, similar in appearance to ships used for transportation, drill while floating on the water’s surface. Drilling operations take place through a hole in the center of the ship’s hull, called a moon pool. A large derrick is mounted permanently above the moon pool, much like a land rig.

Drill ships can drill holes up to 30,000 feet deep while in water up to 12,000 feet deep; these ships are typically used for exploration activities, especially in remote locations. Highly mobile, they can be moved from one site to the next quickly and inexpensively. They are relatively unstable, however, and can be tossed about by large waves and currents. Many drill ships are equipped with dynamic positioning systems that enable the ship to maintain its location, without anchoring, by activating thrusters to keep the ship from straying too far from its desired location.

Onshore drilling rigs These rigs are generally categorized by how deep they can drill. Light-duty rigs can drill to depths of up to 5,000 feet; medium-duty rigs, up to 10,000 feet; heavy-duty rigs, up to 16,000 feet; and very heavy-duty rigs, up to 30,000 feet. Most US land wells are drilled by medium-duty rigs; very few are drilled by light-duty rigs.

Typically, a single rig can drill about three shallow wells or two intermediate-depth wells in one month. A deep well may take four to 12 months to complete. Currently, most of the natural gas wells in the US are drilled at depths of 6,000 feet to 12,000 feet.

Drilling equipment Normal drilling operations proceed from drilling the hole, to adding a new joint of pipe as the hole deepens, to hoisting the drill string out of the hole to put on a new bit and running it back to the bottom. The drill string, also called the drill column or stem, is an assembly of drill pipe and collars that extends from the rig floor to the bottom of the hole. The process of raising and lowering it with a new drill bit is called a “round trip.” Finally, a large diameter steel pipe (known as a casing) is run into the hole and cemented at various predetermined intervals.

The drill bit. The drill bit is a forged metal tool equipped with sharp inserts (or “teeth”). Situated at the bottom of the drill string, it is rotated rapidly in order to penetrate the surface strata and excavate the hole into which pipe is laid to construct the well.

There are dozens of types of bits, ranging in diameter from about four inches to 48 inches. Each is designed for use in specific kinds of rock formations. The shape of the bit and spacing of its cutting teeth are designed to maximize the bit’s rate of penetration and durability for a specific kind of rock. Three companies dominate the market: Smith Bits (a unit of Smith International Inc.), Hughes Christensen Co. (Baker Hughes Inc.), and Security DBS (Halliburton Co.).

Drilling fluids. Drilling fluids (or “muds”) lubricate and cool the rotating drill bit, help loosen and flush away cuttings of rock and earth, and control downhole pressures. These fluids are complex mixtures of clays, polymers, and chemicals, custom blended to meet the downhole conditions of a particular well. Fluids are pumped down through the drill string and bit, and they flow back to the surface on the outside of the drill string. At the surface, the cuttings are removed from the mud, which is reused.

In some cases, air provides significant advantages over muds as a drilling lubricant. Air drilling is less expensive, permits faster penetration, and extends the bit’s life longer than mud does. Air is not as effective as mud in controlling downhole pressures, however, and therefore is not suited for all formations.

Revenues for the global market in drilling fluid are driven by the total footage drilled. They are also sensitive to the amount of deep drilling, as well as to environmental regulations. The drilling fluids market


includes Halliburton’s Baroid Drilling Fluids, M-I Swaco (a 60/40 joint venture between Smith International and Schlumberger Ltd. before these two parties merged in 2010), and Baker Hughes.

Mud pumps. Large, heavy-duty pumps pick up mud from large storage tanks and move it down the drill pipe and drill collars to the bit. The mud jets out of the bit nozzles to move cuttings away from the bit, carrying them to the surface in the space between the drill pipe and the steel casing (“annulus”). At the surface, the cuttings are removed from the mud, which is reused. Major manufacturers include National Oilwell Varco Inc., Gardner Denver Inc., and Rowan’s Ellis Williams.

Drill pipe, casing, and tubing. Drill pipe connects the above-surface drilling rig to the drill bit. The joints between sections of steel drill pipe are welded together to form the drill string. Drilling rigs typically have an inventory of 10,000 feet to 25,000 feet of drill pipe associated with them, depending on their size and service.

Steel casing is used to line the raw, open hole made by the bit in the formation. It keeps the hole from caving in, and, once cemented, keeps fluids in one formation from migrating to another. Tubing, also made of steel, is the pipe through which the oil or gas flows to the surface.

Together, drill pipe, casing, and tubing typically represent the second-largest expense of drilling and equipping a well, trailing only actual payments to contract drillers. Oilfield equipment companies do not sell casing and tubing; steel companies generally supply these products. Market participants include National Oilwell Varco (following its acquisition of Grant Prideco Inc.), Smith International’s Smith Services, United States Steel Corp. and its subsidiary Lone Star Technologies Inc., Ipsco Inc. (a division of SSAB Svenskt Stal AB), Tenaris S.A., and Oil States International Inc.

Wellhead equipment. These products consist of valves of different sizes and designs that are assembled with other components into a structure referred to as a “Christmas tree.” Mounted above ground, the Christmas tree controls the flow of oil and gas from the well by forming a seal to prevent well fluids from blowing or leaking at the surface. Leading manufacturers of wellhead equipment include Cameron Valves & Measurement (a unit of Cameron International Corp.; formerly Cooper Cameron Valves), National Oilwell Varco, Stewart & Stevenson LLC, Aker Kværner ASA, and VetcoGray (a subsidiary of General Electric Co.).

Many service offerings The oilfield services sector offers a wide range of services, with some companies active in many different markets. Some of the services offered include the following:

Pressure pumping services. These services consist of well cementing and stimulation. During well cementing, cement is pumped down the well and back up through the annular space between the casing and the edge of the wellbore. Once hardened, the cement protects the casing from corrosion and helps to control the well.

Well stimulation includes acidizing and fracturing. Acidizing is a process in which pressurized acid or water is pumped into the well, producing formations to create paths through which oil or gas can flow into the well. Fracturing is a production-enhancing service that is popular among North American natural gas producers. Major providers of both of these services include Halliburton Energy Services Group, Schlumberger’s Dowell, and Baker Hughes (following its April 2010 acquisition of BJ Services). A similar technique involves carbon-dioxide injection, which can be used to push oil or gas in a reservoir to the wellhead, from which it can be pumped above ground.

Wireline services. Wireline logging (or well logging) is basically a data recording service. Electronic instruments are lowered into the well on a wireline, where they transmit data to the surface to be recorded. (Wireline is a strong, fine wire that spools onto a reel.) Schlumberger, Baker Hughes’s Baker Atlas, Halliburton, and Weatherford International Ltd. dominate the market.

Logging may be performed in both open and cased wellbores. The most common are openhole logs, which measure the physical properties of underground formations to help determine the locations and reserves of oil and gas. Cased-hole operations include both the collection of data about producing wells and mechanical services, such as perforation to allow hydrocarbons to flow into the well.


Directional drilling and measurement while drilling (MWD). One of the key technologies that has improved the efficiency of reservoir development has been more accurate and reliable directional drilling. Components of a directional drilling assembly include downhole drilling motors, stabilizers, MWD tools, and a directional driller. Market leaders include Halliburton, Schlumberger, Baker Hughes, and Scientific Drilling.

During directional drilling, the top part of the well is drilled as straight as possible and then deflected at an angle, so that the wellbore curves in the desired direction and the drill penetrates the reservoir laterally. Using special drilling tools and devices that measure the direction and angle of the hole, the directional driller guides each wellbore into a different part of the reservoir.

In horizontal drilling, the operator deflects the well off the vertical axis to the point that it runs parallel to the earth’s surface. For some reservoirs, a single horizontal well is more effective than several vertical wells, as the horizontal well allows recovery of a greater percentage of a formation’s total reserves.

The MWD tool is an inline collar that records at-the-bit drilling parameters and telemetry. MWD measurements include weight on bit (WOB), rate of penetration (ROP), torque, and pump pressure. Measurements can be made continuously while drilling is taking place, eliminating the need to stop work in order to run separate survey tools. Considering the time that is needed to pull several thousand feet of drill string from a hole, the ability to measure downhole conditions without interrupting drilling is a major advantage, saving a significant amount of time and money.

Rotary steerable (RS). This technology is an offshoot of standard directional drilling. Introduced in the mid-1990s and commercially available since 1997, RS enables an operator to change the angle of the drill bit while the drill string is still rotating—thus enabling a faster ROP into the reservoir, which helps reduce rig drilling time. There are two forms of RS: push-the-bit and point-the-bit.

“Push-the-bit” RS applies force to the side of the drill bit, which causes the bit’s outer cutting structure to cut sideways into the formation in a curved path. “Point-the-bit” forces the bit in the desired direction by flexing the tool inside its housing; as a result, the bit is pointed in the desired direction without a side load on the drill bit. Another benefit of RS technology is that the continuous rotation of the drill string keeps the hole cleaner, leading to fewer blockages in the drill pipe. The improved drilling efficiency obtainable from RS systems may induce some operators to drill wells that otherwise would not be economical.

Underbalanced drilling (UBD). UBD occurs when the pressure that exists at the bottom of the hole is lower than the pressure of the oil and/or gas formation that is being drilled. When the pressure in the wellbore is lower than that of the reservoir, oil and gas flow is improved. Certain drilling fluids may be used in order to create the pressure differential that occurs in UBD.

Seismic imaging and analysis. Providers of seismic imaging and analysis services acquire, record, process, plot, manage, and interpret geophysical data, both on land and under water, to help clients evaluate subsurface geology before drilling. Seismic imaging uses acoustic signals to determine the structure of underground geological formations. Seismic analysis uses these data to map the layers of rock beneath the earth’s surface, letting geologists detect the presence of oil or gas reservoirs.

Because seismic data are collected before a drilling program begins, the amount of analysis being performed at a given time is a leading indicator of future drilling levels. Changes in seismic crew activity tend to precede changes in drilling activity. Major market participants include WesternGeco (a unit of Schlumberger), Compagnie Générale de Géophysique-Veritas (CGGVeritas), and Seitel Inc.

Marine support services. These services, which are provided to offshore drilling contractors, include towing and anchor handling of mobile drilling rigs and equipment, and the transportation of supplies and personnel. Tidewater Inc. dominates the marine support services segment. Other participants include Seacor Holdings Inc., Hornbeck Offshore Services Inc., Trico Marine Services Inc., and GulfMark Offshore Inc. Helicopter operators transport personnel and supplies to and from offshore drilling rigs, and they can do so more quickly than supply boats. Operators in this business include Bristow Group Inc. (formerly known as Offshore Logistics Inc.), PHI Inc. (formerly Petroleum Helicopters Inc.), and Seacor Holdings’ Era Aviation.


DRILLING ACTIVITY AND OIL PRICES: A COMPLICATED RELATIONSHIP

It is a common observation, one often made even by drillers themselves, that oil prices drive changes in drilling activity. While prices and drilling activity are interrelated, changes in prices do not directly trigger changes in drilling programs.

Drilling activity is most directly influenced by changes to the capital spending budgets of the operators not by day-to-day changes in oil prices. Oil prices are not the primary driver of capital spending budgets, though long-term price trends are an important element. More important, however, are the expected profitability of a particular project and the company’s ultimate return on investment, if it decides to move forward.

Other factors, including development times and costs, also play a significant role in determining how profitable a particular project will be, and what the return to investors will be when compared with other possible projects. It is important to remember that even projects that appear to be profitable may not get backing simply because they do not meet the operator’s minimum requirements for return on investment, or because other projects are more profitable.

Once the operator makes a decision to invest in a new drilling project, there is typically a delay before drilling actually starts. This delay may be fairly short during times when rigs are readily available, but it can grow to several years when rigs are in tight supply.

During times of extremely high rig utilization, drilling may not be possible until new rigs come into operation, extending the delays further. Drillers need to be confident that existing demand for their rigs will be sustained—or have a long-term contract in place—before ordering new rigs, which can cost upward of $600 million for a new drillship, and upwards of $150 million for a new jackup. Even if a decision to invest in new capacity is made, there is a significant lag between that decision and the time when drilling activity actually responds. For example, a jackup rig ordered in 2011 might not be ready for use until about 2013—assuming that adequate shipyard time were available. As more rigs are ordered, shipyard space becomes scarce, and rigs take even longer to build, extending the delay even further.

The same is true when prices are falling and fewer drilling rigs are needed. Rigs may be contracted for years into the future, and breaking those contracts is expensive. Once added to the supply, rigs have a useful life of 25 years or more, lasting through many shifts in price.

Several other factors also help determine the level of drilling activity. The discovery of oil in particular areas may ignite demand for rigs that is not directly tied to changing prices. More specifically, it may spur demand for rigs of a certain type (i.e., deepwater-capable) or in a certain area (i.e., the US Gulf of Mexico). Finds such as the discovery that Chevron Corp. made in the Gulf with its Jack well in September 2006, which indicated the presence of large oil and gas resources in deepwater regions of the Gulf, also can stimulate demand for rigs, regardless of the pricing environment. Shifts in government policy that open new areas for drilling or make drilling more profitable by cutting royalties also can affect demand for rigs and dayrates.

KEY INDUSTRY RATIOS AND STATISTICS

Oil and natural gas prices and supply/demand factors. Shifts in oil and natural gas prices are important for equipment and service providers, because they affect the capital spending decisions of oil and gas producers. Daily oil and natural gas prices are readily available in most daily newspapers, as well as from the US Department of Energy’s Energy Information Service, which also publishes long- and short-term price forecasts. The New York Mercantile Exchange publishes the price of its oil and gas futures contracts.

