Liquid fuels

Overview

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Consumption of petroleum and other liquid fuels¹⁵ increases from 85.7 million barrels per day in 2008 to 112.2 million barrels per day in 2035 in the IEO2011 Reference case. Although world liquids consumption actually declined in 2009 (to 83.9 million barrels per day), it recovered in 2010 to an estimated 86.0 million barrels per day and is expected to continue increasing in 2011 and beyond as economic growth strengthens, especially among the developing non-OECD nations. In the long term, world liquids consumption increases despite world oil prices that rise to $125 per barrel (real 2009 dollars) by 2035. More than 75 percent of the increase in total liquids consumption is projected for the nations of non-OECD Asia and the Middle East, where strong economic growth and, in the case of the Middle East, access to ample and relatively inexpensive domestic resources drive the increase in demand (Figure 27).

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To satisfy the increase in world liquids demand in the Reference case, liquids production increases by 26.6 million barrels per day from 2008 to 2035, including the production of both conventional liquid supplies (crude oil and lease condensate, natural gas plant liquids, and refinery gain) and unconventional supplies (biofuels, oil sands, extra-heavy oil, coal-to-liquids [CTL], gas-to-liquids [GTL], and shale oil) (Figure 28 and Table 3). In the Reference case, sustained high world oil prices allow for the economical development of unconventional resources and the use of enhanced oil recovery (EOR) technologies to increase production of conventional resources. High world oil prices also incentivize the development of additional conventional resources through technically difficult, high-risk, and very expensive projects, including wells in ultra-deep water and the Arctic.

The most significant non-OPEC contributors to production growth are Russia, the United States, Brazil, and Canada (Figure 29). Total non-OPEC liquids production in 2035 is 15.3 million barrels per day higher than in 2008, representing 57 percent of the total world increase. OPEC producers¹⁶ are assumed to restrict investment in incremental production capacity in the Reference case, below the levels justified by high prices. As a result, OPEC provides roughly 42 percent of the world's total liquids supply over the 2008-2035 period, consistent with its share over the past 15 years.

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Unconventional resources from both OPEC and non-OPEC sources become increasingly competitive in the IEO2011 Reference case, although unconventional petroleum liquids production development faces some difficulties, such as environmental concerns for Canada's oil sands projects and investment restrictions for Venezuela's extra-heavy oil projects. Production of nonpetroleum unconventional liquids, such as biofuels, CTL, and GTL, is spurred by sustained high prices in the Reference case (Figure 30). However, their development also depends on country-specific programs or mandates. World production of unconventional liquids, which in 2008 totaled only 3.9 million barrels per day or about 5 percent of total world liquids production, increases in the Reference case to 13.1 million barrels per day in 2035, when it accounts for 12 percent of total world liquids production.

World oil prices

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The impacts of world oil prices¹⁷ on energy demand are a considerable source of uncertainty in the IEO2011 projections. Prices have been exceptionally volatile over the past several years, reaching a high of $145 in July 2008 (daily spot price in nominal dollars) and a low of $30 in December 2008, as the global recession substantially dampened demand and thus prices. Improving economic circumstances, especially in the developing economies, strengthened liquids demand, and prices rose in 2009 and 2010. More recently, growing demand and unrest in many oil-supplying nations of the Middle East and North Africa have supported price increases into 2011. Prices rose from an average $62 per barrel in 2009 to $79 per barrel in 2010, and they are expected to average about $100 per barrel in 2011 [42]. In the IEO2011 Reference case, world oil prices continue increasing, to $108 per barrel in 2020 and $125 per barrel in 2035.

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In addition to the Reference case prices, IEO2011 includes analyses of high and low world oil price paths. The three alternative price paths, which are consistent with those presented in EIA's Annual Energy Outlook 2011 [43], are used to develop five price scenarios that can be used to illustrate the range of uncertainty associated with prices in world liquids markets (Figure 31 and Table 4). The high and low oil price paths and resulting scenarios illustrate price uncertainty, but they do not span the complete range of possible price paths.

