Current Environment ............................................................................................1Industry Profile....................................................................................................11Industry Trends ...................................................................................................13How the Industry Operates...............................................................................22Key Industry Ratios and Statistics...................................................................33How to Analyze an Oil & Gas Production & Marketing Company .............34Glossary................................................................................................................40Industry References...........................................................................................43Comparative Company Analysis ......................................................................45This issue updates the one dated March 29, 2012.The next update of this Survey is scheduled for March 2013.Industry SurveysOil & Gas: Production & MarketingMichael Kay, Integrated Oil & Gas Equity AnalystSeptember 27, 2012CONTACTS:INQUIRIES & CLIENT RELATIONS800.firstname.lastname@example.orgSALES877.email@example.comMEDIAMichael Privitera212.firstname.lastname@example.orgS&P CAPITAL IQ55 Water StreetNew York, NY 10041
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 1CURRENT ENVIRONMENTMajor swings in crude oil prices in 2012Oil and gas markets have been highly volatile so far in 2012. Economic turmoil (particularly in Europe) hasled to lower demand expectations, which in turn increased downward pressure on oil prices through May(when oil prices fell below $78 per barrel). Since July, however, oil prices have rebounded to over $90 perbarrel, on hopes that the European Union (EU), China, and the US would provide additional economicstimulus to counteract slowing growth. Oil prices have also been pushed higher for a number of otherreasons, including the imposition of sanctions on Iran, which is threatening to close the Strait of Hormuz(through which about 20% of the world’s petroleum is shipped); the possibility of Israeli action againstIran’s nuclear facilities; and concerns about reduced production in the North Sea due to turnarounds.We expect oil prices to remain volatile in the near term, as sluggish growth in the US economy, the debtcrisis in the EU, and the slowdown in growth in key emerging markets such as China and India are allexerting pressure on global economic growth. In July 2012, the US Energy Information Administration(EIA), a statistical agency of the US Department of Energy, reduced its global economic growth forecast to2.9% for both years, a cut of 0.1% for 2012 and 0.6% for 2013. In August, it further reduced the forecastfor 2012 to 2.8%, while maintaining the forecast for 2013. In the US, real gross domestic product (GDP)growth slowed to 1.5% in the second quarter of 2012 from 2.0% in the first quarter. As of August 2012,Standard & Poor’s Economics (which operates separately from S&P Capital IQ) expected real US GDP togrow by 2.1% for the full year.Oil demand, which is positively correlated to economic growth, is also seeing a slowdown. According to areport published in July 2012 by the Paris-based International Energy Agency (IEA), an autonomousinternational organization that provides energy research and policy recommendations, global crude oildemand was expected to average 89.1 million barrels per day (b/d) in the first half of 2012, lower than theJanuary 2012 forecast of 89.3 million b/d. In August 2012, the US Energy Information Administration(EIA) lowered its global liquid fuel consumption growth forecast to 0.8 million b/d in 2012 and 0.9 millionb/d in 2013, from its January 2012 growth forecast of 1.3 million b/d and 1.5 million b/d, respectively.Crude oil demand in the US, which accounts for more than 21% of global demand, fell by 2.6% year overyear in the first half of 2012, reflecting sluggish economic growth, according to industry trade groupAmerican Petroleum Institute (API). In August 2012, the EIA forecasted a reduction in crude oilconsumption in the US by 170,000 b/d in 2012. Demand for oil in the EU, which accounts for about 16%of global oil use, has dropped as some of the countries have fallen into recession. In August 2012, the EIAestimated oil demand in Europe this year at 13.9 million b/d, down from 14.2 million b/d in 2011. China,which is world’s second largest consumer of oil, has also seen its demand for oil decline. The EIA, in itsAugust report, forecasted Chinese oil demand to grow by 4.3% in 2012 (the lowest projected growth in 20months), The EIA forecast for 2012 implies second-half growth of 2% and is based on the expectation thatChinese authorities will provide sufficient economic stimulus.Geopolitical issues in the Middle East have raised concerns about global crude oil supplies (discussed inmore detail below). While the sanctions on Iran (which exports nearly 2.2 million b/d of crude) are expectedto disrupt supply, Saudi Arabia is trying to negate the impact by increasing its own output. The Organizationof the Petroleum Exporting Countries (OPEC), which accounts for 40% of the world oil supply, agreed tokeep its production ceiling unchanged at 30 million b/d in a meeting held in June 2012. For the non-OPECcountries, the EIA expects supply to rise by 0.6 million b/d in 2012, and by a further 1.3 million b/d in2013. The largest area of non-OPEC growth is North America, where the EIA estimates that productionwill increase by 970,000 b/d and 510,000 b/d in 2012 and 2013, respectively, due to continuing productiongrowth from US onshore shale and other tight oil formations and from Canadian oil sands.
2 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSWe continue to expect strong global crude oil prices to drive upstream spending and an active merger andacquisition (M&A) environment throughout many areas of the world. According to IHS Herold’s 2011Global Upstream Performance Review, upstream spending was estimated at $406 billion for 2011, anincrease of 12% over the previous year’s level. Domestic oil prices, based on the US benchmark West TexasIntermediate (WTI) crude oil price, remain comfortably above $90 per barrel and global oil prices, based onthe Brent crude oil benchmark, remain above $110 per barrel and should continue to drive upstreamactivity levels over the next 12 months, in our view.As of August 2012, based on data from IHS Global Insight Inc., a global research firm, S&P Capital IQexpected WTI spot prices to average $91.96 per barrel in 2012 and $89.50 in 2013, versus $95.07 in 2011.GEOPOLITICAL RISKS DECLINE, SURPASSED BY ECONOMIC CONCERNSGeopolitical tensions in the Middle East/North Africa such as the friction in Iraq and Iran, supply disruptionsin Libya, and the effects of civil war in Egypt continue to affect the crude oil market. However, demand sideconcerns such as slowing global economic growth (the sluggish US economy, the debt crisis in the EU, andslowing growth in emerging markets) now pose a larger risk for the crude oil market.The Iran issue has been there for some time now, but recent developments have increased its significance. Inan effort to ramp up the sanctions designed to curb Iran’s nuclear program ambitions, the EU imposed an oilembargo against that country and decided to freeze the assets of its central bank beginning in July 2012. InMarch 2012, the EU had disconnected all Iranian banks from the Society for Worldwide InterbankFinancial Telecommunication (SWIFT), thereby stopping all Iranian international banking transactions. Asof July 2012, the US also imposed sanctions against Iran, under which financial institutions doing businesswith Iran’s central bank would be barred from doing business in the US. Further, the US persuaded Iran’soil customers to halt or substantially cut back oil purchases and find alternative sources. In a retaliatorymeasure, Iran announced legislation in July intended to disrupt traffic in the Strait of Hormuz by blocking oiltankers heading through the strait en route to countries no longer buying Iranian crude.Iraq is on a path of recovery with higher oil production expected in the next five years, but ongoingsectarian violence, political instability, and slow growth in infrastructure are proving to be major obstacles.Further, recent deals by oil majors in the self-regulated Kurdistan region have irked Iraq. Exxon Mobil,Chevron Corp., and Total SA have all bought stakes in exploration blocks in Iraq’s Kurdistan region,without the approval of the Iraqi government. Iraq asked the companies to either scrap the deals or face theconsequence of being blacklisted for violating Iraqi law. The companies believe that the contractualconditions in Kurdistan were better than in the rest of Iraq.The political turmoil in Egypt raised concerns in 2011, as it could have disrupted the Suez Canal transitroute, which is used extensively in the transport of oil to global markets. The Egyptian revolution, whichbegan 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 MohammedMorsi was declared the winner. Things have since begun to normalize in Egypt.Libya, which had been in civil war in 2011, is showing signs of recovery. The civil war ended in October,after the death of the country’s former leader, Muammar Gaddafi, and the collapse of his 34-year-oldJamahiriya state. Libya, which had production of 1.6 million b/d of oil before the civil war, expectsproduction to rise to that level again by October 2012. According to the EIA, Libyan production hasalready surpassed 1.5 million b/d.ONSHORE LIQUIDS CONTINUE TO FUEL UNCONVENTIONAL RESOURCE RUSHOver the past decade, oil and gas producers have shifted their focus toward development of unconventionalresources as a new avenue for growth. The scarcity of global oil and gas resources, rising demand, tightsupplies, geopolitical factors, and the increasingly competitive dynamics between international oilcompanies (IOCs) and national oil companies (NOCs) have all driven the increase in unconventional oil andgas production. North America, with its abundance of undeveloped shale and tight gas reserves, has been at
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 3the forefront of this developing trend. Now, the industry has begun a fundamental shift toward finding anddeveloping unconventional oil prospects.Over the last several years, the development of shale natural gas properties, mainly by North Americanexploration and production (E&P) companies, has become a global game-changer and led to an oversuppliednatural gas market. The merger and acquisition (M&A) market for shale gas remains very active, as NOCs,IOCs, and E&Ps all look for future reserve and production growth prospects. Producers have known aboutshale gas and its potential for decades, but new technologies (e.g., horizontal drilling and hydraulic fracturing)and a spike in gas prices earlier in the decade made drilling economically viable. Since 2006, domestic E&Pshave invested significant development capital into these plays, sending North American natural gasproduction levels higher. However, the global economic slowdown in 2008 hurt demand and subsequentlyplaced downward pressure on prices. This has led to a slowdown in gas drilling that, coupled with highercrude oil and natural gas liquids (NGL) prices, has resulted in a pick-up in rigs targeting liquids prospects.Interest in natural gas assets remains strong, as evidenced by IOCs’ and NOCs’ continued entry into NorthAmerican shale gas plays in 2010 and 2011, and through the first half of 2012. Nevertheless, we expect theemerging shift to unconventional crude oil and NGL, which began in early 2010, to garner most of theindustry’s attention over the next several years. With oil prices rising and deepwater Gulf of Mexico drillingslow to return, many gas-dominant domestic producers shifted their strategy during 2010 to raise theirexposure to higher-margin liquids. Major US natural gas producers have disposed of some of their naturalgas assets, planning instead to focus most of their investment capital on liquids. We believe domesticupstream spending increased by about 10% in 2011, reflecting strong activity at onshore liquids resources.We are seeing a similar rise in 2012, with most of the incremental spending directed toward conventionaloil, liquids-rich basins, and oil shales. Dry gas drilling has seen a major slowdown, as domestic gas marketsremain depressed.Eagle Ford, Bakken, Permian Basin, and other shale regions in the spotlightThe Eagle Ford Shale in south Texas has emerged as the hottest play in North America. Petrohawk EnergyCorp. drilled some initial wells in 2008, but there was little enthusiasm given the global recession andflooded gas markets. However, the field has higher liquids content than traditional shale. In 2010,Norway’s Statoil ASA, India’s Reliance Industries Ltd., and China National Offshore Oil Corp. (CNOOC,the third-largest national oil company in China) all entered the Eagle Ford Shale with billion-dollardevelopment deals, a reflection of the international interest in these assets. In August 2011, BHP Billitoncompleted the acquisition of Petrohawk for $15.2 billion. The deal vaulted BHP into the top-10 natural gasproducers worldwide. According to the Land Rig Newsletter, a trade publication, there were 211 rigs in theEagle Ford Shale as of July 27, 2012, up from 177 in the third quarter of 2011.The second most active onshore unconventional oil play has been the Bakken Shale formation. Located inMontana, North Dakota, and part of Saskatchewan, it is estimated to be one of the biggest oil fields in theUS. In 2008, the US Geologic Survey estimated recoverable reserves in the Bakken formation at 3.0 billionto 4.3 billion barrels of oil, but other estimates are much higher. EOG Resources is the largest Bakkenproducer, and integrated oils like Hess Corp. and Marathon Oil Corp. are ramping up development efforts.According to the Land Rig Newsletter, there were 160 active rigs in the Bakken Shale as of July 27, 2012, upfrom 141 in the third quarter of 2011. Bakken oil growth has expanded faster than anticipated, and a buildupof infrastructure is needed to expand takeaway capacity.The Permian Basin, located in western Texas and southeastern New Mexico, is one of the oldest and richestoil basins in the country. Permian formations have long trapped hydrocarbons in shale, other tight sands,and rock extending to approximately 250 miles wide and 300 miles long. Companies have held acreage inthis area for many years, but have been unable to extract oil in the absence of advanced technologicalmethods. However, this region is now in focus. According to Chevron, there are reserves of 60 billion oilequivalent barrels still available, even after extracting around 40 billion oil equivalent barrels since the1920s. According to the Land Rig Newsletter, there were 381 active rigs in the Permian Basin as of July 27,2012, up from 274 in the third quarter of 2011.