Supply and demand statistics for oil and natural gas is available from various sources, including government agencies, such as the International Energy Agency (IEA) and the US Energy Information Administration (EIA), and trade groups, such as the American Petroleum Institute (API) and the American Gas Association (AGA). In addition, S&P Capital IQ produces forecasts for oil and gas supply and demand, based on data


obtained from, and modeling by, IHS Inc. (These and other sources are listed in the “Industry References” section of this Survey.)

Rig count. The rig count is a direct measure of drilling activity, and is either an estimated or actual count of rigs working. Published counts may differ due to varying definitions and sample sizes.

Offshore rig counts are available from companies such as Baker Hughes Inc., and Schlumberger Ltd. Other sources include trade associations, such as the API, and market research firms, such as IHS Petrodata and RigBase. Land rig counts are available from market research firms (such as DataWright Corp., publisher of the Land Rig Newsletter), companies (such as Baker Hughes and Schlumberger), and trade associations (such as the API and the Canadian Association of Oilwell Drilling Contractors).

The EIA publishes a large amount of data regarding the number of drilling rigs in operation, including a monthly breakdown of rigs in operation by site (onshore/offshore) and by type (oil/natural gas), the number of wells drilled (exploration/development) and the type (oil/gas/dry), as well as the total footage drilled. It also publishes a monthly count of the number of crews doing seismic exploration work in the lower 48 states (onshore/offshore) and Alaska.

Rig utilization rates. This measure identifies the percentage of currently active rigs out of the total supply (working, available for work, and idle). A high rig utilization rate indicates that the industry is operating close to capacity—always a good sign. A low rig utilization rate signals a significant oversupply of rigs, which can lead to a difficult operating environment and lower dayrates.

Individual drilling companies typically disclose utilization rates in the footnotes of their financial statements. Average offshore rig utilization rates are available from market research firms such as IHS Petrodata. Average land rig utilization rates are available from sources such as the Land Rig Newsletter and the NOV Downhole Rig Census (formerly the ReedHycalog Rig Census), published by National Oilwell Varco. Reported utilization rates may vary due to differences in definition.

In US land drilling, it is important to distinguish between total utilization and marketed utilization. Total utilization includes rigs that would require some refurbishment before being offered to operators. Marketed utilization excludes mothballed rigs and includes only rigs that have recently been active. (The Land Rig Newsletter defines as “active” any rig that has worked one or more jobs in the previous three months.)

Rig dayrates and daily margins. Daywork rates (or “dayrates”) are the most common way in which drilling contractors are paid. Rig dayrates are usually reported by rig type and location. Reported dayrates can vary due to differences in basis: some may be based on current contract signings and/or rate adjustments, others on a survey of current rates being paid to contracted rigs. Individual drilling companies typically disclose their average dayrates in the footnotes of their financial statements. Average offshore rig dayrates are available from market research firms such as IHS Petrodata.

New rig construction. Knowing the outlook for new rig construction helps to assess the future rig supply, and the driving force behind new construction is dayrates. As dayrates rise, construction becomes more economical, because the anticipated dayrate will allow the drilling company to recover the costs of building the new rig and earn a sufficient return on its investment. The current dayrate is generally described as a percentage of the dayrate level necessary to warrant construction of new offshore rigs. Specifically, it compares the profitability of current mobile offshore drilling rig dayrates with the profitability of dayrates at the peak of the offshore drilling cycle in 1980–1981, when speculative new rig construction was common.

Upstream capital expenditures. Upstream capital expenditures refer to the collective amount spent by companies looking for, and producing, oil and gas. Energy research firm IHS Herold Inc. publishes an annual survey of upstream spending using data from about 200 companies. Barclays PLC, the London-based bank, also publishes an upstream capital spending survey, with data from more than 300 companies.


HOW TO ANALYZE AN OIL & GAS EQUIPMENT & SERVICES COMPANY

When evaluating a company in the oil and gas equipment and services sector, a top-down approach is recommended. Initially, the analyst should examine general industry factors, using some of the ratios and statistics mentioned in the “Key Industry Ratios & Statistics” section of this Survey.

The lifeblood of the oil and gas equipment and services sector is the upstream capital spending by the supermajors, major oil companies, and nationalized oil companies (collectively known as the upstream producers). It is the upstream producers to whom the offshore and land drillers contract out their rigs, and it is to these producers that oilfield services companies offer related services, such as pressure pumping, casing, crew transportation, well servicing, and other ancillary services.

Capital spending by upstream producers is largely dependent on the opportunities for exploration and development that these companies believe are worth pursuing. In general, these upstream producers seek out high-growth low-cost opportunities. Producers’ upstream finding and development (F&D) spending has risen considerably over the last several years, but has started to decelerate. According to IHS Herold’s 2013 Global Upstream Performance Review, published in August 2013, worldwide finding and development (F&D) spending rose 17.69% to $525.9 billion (excluding acquisitions) in 2012, compared with a 20.3% increase in 2011 and a 15.4% increase in 2010. Such spending declined in 2009 by 18%, amid the global recession and tight credit markets. We think recent deceleration in spending is related to rising costs as low-cost opportunities become increasingly scarce.

With the recovery in oil prices to a seemingly stable range of $70 to $100 per barrel, but still on the heels of the 2008 credit crisis, we expect operators to spend near organically generated cash flows or perhaps slightly higher. Since development spending focuses on activities that are closer to generating cash flow, we feel that they will concentrate more on this kind of spending. However, given the impending arrival of a high number of deepwater newbuilds, we expect deepwater exploration spending to advance as well.

While crude prices of more than $100 a barrel probably did not change upstream producers’ approach to spending, the sudden and precipitous decline to the $35 range, coupled with credit constraints, did change the behavior of the less well-capitalized players. The cash-rich operators, which have untapped credit facilities and/or low debt leverage and are focused on big, long-term development projects (such as deepwater reservoirs), were less affected by the drop in prices and continued to spend through the weakness. However, the smaller companies, which are more highly leveraged and more exposed to short-cycle projects (such as North American natural gas drilling), are more likely to rein in spending out of necessity. This implies a shift in upstream spending away from North America—both in exploration and development—since North America has a relatively fragmented oilfield services industry. In addition, North American spending is strongly associated with natural gas development, and natural gas prices, currently in the $4.00/MMBtu range, are not sufficiently high to generate significant interest, except in some of the lower-cost shale plays.

Ultimately, global economic growth will recover and we believe that long-term expectations are for energy prices to move higher. However, due to the continuing decline rate, which appears to be worsening, energy supply (particularly crude oil supply) is likely to be constricted in the near-term. This situation should lead companies—balance sheets permitting—to continue with their long-term projects that they hope will deliver new supply sources.

COMPANY CHARACTERISTICS THAT MAKE FOR SUCCESS

Once the industry’s overall outlook has been assessed, how conditions affect individual companies can be considered. Certain factors—such as rig location, rig type and quality, and contracts—pertain to drilling companies. Other factors, such as technology and product cycles, concern oilfield service and supply companies. The firm’s track record and reputation are significant for both drilling and service companies.

Location is key For contract drilling companies, the location of drilling rigs is of prime importance. While some geographic areas experience a surge in drilling activity, others may be in decline. Most rigs are mobile and can be moved


to regions that are more promising, though this is costly in terms of transportation expenses and lost service time. For this reason, land rigs tend to remain domiciled within a particular region and/or country. Offshore rigs have a higher revenue-to-transportation expense ratio and often are relocated based on market demand.

World markets participate in different stages of the energy cycle, based on their relative cost/benefit ratios (exploration and production costs versus oil and gas prices and dayrates). For instance, the revenue-to-expense ratio is higher in the Gulf of Mexico than in the North Sea. Consequently, when the industry recovers from a bust period, the Gulf of Mexico is among the first regions to benefit, while the North Sea is one of the last.

Types of rigs The type and quality of a drilling company’s rig fleet are major factors in its revenue growth. Pertinent rig qualities may include water depth, hole depth, age and technological sophistication, variable deck load (how much equipment can be loaded on the rig before it becomes unsafe), mud pump capacity, horsepower, and the ability to operate in a harsh environment. Commodity rigs are generally older than premium rigs and lack their sophistication and drilling depth capacity. The desired qualities will depend on what the rig will be needed to do.

During periods of weakness, companies that own premium rig fleets outperform those that own commodity fleets. Rates for commodity shallow-water rigs decline much more quickly than do those for premium deepwater rigs. When the industry improves, the best-positioned companies are leveraged to the early-cycle rigs, such as land drilling rigs and jackups, whose rates improve most rapidly at this time (though they tend to top out earlier). As the recovery continues, utilization rates and dayrates for deepwater rigs rise rapidly.

Types of contracts Drillers are generally paid according to one of three methods: daywork contract, footage contract, or turnkey contract. The contract determines a driller’s prospects for future revenue growth.

Daywork contract. This is the most common type of contract. A daywork contract makes it easy to determine the company’s revenues: simply multiply the daywork rate by the number of days in the contract. Because daywork contracts generally provide for stable revenues, a company with a large percentage of them is viewed favorably.

Footage contract. A footage contract, in contrast, pays based on the depth of the wells drilled. Thus, it exposes the driller to fluctuating revenues, because the depth of any given deposit is unpredictable. Not surprisingly, the use of footage contracts by contract drillers has declined over the years.

Turnkey contract. The turnkey (or fixed-price) contract calls for payment of a stipulated amount to the drilling contractor upon completion of the well. The contractor furnishes all material and labor, controls the entire drilling operation independent of operator supervision, and is paid only if the well is successfully drilled as contracted. Due to the generally low returns and the added risk of operational disruptions, few companies remain committed to the turnkey business. The declining popularity of turnkey contracts has coincided with the industry’s improved fundamentals. During the industry downturns, turnkey drilling is a way of putting a company’s idle rigs to work. As excess rig supply diminishes, however, drilling contractors seek more lucrative daywork contracts.

Contracts: long or short? Another important factor to consider when examining a drilling company is the length of its contracts. When do the company’s current contracts expire? How many will expire within the next 12 months? How many rigs are locked in for three years or longer?

The relative advantages and disadvantages of short- and long-term contracts depend on industry conditions. When dayrates begin to rise, companies with a greater proportion of long-term contracts are at a disadvantage, as their rigs are locked into rates that are lower than those of the improving market. When dayrates decline, companies with short-term contracts suffer because those contracts will soon be renewed at lower dayrates.

Some regions are more reliant on shorter-term contracts than others. For example, contractors in the US Gulf of Mexico typically see shorter-term contracts for their rigs than do contractors in West Africa or


Southeast Asia. Even though overseas regions have seen drilling rigs yield higher dayrates and contract term lengths, corresponding dayrates and term lengths have remained relatively lower in the Gulf. Not surprisingly, contractors have chosen to send many of their Gulf-based drilling rigs to overseas markets, taking advantage of the better opportunities found there.

EVALUATING THE FINANCIAL STATEMENTS

Other important components of a company’s outlook are its financial strength and performance. These elements can be evaluated by reviewing the firm’s financial statements.

Looking at the income statement The sources of a company’s revenues should be determined. For an equipment and services company, what percentage of revenues and earnings comes from products, and what percentage comes from services? Do product sales represent recurring revenues or one-time events? Did they involve older, mature products, or do they reflect market acceptance of the company’s newer products?

For drilling companies, dayrates are of utmost importance in projecting future revenue growth. A lead indicator for dayrates is the rig utilization rate: the percentage of working rigs out of the total fleet (working, available for work, and idle) supply. A high or rising rig utilization rate for a given period is a good sign that demand is strong for the company’s rigs. A very high utilization rate, however, indicates that the driller is operating close to or at maximum capacity. Future gains would have to be fueled by higher dayrates on the rigs that are currently working.

Relatively small changes in dayrates can have a dramatic impact on a drilling contractor’s bottom line. Because most of a drilling rig’s operating costs are fixed, any increase in the dayrate represents pure profit. Thus, rising dayrates result in wider operating margins.

Profit margins show how efficiently a company operates. Look for trends in both operating margins (operating income divided by revenues) and net margins (net income divided by revenues). Are they widening or narrowing? How do the company’s margins compare with those of its peers?

Looking at the balance sheet The balance sheet reveals a company’s capital structure, including its degree of indebtedness. A commonly used measure of financial leverage is the ratio of long-term debt to total capital. For a thorough analysis, compare a company’s debt-to-capital ratio, and its interest coverage ratio (earnings to interest expense), with those of its peers. Companies with unusually high debt levels might have difficulty raising additional debt at a reasonable interest rate, which reduces their financing options.

Certain performance measures can give the analyst valuable insight into how well the company manages its resources. Return on assets (ROA; net income divided by the average level of assets in the period being analyzed) shows a company’s ability to use its assets to generate profits. Return on equity (ROE; net income divided by average equity) measures a company’s success in investing its capital.

The importance of cash flow The most widely used measure of any company’s profitability is net income, which is expressed on a per-share basis as earnings per share (EPS). However, an oil equipment and services company’s income statement often contains a significant level of noncash items, which can distort reported EPS. Thus, no analysis of a company in the industry would be complete without an examination of cash flow.

Cash flow information is disclosed in the cash flow statement, which can be found in a company’s quarterly 10-Q and annual 10-K filings. The statement adds back the cumulative value of noncash expenses (such as depreciation, amortization, and deferred taxes), while subtracting cash outlays that do not appear on the income statement (such as capital expenditures, debt repayment, and dividends on common stock). The result shows the net change in cash and cash equivalents at the end of the period.


It is discretionary cash flow, not earnings, that indicates whether a company will be able to cover its future spending. Negative cash flow may signal unsustainable cash burn for companies with little growth; however, if it yields high growth, it may signal a valuable investment. In general, cash flow growth is an important confirmation of earnings growth, and valued stocks exhibit both.

VALUATION MEASURES

The final step in analyzing a company involves determining if its shares are undervalued or overvalued. S&P Capital IQ suggests using a variety of valuation methods to arrive at a reasonable range of values.