In past editions of the IEO, high and low oil price scenarios typically have examined the impacts of changes in liquids supplies relative to the Reference case, based on different assumptions about OPEC decisionmaking and access to non-OPEC resources and their impacts on world liquids supply. In the IEO2011 Traditional Low Oil Price case, as in past IEOs, the available supply is higher at all price levels; and in the Traditional High Oil Price case, the available supply is lower at all price levels, reflecting shifts in the liquids supply curve. The traditional oil price cases assume that demand curves are constant, with changes in demand resulting only from movement along the demand curves as prices rise or fall.

In contrast, the Low Oil Price and High Oil Price cases in IEO2011 assume that changes in demand growth, resulting in different levels of demand, also affect prices. Thus, the Low Oil Price and High Oil Price cases incorporate alternative assumptions about economic growth and other structural factors in non-OECD countries that shift the "demand schedule" for liquids fuels while also continuing to maintain a portion of the change in "supply schedules" that drive the Traditional High Oil Price and Traditional Low Oil Price cases. The IEO2011 Low Oil Price case assumes that liquids demand in the non-OECD countries (where most of the world's demand uncertainty lies) at any given price level is lower than in the Reference case, and that total liquids supply available at any price point is higher than in the Reference case. It also assumes that the shifts in demand and supply schedules lead to changes in the liquids quantities, resulting in price levels that are the same as those in the Traditional Low Oil Price case. That is, the only change is in the amount of oil consumed in the world market. Similarly, the IEO2011 High Oil Price case assumes that liquids demand in the non-OECD countries at any given price level is higher than in the Reference case, and that the total liquids supply available at any price point is lower than in the Reference case, with the shifts in demand and supply schedules leading to changes in the quantities of liquids available, so that price levels that are the same as those in the Traditional High Oil Price case. Again, the only change is in the amount of oil consumed in the market.

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In the Reference case, world oil prices are $95 per barrel in 2015 (real 2009 dollars), increasing slowly to $125 per barrel in 2035 ($200 per day in nominal terms). The Reference case represents EIA's current best judgment regarding exploration and development costs and accessibility of oil resources outside the United States. It also assumes that OPEC producers will choose to maintain their share of the market and will schedule investments in incremental production capacity so that OPEC's conventional oil production represents about 42 percent of the world's total liquids production. To retain that share, OPEC would have to increase production by 11.3 million barrels per day from 2008 to 2035, or 43 percent of the projected total increase in world liquids supply (Figure 32). Non-OPEC conventional supplies—including production from high-cost projects and from countries with unattractive fiscal or political regimes—account for an increase of 7.1 million barrels per day over the projection, and non-OPEC production of unconventional liquid fuels provides the remaining 8.2 million barrels per day of the increase.

In the High Oil Price case, world oil prices are about $200 per barrel in 2035 ($320 per barrel in nominal terms), with the higher prices resulting from the combination of an outward shift (greater demand at every price level) in the "demand schedule" for liquid fuels in the non-OECD nations and a downward shift (reduced supply at every price level) in the "supply schedule." The shift in the demand schedule is driven by higher economic growth relative to the Reference case in the non-OECD region, with non-OECD growth rates raised by 1.0 percentage point relative to the Reference case in each projection year starting with 2015. The downward shift in the supply schedule is a result of the assumption that several non-OPEC producers further restrict access to, or increase taxes on, production from prospective areas, and that the OPEC member countries reduce their production substantially below current levels. High oil prices encourage the expansion of unconventional production relative to the Reference case.

In the Traditional High Oil Price case, OPEC countries are assumed to reduce their production from the current rate, sacrificing market share, and oil resources outside the United States are assumed to be less accessible and/or more costly to produce than in the Reference case. As in the High Oil Price case, higher oil prices allow unconventional resources to become more economically attractive, and their production increases above the levels in the Reference case. Oil consumption is lower solely due to the higher prices (which are the same as in the High Oil Price case), reflecting a movement upward and to the left along the demand curve.