4 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSThe most active gas play, the Marcellus Shale, is in Appalachia (77 rigs at July 27, 2012). We expect M&Aactivity to remain high at Eagle Ford and Bakken, though capital investments there will have to includeinfrastructure costs, given that those basins are mostly undeveloped. Compared with Eagle Ford, Bakken isa much more fragmented play, characterized by many small, private operators.Other liquids-rich regions garnering attention are the Barnett Shale combo play, a liquids-rich portion of thehuge gas-heavy Barnett Shale in North Texas; the Granite Wash in the Texas Panhandle; the Wolfcamp andLeonard Shales in Texas and New Mexico; the DJ Basin’s Niobrara Shale in Colorado and other states; and theUtica Shale in Ohio. Early well results have been promising at these plays; as development expands, we expectefficiencies to improve in spacing, depth, drill times, and well costs.Canadian oil sands, another unconventional source, also have become economically realistic in recent years.Their further development could help Canada become one of the world’s largest oil producers. Since 2008,France’s Total SA has invested over $3 billion to enter the Athabasca oil sands in Alberta. In March 2010,Devon Energy Corp. and BP plc formed a joint venture to develop oil sands properties in Alberta. An influxof foreign investments in recent years, particularly by the Asian national oil companies, should helpaccelerate development in Canada. Sinopec Corp., China National Offshore Oil Corp. (CNOOC),PetroChina Co. Ltd., and Petroliam Nasional Berhad (Petronas) have all made multibillion-dollarinvestments over the last two years in Canadian oil sands. Sinopec alone has spent close to $8 billion toacquire oil sands deposits.NATURAL GAS MARKETS REMAIN VOLATILEUS natural gas supplies have ballooned in recent years as companies tapped vast reserves in shaleformations. According to the EIA, total marketed production of natural gas grew by 4.8 billion cubic feetper day (Bcf/d) in 2011, a 7.9% increase over 2010. The EIA expects year-over-year growth in marketedproduction of 2.5 Bcf/d in 2012. In the near term, it expects a small drop in production due to losses fromhurricanes and declines related to recent drops in the rig count. According to Baker Hughes Inc., the naturalgas rig count was 498 as of August 3, 2012, compared with 811 at the start of 2012.High production and supply, coupled with weak demand due to mild winter weather in early 2012 led to asteep fall in natural gas prices. According to the EIA, the price of natural gas averaged $1.95 per millionBritish thermal units (MMBtu) in April 2012, compared to $3.17 per MMBtu in December 2011. Sincethen, prices have recovered modestly, averaging $2.95 per MMBtu in July 2012 on the back of increaseddemand for power generation due to a hot summer. The EIA expects natural gas consumption to increaseyear over year by 3.2 Bcf/d (4.8%) in 2012, due to higher demand from power generation.As of August 2012, based on data from IHS Global Insight, S&P Capital IQ expected Henry Hub spotprices to average $2.55 per million Btu in 2012 and $3.83 in 2013, versus $4.00 in 2011.CRUDE DISCONNECT: WTI vs. BRENT CRUDEOver the past five years, West Texas Intermediate (WTI) crude oil prices have traded at a slight premium tothe Brent crude oil benchmark, with a spread ranging generally between +/–$3 per barrel. Since the end of2010, however, WTI has been trading at a discount to Brent, with the differential widening to more than $21per barrel on August 13, 2012, from $2.92 per barrel on December 31, 2010. In our view, these benchmarksare reacting differently to certain fundamental factors, which have led to a disconnect in their relative prices.WTI is a light, sweet crude oil used as an oil price benchmark in the US. Most WTI crude oil is priced at theCushing Hub in Oklahoma and is refined in the Mid-Continent region of the US. Brent is a combination ofcrude oil from 15 different oil fields in the Brent and Ninian systems in the North Sea. Like WTI, Brent is alight, sweet crude, but is slightly more complex to refine, and hence has typically traded at a discount to WTI.WTI has historically been an indicator of North American oil prices and markets, while Brent has been theEuropean indicator. However, as new producers (e.g., Russia and Nigeria) have emerged, they have used theBrent oil price as their benchmark, making it more of a global oil indicator than WTI, in our opinion.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 5The widening differential also reflects growing crude oil inventories at Cushing, as rising production andtakeaway capacity from Canada, the Rocky Mountains, and the Mid-Continent shale plays have increasedsupplies. However, the shortage of pipeline capacity for carrying oil from the main terminal in Cushing torefineries in Texas and other parts of the Gulf Coast has added to the bottleneck at Cushing. According tothe EIA, crude oil inventories at Cushing had increased to 45.2 million barrels as of August 10, 2012, versus29.1 million barrels on January 6.The steep contango of the WTI curve in 2009 and 2010 also promoted the inventory buildup. (Contangooccurs when the current spot rate is lower than the future price.) Speculators can benefit from contango bybuying crude oil at today’s spot price, paying for storage, and then selling at a locked-in future price. Thecontango in oil markets eased considerably in 2011, so new supplies are likely driving inventory builds.Proposed pipeline projects aimed at easing Cushing bottleneckSeveral new projects have been sanctioned in 2012 to alleviate the bottlenecks at Cushing. Enbridge Inc. andEnterprise Products Partners LP of Houston, partners in the Seaway Crude Pipeline, have reversed thatpipeline’s flow to carry crude southward from Cushing to the Gulf Coast. In May 2012, the Seaway pipelinestarted delivering crude oil to the Gulf Coast, pumping 150,000 b/d. This flow will be increased to 400,000b/d by the first quarter of 2013.TransCanada Corp.’s Keystone Gulf Coast Expansion project, also known as Keystone XL, was proposedin 2008 and involved two phases. The first phase involved extension of the pipeline from Cushing to servethe Port Arthur and Houston markets in Texas; the second involved building another pipeline from Albertathrough South Dakota and Nebraska, to join the existing pipeline in Steele City, Nebraska. However, theproject became controversial because its proposed route passes through the Ogallala Aquifer, a significantsource of water for drinking and irrigation for Nebraska and several other states.On January 18, 2012, the Obama Administration denied a permit for the pipeline project due to lack oftime to weigh the environmental risks. TransCanada has submitted a new route for the northern section ofthe Keystone XL project, avoiding the Sandhills region, but it would still pass over the aquifer throughnorthern Holt County, 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 will undergo athorough review process expected to take approximately six to 10 months and, according to NebraskaGovernor Dave Heineman, should be completed in the first quarter of 2013.Meanwhile, in July 2012, the southern leg of the Keystone XL project, from Cushing to Port Arthur andHouston, received final approval from the US Army Corps of Engineers to begin construction of that part,which will extend 485 miles. However, environmentalists still have not given up and have appealed to theEnvironmental Protection Agency (EPA) to step in under the Clean Water Act and overrule the Corps.While we don’t believe that the $21 WTI–Brent differential is sustainable in the long run, the increasingcrude oil production being delivered into Cushing has prevented the differential from reverting to itshistorical norm. We expect Cushing’s storage issues to ease when new storage capacity is added, additionalpipelines are built, or major pipelines are reversed. However, these expansion projects will take years tobuild, dampening the prospects of a meaningful decline in inventories.MOVE OVER OIL AND COAL: GAS AND RENEWABLES INCREASE THEIR MARKET SHAREThe energy landscape is undergoing dramatic structural changes, driven by new engineering technology,which has enabled the discovery and development of new sources of unconventional oil and gas, and bynew and proposed environmental legislation, which are intended to address global warming concerns andreductions of greenhouse gas (GHG) emissions.Structural changes in the automobile, aviation, and power generation sectors are suggesting the use ofcleaner and more efficient technologies. Forecasts by the IEA and EIA indicate that natural gas, renewables,and nuclear power will be increasingly preferred. In addition, a diminishing number of OECD