One common approach looks at the current market price of the company’s shares. What is its price/earnings (P/E) ratio? What is its price/cash flow (P/CF) ratio? How do these values compare with historical ratios and with those of the company’s peers?

The size of the potential market for the company’s products and services may be used to estimate the long-term growth rate. What is the ratio of forward P/E (price per share divided by projected 12-months EPS) to long-term growth (PEG)? Although further analysis is advisable, a common benchmark is that the shares may be undervalued if a company’s PEG is below 1.0 and the fundamentals of the business are healthy.

Sometimes, forward earnings or cash flow become unreliable—due, for instance, to the unpredictability of oil and gas prices. At such times, valuation methods based on asset value or historical performance measures may be useful.

What would the entire business sell for today? Prices paid for recent mergers and acquisitions, known as transaction values (TVs), are useful indicators of how much an entire firm in a similar line of business (debt plus equity) might fetch in the market. Enterprise value (EV)—calculated as the market capitalization of common equity plus preferred equity, minority interest, and the book value of debt, less cash and equivalents—can be used as a proxy for TV. Deal multiples, such as TV to earnings and TV to assets, capture the target valuation of a firm. Market multiples, such as EV to earnings and EV to assets, are useful indicators of how the business is currently valued in the market. A commonly used metric is EV to EBITDA (earnings before interest, taxes, depreciation, and amortization).

A common methodology for valuing companies in various lines of business is the sum-of-the-parts approach. Each business line is valued individually and then summed using a weighted average of each segment’s contribution to the company’s overall revenues.

Investors tend to give higher multiples to rapidly growing companies and lower multiples to more stagnant firms. Thus, certain businesses tend to trade at premiums to their peers, while others trade at discounts. Before deciding whether a company’s stock is undervalued or overvalued, compare its valuation ratios with its own historical ratios as well as with those of its peers and the S&P 500 Composite Stock index.


GLOSSARY

Air gap—The distance between the ocean surface and the hull of a jackup rig.

Barrel (bbl.)—A common unit of liquid measure in the petroleum industry. One barrel of oil equals 42 US standard gallons or 35 British imperial gallons; one long ton equals 7.45 barrels.

Bcf—One billion cubic feet; a measure of natural gas volume.

Blowout—An uncontrolled flow of gas, oil, or other well fluids, into the atmosphere or into an underground formation, which is extremely wasteful of reservoir fluids and drive energy. Also known as a gusher, it can occur when formation pressure exceeds the pressure applied to it by the column of drilling fluid.

Blowout Preventer (BOP)—A large valve at the top of the wellhead that can be closed, in the event that upward pressure from the reservoir begins to overwhelm the downward pressure provided by drilling fluids.

BOE—Acronym for “barrel of oil equivalent,” this unit of measure equates oil and natural gas volumes. One barrel of oil equals 6,000 cubic feet (or six Mcf) of natural gas. Thus, if a company produces one million barrels of oil and six million Mcf of gas, it has produced two million BOE.

Btu—British thermal unit; the amount of heat required to increase the temperature of one pound of water by one degree Fahrenheit, used as a common measure of heating value for different fuels. Prices of different fuels and their units of measure (such as dollars per barrel of crude oil) can easily be compared when expressed as dollars or cents per million Btu (MMBtu).

Cable-tool drilling—A drilling method that uses a drill bit, fastened to a drill stem and jars, suspended from a wireline. The sharpened bit penetrates rock by repeatedly striking it in an up-and-down motion.

Casing—A steel or iron pipe lowered into a well during drilling to prevent its walls from caving and to keep gas, water, or other fluids from entering the well. After the drilling is complete, casing remains in the well as a permanent reinforcement.

Christmas tree—The control valves, pressure gauges, and chokes assembled at the top of a well to control the flow of oil and gas after the well has been drilled and completed.

Core—A cylindrical sample of a formation that is penetrated during a rotary drilling operation. Samples are examined to obtain geological information.

Dayrate—The sum paid to a drilling contractor for each 24 hours of operation under a daywork contract. Under these agreements, contractors are paid on the basis of time worked, not footage drilled.

Decline rate—The rate at which a reserve of natural resources is exploited, calculated as the inverse of the years of reserve remaining (decline rate = 1 divided by years of reserve) and expressed as a percentage. For example, a decline rate of 50% means that, at current production levels, there are 2.0 years of reserves remaining to be exploited.

Deepwater—See Water depths.

Depletion—An accounting term for allocating the cost of a natural resource based on the rate of extraction and production.

Development—Preparation of a mineral deposit for commercial production, including construction of access and extraction facilities.

Development costs—Expenses incurred to obtain access to proven reserves and to provide facilities for extracting, treating, gathering, and storing the oil and gas.

Directional drilling—Intentional deviation of a wellbore from the vertical. Although wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle. Controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth.


Drill bit—The cutting or boring element used to penetrate the Earth in the digging of a well.

Drill collar—A heavy, thick-walled tube, usually steel, placed between the drill pipe and the bit in the drill stem. Drill collars are used to provide weight on the bit and a pendulum effect to the drill stem.

Drilling fluid—Circulating fluid that forces cuttings out of the wellbore and to the surface, and cools the bit and counteracts downhole formation pressure. While a mixture of barite, clay, water, and chemical additives is the most common drilling fluid, wells can also be drilled by using air, gas, water, or oil-based mud as the drilling fluid.

Drill pipe—Heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Lengths of pipe approximately 30 feet long are coupled together by means of tool joints.

Drill ship—A self-propelled floating vessel that specializes in penetrating deepwater and ultra-deepwater formations. Most modern drill ships are dynamically positioned (kept on station using multipositioning thrusters) rather than moored (held in place by lines).

Drill string—The assembly of tools used to drill a well. It includes many pieces of equipment from the top of the drill hole to the bottom.

Dry hole—A well that contains no oil or gas, or too little of either to make production economically viable; also known as a “duster.”

Dynamic positioning system—The means by which a floating drilling vessel maintains its position over a well location. A series of propulsion units are mounted to the vessel’s hull; power to these units is varied, as directed by telemetry signals from beacons on the sea floor, by satellite information, or by the angular movements of a cable.

Exploration—The identification and examination of areas that may contain oil and gas reserves.

Exploration costs—Expenses directly identifiable with exploration activities, including support equipment and facilities, depreciation, and applicable operating costs. May be incurred before a property acquisition (at which time they are called prospecting costs) or afterwards.

Field—An area consisting of a single reservoir or multiple reservoirs grouped on, or related to, the same individual geological structural feature and/or stratigraphic condition.

Floating offshore drilling rig—Also called a floater, a mobile offshore drilling unit that floats and is not secured to the seafloor (except by anchors) when it is in the drilling mode. Floating units include inland barge rigs, drill ships, ship-shaped barges, and semisubmersibles.

Floating production, storage, and offloading offshore (FPSO) vessel—A vessel that produces, stores, and offloads oil and gas. It is moved to an offshore drilling site and can begin pumping oil in a short period of time. It thus reduces expenses by shortening the time between discovery and first production compared with platforms that were traditionally built on drilling sites.

Flooding—Injecting water under pressure into a depleted well to force out any remaining oil.

Horizontal drilling—A drilling method whereby a vertical drilling hole is redirected in order to be parallel to the oil formation.

Hydrocarbons—Organic compounds composed of only hydrogen and carbon molecules. Such compounds include crude oil, natural gas, and bitumen (a heavy, tarlike form of crude oil).

Infill drilling—The drilling of new wells to increase production in a field. There are legal spacing standards between wells.

Intermediate waters—See Water depths.

Jackup rig—A type of mobile offshore drilling rig capable of working in water up to 400 feet deep. Premium jackup rigs can work in depths of up to 550 feet.


The Kelly—A square or hexagonal steel device that is connected to the drill pipe through the rotary table.

Kick—An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick or kill the well, a blowout may occur.

Lease—A legal document executed between a landowner (lessor) and a company or individual (lessee) that grants the right to exploit the premises for minerals or other materials.

Lease sales—A term generally applied to the process by which the US government auctions the right to explore for and extract oil, gas, and other minerals on lands for which it owns the mineral rights. Oil companies acquire most of their offshore blocks (except state-owned tracts) through federal lease sales.

Lifting—Producing an oil well by mechanical means (pumps, compressed air, or gas). Also, refers to tankers and/or barges taking on cargoes of oil and/or oil products at a transshipment point.

Mcf—One thousand cubic feet; the standard measure of natural gas volume. One Mcf is equal to one million Btu of energy at one atmosphere of pressure. Six Mcf equal one barrel of oil equivalent (BOE). MMcf stands for one million cubic feet.

Mineral rights—The ownership rights to oil, gas, and other minerals under a given tract. These include the right to explore, drill, and produce the minerals, or assign such rights to another party in the form of a lease.

Mud—Pumpable fluids circulated in a drill hole to remove rock cuttings and cool the bit. Muds are usually mixtures of water, clay, and chemical additives. (See Drilling fluid.)

Mud pumps—A large high-pressure reciprocating pump used to circulate the mud on a drilling rig; also called a “slush pump.”

Natural gas—A naturally occurring mixture of gases found in porous geologic formations beneath the earth’s surface, often in association with petroleum. The largest constituent of natural gas is methane.

Natural gas liquids (NGLs)—The portion of natural gas (including ethane, propane, and butane) that is stripped out as liquids by special processing facilities at the surface.

Newbuild—A newly manufactured rig, as opposed to one assembled from parts cannibalized from existing rigs.

OPEC—Organization of the Petroleum Exporting Countries; an intergovernmental organization dedicated to the stability and prosperity of the petroleum market. Its members are substantial net exporters of oil.

OPEC automatic price band mechanism—In March 2000, OPEC adopted a price band mechanism to adjust supply up or down to maintain basket prices within its desired band, currently set between $22 and $28 per barrel. The daily crude basket must exceed the upper limit for 20 consecutive trading days, or fall below the lower level for 10 consecutive days, to trigger an output cut or increase of 500,000 barrels per day. In January 2005, the cartel temporarily suspended its $22–$28 per barrel target range, after recognizing that its limits were no longer realistic.

OPEC crude basket price—The arithmetic average price of seven different oils: Algeria’s Sahara Blend, Indonesia’s Minas, Saudi Arabia’s Arab Light, Dubai’s Fateh, Venezuela’s Tia Juana Light, Nigeria’s Bonny Light, and Mexico’s Isthmus. (Of this group of producers, only Mexico is not a member of OPEC.)

Outer Continental Shelf (OCS)—A gently sloping underwater plain that extends seaward from the North American continent. It is bounded on the seaward side by the Continental Slope, which drops more sharply to the deep ocean basins.

Pipeline—A continuous pipe conduit, complete with equipment serving to transport natural gas, supplemental gaseous fuels, oil and/or refined products from one point to another. Transport is usually from a point near the producing field or processing plant to another pipeline, or to points of use (includes interstate, intrastate, and intracompany pipelines).

Plug—To fill a hole with cement and/or mud, as required for safety and environmental purposes, in order to abandon it.


Producer—The owner of wells yielding oil or gas. When the owner is a firm, it is referred to as a production company.

Production costs—Operating costs incurred in producing a barrel of oil or one Mcf of natural gas once a well has been developed; also known as lifting costs.

Remotely operated vehicle (ROV)—An underwater device controlled from a vessel on the water’s surface, which is used to inspect subsea equipment, such as a pipeline, either in place of or in conjunction with diving personnel.

Reserves, net—All proved reserves associated with a company’s net working interests.

Reserves, proved—Oil and gas known to be economically recoverable with present technology and at current cost and price levels.

Reserves-to-production (R/P) ratio—Reserves remaining at the end of a year divided by production at that time. The result is the length of time that the remaining reserves would last if production were to continue at the stated rate.

Reservoir—An accumulation of oil and/or gas trapped in a rock body.

Rig—The derrick and surface equipment of a drilling unit.

Rig count—The number of drilling rigs in use during a particular period of time in a given market. May be reported either as an estimate (based on a sample survey) or an actual count. It also may be reported on a demand basis (reflecting how many rigs are working) or on a supply basis (how many rigs are available to work).

Riser pipe—The pipe and special fittings used on floating offshore drilling rigs to establish a seal between the top of the wellbore (on the ocean floor) and the drilling equipment (above the water’s surface). A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead, and as a conductor of drilling fluid from the well to the vessel.

Rotary drilling—A drilling system in which a rock formation is penetrated by a rotating bit connected to a hollow drill pipe. Fluid is pumped through the pipe so that the rock cuttings can be brought to the surface.

Rotary helper—A worker (roughneck, floorhand, or rig crew member) on a drilling or workover rig, subordinate to the driller, whose primary work station is on the rig floor. On rotary drilling rigs, there are at least two (and usually three or more) roughnecks on each crew.

Rotary steerable system (RSS)—A drilling process in which the direction of the drill bit may be adjusted while the drill string continuously rotates.

Rotary table—The equipment that transfers power from the engines to produce a rotary motion. That motion is transferred to the Kelly, which then transfers that power to the drill pipe.

Roustabout—A worker on an offshore rig who handles the equipment and supplies that are sent to the rig from the shore base. The head roustabout is often the crane operator.

Royalty—Payment to a landowner or other holder of royalty rights for a portion of a property’s gross production of oil and gas. Although lease terms vary, a fairly common royalty is one-eighth of production.

Seismic survey—An exploration method in which sound waves are emitted to locate subsurface structures that may contain oil and/or gas.

Semisubmersible drilling rig—A floating offshore drilling unit with pontoons and columns, which when flooded, cause the unit to submerge to a predetermined depth. Semisubmersibles are either self-propelled or are towed to the drilling site; they may be anchored or dynamically positioned over the site, or both. Types include the bottle-type and the column-stabilized semisubmersible. Living quarters and storage space are assembled on the deck.