In the Low Oil Price case, world crude prices are $50 per barrel in 2035 ($82 per barrel in nominal terms), compared with $125 per barrel in the Reference case. The low prices result from the combination of a shift to lower demand at every price level in the demand schedule and a shift to increased supply at every price level in the supply schedule. The shift in demand is driven by lower economic growth in the non-OECD region relative to the Reference case, with non-OECD growth rates lowered by 1.5 percentage points relative to the Reference case in each projection year starting with 2015. The upward shift in the supply schedule in this case results from greater access and more attractive fiscal regimes in prospective non-OECD areas, as well as higher levels of production from OPEC members. However, the lower prices make it uneconomical to expand production of unconventional resources.

In the Traditional Low Oil Price case, the OPEC countries increase their conventional oil production to obtain a 52-percent share of total world liquids production, and oil resources are more accessible and/or less costly to produce (as a result of technology advances, more attractive fiscal regimes, or both) than in the Reference case. With these assumptions, conventional oil production is higher in the Traditional Low Oil Price case than in the Reference case, but low prices constraint the expansion of unconventional resources. Oil consumption is higher solely as a result of the lower prices (which are the same as in the Low Oil Price case), reflecting a movement downward and to the right along the demand curve.

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World liquids consumption

World liquids consumption in the IEO2011 Reference case increases from 85.7 million barrels per day in 2008 to 97.6 million barrels per day in 2020 and 112.2 million barrels per day (225 quadrillion Btu) in 2035. World GDP is a key driver of demand, growing by an average 3.6 percent per year from 2008 to 2020 and 3.2 percent per year from 2020 to 2035. Developing non-OECD nations, particularly in Asia and the Middle East, experience strong economic growth in the Reference case, which is accompanied by increasing demand for liquids in the transportation and industrial sectors.

Rising prices for liquids increase the cost-competitiveness of other fuels, leading many users of liquids outside the transportation sector to switch to substitute sources of energy when possible. As a result, the transportation share of total liquid fuels consumption increases, accounting for about 80 percent of the overall increase in liquids consumption in all sectors over the projection period (Figure 33). In 2035, the transportation sector consumes 60 percent of total liquids supplied, as compared with 54 percent in 2008.

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Strong expansion of liquids use is projected for non-OECD countries, fueled by a return to robust economic growth, burgeoning industrial activity, and rapidly expanding transportation use. The largest increase in regional non-OECD consumption from 2008 to 2035 is projected for non-OECD Asia, at 17.3 million barrels per day. Within non-OECD Asia, the largest increases in demand come from China (9.1 million barrels per day) and India (4.6 million barrels per day), with the increase from China being the largest for any single country worldwide. Large consumption increases are also expected in the Middle East (2.9 million barrels per day), followed by Central and South America (2.5 million barrels per day) (Figure 34).

Liquids consumption in OECD regions generally grows more slowly over the next 25 years, reflecting slowly growing or declining populations and relatively low economic growth as compared with non-OECD nations. In addition, growth in demand for liquids in many OECD countries is slowed by government policies and legislation aimed at improving the efficiency of personal motor vehicles. This includes increased automobile efficiency standards and government incentives introduced in many nations during the recession, such as the U.S. "cash for clunkers" program, designed to encourage consumers to trade in older, less efficient cars for newer ones that are more fuel-efficient. In Japan and OECD Europe, liquids consumption declines by average annual rates of 0.4 percent (0.5 million barrels per day) and 0.2 percent (0.7 million barrels per day), respectively, from 2008 to 2035.

As a result of the different growth trends for the non-OECD and OECD regions, non-OECD liquids consumption in 2020 exceeds OECD consumption. The difference widens considerably over time, and in 2035 non-OECD consumption is 23 percent greater than OECD consumption. Although China's demand for liquids increases by 3.5 percent per year over the projection, its consumption in 2035 still is 5.0 million barrels per day less than U.S. liquids consumption.
In the Low Oil Price case, non-OECD consumption and OECD consumption are nearly identical, at 57.0 and 56.3 million barrels per day in 2035, respectively. OECD consumption is higher than in the Reference case, because low prices discourage conservation and allow consumers to continue to use liquid fuels without economic impact. Most of the increase in OECD consumption in the Low Oil Price case occurs in the Americas and in Asia.