6 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYS(Organisation for Economic Co-operation and Development) countries are using oil for heating, power, orindustrial processes, and competition from cheap spot natural gas is likely to further cap discretionary use in2012. While oil is irreplaceable as a global feedstock for many industrial processes, its use in OECD powergeneration has already fallen by 40% since 2000.The transportation sector is projected to continue to dominate the demand for liquid fuels, but we expectstrides as vehicle efficiency standards and the penetration of biofuels and hybrid and electric vehicles reducethe need for refinery-sourced gasoline and diesel.America’s natural gas revolutionAdvances in US science and engineering—in seismic, horizontal drilling, and hydraulic fracturing (or“fracking”)—are transforming the energy landscape. These advances are enabling the exploitation of newsources of unconventional gas resources (such as tight gas, shale gas, and coal bed methane, or CBM) inNorth America, in many cases at costs below conventional resources, as well as unconventional sources ofoil (such as shale oil, deepwateroil, and heavy oil). While theseinnovations seemed to surprise thefinancial community, theyrepresent an escalation oftechnology that many engineershad been anticipating for years.If these US-based engineeringtechnologies can be applied tounconventional resourcesworldwide (including large gasdeposits in Europe and Asia), theimplications for the recoverableglobal resource base would beenormous—a game-changer. Thisconcept got a big endorsement byExxonMobil when it purchasedXTO Energy Inc. in June 2010 toprovide a complementary platformto expand its unconventional oiland gas production technologiesworldwide. Likewise, Chevron Corp. merged Atlas Energy Inc. in February 2011 to acquire itsunconventional Marcellus Shale gas holdings in the Appalachian Basin of the US. In August 2011, BHPBilliton also jumped on the unconventional gas bandwagon by acquiring Petrohawk Energy, a majoroperator in the Eagle Ford Shale play. In another significant development, Kinder Morgan Inc. acquired ElPaso Corp. in May 2012. The combined entity owns the largest natural gas pipeline network in the US. InJune 2012, Malaysian oil company Petroliam Nasional Berhad (Petronas) reached an agreement to acquireCanadian natural gas exploration and production company Progress Energy Resources Corp. for C$5.5billion (which was increased in July to C$5.9 billion).Natural gas has favorable attributes as a clean burning, low-carbon fuel. Thus, the environmentalconsequences of its possible exploitation as a cheap and plentiful energy resource could have major globalimplications, as natural gas displaces significant quantities of dirty coal by as a fuel source.Major shale gas plays in the US include Barnett (Texas), Fayetteville (Arkansas), Haynesville (Louisiana,Texas, and Arkansas), Marcellus (Ohio, West Virginia, Pennsylvania, and New York), and Woodford(Oklahoma). The Barnett is the most established shale play in the US, while the Haynesville and Marcellusare large, but the least developed.Chart H05: PROJECTEDUS NATURAL GASPRODUCTIONPROJECTED US NATURAL GAS PRODUCTION(In trillions of cubic feet)0510152025302010 2011 E2015 E2020 E2025 E2030 E2035Onshoreunconventional -Coalbed methaneOnshoreunconventional -ShalegasAlaskaNon-associatedoffshoreAssociateddissolved*Tight gasOther onshore*Offshore and onshore.Source: US Energy Information Administrations December 2011 forecast.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 7Restrictions on hydraulic fracking under consideration in the USThe massive development of shale resources has vastly altered the domestic oil and gas industry. The US isnow the world’s top natural gas producing nation, with access to an abundance of undeveloped shale andtight gas reserves. We anticipate these structural changes will have a major impact on the future of USenergy policy as the industry exploits deeper, and harder to reach, resources. While tighter restrictions onthe use of fracking could potentially jeopardize some domestic production growth, the industry has begunto take steps to minimize the environmental impact of the technology, through disclosure andenvironmental management, in order to gain back some public trust. In June 2011, the governor of Texassigned into law a bill that will require companies to make public the chemicals they use on every hydraulicfracturing job in the state.In April 2012, the Obama Administration set the national standards to control air pollution from gas wellsthat are drilled using fracking. The standards require the capturing of gases released in the air earlier. InMay 2012, the US Department of the Interior released a new set of rules for fracking. The rules require thatcompanies report publicly what chemicals they use in fracking, although they may keep the identity of someof those chemicals private as trade secrets. The rules also set standards for building wells. In June 2012, theInterior Department announced a 60-day extension on the comment period pertaining to the rules.Many oil and gas formations have low permeability, particularly tight sands, shale, and coalbed methane.Fracking is a technique used to create fractures from the well bore into rock or coal formations, allowing oilor gas to move more freely to the well. In order to create fractures, a mixture of water, sand, and chemicalsis pumped into the formation. Some of the fracking fluid is pumped out of the well and into surface pits ortanks during the extraction process, but significant volumes of fluid may remain underground. When a wellhas an excess of fracking fluids, they are either disposed of or used at another job. In addition, fracking isused in many CBM production areas, which usually contain groundwater of high-enough quality to beconsidered underground sources of drinking water.Environmentalists generally have three major concerns with fracking: the lack of measurement ofgreenhouse gas (GHG) emissions in shale production, the lack of transparency in hydraulic fluid chemicaldisclosure, and well performance. GHG emissions in shale production. Natural gas flaring and venting, used to eliminate waste gas that isotherwise not usable or transportable, as well as any groundwater contamination, may be offsetting anyimpact of lower carbon content versus coal or petroleum. Currently, upstream companies are not trackinghow much methane is being vented or leaked, possibly offsetting some of the benefits versus coal production.One issue that has arisen with respect to natural gas and the greenhouse gas effect is the fact that methane,its principal component, is a major GHG. Lack of transparency. Historically, one of the main criticisms of the oil and gas industry has been a lackof transparency. The fracking issue has further damaged this reputation, causing the industry to lose its licenseto operate in many communities today (e.g., New York State). The public has begun demanding disclosure ofall chemicals used in fracking to better understand the impact on the environment and human health. Thenew bill in Texas to disclose fracking fluids is significant, given the state’s stature as a major oil and gasproducer. Well performance. A critical process to avoid groundwater contamination is a company’s wellconstruction, well completion, and water disposal methods. The majority of fracking activities take place atdepths far below existing groundwater sources, making deeper wells safer than shallow wells, which may beonly a few hundred feet below the water table. Well construction failures, such as faulty cementing andcasing, are not limited to offshore wells, and can cause excessive pressure issues. Insufficient cement orimproper casing may also fail to provide aquifers with protection from contamination. Another concern iswhat happens to the flow-back water, or produced water, that comes out of the well after drilling.Presently, companies are trucking water offsite to treatment facilities for disposal, or retreating and reusingflow-back water for new jobs. There is currently limited analysis available as to what is in the flow-backwater (which may change materially from its original state after being injected into the earth) and,
8 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSconsequently, what impact it has on the environment. Another concern is whether the flow-back water isbeing placed in lined pits or enclosed tanks when it is pumped out of the well.While environmental risks are inherent in fossil fuel drilling, we think the industry is likely to place a biggeremphasis on safety and quality control, improving disclosure practices, and implementing better and more-accountable environmental management systems.OPEC COMPLIANCE IN THE SPOTLIGHTOn December 14, 2011, the cartel agreed to increase OPEC’s output target to 30 million b/d, effectiveJanuary 1, 2012, though there were no details relating to individual country allocations. This was the firstnew target agreement in three years, and the first in more than two decades to include Iraq in the OPECtarget system. The increased target is more in line with current production output and accommodates theincreased production from Libya and Iraq. In June 2012, the cartel reaffirmed the target output of 30million b/d.Since 2009, the OPEC-11 (i.e., the OPEC countries, excluding Iraq) had maintained the output target at24.845 million b/d. While OPEC members, led by Saudi Arabia, the United Arab Emirates (UAE), andKuwait, had shown fairly good overall compliance with the output targets in early 2009, the subsequent risein oil prices made it more difficult for the cartel to maintain supply discipline. Compliance with allocatedoutput targets (as a percentage of the total) fell from 83% in March 2009 (when WTI oil prices averaged$48 per barrel) to 80% in December 2011. The group’s adherence to supply targets has slipped with the risein oil prices. The IEA estimates that OPEC crude production increased by 0.41 million b/d to 29.98 millionb/d in 2011, as the cartel sought to provide balance and stability to the global oil market in the face ofhigher global oil demand. According to the EIA, OPEC output was 31.19 million b/d as of July 2012, wellabove the target of 30 million b/d. As of August 2012, the EIA expected OPEC members to continue toproduce more than 30 million b/d of crude oil over the next two years to accommodate the increase inworld oil consumption and to balance supply disruptions.OPEC’s compliance to its output targets may become increasingly difficult as members raise crudeproduction capacity by a net 500,000 b/d over the 2011–13 timeframe, according to August 2012 estimatesby the EIA. However, increased output targets may help with compliance. With Iran under siege from theEuropean Union’s oil embargo and the freeze of its central bank’s assets, other OPEC members, especiallySaudi Arabia, have experienced increased demand in 2012. War-torn Libya rebounded sharply in the latterpart of 2011, posting its largest monthly increase in oil production in December. Production in Libya isexpected to reach the pre-war level of around 1.6 million b/d by October 2012. Iraq, too, reported a higheraverage supply for 2011. As of June 2012, Iraq’s exports had increased by 20% to 2.5 million b/d. Further,Iraq is expected to increase its supply by 400,000 barrels per day in 2013.Chart H10: OPEC SPARECAPACITY VERSUSCRUDE OIL PRICES0.000.751.502.253.003.754.505.252004 2005 2006 2007 2008 2009 2010 2011 2012020406080100120140OPECsparecapacity (million b/d, left scale) Oil price(West Texas Intermediate, $per barrel, right scale)OPEC SPARE CAPACITY VERSUS CRUDE OIL PRICESSources: US Energy Information Administration.