Shallow water—See Water depths.


Shut in—To close the valves located at the top of a well so that the gas or oil it contains stops flowing to the surface. Such stoppages are typically temporary.

Spar—Floating production facility anchored to the seabed with catenary mooring lines.

Spot price—In a one-time open market transaction, the price for immediate delivery of a specific quantity of a commodity product purchased “on the spot” at current market prices.

Submersible drilling rig—A mobile bottom-supported offshore drilling structure with several compartments that are flooded to cause the structure to submerge and rest on the seafloor. Submersible rigs are designed for use in shallow waters to a maximum of 175 feet. Submersibles include the posted barge submersible, the bottle-type submersible, and the arctic submersible.

Tcf—One trillion cubic feet; a measure of natural gas volume.

Tonne—Metric measure of mass. One metric tonne equals 1.10 short tons, 0.98 long tons, and 2,205 pounds.

Tubing—A small-diameter, removable pipe through which oil and gas are produced from a well.

Turnkey contract—A fixed-sum drilling contract for the completion of a well. A lump sum payment is usually made at the end of the job. All unexpected costs must be borne by the drilling contractor.

Ultra-deepwater—See Water depths.

Underbalanced drilling—Drilling where the pressure in the wellbore is lower than the pressure in the formation being drilled.

Utilization rate—The proportion of the total available rig fleet that is active at a given time. Computed by dividing the number of active rigs by the total number of available rigs.

Water depths—Underwater drilling operations are categorized by water depth, as follows: shallow waters (depths up to 550 feet); intermediate waters (depths of 551 to 5,000 feet); deepwater (depths of 5,001 to 7,499 feet); ultra-deepwater (depths greater than 7,500 feet). Some industry participants define only shallow water (up to 1,000 feet) and deepwater (beyond 1,000 feet).

Wellbore—The hole drilled by the drill bit.

Well completion—To prepare a well for the production of oil and gas; the method by which a flow line for hydrocarbons is established between the reservoir and the surface.

Wellhead price—The price of natural gas or petroleum at the well; also known as the field price.

Well servicing—The maintenance work performed on an oil or gas well to improve or maintain the production from a formation already in operation.

Wildcat—A well drilled in an area where no oil or gas production exists.

Wireline—A slender rodlike or threadlike piece of metal, small in diameter, used to lower logging tools, perforating guns, valves, and fishing tools into a well. May also include electrical conductors to power and control instruments and to convey data to the surface.

Working gas—Gauges the overall level of gas inventory that can be drawn upon. It is the volume of gas in a reservoir that is in addition to the base gas; base gas is the minimum amount of gas needed as a “permanent inventory” to maintain pressure in the reservoir and deliverability rates throughout the withdrawal season.


INDUSTRY REFERENCES

PERIODICALS

Basic Petroleum Data Book http://www.api.org Semiannual; comprehensive compilation of historical data covering all segments of the oil and gas industry.

Drilling Contractor http://www.drillingcontractor.org Bimonthly; official publication of the International Association of Drilling Contractors (IADC). Contains information on issues pertinent to contract drilling companies.

The Land Rig Newsletter http://www.landrig.com Monthly newsletter; covers US and international onshore oil services market of the oil and gas industry.

Mechanical Engineering http://www.asme.org/about-asme/news-media/newsletters Monthly publication discussing the role of mechanical engineering in technological advancements.

Offshore Oil & Gas Journal http://www.offshore-mag.com/index.html http://www.ogj.com/index.html Monthly and weekly journals, respectively, containing analysis, charts, illustrations, and market statistics on the oil and gas industry.

Oil and Gas Investor http://www.oilandgasinvestor.com Monthly; analysis and market statistics on the petroleum and power industry.

Platts Energy Trader Platts Oilgram News Oilgram Price Report http://www.platts.com Daily newsletters; reporting on oil and gas developments of international significance. Platts is a unit of McGraw Hill Financial.

Upstream http://www.upstreamonline.com Daily newspaper; covers worldwide exploration and production activities.

World Oil http://www.worldoil.com Monthly magazine covering operating management, drilling contractors, production engineering, and similar topics. In its October issue, it publishes the annual NOV Downhole Rig Census (formerly the ReedHycalog Rig Census).

World Rig Forecast http://www.ihs.com/info/en/a/ods-petrodata/index.aspx A monthly series of short- and medium-term offshore mobile rig market forecasts, disaggregated by type of rig and geographic region, with supply and demand projections.

BOOKS

Fundamentals of Oil & Gas Accounting, 4th Ed. Rebecca A. Gallun, John W. Stevenson, Linda M. Nichols Comprehensive accounting guide for oil and gas operations.

Petroleum Accounting: Principles, Procedures, & Issues, 5th Ed. Dennis Jennings, Joseph Feiten, Horace Brock Focuses on US financial accounting and reporting for petroleum exploration and production activities. Describes petroleum activities and the numerous accounting principles, practices, and procedures employed in petroleum reporting.

RESEARCH FIRMS

Energy Intelligence Group Inc. http://www.energyintel.com Publishes daily and weekly newsletters and special reports on oil and gas pricing, and developments of domestic and international significance. Publications include Natural Gas Week, Natural Gas Week’s Daily Price Snapshot, Oil Daily, and Petroleum Intelligence Weekly.

IHS Inc. http://www.ihs.com This research firm provides economic data, forecasts, analysis, and consulting. Among its many publications are Monthly Oil Market Outlook and Monthly Natural Gas Price Outlook.

IHS Petrodata http://www.ihs.com/info/en/a/ods-petrodata/index.aspx Independent source of market intelligence and data for the offshore oil and gas industry worldwide. Releases free updates on rig counts and dayrates; publishes reports on various topics, including floating and jackup rigs, and supply vessels, among many others. Includes RigBase.


Marcon International Inc. http://www.marcon.com Provider of news and data on the tanker, barge, and offshore supply vessel markets; broker of sale and purchase transactions.

Rigzone http://www.rigzone.com Provider of news, data, and market research on the offshore oil and gas industry.

GOVERNMENT AGENCIES

Bureau of Ocean Energy Management (BOEM) http://boem.gov Agency within the US Department of the Interior that manages the exploration and development of US offshore resources. BOEM seeks to balance economic development, energy independence, and environmental protection through oil and gas leases, renewable energy development, and environmental reviews and studies. Split off in October 2011 from the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE), which in turn was formerly called the Minerals Management Service (MMS).

Bureau of Safety and Environmental Enforcement (BSEE) http://bsee.gov Agency within the US Department of the Interior that works to promote safety, protect the environment, and conserve resources offshore through regulatory oversight and enforcement. Its key functions include the Offshore Regulatory Program, the Oil Spill Response division, and the Environmental Compliance Division. Like BOEM, it was split off from the BOEMRE in October 2011.

Energy Information Administration (EIA) http://www.eia.gov Created by Congress in 1977, the EIA is a statistical agency within the US Department of Energy. Provides policy-independent data, forecasts, and analyses related to the domestic energy industries.

International Energy Agency (IEA) http://www.iea.org An autonomous agency, organized in 1974, linked with the Organisation for Economic Co-operation and Development (OECD). To meet oil supply emergencies, its 25 member countries share energy information and coordinate energy policies and programs.

National Petroleum Council (NPC) http://www.npc.org An advisory committee to the US Secretary of Energy, created in 1946. Its reports have concerned every aspect of oil and gas operations.

Organization of the Petroleum Exporting Countries (OPEC) http://www.opec.org An intergovernmental organization dedicated to the stability and prosperity of the petroleum market. Members are substantial net exporters of oil.

US Geological Survey (USGS) http://www.usgs.gov A part of the Department of the Interior; collects, monitors, analyzes and provides scientific understanding of natural resource conditions.

TRADE ASSOCIATIONS

American Gas Association (AGA) http://www.aga.org Represents the US natural gas industry, primarily companies involved in the distribution and transportation of natural gas. Provides statistical data and projections for the US natural gas industry.

American Petroleum Institute (API) http://www.api.org Represents all branches of the US petroleum industry. Publishes statistics covering all aspects of the oil and gas industry, including weekly inventory reports for crude oil and petroleum products.

Canadian Association of Oilwell Drilling Contractors (CAODC) http://www.caodc.ca Represents upstream Canadian petroleum drilling contractors (land-based and offshore), service rig contractors, and associate companies. Provides training and educational publications for the oil and gas industry, as well as free weekly Canadian rig and well counts.

International Association of Drilling Contractors (IADC) http://www.iadc.org Represents the worldwide oil and gas drilling industry. Provides educational materials and statistics pertaining to the industry.


CORPORATE INFORMATION

Financial information, such as quarterly and annual reports, can be obtained directly from company websites. Some sites, including the following, also provide free industry information such as rig counts and dayrate indices.

Association of Energy Service Companies (AESC) Service Rig Count http://wellservicingmagazine.com/rig-count This North American well service rig count is provided monthly by the AESC, and replaces the Guiberson Well Service Rig Count.

Baker Hughes Rig Count http://www.bakerhughes.com Estimates of rotary rig counts, provided by Baker Hughes to the petroleum industry since 1944. Includes free weekly estimates of US and Canadian rotary rig counts, monthly international rotary rig counts, and the US and Canadian workover rig count.

M-I Rig Count http://www.slb.com Weekly US and Canadian rig count, and biweekly worldwide rig count, provided by Schlumberger; based on a physical count of the number of rigs drilling, logging, cementing, coring, well testing, fishing, waiting on weather, running, casing, and blowout preventer testing.


COMPARATIVE COMPANY ANALYSIS

Operating Revenues

Million $ CAGR (%) Index Basis (2003 = 100)

Ticker Company Yr. End 2013 2012 2011 2010 2009 2008 2003 10-Yr. 5-Yr. 1-Yr. 2013 2012 2011 2010 2009

OIL & GAS DRILLING‡ATW † ATWOOD OCEANICS SEP 1,063.7 787.4 645.1 650.6 586.5 526.6 144.8 22.1 15.1 35.1 735 544 446 449 405DO [] DIAMOND OFFSHRE DRILLING INC DEC 2,895.4 2,986.5 3,322.4 3,323.0 3,631.3 3,544.1 680.9 15.6 (4.0) (3.0) 425 439 488 488 533ESV [] ENSCO PLC DEC 4,919.8 D 4,300.7 D 2,842.7 A 1,696.8 D 1,945.9 D 2,450.4 D 790.8 D 20.1 15.0 14.4 622 544 359 215 246HP [] HELMERICH & PAYNE SEP 3,387.6 3,151.8 2,543.9 1,875.2 D 1,894.0 2,036.5 507.3 20.9 10.7 7.5 668 621 501 370 373NBR [] NABORS INDUSTRIES LTD DEC 6,152.0 D 6,989.6 6,060.4 C,D 4,174.6 A,C 3,692.4 5,511.9 1,880.0 12.6 2.2 (12.0) 327 372 322 222 196

NE [] NOBLE CORP PLC DEC 4,234.3 3,547.0 2,695.8 2,807.2 A 3,640.8 3,446.5 987.4 15.7 4.2 19.4 429 359 273 284 369PTEN † PATTERSON-UTI ENERGY INC DEC 2,716.0 2,723.4 2,565.9 1,462.9 A,C 781.9 D 2,209.1 776.2 A,C 13.3 4.2 (0.3) 350 351 331 188 101PES § PIONEER ENERGY SERVICES CORP DEC 960.2 919.4 715.9 A 487.2 325.5 610.9 A 107.9 24.4 9.5 4.4 890 852 664 452 302RDC [] ROWAN COS PLC DEC 1,579.3 1,392.6 939.2 D 1,819.2 1,770.2 2,212.7 679.1 8.8 (6.5) 13.4 233 205 138 268 261RIG [] TRANSOCEAN LTD DEC 9,484.0 D 9,196.0 D 9,142.0 A,C 9,576.0 11,556.0 12,674.0 2,434.3 C 14.6 (5.6) 3.1 390 378 376 393 475

UNT † UNIT CORP DEC 1,351.8 1,315.1 1,209.2 871.7 702.8 1,358.5 299.8 A 16.3 (0.1) 2.8 451 439 403 291 234

OIL & GAS EQUIPMENT & SERVICES‡BHI [] BAKER HUGHES INC DEC 22,364.0 21,361.0 19,831.0 14,414.0 A 9,664.0 11,864.0 5,292.8 D 15.5 13.5 4.7 423 404 375 272 183BAS § BASIC ENERGY SERVICES INC DEC 1,262.9 1,374.9 1,243.3 A 728.2 526.6 1,004.9 A 180.9 A,C 21.4 4.7 (8.1) 698 760 687 403 291BRS § BRISTOW GROUP INC # MAR 1,669.6 1,508.5 1,341.8 1,232.8 1,167.8 1,133.8 C 563.6 11.5 8.0 10.7 296 268 238 219 207CJES § C&J ENERGY SERVICES INC DEC 1,070.3 A 1,111.5 A 758.5 A 244.2 67.0 NA NA NA NA (3.7) ** ** ** ** NACAM [] CAMERON INTERNATIONAL CORP DEC 9,838.4 A 8,502.1 A 6,959.0 A 6,134.8 A 5,223.2 A 5,848.9 A 1,634.3 F 19.7 11.0 15.7 602 520 426 375 320