In contrast to the OECD, non-OECD consumption is 4.8 million barrels per day lower in the Low Oil Price case than in the Reference Case. In this case, slower growth in demand for liquids among the developing nations keeps world oil prices low—in contrast to the Traditional Low Oil Price case, where low prices encourage increased consumption worldwide. Although OECD liquids consumption levels in 2035 are similar in the Low Oil Price and Traditional Low Oil Price cases, non-OECD consumption grows to a total of 74.4 million barrels per day in 2035 in the Traditional Low Oil Price case—17.4 million barrels per day higher than in the Low Oil Price case and 12.6 million barrels higher than in the Reference case.

In the High Oil Price case, where high oil prices are a result of strong growth in non-OECD demand for liquids, non-OECD liquids consumption represents 61 percent of the world total in 2035. China's consumption of liquids grows by an average of 3.8 percent per year (from 7.8 million barrels per day in 2008 to 21.2 million barrels per day in 2035), as compared with 3.5 percent per year in the Reference case. India and the Middle East also increase consumption by an average of more than 2.0 percent per year. OECD consumption declines slightly through the mid-term and increases only slightly in the longer term, with high world oil prices encouraging consumers to conserve fuel and turn to alternatives fuels whenever possible. OECD liquid fuel use in the High Oil Price case remains below the 2008 level of 48.0 million barrels per day through 2035.

Non-OECD demand, which is higher in the High Oil Price case than in the Reference case, provides support for higher world oil prices. For example, in the High Oil Price case China's liquids consumption in 2035 is equal to U.S. consumption. In contrast, in the Traditional High Oil Price case, demand for liquids in all regions is affected only by price, with high prices dampening liquids demand and encouraging conservation and fuel switching. As a result, liquids consumption in the Traditional High Oil Price case is lower than in the Reference case in every IEO2011 region. In the Traditional High Oil Price case, non-OECD liquids consumption totals 59.4 million barrels per day in 2035, as compared with 74.2 million barrels per day in the High Oil Price case and 61.8 million barrels per day in the Reference case. OECD liquids consumption in 2035 in the Traditional High Oil Price case is almost the same as in the High Oil Price case.

Recent market trends

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In 2010, world oil prices responded primarily to expectations about demand, with producers, consumers, and traders looking for some indication as to when the world's economy would recover, what shape the recovery would take, and how strong the corresponding increase in oil demand would be. While stronger than expected regional growth led many market players to expect a buoyant return of global liquids demand and an increase in oil prices, the financial crises in several European nations served as a caution about the still fragile global economy and the potential negative impact of higher oil prices on demand.

In addition, 2010 was an eventful year for supply factors that shape long-term pricing. The Deepwater Horizon oil spill in the U.S. Gulf of Mexico may have consequences for future U.S. production that are not yet fully understood. In addition, new discoveries and development in Africa's frontier exploration regions have increased production expectations for the continent and expanded the range of countries with future production potential, which not so long ago was generally limited to a few established producers relying on EOR and deepwater production in Angola and Nigeria [44].

In addition, although OPEC compliance¹⁸ with its 2008 production quotas has held relatively steady, averaging under 60 percent for the year, the recent decision by OPEC not to increase official production targets despite rising oil prices, along with public statements by members calling for $80 to $100 per barrel as the new "fair" oil price, has drawn into question the organization's concern for world economic recovery [45].

Iraq, the only OPEC member not subject to a production quota, has seen initial production gains at the individual fields included in its two 2009 bid rounds; however, those gains have only compensated for other declines and have not lead to an increase in total production. Although foreign companies in Iraq have been able to establish operations and achieve initial production gains in relatively short order despite ongoing security risks and political uncertainty, most industry analysts still do not expect Iraq to reach its production target of 9.5 million barrels per day—almost four times the country's current production level—within the next decade [46].