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 9With OPEC spare capacity at 3.13 million b/d as of July 2012, and given the uncertainty in Middle Eastpolitics, we see OPEC discipline as one of the primary factors determining crude oil prices in the short term.Non-OPEC production ramping upAs of August 2012, the EIA projected that non-OPEC crude oil and liquid fuels production will increase byan average of 600,000 b/d in 2012 and by a further 1.3 million b/d in 2013. Increases in non-OPEC oilproduction will be concentrated in a few countries, particularly in the US, Canada, China, Russia, Columbia,Kazakhstan, and Brazil. Non-OPEC liquids supply fell by only 0.02 million b/d to 51.77 million b/d in2011, according to the EIA.CRUDE REALITY: THE DEEPWATER HORIZON EXPLOSIONOn April 20, 2010, an explosion occurred in the Gulf of Mexico on the Transocean Inc.–owned DeepwaterHorizon drilling rig, which had just completed drilling BP plc’s Macondo prospect on Mississippi CanyonBlock 252 (MC252); 11 of the 126-person crew on the rig were killed. BP served as the operator of theMacondo well and held a 65% interest in the prospect. Anadarko Petroleum Corp. had a 25% stake, andMitsui E&P USA LLC (an affiliate of Mitsui & Co., Ltd.) had 10%. The Deepwater Horizon crew consistedmainly of personnel from Transocean, but also had some people from BP, Halliburton Co., and MI Swaco(a joint venture between Schlumberger Ltd. and Smith International Inc.). The explosion set off the largestoil spill in US history and caused an environmental disaster.Critics targeted BP, the US government, and the broader oil industry. As a result, on May 11, 2010, USSecretary of Interior Ken Salazar began a restructuring of the Minerals Management Service (MMS), which wasresponsible for collecting energy revenues on behalf of US taxpayers, and for enforcing the regulations andlaws that apply to offshore energy operators. Salazar said the MMS’s inspection, investigation, and enforcementoperations would operate separately and independently from the agency’s leasing, revenue collection, andpermitting functions. On May 27, MMS director Elizabeth Birnbaum resigned after her agency came underintense criticism from the US Congress for being too “cozy” with the energy industry that it was supposedto regulate. The MMS was subsequently renamed the Bureau of Ocean Energy Management, Regulation,and Enforcement (BOEMRE). On October 1, 2011, the BOEMRE itself was reorganized and replaced bytwo independent entities—the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety andEnvironmental Enforcement (BSEE)—as part of a major reorganization.Spill highlights disparity between investment to increase oil supplies and safety/environmental practicesThe Gulf oil spill appears to have been an accident waiting to happen, reflecting a strategic mismatch datingback decades between increased investment for the exploration and production of oil and gas, versus little,if any, investment to mitigate the risks of this new supply. Operational risks grew as producers exploitedfrontier regions in the deepwater in search of new oil supplies to feed growing global demand. The Gulf oilspill made it clear that oil and gas producers did not have the necessary technology or equipment to respondto a major accident. Furthermore, there are significant differences in engineering design, safety, andenvironmental practices between companies and countries—and that various oil spills over the past decadeshighlight the need for high quality, unified engineering standards on a global basis.In the aftermath of the Gulf oil spill, the safety and environmental practices of drilling operations have comeunder heightened scrutiny. S&P Capital IQ believes that going forward, there will be increased investmentin development of safety, environmental control, and cleanup practices for US drilling operations, as well asfor alternative and renewable energy.Intense US government and public criticism spurred the oil industry into action. On July 21, 2010,ExxonMobil, Chevron, ConocoPhillips, and Royal Dutch Shell PLC said they would contribute $250million each toward the design and development of a modular, rapid-response system that would captureand contain oil in the event of a future undersea well blowout in the Gulf of Mexico. The new system couldbe mobilized within 24 hours and adaptable to a wide range of well designs and equipment, oil and gas flowrates, and weather conditions. The four companies formed a nonprofit organization—the Marine WellContainment Co. (MWCC)—to operate and maintain the system, with ExxonMobil leading the initialengineering effort. Other companies were invited to participate in the organization and the MWCC now has
10 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYS10 member companies (Apache Corp., Anadarko Petroleum, BHP Billiton, BP, Statoil, and Hess, in additionto the four founding members).Prospects for new US energy legislationThere had been significant public pressure on both the US Congress and the Obama Administration, in theaftermath of the Gulf oil spill, to secure increased oversight of US drilling (onshore and offshore, and forboth oil and natural gas). Such provisions are likely to affect how US oil and gas business will be done, andincrease the cost of drilling exploratory wells in the Gulf of Mexico (and perhaps in the US).On July 30, 2010, the US House of Representatives passed a sweeping energy bill that would have lifted the$75 million cap on the economic liability from an oil spill, prevented companies with poor safety recordsfrom bidding on oil and gas leases, and created three new agencies to oversee energy exploration andproduction on federal lands. The bill would have enacted tougher safety regulations for BOPs, alloweddeepwater drillers that meet higher safety standards to seek relief from future deepwater moratoriums, andrequired drilling rigs and other vessels operating in the Outer Continental Shelf (OCS) to be owned by UScompanies. The US Senate rejected the bill in September 2010. With a Republican-controlled House ofRepresentatives and a Democrat-controlled Senate, we are growing increasingly skeptical of seeing anymajor bills pass on drilling reform.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 11INDUSTRY PROFILEGlobal landscape continues to evolveIn the worldwide oil and gas industry, state-owned firms dominate exploration and production (known asthe upstream), while publicly owned companies dominate the refining and marketing end of the industry(the downstream). The publicly owned companies are the focus of this Industry Survey.Estimating the size of the global oil industry is difficult. The state-owned companies do not issue stock andthus cannot be valued based on market capitalization. In addition, due to variations in accounting standardsand other measures, it is difficult to estimate the industry’s revenues and earnings. Therefore, S&P CapitalIQ ranks the world’s top oil companies based on their oil and gas assets, and according to financial andother measures.Worldwide proved reserves rose in 2011According to Oil & Gas Journal (OGJ), a weekly industry trade publication, worldwide proved reserves of oilrose by 3.4% to 1.52 trillion barrels in 2011, and worldwide proved natural gas reserves increased 1.5% to6.7 quadrillion cubic feet. The rise in reserves reflects additions in the Middle East. Results by region follow. Asia-Pacific. After limited reserve growth in 2010, the Asia Pacific region saw reserve growth of 13% foroil, but a 6% decline for gas in 2011. It is estimated the region holds 45.36 billion barrels of oil (45% ofwhich is in China), or 3% of worldwide reserves, and 504.5 trillion cubic feet (Tcf) of natural gas, or 7% ofglobal gas reserves. Europe. In Europe, estimated to hold 35% of worldwide natural gas reserves, total oil and gas reserveswere relatively flat in 2011 from a year earlier. Declines occurred mainly in Western Europe (Denmark,France, Norway, and the UK). Europe is estimated to hold 111 billion barrels of oil (90% of which is inEastern Europe) and 2,177 Tcf (94% in Eastern Europe). Western Hemisphere. The region saw modest oil reserve growth in 2011, with reserves of about 443billion barrels. This compares to a 34% rise in 2010, which reflected a 213% rise in Venezuela. TheWestern Hemisphere has a 29% share of the world’s oil and 9% of its gas reserves. It is estimated that theregion holds 621 Tcf of natural gas. Africa. Growth in Africa slowed in 2011, but has grown over the last several years as huge offshoreprojects were developed. Africa now represents 8% of the world’s oil and gas reserves. Middle East. Home to 52% of the world’s oil reserves, the Middle East saw a slight boost in 2011 oilreserves. New gas projects throughout the region boosted gas reserves. OPEC. Among the members of the Organization of Petroleum Exporting Countries (OPEC), total oilreserves increased by almost 5% to 1.11 trillion barrels in 2011, and their share of the world’s oil reservessteadied at 73%.From a production standpoint, worldwide oil volume declined slightly to about 72.56 million barrels perday (b/d), compared to 72.618 million b/d in 2010. Oil production from OPEC was estimated at 35.66million b/d in 2011, up 1% from 2010.MAJOR GLOBAL PLAYERSAccording to Petroleum Intelligence Weekly (PIW), an industry publication, political and financial factorscontinued to mold the hierarchy of the world’s top oil companies. Energy Intelligence Group, an energypublishing firm, rates oil and gas companies using the PIW rankings, a composite index based on reserves,oil and gas production, refinery capacity, and product sales.