CRR † CARBO CERAMICS INC DEC 667.4 645.5 625.7 473.1 341.9 387.8 D 169.9 14.7 11.5 3.4 393 380 368 278 201DRC † DRESSER-RAND GROUP INC DEC 3,056.3 2,736.4 2,311.6 A 1,953.6 2,289.6 2,194.7 1,335.3 8.6 6.8 11.7 229 205 173 146 171DRQ † DRIL-QUIP INC DEC 872.4 733.0 601.3 566.3 540.2 542.8 219.5 14.8 10.0 19.0 397 334 274 258 246ERA § ERA GROUP INC DEC 299.0 272.9 258.1 235.4 NA NA NA NA NA 9.5 ** ** ** ** NAEXH § EXTERRAN HOLDINGS INC DEC 3,160.4 D 2,803.6 D 2,683.5 2,461.5 2,715.6 D 3,178.7 1,072.3 C 11.4 (0.1) 12.7 295 261 250 230 253

FTI [] FMC TECHNOLOGIES INC DEC 7,126.2 6,151.4 A 5,099.0 F 4,125.6 F 4,405.4 4,550.9 D 2,307.1 11.9 9.4 15.8 309 267 221 179 191GEOS § GEOSPACE TECHNOLOGIES CORP SEP 300.6 191.7 173.0 128.5 92.9 134.5 50.9 19.4 17.5 56.8 591 377 340 253 183GIFI § GULF ISLAND FABRICATION INC DEC 608.3 521.3 307.8 248.3 311.5 420.5 203.7 11.6 7.7 16.7 299 256 151 122 153HAL [] HALLIBURTON CO DEC 29,402.0 F 28,503.0 F 24,829.0 F 17,973.0 F 14,675.0 F 18,279.0 F 16,246.0 D 6.1 10.0 3.2 181 175 153 111 90HLX † HELIX ENERGY SOLUTIONS GROUP DEC 876.6 846.1 D 1,398.6 1,199.8 1,388.1 D 2,148.3 396.3 8.3 (16.4) 3.6 221 214 353 303 350


Operating Revenues



HOS § HORNBECK OFFSHORE SVCS INC DEC 548.1 D 512.7 381.6 420.8 385.9 432.1 110.8 17.3 4.9 6.9 495 463 344 380 348IO § ION GEOPHYSICAL CORP DEC 549.2 526.3 454.6 444.3 419.8 679.5 A 150.0 13.9 (4.2) 4.3 366 351 303 296 280MTRX § MATRIX SERVICE CO JUN 892.6 739.0 627.1 550.8 NA H 689.7 607.9 3.9 5.3 20.8 147 122 103 91 NANOV [] NATIONAL OILWELL VARCO INC DEC 22,767.0 A 20,041.0 A 14,658.0 A 12,156.0 A 12,712.0 A 13,431.4 A 2,004.9 27.5 11.1 13.6 1,136 1,000 731 606 634NR § NEWPARK RESOURCES DEC 1,042.4 D 1,038.0 958.2 716.0 490.3 858.3 373.2 10.8 4.0 0.4 279 278 257 192 131

OII † OCEANEERING INTERNATIONAL DEC 3,287.0 2,782.6 2,192.7 A 1,917.0 1,822.1 1,977.4 639.2 17.8 10.7 18.1 514 435 343 300 285OIS † OIL STATES INTL INC DEC 2,670.2 A,C 4,397.9 F 3,479.2 A,F 2,412.0 A,F 2,108.3 F 2,948.5 A,F 723.7 F 13.9 (2.0) (39.3) 369 608 481 333 291SLB [] SCHLUMBERGER LTD DEC 45,266.0 D 42,149.0 D 39,540.0 D 27,447.0 A 22,702.0 D 27,162.9 D 13,892.6 D 12.5 10.8 7.4 326 303 285 198 163CKH § SEACOR HOLDINGS INC DEC 1,247.3 A,C 1,581.2 A,C 2,141.9 A 2,649.4 C 1,711.3 A 1,656.0 A 406.2 A 11.9 (5.5) (21.1) 307 389 527 652 421SPN † SUPERIOR ENERGY SERVICES INC DEC 4,611.8 4,568.1 A,C 2,070.2 A 1,681.6 A 1,449.3 1,881.1 500.6 24.9 19.6 1.0 921 912 414 336 289

TESO § TESCO CORP DEC 525.3 A 553.1 513.0 A 378.7 356.5 C 534.9 143.7 13.8 (0.4) (5.0) 366 385 357 264 248TTI § TETRA TECHNOLOGIES INC/DE DEC 909.4 880.8 A 845.3 872.7 878.9 1,009.1 318.7 D 11.1 (2.1) 3.2 285 276 265 274 276TDW † TIDEWATER INC # MAR 1,435.1 1,244.2 1,067.0 1,055.4 1,168.6 1,390.8 652.6 8.2 0.6 15.3 220 191 163 162 179

OTHER COMPANIES WITH SIGNIFICANT OIL & GAS EQUIPMENT & SERVICES OPERATIONSGLF GULFMARK OFFSHORE INC DEC 454.6 389.2 381.9 359.8 388.9 411.7 A 129.9 13.3 2.0 16.8 350 300 294 277 299SDRL SEADRILL LTD DEC 5,282.0 A 4,478.0 4,192.0 C 4,040.8 A,C 3,253.9 2,105.8 A NA NA 20.2 18.0 ** ** ** ** NARIG [] TRANSOCEAN LTD DEC 9,484.0 D 9,196.0 D 9,142.0 A,C 9,576.0 11,556.0 12,674.0 2,434.3 C 14.6 (5.6) 3.1 390 378 376 393 475WFT WEATHERFORD INTL PLC DEC 15,263.0 15,215.0 A 12,988.0 10,220.8 8,826.9 A 9,600.6 A 2,591.4 19.4 9.7 0.3 589 587 501 394 341

Note: Data as originally reported. CAGR-Compound annual grow th rate. ‡S&P 1500 index group. []Company included in the S&P 500. †Company included in the S&P MidCap 400. §Company included in the S&P SmallCap 600. #Of the follow ing calendar year. **Not calculated; data for base year or end year not available. A - This year's data reflect an acquisition or merger. B - This year's data reflect a major merger resulting in the formation of a new company. C - This year's data reflect an accounting change. D - Data exclude discontinued operations. E - Includes excise taxes. F - Includes other (nonoperating) income. G - Includes sale of leased depts. H - Some or all data are not available, due to a f iscal year change.


Net Income



OIL & GAS DRILLING‡ATW † ATWOOD OCEANICS SEP 350.2 272.2 271.7 257.0 250.7 215.4 (12.8) NM 10.2 28.7 NM NM NM NM NMDO [] DIAMOND OFFSHRE DRILLING INC DEC 548.7 720.5 962.5 955.5 1,376.2 1,311.0 (48.4) NM (16.0) (23.8) NM NM NM NM NMESV [] ENSCO PLC DEC 1,423.2 1,215.2 600.4 542.3 775.8 1,160.0 107.2 29.5 4.2 17.1 1,328 1,134 560 506 724HP [] HELMERICH & PAYNE SEP 721.5 573.6 434.7 286.1 353.5 461.7 17.9 44.7 9.3 25.8 4,037 3,209 2,432 1,601 1,978NBR [] NABORS INDUSTRIES LTD DEC 154.2 241.4 344.1 106.8 (85.5) 551.2 192.2 (2.2) (22.5) (36.1) 80 126 179 56 (45)

NE [] NOBLE CORP PLC DEC 782.7 522.3 370.9 773.4 1,678.6 1,561.0 166.4 16.7 (12.9) 49.8 470 314 223 465 1,009PTEN † PATTERSON-UTI ENERGY INC DEC 188.0 299.5 322.8 117.9 (34.0) 347.1 55.8 12.9 (11.5) (37.2) 337 537 579 211 (61)PES § PIONEER ENERGY SERVICES CORP DEC (35.9) 30.0 11.2 (33.3) (23.2) (62.7) (1.8) NM NM NM NM NM NM NM NMRDC [] ROWAN COS PLC DEC 252.6 203.3 135.7 280.0 367.5 427.6 (7.8) NM (10.0) 24.2 NM NM NM NM NMRIG [] TRANSOCEAN LTD DEC 1,406.0 808.0 (5,922.0) 961.0 3,181.0 4,202.0 18.4 NM (19.7) 74.0 NM 4,391 NM NM NM

UNT † UNIT CORP DEC 184.7 23.2 195.9 146.5 (55.5) 143.6 48.9 14.2 5.2 697.1 378 47 401 300 (114)

OIL & GAS EQUIPMENT & SERVICES‡BHI [] BAKER HUGHES INC DEC 1,096.0 1,311.0 1,739.0 812.0 421.0 1,635.0 180.1 19.8 (7.7) (16.4) 609 728 966 451 234BAS § BASIC ENERGY SERVICES INC DEC (35.9) 20.9 47.2 (43.6) (253.5) 68.2 3.0 NM NM NM (1,213) 704 1,592 (1,470) NMBRS § BRISTOW GROUP INC # MAR 186.7 130.1 63.5 132.3 112.0 124.6 53.1 13.4 8.4 43.5 352 245 120 249 211CJES § C&J ENERGY SERVICES INC DEC 66.4 182.4 162.0 32.3 (2.4) NA NA NA NA (63.6) ** ** ** ** NACAM [] CAMERON INTERNATIONAL CORP DEC 699.2 750.5 521.9 562.9 475.5 593.7 57.2 28.4 3.3 (6.8) 1,222 1,311 912 983 831

CRR † CARBO CERAMICS INC DEC 84.9 105.9 130.1 78.7 52.8 60.4 29.6 11.1 7.0 (19.9) 287 358 440 266 179DRC † DRESSER-RAND GROUP INC DEC 168.4 179.0 119.7 146.7 210.8 197.7 20.4 23.5 (3.2) (5.9) 827 879 588 720 1,035DRQ † DRIL-QUIP INC DEC 169.8 119.2 95.3 102.2 105.1 105.6 9.0 34.2 10.0 42.5 1,897 1,332 1,064 1,142 1,175ERA § ERA GROUP INC DEC 18.7 7.8 2.1 (3.6) NA NA NA NA NA 140.2 ** ** ** ** NAEXH § EXTERRAN HOLDINGS INC DEC 59.2 (106.3) (334.6) (147.1) (253.2) (947.7) (108.6) NM NM NM NM NM NM NM NM

FTI [] FMC TECHNOLOGIES INC DEC 501.4 430.0 399.8 375.9 361.3 352.9 75.6 20.8 7.3 16.6 663 569 529 497 478GEOS § GEOSPACE TECHNOLOGIES CORP SEP 69.6 35.1 29.7 14.1 1.8 14.2 (2.5) NM 37.5 98.1 NM NM NM NM NMGIFI § GULF ISLAND FABRICATION INC DEC 7.2 (4.1) (1.8) 13.1 20.8 29.0 15.8 (7.5) (24.3) NM 46 (26) (11) 83 132HAL [] HALLIBURTON CO DEC 2,106.0 2,577.0 3,005.0 1,795.0 1,154.0 1,961.0 339.0 20.0 1.4 (18.3) 621 760 886 529 340HLX † HELIX ENERGY SOLUTIONS GROUP DEC 108.8 (70.0) 130.0 (126.9) 146.5 (630.8) 33.7 12.4 NM NM 323 (208) 386 (377) 435


Net Income



HOS § HORNBECK OFFSHORE SVCS INC DEC 64.1 37.0 (2.6) 36.4 50.4 117.1 11.2 19.1 (11.4) 73.1 573 331 (23) 325 450IO § ION GEOPHYSICAL CORP DEC (245.9) 63.3 24.8 (36.8) (110.1) (221.0) (23.2) NM NM NM NM NM NM NM NMMTRX § MATRIX SERVICE CO JUN 24.0 17.2 19.0 4.9 NA 30.6 9.5 9.7 (4.7) 39.7 252 180 199 51 NANOV [] NATIONAL OILWELL VARCO INC DEC 2,327.0 2,491.0 1,994.0 1,667.0 1,469.0 1,952.0 76.8 40.6 3.6 (6.6) 3,029 3,243 2,596 2,170 1,912NR § NEWPARK RESOURCES DEC 52.6 60.0 80.0 41.6 (20.6) 39.3 2.1 38.2 6.0 (12.3) 2,534 2,890 3,853 2,004 (991)

OII † OCEANEERING INTERNATIONAL DEC 371.5 289.0 235.7 200.5 188.4 199.4 29.3 28.9 13.3 28.5 1,268 986 804 684 643OIS † OIL STATES INTL INC DEC 314.9 448.6 322.5 168.0 59.1 222.7 44.4 21.6 7.2 (29.8) 709 1,010 726 378 133SLB [] SCHLUMBERGER LTD DEC 6,801.0 5,439.0 4,777.0 4,267.0 3,156.0 5,397.0 472.6 30.6 4.7 25.0 1,439 1,151 1,011 903 668CKH § SEACOR HOLDINGS INC DEC 47.3 34.4 41.1 244.7 143.8 223.7 12.0 14.7 (26.7) 37.4 396 288 343 2,047 1,203SPN † SUPERIOR ENERGY SERVICES INC DEC (111.4) 383.1 142.6 81.8 (102.3) 361.7 30.5 NM NM NM (365) 1,256 467 268 (335)

TESO § TESCO CORP DEC 36.3 49.8 27.0 7.0 (5.3) 52.9 (18.9) NM (7.3) (27.2) NM NM NM NM NMTTI § TETRA TECHNOLOGIES INC/DE DEC 0.2 16.0 4.2 (43.3) 68.8 (9.7) 19.4 (38.3) NM (99.0) 1 82 22 (223) 355TDW † TIDEWATER INC # MAR 140.3 150.8 87.4 105.6 259.5 406.9 41.7 12.9 (19.2) (7.0) 337 362 210 254 623

OTHER COMPANIES WITH SIGNIFICANT OIL & GAS EQUIPMENT & SERVICES OPERATIONSGLF GULFMARK OFFSHORE INC DEC 70.6 19.3 49.9 (34.7) 50.6 183.8 0.5 NM (17.4) 266.3 NM 3,609 NM NM NMSDRL SEADRILL LTD DEC 2,653.0 1,108.0 1,401.0 1,116.9 1,261.2 (164.4) NA NA NM 139.4 ** ** ** ** NARIG [] TRANSOCEAN LTD DEC 1,406.0 808.0 (5,922.0) 961.0 3,181.0 4,202.0 18.4 NM (19.7) 74.0 NM 4,391 NM NM NMWFT WEATHERFORD INTL PLC DEC (345.0) (778.0) 189.0 (107.9) 253.8 1,366.8 143.4 NM NM NM (241) (543) 132 (75) 177

Note: Data as originally reported. CAGR-Compound annual grow th rate. ‡S&P 1500 index group. []Company included in the S&P 500. †Company included in the S&P MidCap 400. §Company included in the S&P SmallCap 600. #Of the follow ing calendar year. **Not calculated; data for base year or end year not available.