World liquids production

In the IEO2011 Reference case, world liquids production in 2035 exceeds the 2008 level by 26.6 million barrels per day, with production increases expected for both OPEC and non-OPEC producers (Figure 35). Overall, 57 percent of the total increase is expected to come from non-OPEC areas, including 31 percent from non-OPEC unconventional liquids production alone. OPEC produces 46.9 million barrels per day in 2035 in the Reference case, and non-OPEC producers provide 65.3 million barrels per day.

The Reference case assumes that OPEC producers will choose to maintain their market share of world liquids supply and will invest in incremental production capacity so that their liquids production represents approximately 40 percent of total global liquids production throughout the projection. Increasing volumes of conventional liquids (crude oil and lease condensate, natural gas plant liquids [NGPL], and refinery gain) from OPEC members contribute 10.3 million barrels per day to the total increase in world liquids production from 2008 to 2035, and conventional liquids supplied from non-OPEC nations contribute 7.1 million barrels per day.

Unconventional liquids production increases by about 5 percent annually on average over the projection period, because sustained high oil prices make unconventional liquids more competitive, and "above-ground" factors limit the production of economically competitive conventional liquids.¹⁹ Unconventional fuels account for 35 percent (9.2 million barrels per day) of the increase in total liquids production in the Reference case, and 8.2 million barrels per day of the increase in unconventional supply comes from non-OPEC sources. High oil prices, improvements in exploration and extraction technologies, emphasis on recovery efficiency, and the emergence and continued growth of unconventional resource production are the primary factors supporting the growth of non-OPEC liquids production in the IEO2011 Reference case.

Liquids production modeling approach

The IEO2011 projections for liquids production are based on a two-stage analytical approach. Production projections before 2015 are based largely on a project-by-project assessment of production volumes and associated scheduling timelines, with consideration given to the decline rates of active projects, planned exploration and development activity, and country-specific geopolitical situations and fiscal regimes. There are often lengthy delays between the point at which supply projects are announced and when they begin producing. The extensive and detailed information available about such projects, including project scheduling and the investment and development plans of companies and countries, makes it possible to take a detailed approach to the modeling of mid-term supply.

Although some projects are publicized more than 7 to 10 years before their first production, others can come on line within 3 years. For that reason, project-by-project analyses are unlikely to provide a complete representation of company or country production plans and achievable production volumes beyond 3 years into the future. Instead, production decisions made after the mid-term, or 2015, are assumed to be based predominantly on resource availability and the resulting economic viability of production.

In view of the residual effects of previous government policies and the unavoidable lag time between changes in policy and any potential production changes, however, most country-level changes in production trends are noticeable only in 2020 and beyond. Geopolitical and other above-ground constraints are not assumed to disappear entirely after 2015, however. Longstanding above-ground factors for which there are no indications of significant future changes—for instance, the government-imposed investment conditions currently in place in Iran, or OPEC adherence to production quotas—are expected to continue affecting world supplies long after 2015. Even if above-ground constraints were relaxed, the expansion of production capacity could be delayed, depending on the technical difficulty and typical development schedules of the projects likely to be developed in a particular country.

For some resource-rich countries it is assumed that current political barriers to production increases will not continue after 2015. For instance, both Mexico and Venezuela currently have laws that restrict foreign ownership of hydrocarbon resources. Their resource policies have discouraged investment—both foreign and domestic—and hindered their ability to increase or even maintain historical production levels. In the Reference case, both Mexico and Venezuela ease restrictions at some point after 2015, allowing some additional foreign involvement in their oil sectors that facilitates increases in liquids production, including from deepwater prospects in Mexico and extra-heavy oils in Venezuela's Orinoco belt.

Iraq is another resource-rich country where currently there are significant impediments to investment in the upstream hydrocarbon sector. Liquids production in Iraq dropped substantially after the U.S.-led invasion in 2003. From 2002 to 2003 production declined from 2.0 million barrels per day to 1.3 million barrels per day, and since then it has achieved only inconsistent and slow growth. Although Iraq's production levels are not expected to increase substantially in the near term, it is assumed that political and legal uncertainty eventually will subside, and that renewed investment and development activity will ensue, resulting in significant growth in production from 2015 to 2035.