12 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSBased on a combination of 2010 data—such as oil and gas reserves, production, refining capacity, and productsales volumes—Saudi Arabia’s Saudi Arabian Oil Co. (Saudi Aramco) continued to be No. 1, and Iran’sNational Iranian Oil Co. (NIOC) held the No. 2 spot. Venezuela’s Petróleos de Venezuela SA (PDV) stayed infourth place, China’s China National Petroleum Corp. (CNPC, the parent of PetroChina Co. Ltd.) remainedat No. 5, and Mexico’s Petróleos Mexicanos (Pemex) kept its spot at No. 11.All but one of the six supermajor oil companies were included in PIW’s top 10 for 2011 (using data from2010): ExxonMobil Corp. at No. 3, BP at No. 6, Royal Dutch Shell at No. 7, Chevron at No. 8, and TotalSA at No. 9; ConocoPhillips slipped to the No. 12 spot. These supermajors are also among the industryleaders based on refinery distillation capacity.We believe that further consolidation is inevitable. Over the past 10 years, mergers and privatizationsenhanced the positions of the major oil companies. Higher oil prices have provided an engine for M&Aactivity, and resource nationalism in some countries. While the supermajor oils and other international oilcompanies (IOCs) built up considerable cash, opportunities for upstream investment appeared to decline, asthese Western oil companies lacked access to large oil and gas reserves, and faced increased competitionfrom the NOCs. As a result, “emerging majors,” which have some state ownership and are willing to takegreater risks for smaller rewards, are overshadowing the long-term upstream growth options of the IOCs.Rising resource nationalism in Russia and Venezuela, and expansion by firms in China have led to aresurgence of the NOCs over the past few years.As of August 31, 2012, companies within the S&P Global Industry Classification Standard (GICS) for theEnergy Sector represented 10.53% of the market value within the S&P Composite 1500 Index, andcompanies within the Integrated Oil & Gas subindustry represented 5.10%.Table B02:World’s top 20oil companiesWORLDS TOP 20 OIL COMPANIES—2011*------- OUTPUT ------- REFINERY PRODUCTSTATE ------ RESERVES ------ LIQUIDS CAPACITY SALESPIW* OWNERSHIP LIQUIDS GAS (THOUS. GAS (THOUS. (THOUS.RANK COMPANY COUNTRY (%) (MIL. BBL) (BCF) B/D) (MMcf/D) B/D) B/D)1. Saudi Aramco Saudi Arabia 100 264,500 283,100 10,007 8,121 2,423 2,9622. NIOC Iran 100 151,821 1,168,599 4,292 13,292 1,741 2,1173. ExxonMobil US (public) 11,673 78,815 2,422 12,148 6,260 6,4144. PDV Venezuela 100 296,501 195,095 2,970 4,003 3,035 2,5345. CNPC China 100 25,682 116,814 2,840 8,018 3,142 2,1066. BP UK (public) 10,709 42,700 2,374 8,401 2,667 5,9277. Royal Dutch Shell UK/Netherlands (public) 6,146 47,135 1,709 9,305 3,594 6,4608. Chevron US (public) 6,503 24,251 1,923 5,040 2,160 3,1139. Total France (public) 5,987 25,788 1,340 5,648 2,363 3,77610. Gazprom Russia 50 9,452 670,700 870 49,188 1,091 81611. Pemex Mexico 100 11,394 12,494 2,901 4,633 1,710 1,66812. ConocoPhillips US (public) 4,691 21,716 1,268 4,860 2,657 3,04013. KPC Kuwait 100 101,548 64,007 2,556 1,464 1,136 1,03914. Lukoil Russia (public) 13,319 23,615 1,942 2,063 1,436 2,16515. Petrobras Brazil 32.2 10,766 11,953 2,150 2,570 2,107 2,75316. Sonatrach Algeria 100 11,300 159,100 1,538 7,547 456 65217. Adnoc UAE 100 52,812 115,002 1,538 2,665 500 37118. Petronas Malaysia 100 8,568 117,180 577 5,178 448 83719. Rosneft Russia 75.2 18,110 27,922 2,322 1,193 1,019 98920. Qatar Petroleum Qatar 100 10,363 643,846 1,285 7,014 216 438*Petroleum Intelligence Weekly s ranking as of December 2011, based on 2010 fiscal year-end operating results. BBL-barrels.BCF-billion cubic feet. B/D-Barrels per day. MMcf/D-Million cubic feet per day.Source: Petroleum Intelligence Weekly.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 13INDUSTRY TRENDSThe return to global economic growth drove oil prices upward from mid-2009 to mid-2011. In the secondhalf of 2011, amid the fear of tightening credit markets and a double-dip recession, West Texas Intermediate(WTI) crude oil prices reached a low point in October at close to $75/bbl before recovering to $109 byFebruary 2012. However, oil prices have been volatile because of uncertainty over demand growth andpotential supply disruptions due to geopolitics. We expect the volatility to continue in the near term.International oil companies (IOCs) have seen considerable profit and cash flow growth since early in thedecade. Nevertheless, we believe the landscape has become increasingly difficult for IOCs to generategrowth as government control over the majority of the world’s oil reserves have made it increasinglydifficult to access new upstream resources.Available upstream assets require large investments to extend their lives, and the industry’s costs are risingamid a global squeeze on labor and equipment, as well as increased tax and royalty rates. Upstream growthoptions for IOCs are becoming limited, compared with those available to emerging majors with some stateownership, which are willing to take greater risks for smaller rewards.With global consumption of crude oil and natural gas liquids (NGL) on the rise, production must rise tomeet demand needs. Most of the world’s liquids production is conventional (crude oil and NGL). However,we expect an increasing percentage of global production to come from unconventional resources (oil sands,oil shale, heavy oil, biofuels, coal-to-liquids, and gas-to-liquids) in the future. Rising oil prices over the lastdecade and technological advancement have allowed unconventional liquids resources to becomeeconomically competitive.Global and domestic natural gas consumption showed modest growth in 2011 on increased powergeneration and higher demand from the industrial sectors. According to the EIA, natural gas consumptionin the US in 2011 increased 2.7%, year on year, to 66.91 billion cubic feet per day. The EIA estimates 2012natural gas demand of 69.82 Bcf (up 4.7% from 66.65 Bcf in 2011), and 2013 demand of 70.91 Bcf (up1.6% from 2012).Long-term global natural gas demand appears poised for growth as supplies become globally accessiblethrough huge liquefaction projects adding LNG supply (mainly in the Middle East and Australia) andincreased pipeline capacity from emerging markets. In the US, rising natural gas prices from 2000–08 andthe widespread use of horizontal techniques and hydraulic fracturing drove a massive drilling campaign,which has led to a significant boost in domestic supplies.Domestic upstream participants have been under a rapidly developing consolidation market. As IOCs lookinto avenues for growth, one region catching attention is US onshore unconventional properties. Domesticexploration and production companies have historically maintained natural gas–heavy portfolios and ledthe emergence of US shale natural gas. Realizing the long-term growth potential for natural gas and themassive recoverable reserve estimates, IOCs’ main method of entry into US shale plays has been viaacquisition, as they were left with little choice since exploration and production companies have amassedmost “sweet-spot” acreage at these plays.Notably, ExxonMobil’s acquisition of XTO Energy in June 2010 added a major acreage footprint in the USat several of the largest onshore unconventional natural gas plays, significantly expanding the company’sexposure to natural gas. Similarly, Chevron Corp.’s acquisition of Atlas Energy will provide an industry-leading position in the Marcellus Shale, a largely undeveloped play that is currently exhibiting the highestactivity rate and rate of return of all shale gas plays.As oil and gas prices have disconnected, producers have shifted focus toward onshore crude oil and NGLunconventional resources. We have seen many IOCs and national oil companies (NOCs) enter domesticplays like the Eagle Ford Shale in south Texas, the DJ Basin Niobrara Shale, the Bakken Oil Shale inMontana and North Dakota, and the Permian Basin. We expect further consolidation in the oil patch in
14 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYS2012, reflecting tight market conditions, limited organic growth opportunities, and growing competitionfrom NOCs.GLOBAL UPSTREAM SPENDING REBOUNDED IN 2011Based on 2010 company data, we believe the rebound in global upstream spending that began in 2010 willcontinue through 2012, reflecting improving economies, and oil and gas fundamentals. According to IHSHerold’s 2011 Global Upstream Performance Review, worldwide finding and development spending rose16% to $369 billion (excluding acquisitions) in 2010, rebounding from a 18% decline, to $318 billion(excluding acquisitions), in 2009 amid the global recession and tight credit markets. For 2011, IHS Heroldestimated that organic capital spending increased by 11% for both exploration and production (E&P)companies, and integrated oil companies.Relatively higher upstream spending in 2010 translated into increased demand for oilfield serviceequipment, especially in the Africa and Middle East region. This is pushing oilfield service costs higher,particularly in light of resumed activity in the Gulf of Mexico, according to data from IHS Herold. Withcrude oil prices trending above $100 per barrel, IHS Herold believes that there is enough room to increaseservice costs, without affecting the profit margins of oil and gas producers. Reserve replacement, as well asfinding and development replacement rates, softened in 2010, but at 160% and 128% of production,respectively, they remained well above full-replacement levels. We believe domestic upstream spendingincreased by about 10% in 2011, reflecting strong activity at onshore liquids resources. We are seeing asimilar rise in 2012, with most incremental spending directed toward conventional oil, liquids-rich basins,and oil shales. Dry gas drilling is expected to see a major slowdown as domestic gas markets remaindepressed.Integrated oilsS&P Capital IQ estimates that the supermajor oil companies, which represent about 30% of total upstreamspending, saw a 20% rise in 2011 upstream spending. ExxonMobil, which shelled out nearly $36.7 billionin 2011, was the largest capital spender globally.Exploration & production companiesCapital spending by exploration and production (E&P) companies rebounded sharply in 2011, after a fallof nearly 40% in the previous year, according to IHS Herold data. Higher oil prices and an improved creditmarket were among the major factors that boosted E&P companies’ capital spending.Most economical gas shale plays and emerging onshore liquids resources continue to be hot attractions,driving much of 2012 upstream spending for the E&P group. In 2010, much of the focus in the US E&Psector shifted from natural gas shale plays (i.e., Haynesville Shale, Marcellus Shale, Fayetteville Shale, andWoodford Shale) to liquids-rich plays (i.e., the Eagle Ford Shale in south Texas; the Bakken Shale inMontana and North Dakota; the Permian Basin in Texas). In 2011, a significant percentage of capitalspending was focused on higher-margin liquids-rich assets.On our forecasts for production growth, rising oil prices, and growth in earnings and cash flow, we believethat US E&P capital spending increased about 25% in 2011, and we expect spending to increase about12%–15% in 2012, with natural gas–focused E&Ps down 3%–7% and oil-focused E&Ps up 20%–23%.COMPETITIVE DYNAMIC REDEFINES ENERGY MARKETS&P Capital IQ believes the competitive dynamics between the national oil companies (NOCs) and theIOCs—one of the most important trends in energy today—have permanently changed, driven by high oilprices and limited access to upstream resources. While it does not appear that the world is running out ofoil, the easy access to supplies seems to be gone, and what’s left is harder to recover. There have been oilcrises before, but the Western nations were previously the main consumers of oil exports; now, we seeincreased demand from Asia-Pacific and the Middle East.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 15Furthermore, in the past, both North America and Europe had solid oil production on which to rely, fromAlaska and the North Sea. This has changed, however, and now oil production within the Organisation forEconomic Co-operation and Development (OECD) nations is declining. Outside of Russia and the MiddleEast, the largest opportunities for oil may lie in deepwaters (water depths of more than 1,000 feet) in the Gulfof Mexico, Brazil, and offshore Africa (which is politically volatile).Major exporting nations have found they have more leverage with consuming countries than they didpreviously, and they are tightening their grip on upstream production. As the major importing nationsscramble to adapt, energy security has emerged as a global foreign policy concern. Energy security is no longerjust about the availability of supplies at affordable prices, but now includes other issues such as the disruptionof supplies, security of demand, supply diversification, buffers against supply shocks, globalization of theentire energy chain, and increased interdependence in the world.IOCs need to adapt to this new competitive NOC dynamic, as the limited resource environment will workagainst them—drilling acreage available for purchase today may be much harder to obtain in 20 years. Oneway the IOCs may adapt to this new model is to exploit their core competencies in size and technology.As a result, we have seen increased movement by the IOCs into frontier regions (such as deepwaters and theArctic) and unconventional oil and gas plays (such as heavy oil, tar sands and shale oil, and tight gas, shalegas, and coalbed methane, or CBM). They are also exploring new markets in liquefied natural gas (LNG),gas-to-liquids (GTL), and alternative technologies (such as biofuels and renewable energy), as well asinnovative deal-making with host governments and the financial markets.NOCs are driving acquisition marketWe are expecting a strong global merger and acquisition (M&A) environment in over the balance of 2012and into 2013, driven by aggressive spending by NOCs (especially Asian NOCs), and significant portfoliorestructuring expected among IOCs. Oil and gas M&A has rebounded from the depths of late 2008 to mid-2009, propelled by a rapid rise in crude oil prices and the continued emergence of unconventional resources.In 2010, we saw a flurry of activity from NOCs investing overseas, while the IOCs maintained noticeablyless acquisitive strategies. The momentum continued in 2011, with NOCs sealing several important deals.Unconventional shale plays in both gas and tight oil continue to be the driving force behind M&A activity,given the transformative nature of these assets, especially in North America. Notably, the Chinese NOCshave been accelerating their acquisitions in the US and Canada, targeting liquids-rich onshore plays withjoint venture partners in need of capital to develop acreage. We expect sustained strength in oil prices,growing confidence in economies, limited growth avenues, and a global drive for energy independence to beprimary drivers in M&A activity in 2012 and 2013, with the focus expected to remain on North America.A quick review of recent upstream dealsM&A activity picked up in the second half of 2010, with the NOCs continuing to be the driving force.According to IHS Herold, total global M&A transaction value rose 40% to a record $206 billion in 2010,driven by massive asset divestiture programs. Momentum continued in 2011, though the total wassomewhat lower: $156 billion, down 24% from 2010. IHS Herold expected the volatile environment toaccelerate global upstream M&A in 2012.Among the major deals so far in 2012, China National Offshore Oil Corp. (CNOOC), which is China’slargest producer of offshore crude oil and natural gas, made an offer in July 2012 to acquire Calgary-basedoil and gas producer Nexen Inc. for US$15.1 billion. The deal would make CNOOC an operator of a majoroil sands project, thereby giving it the expertise to tap massive unconventional oil reserves at home. InFebruary 2012, El Paso Corp. agreed to sell its exploration and production business, EP Energy Corp., for$8.2 billion to a consortium led by private-equity firms Apollo Global Management LLC and RiverstoneHoldings LLC. In June 2012, Malaysian oil company Petroliam Nasional Berhad (Petronas) reached anagreement to acquire Canadian natural gas exploration and production company Progress Energy ResourcesCorp. for C$5.5 billion (which was increased in July to C$5.9 billion).