Return on Revenues (%) Return on Assets (%) Return on Equity (%)

Ticker Company Yr. End 2013 2012 2011 2010 2009 2013 2012 2011 2010 2009 2013 2012 2011 2010 2009

OIL & GAS DRILLING‡ATW † ATWOOD OCEANICS SEP 32.9 34.6 42.1 39.5 42.8 10.6 10.2 13.3 15.9 19.2 16.9 15.2 18.0 20.8 25.8DO [] DIAMOND OFFSHRE DRILLING INC DEC 19.0 24.1 29.0 28.8 37.9 7.0 10.1 14.1 14.7 24.6 11.9 16.2 23.5 25.5 39.4ESV [] ENSCO PLC DEC 28.9 28.3 21.1 32.0 39.9 7.5 6.7 4.8 7.9 12.3 11.6 10.7 7.1 9.5 15.2HP [] HELMERICH & PAYNE SEP 21.3 18.2 17.1 15.3 18.7 12.0 10.7 9.4 6.8 9.1 17.4 16.1 14.3 10.4 14.3NBR [] NABORS INDUSTRIES LTD DEC 2.5 3.5 5.7 2.6 NM 1.2 1.9 2.8 1.0 NM 2.5 4.1 6.2 2.0 NM

NE [] NOBLE CORP PLC DEC 18.5 14.7 13.8 27.6 46.1 5.1 3.7 3.0 7.9 21.7 9.8 6.9 5.1 11.1 27.8PTEN † PATTERSON-UTI ENERGY INC DEC 6.9 11.0 12.6 8.1 NM 4.1 6.8 8.4 3.9 NM 7.0 11.6 13.7 5.5 NMPES § PIONEER ENERGY SERVICES CORP DEC NM 3.3 1.6 NM NM NM 2.4 1.1 NM NM NM 5.7 2.5 NM NMRDC [] ROWAN COS PLC DEC 16.0 14.6 14.5 15.4 20.8 3.2 2.8 2.1 4.9 7.5 5.4 4.6 3.4 8.2 12.7RIG [] TRANSOCEAN LTD DEC 14.8 8.8 NM 10.0 27.5 4.2 2.3 NM 2.6 8.9 8.7 5.1 NM 4.6 17.2

UNT † UNIT CORP DEC 13.7 1.8 16.2 16.8 NM 4.7 0.7 6.6 6.0 NM 8.9 1.2 10.7 8.9 NM

OIL & GAS EQUIPMENT & SERVICES‡BHI [] BAKER HUGHES INC DEC 4.9 6.1 8.8 5.6 4.4 4.0 5.1 7.3 4.7 3.6 6.3 8.0 11.7 7.6 6.0BAS § BASIC ENERGY SERVICES INC DEC NM 1.5 3.8 NM NM NM 1.4 3.8 NM NM NM 5.7 14.3 NM NMBRS § BRISTOW GROUP INC # MAR 11.2 8.6 4.7 10.7 9.6 5.9 4.6 2.4 5.1 4.4 11.2 8.4 4.2 9.2 9.0CJES § C&J ENERGY SERVICES INC DEC 6.2 16.4 21.4 13.2 NM 6.2 23.5 42.4 17.2 NA 10.2 36.7 64.2 36.8 NACAM [] CAMERON INTERNATIONAL CORP DEC 7.1 8.8 7.5 9.2 9.1 5.5 7.3 6.0 7.2 7.0 12.2 14.6 11.5 13.5 15.2

CRR † CARBO CERAMICS INC DEC 12.7 16.4 20.8 16.6 15.4 10.1 13.7 19.4 14.1 9.9 11.5 15.8 22.6 16.1 11.7

DRC † DRESSER-RAND GROUP INC DEC 5.5 6.5 5.2 7.5 9.2 4.8 5.6 4.5 6.6 10.0 14.1 18.2 12.2 14.0 23.8

DRQ † DRIL-QUIP INC DEC 19.5 16.3 15.8 18.1 19.5 12.9 10.3 9.4 11.6 14.0 14.7 12.0 10.9 13.3 16.6

ERA § ERA GROUP INC DEC 6.3 2.9 0.8 NM NA 2.0 0.8 0.3 NA NA 5.3 2.8 1.0 NA NA

EXH § EXTERRAN HOLDINGS INC DEC 1.9 NM NM NM NM 1.4 NM NM NM NM 3.8 NM NM NM NM

FTI [] FMC TECHNOLOGIES INC DEC 7.0 7.0 7.8 9.1 8.2 8.0 8.5 10.1 10.5 10.2 24.1 26.4 29.2 31.1 40.2

GEOS § GEOSPACE TECHNOLOGIES CORP SEP 23.1 18.3 17.2 11.0 1.9 23.7 15.4 16.5 9.2 1.2 27.6 17.9 18.9 11.0 1.5

GIFI § GULF ISLAND FABRICATION INC DEC 1.2 NM NM 5.3 6.7 1.7 NM NM 3.9 6.1 2.6 NM NM 4.7 7.9HAL [] HALLIBURTON CO DEC 7.2 9.0 12.1 10.0 7.9 7.4 10.1 14.3 10.3 7.5 14.4 17.8 25.5 18.8 14.0HLX † HELIX ENERGY SOLUTIONS GROUP DEC 12.4 NM 9.3 NM 10.6 3.7 NM 3.6 NM 2.1 7.5 NM 9.7 NM 7.2


Return on Revenues (%) Return on Assets (%) Return on Equity (%)


HOS § HORNBECK OFFSHORE SVCS INC DEC 11.7 7.2 NM 8.7 13.1 2.3 1.6 NM 2.0 3.0 5.2 3.3 NM 4.4 6.8IO § ION GEOPHYSICAL CORP DEC NM 12.0 5.4 NM NM NM 8.3 3.6 NM NM NM 14.2 6.2 NM NMMTRX § MATRIX SERVICE CO JUN 2.7 2.3 3.0 0.9 NA 6.5 5.5 6.4 NA NA 10.7 8.4 10.1 NA NANOV [] NATIONAL OILWELL VARCO INC DEC 10.2 12.4 13.6 13.7 11.6 7.0 8.7 8.2 7.5 6.8 11.0 13.2 12.0 11.2 11.0NR § NEWPARK RESOURCES DEC 5.0 5.8 8.4 5.8 NM 5.4 6.4 9.9 6.3 NM 9.6 11.9 17.5 10.6 NM

OII † OCEANEERING INTERNATIONAL DEC 11.3 10.4 10.7 10.5 10.3 12.6 11.2 10.6 10.3 10.6 19.3 17.1 16.0 15.3 17.2OIS † OIL STATES INTL INC DEC 11.8 10.2 9.3 7.0 2.8 7.3 11.0 9.6 6.8 2.8 12.4 20.3 18.0 11.2 4.5SLB [] SCHLUMBERGER LTD DEC 15.0 12.9 12.1 15.5 13.9 10.6 9.3 8.9 10.0 9.6 18.3 16.5 15.3 17.0 17.5CKH § SEACOR HOLDINGS INC DEC 3.8 2.2 1.9 9.2 8.4 1.4 0.9 1.1 6.5 4.0 3.0 2.0 2.3 13.1 8.1SPN † SUPERIOR ENERGY SERVICES INC DEC NM 8.4 6.9 4.9 NM NM 6.5 4.1 3.0 NM NM 13.5 10.4 6.7 NM

TESO § TESCO CORP DEC 6.9 9.0 5.3 1.9 NM 5.9 8.8 5.4 1.6 NM 7.4 11.3 6.8 1.9 NMTTI § TETRA TECHNOLOGIES INC/DE DEC 0.0 1.8 0.5 NM 7.8 0.0 1.3 0.3 NM 5.0 0.0 3.0 0.8 NM 12.6TDW † TIDEWATER INC # MAR 9.8 12.1 8.2 10.0 22.2 3.1 3.7 2.2 3.0 8.2 5.4 5.9 3.5 4.2 11.0

OTHER COMPANIES WITH SIGNIFICANT OIL & GAS EQUIPMENT & SERVICES OPERATIONSGLF GULFMARK OFFSHORE INC DEC 15.5 5.0 13.1 NM 13.0 4.0 1.2 3.4 NM 3.2 6.8 1.9 5.1 NM 5.5SDRL SEADRILL LTD DEC 50.2 24.7 33.4 27.6 38.8 11.6 5.8 7.8 7.1 9.7 40.8 19.3 24.6 23.3 37.0RIG [] TRANSOCEAN LTD DEC 14.8 8.8 NM 10.0 27.5 4.2 2.3 NM 2.6 8.9 8.7 5.1 NM 4.6 17.2WFT WEATHERFORD INTL PLC DEC NM NM 1.5 NM 2.9 NM NM 0.9 NM 1.4 NM NM 2.0 NM 2.8

Note: Data as originally reported. ‡S&P 1500 index group. []Company included in the S&P 500. †Company included in the S&P MidCap 400. §Company included in the S&P SmallCap 600. #Of the follow ing calendar year.


Debt as a % ofCurrent Ratio Debt / Capital Ratio (%) Net Working Capital


OIL & GAS DRILLING‡ATW † ATWOOD OCEANICS SEP 2.9 2.7 2.9 3.9 2.7 36.4 29.9 23.8 14.3 19.9 425.5 354.9 172.4 86.3 143.5DO [] DIAMOND OFFSHRE DRILLING INC DEC 3.6 4.4 4.7 3.0 4.2 30.3 22.8 23.5 25.4 26.4 113.8 90.8 95.6 120.9 114.2ESV [] ENSCO PLC DEC 1.5 1.7 1.2 4.1 3.4 26.4 28.2 30.3 3.7 4.2 967.2 653.6 NM 22.1 22.0HP [] HELMERICH & PAYNE SEP 2.8 2.3 2.3 2.8 1.7 1.4 3.7 5.2 9.1 11.1 9.9 37.9 43.6 85.7 190.0NBR [] NABORS INDUSTRIES LTD DEC 2.1 2.8 1.7 1.2 3.6 37.3 39.8 40.3 33.2 40.3 270.7 218.9 338.2 668.2 251.3

NE [] NOBLE CORP PLC DEC 1.3 1.4 1.3 1.2 3.4 39.4 36.8 34.7 26.6 9.6 NM NM NM NM 71.6PTEN † PATTERSON-UTI ENERGY INC DEC 2.3 1.9 1.8 1.8 2.4 15.8 16.5 13.0 12.7 0.0 150.2 203.6 142.2 162.6 0.0PES § PIONEER ENERGY SERVICES CORP DEC 2.0 1.4 1.9 2.0 2.9 45.3 44.1 40.9 37.0 33.6 421.5 833.5 322.3 367.1 285.7RDC [] ROWAN COS PLC DEC 4.3 5.3 2.4 2.5 2.7 27.4 28.6 18.5 20.9 18.0 171.1 159.7 230.1 142.5 80.2RIG [] TRANSOCEAN LTD DEC 1.9 1.6 1.4 1.6 1.2 37.8 40.8 41.3 29.5 31.6 322.5 348.4 510.8 390.4 NM

UNT † UNIT CORP DEC 0.9 0.9 1.1 1.3 1.2 17.8 21.2 10.2 6.7 1.5 NM NM NM 397.1 130.7

OIL & GAS EQUIPMENT & SERVICES‡BHI [] BAKER HUGHES INC DEC 2.5 2.5 2.8 2.8 3.9 18.0 18.4 19.6 20.1 19.7 57.8 61.0 61.1 63.8 38.7BAS § BASIC ENERGY SERVICES INC DEC 2.4 2.5 2.7 2.8 3.5 62.4 60.2 58.0 52.7 50.7 355.2 324.6 281.2 223.9 205.4BRS § BRISTOW GROUP INC # MAR 1.6 2.8 3.7 3.8 3.1 29.9 30.4 30.9 29.6 32.0 313.6 175.5 138.3 151.4 200.2CJES § C&J ENERGY SERVICES INC DEC 2.1 2.4 2.8 1.0 0.9 16.3 19.2 0.0 26.9 46.6 124.7 119.7 0.0 NM NMCAM [] CAMERON INTERNATIONAL CORP DEC 1.9 2.2 2.2 1.9 2.1 29.5 26.4 24.3 14.7 23.4 65.6 54.7 50.0 32.8 51.0

CRR † CARBO CERAMICS INC DEC 6.6 6.9 3.8 4.6 6.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

DRC † DRESSER-RAND GROUP INC DEC 1.8 1.4 1.2 1.6 1.6 48.0 47.4 51.9 24.9 26.0 162.8 258.2 440.6 89.1 105.4

DRQ † DRIL-QUIP INC DEC 7.6 6.0 5.3 6.2 5.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1