Non-OPEC production

The return to sustained high oil prices projected in the IEO2011 Reference case encourages producers in non-OPEC nations to continue investment in conventional liquids production capacity and increase investment in EOR projects and unconventional liquids production. Non-OPEC production increases steadily in the projection, from 50.0 million barrels per day in 2008 to 65.3 million barrels per day in 2035, as high prices attract investment in areas previously considered uneconomical, and fears of supply restrictions encourage some net consuming nations to expand unconventional liquids production from domestic resources, such as coal and crops.

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Despite the maturity of most non-OPEC producing basins, conventional liquids production in the Reference case increases from 46.8 million barrels per day in 2008 to 53.9 million barrels per day in 2035. The overall increase results primarily from production increases in four countries: Brazil, Russia, Kazakhstan, and the United States (Figure 36). Among non-OPEC producers, the near absence of prospects for new, large conventional petroleum liquids projects, along with declines in production from existing conventional fields, results in heavy investment in the development of smaller fields. Producers are expected to concentrate their efforts on more efficient exploitation of fields already in production, either through the use of more advanced technology for primary recovery efforts or through EOR. Those efforts are expected to allow most established non-OPEC producers to maintain or slow production declines but not to raise production volumes.

In the Reference case, unconventional liquids production from non-OPEC suppliers rises to 6.5 million barrels per day in 2020 and 11.4 million barrels per day in 2035. In both the High Oil Price and Traditional High Oil Price cases, non-OPEC unconventional liquids production rises to about 17.4 million barrels per day in 2035, as significantly higher prices encourage the development of alternative fuel sources to the limits imposed by expected environmental protection measures and industry expansion in general. In contrast, in the Low Oil Price and Traditional Low Oil Price cases, fewer unconventional resources become economically competitive, and non-OPEC production of unconventional liquids rises to only about 7.0 million barrels per day in 2035 in each low price case.

Major areas of decline in non-OPEC liquids production

In the IEO2011 Reference case, Mexico and the North Sea are the only non-OPEC production areas that lose more than 1 million barrels of liquids production per day from 2008 to 2035. The most significant decline in non-OPEC liquids production is projected for OECD Europe, with a decrease from 5.1 million barrels per day in 2008 to 3.0 million barrels per day in 2035. Most of the decline is in North Sea production, which includes offshore operations by Norway, the United Kingdom, the Netherlands, and Germany. Over time, fewer and fewer prospects capable of compensating for declines in existing fields have been discovered. The drop in North Sea liquids production does not vary significantly among the four price cases, both because the projected production is based on depletion of resources and because all the countries currently producing liquids from North Sea operations are expected to continue encouraging investment and providing open access to development.

In Mexico, liquids production sinks to approximately 1.4 million barrels per day in 2025 before rebounding slowly to 1.7 million barrels per day in 2035, still 1.5 million barrels per day below the 2008 production volume of 3.2 million barrels per day. The rebound after 2025 depends entirely on the development of potential resources in the deepwater Gulf of Mexico, which must begin some years in advance of any increase in production levels. The outlook for Mexico's liquids production is markedly different from the IEO projection just 5 years ago, in which production did not fall below 2.9 million barrels per day, and a long-term recovery began in 2013. The difference between the projections is the result of production declines at Cantarell, which have been more severe than expected, as well as diminished expectations for Chicontepec production and more pessimistic assumptions about the level of future investment, both foreign and domestic, in Mexico's deepwater production.

Although the shortage of investment in Mexico is expected to lead to a mid-term decline, Mexico has potential resources to support a long-term recovery in total production, primarily in the Gulf of Mexico. The extent and timing of a recovery will depend in part on the level of economic access granted to foreign investors and operators. Mexico's national oil company, Petróleos Mexicanos (PEMEX), currently does not have the technical capability or financial means to develop potential deepwater projects in the Gulf of Mexico.