16 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSSo far, in 2012, 60% of total global deal count came from North America, with the focus on more liquids-rich opportunities. Higher oil prices and lower gas prices are leading to a shift toward liquids. China madethe largest acquisition in the Canadian oil sands, while the US shale market continued to attract hugeinvestments by international investors, including the supermajors and new entrants.Several supermajors have entered the Marcellus Shale since 2009, which is largely believed to be the mosteconomic of US natural gas shale plays under current market fundamentals, with Royal Dutch Shell’s $4.7billion acquisition of 650,000 net acres and Chevron’s acquisition of Atlas Energy Inc., a premier MarcellusShale player. Mitsui E&P USA LLC, an affiliate of Mitsui & Co., Ltd., acquired a 32.5% stake inAnadarko’s Marcellus Shale assets for $1.4 billion, while coal producer CONSOL Energy Inc. bolstered itsupstream gas portfolio in Marcellus with two acquisitions totaling over $4.5 billion. In August 2011,CONSOL entered into a$3.2 billion joint venture with Noble Energy to develop 663,000 acres atMarcellus. We believe the huge resource base and recoverable reserve potential of the play have attractedlarger international players seeking growth.Chinese state-owned entities continue to aggressively pursue global upstream expansion. In 2011, dealactivity included China Petrochemical’s $3.75 billion offer to buy deepwater assets offshore Brazil fromGalp Energia SGPS SA; Sinopec Corp.’s offer to buy gas-weighted assets of Daylight Energy Ltd. for $3.03billion, and the 15% stake in Australia Pacific LNG of ConocoPhillips for $1.75 billion; and ChinaNational Offshore Oil Corp.’s (CNOOC) $2.07 billion deal to acquire a 35% stake in Long Lake oil sandsSAGD project of OPTI Canada Inc.WORLDWIDE REFINING CAPACITY CONTINUES TO EXPANDBased on refining capacity and using data from OGJ’s 2011 Worldwide Refining Survey, the five largestglobal refiners in 2010 were ExxonMobil (5.79 million barrels per calendar day, or b/cd, of crude capacity),TABLE B09:Worldwideenergy M&ALARGEST WORLDWIDE ENERGY MERGERS & ACQUISITIONS—2012(Ranked by estimated transaction value)ANNOUNCED CLOSED ANNOUNCEDACQUIRER SELLER DATE DATE VALUE (MIL$)CNOOC Canada Nexen Inc. 7/23/12 Pending 19,413Energy Transfer Partners Sunoco 4/30/12 Pending 8,712Access Industries, Inc.; Apollo GlobalManagement; Korea National OilCorporation; Riverstone HoldingEP Energy Corporation 2/24/12 5/24/12 8,187PETRONAS Carigali Canada Ltd Progress Energy Resources Corp. 6/28/12 Pending 5,138Cassa depositi e Prestiti Snam S.p.A. 5/30/12 Pending 4,361TonenGeneral Sekiyu EMG Marketing G.K. 1/29/12 6/1/12 3,936Alimentation Couche-Tard Statoil Fuel & Retail ASA 4/18/12 6/20/12 3,594Icahn Enterprises Holdings CVR Energy 2/16/12 5/18/12 3,231Cosan S. A. Indústria e Comércio Companhia de Gas de Sao Paulo 5/3/12 Pending 2,900Williams Partners Caiman Eastern Midstream 3/19/12 4/27/12 2,493Tinkler Group Pty Ltd Whitehaven Coal Limited 6/13/12 Pending 2,264Global Infrastructure Partners Access Midstream Partners 6/8/12 6/29/12 2,000Japan Australia LNG Browse LNG Development Project 5/1/12 Pending 2,000Corporacion Financiera Colombiana Promigas SAESP 6/7/12 Pending 1,968PTT Exploration and Production PublicCompany LimitedCove Energy PLC 5/23/12 Pending 1,851Pengrowth Energy NAL Energy Corporation 3/23/12 5/31/12 1,829Suburban Propane Partners Inergy L.P.s retail propaneoperations4/26/12 Pending 1,800SandRidge Energy Dynamic Offshore Resources 2/1/12 4/17/12 1,642Sinopec International PetroleumExploration & Production CorporationTalisman Energy 7/23/12 Pending 1,500Source: S&P Capital IQ.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 17Royal Dutch Shell PLC (4.12 million b/cd), China Petroleum & Chemical Corp. (Sinopec Corp., 3.97million b/cd), BP PLC (3.32 million b/cd), and Valero Energy Corp. (2.78 million b/cd).According to the OGJ, the world’s largest refineries in 2011 were Reliance Industries Ltd.’s JamnagarRefinery (1,240,000 b/cd) in India, Paraguana Refining Center (940,000 b/cd) in Venezuela, SK Corp.’sUlsan Refinery (850,000 b/cd) in South Korea, GS-Caltex Oil Corp.’s Yeosu Refinery (730,000 b/cd) inSouth Korea, and ExxonMobil’s Jurong Island Refinery (605,000 b/cd) in Singapore.After growing slowly in 2010, global refining capacity contracted slightly in 2011 for first time in nearly 10years, according to the OGJ. Worldwide refining capacity fell by 175,000 b/cd, to 88.05 million b/cd. Thetotal number of refineries fell by seven to 655.Western Europe lost a net of two refineries in 2011, while total capacity for its plants fell by more than225,000 b/cd. In North America, four refineries were closed, with a loss of 55,000 b/cd in capacity.Although no new refineries started in Asia in 2011, several new ones were in various stages of planning andconstruction. In terms of capacity addition, Asian refineries added 44,000 b/cd, while Middle Easternrefineries added more than 32,000 b/cd, according to the OGJ.Refineries slow, idle, and close in OECD countriesAs the global refining market restructures amid sharply reduced demand and new and evolving productrequirements, less efficient and flexible facilities worldwide are being permanently shut-in, while newer plantsare being brought on-stream in emerging markets in India, China,Brazil, Russia, and the Middle East. In 2011, capacity growthoccurred almost entirely in Asia and the Middle East, where newcapacity was added and existing refineries expanded to meetanticipated market growth in these regions. In contrast, NorthAmerica (mainly the US) and Western Europe saw the closing ofseveral refineries.Much of the decline in capacity in 2011 was in OECD countries,where the global recession hit the hardest. The US and Europeandebt crises, in particular, rattled Western European and NorthAmerican financial markets, impacting the oil industry. Refineryutilization rates were particularly hard hit in the US, Japan, andEurope, where refineries were operated by commercially sensitiveoperators, such as the IOCs. There was apparently no place tohide, and even the supermajor oils felt the downstream losses. BP. In early 2011, BP announced that it intends to reposition itsdownstream business in the US and divest two of its US refineriesto better align with changing trends in global demand. It intends toseek buyers for two refineries (Texas City, Texas, and the Carsonrefinery near Los Angeles), and its associated integrated marketingbusiness in southern California, Arizona, and Nevada. In itssecond-quarter 2012 report, the company said that it was on targetto sell both refineries by the end of 2012. Shortly after, in August,it completed the sale of the Carson refinery and related logisticsand marketing assets to Tesoro Corp. for $2.5 billion. Royal Dutch Shell. Since 2009, Royal Dutch Shell has beenrestructuring its downstream operations to focus on fewer andmore profitable markets with growth potential (Asia-Pacific) through disposal of $8 billion in non-coreassets and selective growth investments. Total. In early 2010, Total SA said that there was not much hope for refinery margins in the WesternHemisphere to recover without further capacity closures in the region. As a result, Total plans a reductionTable 02:LARGESTWORLDWIDEREFINERSLARGEST WORLDWIDE REFINERS(As of December 31, 2011)CAPACITYREFINER THOUS. B/D)1. ExxonMobil 5,7882. Royal Dutch Petroleum 4,1943. Sinopec 3,9714. BP PLC 3,3225. Valero Energy 2,7776. Petroleos de Venezuela SA 2,6787. China National Petroleum 2,6758. ConocoPhillips 2,5689. ChevronPhillips 2,56010. Saudi Aramco 2,45211. Total SA 2,31412. Petroleo Brasileiro SA 1,99713. Petroleos Mexicanos 1,70314. National Iranian Oil 1,45015. JX Nippon Oil & Energy 1,42316. Rosneft 1,29317. OAO Lukoil 1,21718. Marathon Oil 1,19319. SK Innovation 1,11520. Repsol YPF SA 1,10521. Kuwait National Petroleum 1,08522. Pertamina 99323. Agip Petroli SPA 90424. Flint Hills Resources 81725. Sunoco 375Source: Oil & Gas Journal.