ERA § ERA GROUP INC DEC 3.5 3.3 2.0 2.5 NA 30.2 30.8 33.7 57.4 NA 372.2 412.5 358.5 920.1 NA

EXH § EXTERRAN HOLDINGS INC DEC 1.9 1.6 1.7 1.5 1.7 44.7 49.5 53.2 52.3 55.4 258.8 337.7 390.5 471.5 388.4

FTI [] FMC TECHNOLOGIES INC DEC 1.5 1.8 1.2 1.6 1.3 35.6 45.5 2.3 20.0 26.2 94.4 104.1 6.5 41.3 71.6

GEOS § GEOSPACE TECHNOLOGIES CORP SEP 6.7 4.5 8.1 6.0 7.4 0.3 0.0 0.0 5.0 6.9 0.5 0.0 0.0 7.9 10.6

GIFI § GULF ISLAND FABRICATION INC DEC 1.8 1.9 2.3 7.1 3.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0HAL [] HALLIBURTON CO DEC 2.7 2.8 2.8 3.2 3.0 36.5 23.4 26.8 26.9 30.5 90.1 57.8 64.6 62.4 66.5HLX † HELIX ENERGY SOLUTIONS GROUP DEC 3.9 1.8 2.4 2.0 1.5 23.6 36.4 38.4 44.6 42.1 98.6 285.6 209.4 361.3 684.2


Debt as a % ofCurrent Ratio Debt / Capital Ratio (%) Net Working Capital


HOS § HORNBECK OFFSHORE SVCS INC DEC 6.1 2.1 7.0 4.0 3.1 39.0 37.2 37.3 41.6 42.8 205.0 219.2 192.1 467.6 870.9IO § ION GEOPHYSICAL CORP DEC 2.4 1.8 2.2 2.3 0.9 45.2 16.9 18.8 21.2 2.2 86.1 61.8 60.7 57.2 NMMTRX § MATRIX SERVICE CO JUN 1.8 2.2 2.2 1.9 NA 0.0 0.0 0.0 0.1 NA 0.0 0.0 0.0 0.3 NANOV [] NATIONAL OILWELL VARCO INC DEC 2.5 2.8 2.2 2.3 2.3 11.4 12.4 0.8 2.8 5.1 32.3 31.4 2.4 8.6 16.2NR § NEWPARK RESOURCES DEC 3.6 3.8 3.8 4.0 2.5 22.1 31.4 25.8 27.8 22.2 42.6 57.8 46.7 52.5 64.9

OII † OCEANEERING INTERNATIONAL DEC 2.0 1.9 2.0 2.2 2.2 0.0 4.5 6.5 0.0 8.3 0.0 16.0 24.9 0.0 24.7OIS † OIL STATES INTL INC DEC 4.1 3.5 3.1 2.0 2.9 26.2 33.0 35.7 30.0 10.3 84.4 97.9 112.6 134.1 26.9SLB [] SCHLUMBERGER LTD DEC 1.9 2.0 1.9 1.7 1.9 20.2 20.8 20.6 14.4 18.6 81.8 80.7 85.6 76.3 68.1CKH § SEACOR HOLDINGS INC DEC 3.4 2.7 2.6 2.1 3.3 31.0 28.5 29.7 23.0 23.0 137.2 205.8 156.3 115.4 103.6SPN † SUPERIOR ENERGY SERVICES INC DEC 2.3 1.9 2.2 1.5 3.8 25.5 27.0 49.5 32.2 38.0 199.3 267.3 350.1 276.8 133.6

TESO § TESCO CORP DEC 3.4 3.1 2.3 3.1 3.6 0.0 0.0 0.9 0.0 2.2 0.0 0.1 2.3 0.0 5.6TTI § TETRA TECHNOLOGIES INC/DE DEC 2.2 1.7 2.3 1.9 1.6 40.3 35.8 34.6 35.1 32.9 193.0 185.8 103.0 154.0 209.1TDW † TIDEWATER INC # MAR 2.0 1.9 2.9 3.2 2.9 35.1 26.7 25.7 20.4 9.3 359.7 414.1 208.7 177.0 72.2

OTHER COMPANIES WITH SIGNIFICANT OIL & GAS EQUIPMENT & SERVICES OPERATIONSGLF GULFMARK OFFSHORE INC DEC 2.6 3.8 3.9 2.1 1.9 30.0 30.6 21.7 21.8 22.9 429.7 222.8 170.9 288.8 370.7SDRL SEADRILL LTD DEC 0.7 0.7 0.7 1.1 1.1 63.7 63.3 60.0 60.7 60.6 NM NM NM NM NMRIG [] TRANSOCEAN LTD DEC 1.9 1.6 1.4 1.6 1.2 37.8 40.8 41.3 29.5 31.6 322.5 348.4 510.8 390.4 NMWFT WEATHERFORD INTL PLC DEC 1.5 1.6 1.8 2.5 2.2 46.4 44.5 40.3 41.0 37.6 229.6 212.4 182.3 167.0 174.9



Price / Earnings Ratio (High-Low) Dividend Payout Ratio (%) Dividend Yield (High-Low, %)

Ticker Company Yr. End 2013 2012 2011 2010 2009 2013 2012 2011 2010 2009

OIL & GAS DRILLING‡ATW † ATWOOD OCEANICS SEP 11 - 8 12 - 8 12 - 7 10 - 6 10 - 3 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0DO [] DIAMOND OFFSHRE DRILLING INC DEC 19 - 14 14 - 11 12 - 7 16 - 8 11 - 5 89 68 51 76 81 6.4 - 4.6 6.4 - 4.8 6.8 - 4.3 9.6 - 4.9 15.0 - 7.4ESV [] ENSCO PLC DEC 11 - 8 12 - 8 20 - 12 14 - 9 9 - 4 37 29 45 28 2 4.4 - 3.4 3.6 - 2.4 3.7 - 2.3 3.2 - 2.0 0.5 - 0.2HP [] HELMERICH & PAYNE SEP 13 - 8 13 - 7 18 - 9 18 - 12 14 - 6 13 5 6 8 6 1.6 - 1.0 0.7 - 0.4 0.7 - 0.3 0.6 - 0.4 1.0 - 0.4NBR [] NABORS INDUSTRIES LTD DEC 36 - 28 28 - 15 27 - 9 73 - 42 NM- NM 31 0 0 0 NM 1.1 - 0.9 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

NE [] NOBLE CORP PLC DEC 14 - 11 20 - 14 32 - 19 15 - 9 7 - 3 25 26 41 29 3 2.2 - 1.8 1.9 - 1.3 2.2 - 1.3 3.4 - 1.9 0.9 - 0.4PTEN † PATTERSON-UTI ENERGY INC DEC 20 - 14 11 - 7 16 - 7 29 - 15 NM- NM 16 10 10 26 NM 1.1 - 0.8 1.6 - 0.9 1.3 - 0.6 1.7 - 0.9 2.7 - 1.1PES § PIONEER ENERGY SERVICES CORP DEC NM- NM 22 - 12 95 - 31 NM- NM NM- NM NM 0 0 NM NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0RDC [] ROWAN COS PLC DEC 19 - 15 24 - 17 41 - 26 15 - 9 9 - 3 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0RIG [] TRANSOCEAN LTD DEC 15 - 11 26 - 17 NM- NM 32 - 14 10 - 5 43 35 NM 0 0 3.8 - 2.8 2.0 - 1.3 6.2 - 2.8 0.0 - 0.0 0.0 - 0.0

UNT † UNIT CORP DEC 14 - 11 NM- 67 16 - 8 16 - 11 NM- NM 0 0 0 0 NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

OIL & GAS EQUIPMENT & SERVICES‡BHI [] BAKER HUGHES INC DEC 24 - 17 18 - 12 20 - 11 28 - 17 35 - 19 24 20 15 29 44 1.5 - 1.0 1.6 - 1.1 1.4 - 0.7 1.7 - 1.0 2.3 - 1.2BAS § BASIC ENERGY SERVICES INC DEC NM- NM 44 - 17 32 - 11 NM- NM NM- NM NM 0 0 NM NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0BRS § BRISTOW GROUP INC # MAR 17 - 10 15 - 11 30 - 22 13 - 8 12 - 5 19 22 34 0 0 1.9 - 1.2 2.1 - 1.5 1.6 - 1.1 0.0 - 0.0 0.0 - 0.0CJES § C&J ENERGY SERVICES INC DEC 20 - 14 7 - 5 11 - 4 NA - NA NA - NA 0 0 0 NA NA 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 NA - NA NA - NACAM [] CAMERON INTERNATIONAL CORP DEC 23 - 18 20 - 13 30 - 18 22 - 14 20 - 8 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

CRR † CARBO CERAMICS INC DEC 36 - 17 29 - 13 33 - 16 31 - 17 31 - 12 31 22 16 22 31 1.8 - 0.9 1.7 - 0.8 1.0 - 0.5 1.3 - 0.7 2.7 - 1.0DRC † DRESSER-RAND GROUP INC DEC 30 - 24 24 - 17 37 - 23 24 - 16 13 - 6 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0DRQ † DRIL-QUIP INC DEC 29 - 18 26 - 19 35 - 20 33 - 16 22 - 7 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0ERA § ERA GROUP INC DEC 38 - 13 NA - NA NA - NA NA - NA NA - NA 0 0 0 NA NA 0.0 - 0.0 NA - NA NA - NA NA - NA NA - NAEXH § EXTERRAN HOLDINGS INC DEC 38 - 24 NM- NM NM- NM NM- NM NM- NM 0 NM NM NM NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

FTI [] FMC TECHNOLOGIES INC DEC 28 - 20 31 - 21 33 - 21 29 - 15 20 - 8 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0GEOS § GEOSPACE TECHNOLOGIES CORP SEP 21 - 12 32 - 14 23 - 11 43 - 15 NM- 30 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0GIFI § GULF ISLAND FABRICATION INC DEC 55 - 38 NM- NM NM- NM 34 - 16 16 - 3 82 NM NM 4 9 2.1 - 1.5 2.0 - 1.1 1.2 - 0.7 0.3 - 0.1 2.6 - 0.6HAL [] HALLIBURTON CO DEC 24 - 15 14 - 9 18 - 8 21 - 11 25 - 11 22 13 11 18 28 1.5 - 0.9 1.4 - 0.9 1.3 - 0.6 1.7 - 0.9 2.5 - 1.1HLX † HELIX ENERGY SOLUTIONS GROUP DEC 27 - 20 NM- NM 18 - 9 NM- NM 18 - 2 0 NM 0 NM 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

20092013 2012 2011 2010


Price / Earnings Ratio (High-Low) Dividend Payout Ratio (%) Dividend Yield (High-Low, %)

Ticker Company Yr. End 2013 2012 2011 2010 2009 2013 2012 2011 2010 2009

HOS § HORNBECK OFFSHORE SVCS INC DEC 33 - 19 42 - 30 NM- NM 19 - 9 16 - 5 0 0 NM 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0IO § ION GEOPHYSICAL CORP DEC NM- NM 22 - 13 93 - 28 NM- NM NM- NM NM 0 0 NM NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0MTRX § MATRIX SERVICE CO JUN 27 - 12 23 - 14 20 - 10 66 - 43 NA - NA 0 0 0 0 NA 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0NOV [] NATIONAL OILWELL VARCO INC DEC 16 - 12 15 - 10 18 - 10 17 - 8 14 - 6 17 8 10 10 31 1.4 - 1.1 0.8 - 0.5 0.9 - 0.5 1.3 - 0.6 5.0 - 2.2NR § NEWPARK RESOURCES DEC 22 - 12 15 - 8 11 - 6 20 - 8 NM- NM 0 0 0 0 NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

OII † OCEANEERING INTERNATIONAL DEC 26 - 16 22 - 16 23 - 15 21 - 11 18 - 8 24 26 21 0 0 1.5 - 1.0 1.6 - 1.2 1.4 - 0.9 0.0 - 0.0 0.0 - 0.0OIS † OIL STATES INTL INC DEC 20 - 13 10 - 7 14 - 7 20 - 10 34 - 9 0 0 0 0 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0SLB [] SCHLUMBERGER LTD DEC 18 - 13 20 - 14 27 - 15 25 - 15 27 - 13 24 27 28 25 32 1.8 - 1.3 1.9 - 1.4 1.8 - 1.0 1.6 - 1.0 2.4 - 1.2CKH § SEACOR HOLDINGS INC DEC 42 - 29 59 - 47 58 - 39 10 - 6 13 - 7 0 296 0 131 0 0.0 - 0.0 6.3 - 5.0 0.0 - 0.0 22.4 - 12.9 0.0 - 0.0SPN † SUPERIOR ENERGY SERVICES INC DEC NM- NM 12 - 7 24 - 12 34 - 17 NM- NM NM 0 0 0 NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0

TESO § TESCO CORP DEC 22 - 12 13 - 7 33 - 14 86 - 47 NM- NM 0 0 0 0 NM 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0TTI § TETRA TECHNOLOGIES INC/DE DEC NM- NM 51 - 25 NM- NM NM- NM 13 - 2 NM 0 0 NM 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0TDW † TIDEWATER INC # MAR 22 - 16 21 - 14 37 - 23 28 - 18 10 - 6 35 33 58 49 20 2.2 - 1.6 2.4 - 1.6 2.6 - 1.6 2.6 - 1.8 3.2 - 1.9

OTHER COMPANIES WITH SIGNIFICANT OIL & GAS EQUIPMENT & SERVICES OPERATIONSGLF GULFMARK OFFSHORE INC DEC 20 - 12 77 - 37 26 - 16 NM- NM 18 - 8 37 137 0 NM 0 3.0 - 1.9 3.7 - 1.8 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0SDRL SEADRILL LTD DEC 8 - 6 18 - 13 13 - 8 19 - 7 16 - 16 48 182 103 68 0 7.9 - 5.7 13.7 - 10.2 12.7 - 8.1 10.4 - 3.5 0.0 - 0.0RIG [] TRANSOCEAN LTD DEC 15 - 11 26 - 17 NM- NM 32 - 14 10 - 5 43 35 NM 0 0 3.8 - 2.8 2.0 - 1.3 6.2 - 2.8 0.0 - 0.0 0.0 - 0.0WFT WEATHERFORD INTL PLC DEC NM- NM NM- NM NM- 43 NM- NM 68 - 26 NM NM 0 NM 0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0 0.0 - 0.0