Major areas of growth in non-OPEC liquids production

The largest increase in non-OPEC total liquids production is expected for Brazil, where total production in 2035 is 4.1 million barrels per day above the 2008 level of 2.4 million barrels per day. Of that increase, 2.9 million barrels per day is attributed to conventional liquids production. The strong growth in Brazil's conventional production results in part from short- and mid-term increases at producing fields for which expansions currently are either planned or in progress. In addition, recent and expected discoveries in the Campos and Santos basins, including the massive Tupi and related Guara and Iara discoveries, both add to production in the mid- and long term and suggest the presence of other large fields in the same formation [47]. The vast size of the sub-salt potential in Brazil, as well as national economic strategy and industrialization goals, has led Brazil to pursue new petroleum legislation [48]. The legislative change most pertinent to production potential is the requirement that the state oil company, Petrobras, be the sole operator and a minimum 30-percent equity holder for all sub-salt fields.

Although Petrobras has repeatedly proven itself a leader in deepwater development and is known to have the technical capabilities to develop sub-salt prospects, it is not expected to have the resources (financial, labor, etc.) to develop its domestic plays completely on its own. The different IEO2011 price cases assume different investment terms offered by Brazil to foreign investors and hence different rates of sub-salt development. Although both the High Oil Price case and the Traditional High Oil Price case assume more restrictive terms of access to Brazil's conventional resources, the increase in world liquids demand in the High Oil Price cases supports a production level of 5.3 million barrels per day in 2035, compared with 5.0 million barrels per day in the Traditional High Oil Price case. In contrast, both the Low Oil Price and Traditional Low Oil Price cases assume open terms of access to Brazil's conventional resources, resulting in production increases averaging 3.4 percent per year and conventional production of 5.1 million barrels per day in 2035 in the Low Oil Price case (as a result of lower world liquids demand) and 5.6 million barrels per day in 2035 in the Traditional Low Oil Price case.

In addition to the growth in conventional liquids production, Brazil's biofuel production also increases, from 0.5 million barrels per day in 2008 to 1.7 million barrels per day in 2035 in the Reference case. The growth is a result of steadily increasing yields and expansion of crop production, with most of the increase consisting of ethanol. Brazil's major ethanol production is derived from sugar cane, currently the highest yielding and least expensive feedstock for ethanol. Brazil also has a large amount of land available for sugar cane production, in the form of previously cleared and currently underutilized pasture land. The country's domestic consumption is not expected to rise as fast as its expansion of ethanol production, making Brazil a net ethanol exporter over the course of the projection. Thus, its production depends largely on other countries' policies and demand for ethanol.

In the High Oil Price case, Brazil's ethanol production totals 1.9 million barrels per day in 2035, reflecting higher demand for ethanol both at home and abroad. In the Low Oil Price case, which assumes reduced domestic and international demand for ethanol, Brazil's ethanol production totals 1.1 million barrels per day in 2035. Even in the Low Oil Price case, however, there is only a small drop in Brazil's domestic ethanol consumption, because of the country's mandatory minimum E25 blend and the fact that ethanol makes up nearly 50 percent of the country's domestic gasoline market [49].

The second-largest contributor to future increases in non-OPEC total liquids production is the United States. U.S. conventional liquids production grows from 7.8 million barrels per day in 2008 to 9.9 million barrels per day in 2035 in the Reference case, as rising world oil prices spur both onshore and offshore drilling. In the short term, the vast majority of the increase in crude oil production comes from deepwater offshore fields. Fields that started producing in 2009, or that are expected to start producing in the next few years, include Great White, Norman, Tahiti, Gomez, Cascade, and Chinook. All are in water depths greater than 2,600 feet, and most are in the U.S. Central Gulf of Mexico. Production from those fields, combined with increased production from fields that started producing in 2007 and 2008, contributes to the near-term growth in U.S. offshore production. The reduction in crude oil production resulting from the current moratorium on deepwater drilling in the Gulf of Mexico is estimated to average about 31,000 barrels per day in the fourth quarter of 2010 and about 82,000 barrels per day in 2011, but production levels are expected to recover in the mid-term. Production from other recently discovered and yet-to-be discovered fields offsets production declines in older fields in the projection, resulting in a net increase in liquids production through 2035.

Is Brazil the world's next major oil producer?