18 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSof its global refining capacity. It plans to lower its gasoline output by 60% and has put up its UK Lindsayrefinery for sale, which will cut its refining capacity by 20%. Total agreed not to sell or close any of itsFrench refineries over the next five years. ConocoPhillips. In July 2011, the company’s board of directors approved a plan to separate the Refining& Marketing and Exploration & Production businesses into two stand-alone, publicly traded corporationsvia a tax-free spin-off of the refining and marketing business to ConocoPhillips shareholders. The companycompleted the spin-off of Phillips 66 in April 2012, thus becoming the largest independent exploration andproduction (E&P) company, based on proved reserves and production of liquids and natural gas. Chevron. In 2010, Chevron implemented a plan to restructure its global downstream business to make itsmaller and less complex. In August 2011, Chevron closed on a deal for Valero Energy Corp. to buyChevron Ltd., the entitythat holds the 220,000barrel–per-dayPembroke refinery andother downstream assetsin the UK and Ireland.The sale price was $730million, plus anadditional paymentestimated to be $1billion for ChevronLtd.’s inventory andother items. Marathon Oil. In2011, Marathon OilCorp. spun off itsdownstream operationsinto a stand-aloneindependent refiner,Marathon PetroleumCorp. The company hasa goal of divestingbetween $1.5 and $3.0billion of non-core assetsbetween 2011 and 2013and expected investmentin exploration anddevelopment activities. Motiva. In March2009, MotivaEnterprises LLCannounced it wasdelaying for more thantwo years the 2011completion date for aplanned addition to itsrefinery in Port Arthur,Texas. In May 2011, thecompany announcedthat it had completedthe placement of theTable B04:ESTIMATEDWORLDWIDEREFININGCAPACITY,BY REGIONESTIMATED WORLDWIDE REFINING CAPACITY, BY REGION(In thousands of barrels per day, as of December 31, 2011)CATALYTIC CATALYTICNO. OF CRUDE HYDRO- CATALYTIC HYDRO- CONVERSIONREGION REFINERIES FEED TREATING* COKING† CRACKING† CRACKING† CAPACITY§ASIA-PACIFIC 164 24,918 10,223 581 3,208 1,242 5,031% of world 25.0 28.3 22.4 12.4 21.8 22.6 20.2China 54 6,866 541 156 588 185 929Japan 30 4,730 5,016 123 987 182 1,292India 21 4,043 251 170 531 166 867South Korea 6 2,760 1,450 19 314 327 660Singapore 3 1,357 707 0 80 129 209China, Taiwan 4 1,310 673 51 218 25 294Indonesia 8 1,012 23 33 101 100 234Australia 7 760 544 0 235 18 253Others 31 2,081 1,018 29 154 110 293WESTERN EUROPE 99 14,432 10,077 343 2,216 1,189 3,748% of world 15.1 16.4 22.0 7.3 15.1 21.7 15.1Germany 15 2,417 2,012 106 349 203 658Italy 17 2,337 1,251 45 322 303 670United Kingdom 10 1,767 1,272 65 445 36 545France 12 1,719 1,233 0 347 72 419Spain 9 1,272 825 61 191 132 384Netherlands 6 1,197 1,016 42 102 198 342Belgium 4 740 688 0 134 0 134Turkey 6 714 265 0 29 54 83Others 20 2,270 1,516 25 298 192 515EASTERN EUROPE 89 10,369 4,274 319 877 330 1,527% of world 13.6 11.8 9.3 6.8 6.0 6.0 6.1Russia 40 5,431 2,171 85 331 57 473Ukraine 6 880 315 22 70 7 99Others 43 4,058 1,788 212 476 266 954MIDDLE EAST 44 7,277 2,047 90 358 597 1,045% of world 6.7 8.3 4.5 1.9 2.4 10.9 4.2Saudi Arabia 7 2,112 493 0 104 134 237Iran 9 1,451 183 0 35 137 172Kuwait 3 936 589 72 36 116 224United Arab Emirates 5 773 159 0 34 31 65Others 20 2,005 623 18 149 180 347AFRICA 45 3,218 834 66 210 62 338% of world 6.9 3.7 1.8 1.4 1.4 1.1 1.4Egypt 9 726 208 39 0 34 73Others 36 2,491 626 27 210 28 265WEST. HEMISPHERE 214 27,841 18,275 3,282 7,824 2,069 13,175% of world 32.7 31.6 40.0 70.1 53.2 37.7 53.0Canada 17 1,918 1,384 59 482 210 752Brazil 13 1,917 284 115 505 0 621Mexico 6 1,540 926 191 381 0 572Venezuela 5 1,282 390 145 232 0 377United States 125 17,788 14,062 2,543 5,650 1,726 9,919Others 48 3,396 1,230 228 574 132 935TOTAL WORLD 655 88,056 45,730 4,681 14,693 5,489 24,863*Removes sulfur and other impurities from crude feedstock. †Process that converts heavy crude oil into light refined oiproducts. §S&P defines conversion capacity as the sum of coking, hydrocracking, and catalytic cracking capacity.Sources: Oil & Gas Journal; S&P Capital IQ.
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 19expansion project’s 375-foot tall delayed-coker, which has a capacity of 95,000 b/d. The end result will be arefinery complex that can process 600,000 barrels of crude oil per day, making it the largest in the nation. Itis expected to be completed in 2012. Valero. In 2010, Valero sold its terminal operations; discontinued operations at its refinery in DelawareCity, Delaware; and sold its refinery in Paulsboro, New Jersey. In August 2011, Valero acquired ChevronLtd. from Chevron Corp. (see above for details). In April 2012, the company entered into agreements to sellAlaska assets. One transaction closed in the second quarter of 2012 resulting in net gain of $7 million. Theremaining transaction, with a value of $375 million before closing adjustments, is expected to close in thesecond half of 2012. Sunoco. In late 2009, Sunoco Inc. permanently shut down its Eagle Point refinery at Westville, NewJersey, and by early 2010, the company sold most of its chemical business to Braskern S.A. In September2011, Sunoco announced plans to shut down or sell its two remaining refineries, the Philadelphia andMarcus Hook plants. In its second quarter results, the company said that it was looking at alternate uses ofthe Marcus Hook facility.By comparison, refineries operated by the NOCs were less likely to adjust their throughputs to reflecteconomic reality. As a result, the IEA estimates that the OECD regions bore the brunt of current reducedrefining throughputs, and a global refining capacity overhang is expected to remain in the market for atleast five years. According to June 2011 data, the IEA projected 25%–30% of OECD refining capacitywould be “temporarily” idled by 2014, compared with only about 20% in the non-OECD regions.US refining: fewer but larger refineriesRefiners today need size and technology to generate the operational efficiencies required to remaincompetitive. The sector has seen much consolidation over the past two decades, resulting in the closure ofolder and smaller refineries.Using data from the US EIA and the OGJ, S&P Capital IQ estimates that US refining capacity peaked in1981 at 18.62 million b/cd, but dropped by 2.97 million b/cd to 15.65 million b/cd by 1989. During thisperiod, the number of US refineries fell from 324 to 204, reflecting the 1981 elimination of price controls onrefined oil products that had supported many marginally profitable refineries. As these less efficient, olderplants were taken out of service, refinery utilization rates rose from 69% in 1981 to 87% in 1989.Although numerous US refineries were also shut down during the 1990s—reflecting, in part, the impact ofenvironmental regulations—US refining capacity has actually expanded. Data from the US EIA and the OGJindicate that the total number of US refineries dropped from 204 in 1989 to 149 in 2003, and then declinedto 125 in 2011. US refining capacity, however, rose: from 15.66 million b/cd in 1989 to 17.78 million b/cdin 2011. During this period, the average refinery size more than doubled, from 57,000 b/cd in 1981 to129,500 b/cd in 2011.As the average size of a refinery increased, so did the US refinery utilization rate, from 87% in 1989 to 93%in 2004. Using data from the US EIA and the OGJ, refinery utilization averaged around 90% from 2005through 2007, but dropped to around 86% in 2011, reflecting reduced global demand. In general, refineryoperational efficiencies tend to become optimized at rates in the high 80% to low 90% range. Thus, USrefiners have moved down to a less profitable operating range, and as a result, we look for more refinerycurtailments in order to restore balance to the market in the Western Hemisphere.A lack of geographic diversification also plagues the US refining industry, with about 47% of US refiningcapacity located in the US Gulf of Mexico. While this Gulf capacity is strategically positioned near majordistribution hubs and sources of oil production, it is vulnerable to severe storms. For example, in theaftermath of Hurricanes Katrina and Rita in 2005, about 30% (or 5.4 million b/cd) of US refining capacityin the US Gulf of Mexico was shut down.