2013 2012 2011 2010 2009


Earnings per Share ($) Tangible Book Value per Share ($) Share Price (High-Low, $)


OIL & GAS DRILLING‡ATW † ATWOOD OCEANICS SEP 5.38 4.17 4.20 3.99 3.91 34.46 29.63 25.44 21.26 17.16 59.49 - 43.91 50.18 - 34.93 48.84 - 30.64 40.48 - 23.71 40.58 - 13.03DO [] DIAMOND OFFSHRE DRILLING INC DEC 3.95 5.18 6.92 6.87 9.90 33.35 32.92 31.17 27.78 26.11 76.85 - 54.78 73.50 - 54.86 81.19 - 51.16 107.12 - 54.70 108.78 - 53.30ESV [] ENSCO PLC DEC 6.10 5.24 3.09 3.80 5.45 40.39 36.26 32.01 39.34 36.22 65.82 - 51.01 61.48 - 41.63 60.31 - 37.39 53.93 - 33.33 51.30 - 22.04HP [] HELMERICH & PAYNE SEP 6.75 5.35 4.06 2.70 3.36 41.64 36.28 30.54 26.53 25.43 84.87 - 55.78 68.60 - 38.71 73.40 - 35.58 49.46 - 32.34 46.24 - 19.50NBR [] NABORS INDUSTRIES LTD DEC 0.51 0.82 1.19 0.37 (0.30) 18.48 18.85 17.68 16.92 17.59 18.33 - 14.34 22.73 - 12.40 32.47 - 11.05 27.05 - 15.54 24.07 - 8.25

NE [] NOBLE CORP PLC DEC 3.05 2.05 1.46 3.03 6.44 32.84 30.56 29.35 28.39 26.29 42.34 - 34.38 41.71 - 28.73 46.72 - 27.33 45.60 - 26.23 45.18 - 20.03PTEN † PATTERSON-UTI ENERGY INC DEC 1.29 1.96 2.08 0.77 (0.22) 17.95 16.92 15.03 13.02 12.99 26.09 - 18.59 22.14 - 12.81 34.09 - 15.06 22.67 - 11.85 18.07 - 7.49PES § PIONEER ENERGY SERVICES CORP DEC (0.58) 0.49 0.19 (0.62) (0.46) 7.77 7.45 6.73 6.90 7.32 9.91 - 6.46 10.60 - 5.91 18.00 - 5.83 9.90 - 5.00 8.37 - 3.13RDC [] ROWAN COS PLC DEC 2.04 1.65 1.09 2.39 3.24 39.39 36.48 35.01 29.71 27.32 38.65 - 30.21 39.40 - 28.61 44.83 - 28.13 35.39 - 20.44 27.54 - 10.28RIG [] TRANSOCEAN LTD DEC 3.87 2.27 (18.40) 2.99 9.87 37.99 35.49 35.46 41.20 38.27 59.50 - 44.19 59.03 - 38.80 85.98 - 38.21 94.88 - 41.88 94.44 - 46.11

UNT † UNIT CORP DEC 3.83 0.48 4.11 3.10 (1.18) 42.98 39.33 39.09 34.33 31.50 52.81 - 40.51 50.90 - 32.08 63.81 - 33.56 51.00 - 33.36 47.25 - 17.75

OIL & GAS EQUIPMENT & SERVICES‡BHI [] BAKER HUGHES INC DEC 2.47 2.98 3.99 2.06 1.36 24.80 22.94 19.79 15.42 18.18 58.83 - 40.98 52.96 - 37.08 81.00 - 41.91 57.45 - 35.62 48.19 - 25.69BAS § BASIC ENERGY SERVICES INC DEC (0.89) 0.51 1.17 (1.10) (6.39) 3.71 4.45 4.77 5.81 7.42 17.40 - 11.06 22.50 - 8.52 37.79 - 12.49 17.54 - 7.03 15.18 - 5.30BRS § BRISTOW GROUP INC # MAR 5.15 3.61 1.76 3.67 3.23 46.62 43.41 41.36 40.56 36.41 85.70 - 53.57 54.97 - 37.92 52.89 - 37.98 48.10 - 28.32 39.20 - 16.42CJES § C&J ENERGY SERVICES INC DEC 1.25 3.51 3.13 0.62 (0.05) 6.73 5.27 5.87 0.91 (0.03) 25.35 - 17.45 23.11 - 16.05 32.94 - 12.65 NA - NA NA - NACAM [] CAMERON INTERNATIONAL CORP DEC 2.89 3.05 2.13 2.32 2.15 9.14 13.40 11.33 10.91 9.04 67.42 - 52.50 60.00 - 38.38 63.16 - 38.77 51.71 - 31.42 42.49 - 17.19

CRR † CARBO CERAMICS INC DEC 3.67 4.59 5.62 3.41 2.27 32.51 30.06 26.42 21.67 18.88 132.55 - 62.11 135.00 - 60.33 183.34 - 90.41 105.00 - 58.70 71.26 - 26.33DRC † DRESSER-RAND GROUP INC DEC 2.21 2.37 1.54 1.81 2.58 (1.43) (4.32) (6.35) 2.17 1.16 67.38 - 52.75 56.51 - 41.01 56.53 - 34.68 43.64 - 28.98 32.96 - 16.58DRQ † DRIL-QUIP INC DEC 4.18 2.96 2.38 2.57 2.68 30.54 26.35 23.03 20.68 17.78 121.07 - 73.70 77.12 - 57.27 82.49 - 47.40 83.80 - 40.38 59.00 - 18.13ERA § ERA GROUP INC DEC 0.92 0.37 0.10 (0.17) NA 21.59 13.17 11.22 163,240.99 NA 34.64 - 12.00 NA - NA NA - NA NA - NA NA - NAEXH § EXTERRAN HOLDINGS INC DEC 0.90 (1.68) (5.34) (2.37) (4.12) 24.16 21.47 20.22 19.79 20.15 34.48 - 22.01 22.23 - 8.79 25.42 - 8.07 30.28 - 19.24 26.99 - 13.69

FTI [] FMC TECHNOLOGIES INC DEC 2.10 1.79 1.66 1.54 1.46 5.79 3.55 4.19 3.63 2.65 59.79 - 42.04 55.19 - 36.89 54.88 - 34.46 45.40 - 23.08 29.78 - 11.68GEOS § GEOSPACE TECHNOLOGIES CORP SEP 5.40 2.76 2.39 1.16 0.15 22.19 16.64 13.77 10.97 9.68 113.73 - 65.31 89.13 - 37.96 54.99 - 25.87 50.15 - 16.92 21.85 - 4.50GIFI § GULF ISLAND FABRICATION INC DEC 0.49 (0.29) (0.13) 0.90 1.44 19.01 18.92 19.67 20.03 19.14 26.82 - 18.76 35.48 - 19.89 36.00 - 19.55 30.56 - 14.18 22.90 - 4.92HAL [] HALLIBURTON CO DEC 2.35 2.78 3.27 1.98 1.28 13.44 14.67 12.40 9.95 8.46 56.52 - 35.07 39.19 - 26.28 57.77 - 27.21 41.73 - 21.10 32.00 - 14.68HLX † HELIX ENERGY SOLUTIONS GROUP DEC 1.03 (0.67) 1.23 (1.22) 0.92 13.59 12.57 12.87 11.34 12.71 27.58 - 20.33 21.09 - 14.90 21.65 - 10.92 17.00 - 8.38 16.92 - 2.21


Earnings per Share ($) Tangible Book Value per Share ($) Share Price (High-Low, $)


HOS § HORNBECK OFFSHORE SVCS INC DEC 1.79 1.05 (0.09) 1.38 1.94 35.89 32.86 30.65 31.67 30.47 59.93 - 34.82 43.83 - 31.26 36.24 - 19.80 25.75 - 12.63 30.76 - 10.28IO § ION GEOPHYSICAL CORP DEC (1.59) 0.40 0.15 (0.27) (1.03) 1.16 2.57 2.10 1.84 0.82 7.70 - 2.81 8.79 - 5.28 13.92 - 4.20 8.81 - 3.26 6.56 - 0.83MTRX § MATRIX SERVICE CO JUN 0.92 0.66 0.72 0.19 NA 7.65 6.83 6.18 5.55 NA 24.74 - 11.41 15.06 - 9.35 14.69 - 7.34 12.60 - 8.25 13.21 - 5.00NOV [] NATIONAL OILWELL VARCO INC DEC 5.46 5.86 4.73 3.99 3.53 18.97 19.50 17.45 13.90 10.93 84.71 - 63.08 89.95 - 59.07 86.71 - 47.97 67.72 - 32.18 50.17 - 22.19NR § NEWPARK RESOURCES DEC 0.62 0.69 0.89 0.47 (0.23) 5.29 4.50 4.42 3.78 3.26 13.64 - 7.70 10.62 - 5.19 10.09 - 5.19 9.50 - 3.60 4.68 - 2.22

OII † OCEANEERING INTERNATIONAL DEC 3.43 2.68 2.18 1.83 1.71 15.07 12.73 10.68 11.32 9.77 87.64 - 54.27 58.53 - 43.22 49.26 - 31.77 38.43 - 19.88 30.45 - 13.89OIS † OIL STATES INTL INC DEC 5.65 8.47 6.30 3.34 1.19 36.47 32.86 26.65 19.93 22.93 113.64 - 71.28 87.65 - 60.03 87.00 - 44.77 65.98 - 33.65 40.27 - 11.14SLB [] SCHLUMBERGER LTD DEC 5.14 4.09 3.54 3.41 2.63 15.34 11.57 9.17 8.90 10.90 94.91 - 69.08 80.78 - 59.12 95.64 - 54.79 84.11 - 51.67 71.10 - 35.05CKH § SEACOR HOLDINGS INC DEC 2.37 1.69 1.94 11.43 7.21 67.24 84.47 81.34 79.64 83.10 99.00 - 67.76 100.00 - 79.78 113.20 - 75.04 116.00 - 67.01 91.93 - 52.95SPN † SUPERIOR ENERGY SERVICES INC DEC (0.70) 2.57 1.79 1.04 (1.31) 8.45 8.43 10.43 8.32 8.70 29.22 - 21.10 31.88 - 17.54 42.87 - 22.19 35.44 - 18.02 25.91 - 11.20

TESO § TESCO CORP DEC 0.93 1.29 0.71 0.19 (0.14) 12.06 11.09 9.67 9.00 8.68 20.12 - 11.05 16.88 - 8.70 23.39 - 10.01 16.40 - 9.00 13.29 - 6.25TTI § TETRA TECHNOLOGIES INC/DE DEC 0.00 0.21 0.05 (0.57) 0.92 4.25 4.16 5.37 5.30 6.15 13.41 - 7.72 10.66 - 5.35 16.00 - 6.77 14.64 - 8.00 11.62 - 1.94TDW † TIDEWATER INC # MAR 2.84 3.04 1.71 2.06 5.04 48.17 45.75 43.48 42.12 41.20 63.22 - 45.05 63.27 - 42.33 63.55 - 38.80 57.08 - 37.99 52.05 - 31.09

OTHER COMPANIES WITH SIGNIFICANT OIL & GAS EQUIPMENT & SERVICES OPERATIONSGLF GULFMARK OFFSHORE INC DEC 2.70 0.73 1.92 (1.36) 2.01 38.09 36.16 35.36 34.08 32.20 53.89 - 33.61 56.41 - 27.17 49.95 - 30.08 35.66 - 23.27 35.41 - 15.79SDRL SEADRILL LTD DEC 5.66 2.37 3.05 2.73 3.16 13.46 8.92 9.95 8.24 6.41 48.09 - 34.57 42.34 - 31.37 38.49 - 24.68 52.77 - 17.81 51.38 - 50.67RIG [] TRANSOCEAN LTD DEC 3.87 2.27 (18.40) 2.99 9.87 37.99 35.49 35.46 41.20 38.27 59.50 - 44.19 59.03 - 38.80 85.98 - 38.21 94.88 - 41.88 94.44 - 46.11WFT WEATHERFORD INTL PLC DEC (0.45) (1.02) 0.25 (0.15) 0.35 4.99 5.45 5.59 6.10 6.56 17.38 - 11.08 18.33 - 8.84 28.11 - 10.85 22.98 - 12.34 23.75 - 9.08

Note: Data as originally reported. ‡S&P 1500 index group. []Company included in the S&P 500. †Company included in the S&P MidCap 400. §Company included in the S&P SmallCap 600. #Of the follow ing calendar year. J-This amount includes intangibles that cannot be identif ied.

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In this regard, S&P Capital IQ Equity Research has no access to nonpublic information received by other units of Standard & Poor’s.

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Notice to all Non U.S. Residents: S&P Capital IQ’s Industry Surveys may be distributed in certain localities, countries and/or jurisdictions (“Territories”) by independent third parties or independent intermediaries and/or distributors (the “Intermediaries” or “Distributors”). Intermediaries are not acting as agents or representatives of S&P Capital IQ. In Territories where an Intermediary distributes S&P Capital IQ’s Industry Surveys, the Intermediary, and not S&P Capital IQ, is solely responsible for complying with all applicable regulations, laws, rules, circulars, codes and guidelines established by local and/or regional regulatory authorities, including laws in connection with the distribution of third-party investment research, licensing requirements, supervisory and record keeping obligations that the Intermediary may have under the applicable laws and regulations of the territories where it distributes the Industry Surveys. 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