20 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSLNG LEADS NATURAL GAS INTO THE GLOBAL MARKETPLACEWith global natural gas consumption expected to increase and world oil prices returning to high levels,consumers are expected to opt for less expensive natural gas for their energy needs when possible. Inaddition, natural gas produces less carbon dioxide when burned than oil or coal, and governmentsimplementing plans to reduce greenhouse gas (GHG) emissions may encourage its use over other fossil fuels.While proved natural gas reserves worldwide have grown faster than gas demand, the IEA anticipates thatOECD countries increasingly will need to import natural gas, because the discovery of additional gasreserves in OECD countries has not kept pace with depletion and the rise in demand. As a result, OECDregions are now becoming more import dependent. According to the US EIA, OECD countries accountedfor over 90% of all LNG imports in 2006. LNG imports to the US have risen in recent years, from about0.23 Tcf (or 4.6 million tonnes, or mmt) in 2002, to about 0.5 Tcf in 2009. Still, LNG imports representedonly about 1.8% of US natural gas consumption in 2010. However, a sharp increase in US shale gasproduction seems to have affected LNG imports in the last couple of years. According to the EIA, the USimported 0.43 Tcf of LNG in 2010 and 0.35 Tcf in 2011. It expected the US to import 0.17 Tcf of LNG in2012.While OECD North America is expected to remain largely a self-contained market for natural gas, thedependence of OECD Europe on imported natural gas is expected to increase. In 2006, 44% of OECDEurope’s natural gas demand was met with imports from outside the region (Russia and Algeria accountedfor over 30% of OECD Europe’s natural gas supply). In OECD Asia, Japan and South Korea are almostentirely dependent on LNG imports for natural gas supplies. These two Asian countries are expected tocontinue to be major players in LNG markets (Japan represented 41% of global LNG imports in 2006, andSouth Korea 15%), despite consuming relatively small amounts of natural gas on a global scale.LNG liquefaction capacity is forecast to expand almost fivefold, from 133.5 million tonnes per annum (mtpa)in 2005 to 720.0 mtpa in 2030. This corresponds to the addition of 100 new LNG production facilities (alsoknown as LNG trains), 40% of which will be in the Middle East. Importing regions, particularly NorthAmerica, Korea, China, and India, will need to add almost 660 mtpa of new regasification capacity to whatexisted in 2004 (almost 263 mtpa at 43 terminals, 25 of which were in Japan).This increase in world liquefaction capacity is expected to exceed world demand in the near term, makingLNG available to the US market, particularly in the summer to fill storage facilities. Over the long term,high LNG prices (which are tied to oil prices in many markets) and ample domestic natural gas supplies areexpected to reduce US demand for LNG imports. That said, the amount of LNG available is subject torevision as world natural gas consumption patterns change.Should the US now import or export?Just a few years ago, it was believed that growing volumes of LNG imports to the US would be required tosupplement declining Canadian natural gas supplies. The dynamic has shifted with the recent shale gasexplosion in the US adding significant supplies. We expect LNG import expectations to decline as the US isnow oversupplied with natural gas. In fact, with the massive gas resources under development domestically,we believe the question has now shifted to whether the US will export LNG, which is both a fundamentaland political question. For so long, the US has been dependent on foreign energy sources. Now that it hasamassed such a large base of reserves, and gained at least some form of energy independence, USpolicymakers will have to decide whether it is in the best domestic interest to export its natural gasresources in the form of LNG.There were 15 LNG import (regasification) terminals operating in the US in 2012. The six top terminals arelocated at Sabine, Louisiana (4.0 billion cubic feet per day, or Bcf/d); Lake Charles, Louisiana (2.1 Bcf/d);Sabine, Texas (2.0 Bcf/d); Cove Point, Maryland (1.8 Bcf/d); Hackberry, Louisiana (1.8 Bcf/d); and ElbaIsland, Georgia (1.6 Bcf/d).
INDUSTRY SURVEYS OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 21According to IHS, US import capacity totaled a little less than 5.0 Bcf/d in 2007. Such capacity has nowexpanded by more than 5 times to nearly 22 Bcf/d. LNG import projects are also being developed for Mexicoand Canada.ALTERNATIVES TO FOSSIL FUELSWith oil dependence and global warming on the top of the international energy agenda, alternatives to fossilfuel energy are of increased interest. These alternatives include nuclear power, as well as renewable sources,such as hydroelectric, biomass, geothermal, solar (both solar collectors that transform sunlight into heat,and photovoltaic panels that generate electricity from sunlight), and wind.According to the US EIA’s International Energy Outlook 2012, alternative energy sources contributed to7% of world energy consumption in 2010, and that percentage is projected to rise only slightly, to 11% by2035. Why? Because concerns over plant safety and waste disposal have hindered nuclear power development,and available technologies for renewable energy sources are generally not cost-competitive with fossil fuels,such as coal (the baseline fossil fuel).Exceptions include hydroelectric, which is already competitive, as well as geothermal, wind, and biomass,which offer competitive economies to coal and operate at levelized costs of four to five cents per kilowatt-hour. Reflecting these economies, it is not surprising that hydropower, geothermal power, and municipalsolid waste accounted for about 94% of renewable electricity generation in 2005, according to estimates byExxonMobil.Much of the growth in renewable generation is projected to result from the completion of largehydroelectric facilities in emerging economies, such as Asia. Hydroelectric capacity outside the emergingeconomies is not expected to grow substantially. Using 2012 projections by ExxonMobil for the time frameof 2010–2040, the consumption of biomass (including traditional fuels such as wood and dung) and solidwaste is expected to grow by 0.3% per year, and other renewables (supported by subsidies and relatedmandates) about 5%.Most of the supermajors, such as BP, Chevron, Royal Dutch Shell, and Total, are researching and buildingrenewable energy businesses with a long-term view. BP Alternative Energy was launched in 2005, with a focuson solar power, wind, and hydrogen power. With Chevron’s acquisition of Unocal in 2005, the companybecame one of the largest renewable energy producers in the world. Shell Renewables was established in 1997and is now one of five core businesses for Royal Dutch Shell: it focuses on wind and solar photovoltaics, but isalso involved in biofuels, geothermal, and hydrogen. Since 1983, Total has been investing in renewables,such as solar and wind power, through its 35% stake in Total Energie.However, with many renewable energy businesses barely profitable and technologies still in their infancy,ExxonMobil has been investing in research to search for the most viable and profitable carbon alternatives,and in July 2009 formed an alliance with Synthetic Genomics (SGI) to research and develop next-generationbiofuels from photosynthetic algae, a technologically enhanced version of naturally occurring algae.Greenhouse gas concernsMany chemicals found in the Earth’s atmosphere act as greenhouse gases, which allow sunlight to enter theatmosphere freely. When sunlight strikes the Earth’s surface, some of it is reflected back toward space asinfrared radiation (heat). Greenhouse gases absorb this infrared radiation and trap the heat in theatmosphere. Given the natural variability of the Earth’s climate, there is considerable uncertainty about howthe climate system reacts to emissions of GHG.Assessments by the US EIA generally suggest that the Earth’s climate has warmed over the past century andthat human activity has been an important factor. Rising temperatures, in turn, may produce changes inweather, sea levels, and land use patterns.Many gases exhibit greenhouse properties. Some of these gases (e.g., water vapor, carbon dioxide, methane,and nitrous oxide) occur in nature, while others, such as gases used for aerosols, are exclusively manmade.
22 OIL & GAS: PRODUCTION & MARKETING / SEPTEMBER 27, 2012 INDUSTRY SURVEYSAccording to estimates by the US EIA, levels of GHG have increased about 25% since large-scaleindustrialization began about 150 years ago. During the past 20 years, about 75% of the man-made carbondioxide emissions were from burning fossil fuels (such as oil, gas, or coal). Among the fossil fuels, coal hasthe highest carbon content, natural gas the lowest; petroleum’s carbon content falls in the middle.HOW THE INDUSTRY OPERATESThe modern petroleum industry got its start in 1859 near Titusville, Pennsylvania, where “Colonel” EdwinDrake (1819–1880) became the first person to drill successfully for oil. In 1901, a huge gusher blew atSpindletop, a hill in eastern Texas, foreshadowing that state’s future as the hub of US oil production.The advent of the automobile created a market for gasoline, which until then had been the industry’s largestwaste byproduct. Meanwhile, demand for kerosene (produced by refining crude oil) began to decline withthe introduction of Thomas Edison’s electric light.The oil industry has changed significantly over the past century. As worldwide deposits have been identified,US influence on the global oil market has greatly diminished. In 1934, the United States accounted for 60%of total world oil production. In 2010, it produced just 8.7%, according to the June 2011 issue of the BPStatistical Review of World Energy. This same source noted that fossil fuels (crude oil, natural gas, andcoal) fulfill about 88% of the world’s primary energy needs and, in addition, are used as feedstocks by thechemicals, plastics, and pharmaceuticals industries.THE ENERGY SECTOR IS CYCLICALHistorically, the energy sector has been cyclical in nature. S&P Capital IQ dates past cycles based on thelevel of US upstream spending by all market participants. We estimate that boom periods existed from 1947to 1957, 1972 to 1981, and 1996 to the present, and that bust periods existed from 1958 to 1971 and from1982 to 1995. However, we believe that stronger-than-expected demand growth and weak production trendshave fundamentally changed the nature of the energy sector. As a result, we forecast that sustained, high levelsof energy investment will be necessary for suppliers to keep pace with demand, extending the energy cycle.We believe that the last lengthy energy downturn (1982–1995) reflected three main factors. First, producerschanged their focus, emphasizing return on investment rather than production growth. Second, with oil andnatural gas prices hovering around much lower than historical averages, industry fundamentals were soft andinvestor interest was low. Third, access to low-cost reserves in foreign or US federal lands was limited.Then the scenario changed, and the sector entered a boom in 1996 (temporarily interrupted by the 1997–98Asian economic crisis), reflecting our belief that producers came under pressure to replenish their reserves inorder to maintain their production targets in the face of rising decline rates. New technology improved thetechnical and economic prospects of new projects in harsh environments, such as arctic and deepwaterfinds. Access to certain foreign lands and some environmentally restricted lands came under review, and oiland gas prices rose and stayed above historical averages. In order to meet an increase in global demand,huge additions and expansions to existing energy infrastructure (pipelines, tankers, rigs, and refineries) willbe required, as well as the replacement of outdated existing facilities.INDUSTRY DIVISIONSThe oil and gas business has three major segments: exploration and production of oil and natural gas (theupstream); the transportation, storage, and trading of crude oil, refined products, and natural gas (themidstream); and refining and marketing of crude oil (the downstream). Participants include integrated oiland gas companies, and pure-play companies in various areas, including exploration and production,midstream services, refining and marketing, and oilfield services and drilling. This Survey covers all but thelast category. (For more information about the oilfield service and drilling sectors, refer to the Oil & Gas:Equipment & Services issue of Industry Surveys, and for more information about natural gas transportationand trading, refer to the Natural Gas Distribution issue of Industry Surveys.)