In 2007, a consortium led by Petrobras, Brazil's national oil company, discovered the Tupi field in the Santos Basin off the coast of Brazil. The field, now known as a "pre-salt deposit," was found 18,000 feet below the ocean surface underneath a 6,000-foot layer of salt. Tupi and other pre-salt finds hold the potential to make Brazil one of the world's most prolific oil exporters. Although Brazil already produces 2.1 million barrels per day of crude oil and lease condensate, it did not become a net exporter until 2009. In the next decade, Brazil aspires to more than double its conventional production and significantly expand its oil exports.

According to Oil & Gas Journal, Brazil's proven oil reserves are estimated currently at 12.9 billion barrels, not including major pre-salt fields. Estimates of Brazil's pre-salt reserves have varied widely. In 2008, Haroldo Lima, Director General of Brazil's National Petroleum Agency, stated that the country's pre-salt deposits could contain between 50 and 70 billion barrels of oil [50]. More recently, in January 2011, Petrobras announced its assessment that the Tupi and Iracema fields (renamed Lula and Cernambi) contain 6.5 billion and 1.8 billion barrels of commercially recoverable oil, respectively [51]. It will be some time before the Brazil's pre-salt reserves are fully quantified, but knowledge of exact reserve levels is not critical to assessing the viability of Brazil's proposal to expand their production in the coming years.

In its 2010-2014 business plan, Petrobras outlined production targets of 3.0 million barrels per day in 2014 and 4.0 million barrels per day in 2020. In the plan, more than one-quarter of the company's Brazilian production in 2020 comes from pre-salt fields [52]. In the IEO2011 Reference case, Brazil's conventional liquids production increases to 3.3 million barrels per day in 2020 and 4.9 million barrels per day in 2035; and its total liquids supply, including unconventional liquids such as ethanol and biodiesel, increases to 6.6 million barrels per day in 2035. The projections reflect a somewhat more conservative view of the pace of expansion, given the financial, regulatory, and operational challenges that Petrobras will need to overcome in order to realize the full potential of Brazil's pre-salt resources.
Financing the development of pre-salt oil fields will be expensive. One analyst has suggested that Brazil's current undertaking could be "the largest private sector investment program in the history of mankind [53]." The Petrobras business plan includes investments of $224 billion between 2010 and 2014, more than half of which will be spent on exploration and production activities. To facilitate the plan, the company raised $67 billion in the world's largest initial public offering ever in September 2010. However, most of the capital came in the form of a reserves-for-shares swap with the Brazilian government [54]. Petrobras will need to fund the majority of its investments through operating cash flow. The increase in the government's equity points to an expansion of state involvement in the petroleum sector.

The government's capitalization of Petrobras was part of a set of laws passed in 2010 to regulate development of Brazil's pre-salt reserves. The legislation also established a new federal agency (Petrosal) to administer pre-salt production and set up a fund to align the expenditure of pre-salt revenues with Brazil's development goals. Most importantly in terms of Brazil's investment climate, the law changed the country's concession-based system for exploration to a production-sharing agreement (PSA) system. Under the PSA system, Petrobras will hold at least a 30-percent share of each project and be the operator [55]. Some analysts fear that the new system will reduce foreign interest in investing in Brazil and overburden Petrobras. The re-launch of Brazil's latest bid round for oil exploration blocks is scheduled for 2011, pending settlement of a dispute over the distribution of pre-salt royalties among Brazilian states. The results of the bid round will highlight the full impact of the legislative changes on the development of pre-salt resources [56].

Development of pre-salt deposits represents a daunting task, with considerable technological uncertainty about how the geologic formations will behave once production has begun. In addition, the reserves are located more than 150 miles off Brazil's coast, making them difficult for pipelines and people to reach. Petrobras plans to purchase 45 floating production, storage, and offloading (FPSO) vessels to extract the pre-salt oil; however, only 75 such rigs currently exist in the world [57].

In addition to massive investments in physical capital, the planned expansion of Brazil's production will require additional human capital. Petrobras plans to train 243,000 technical professionals to work in the petroleum industry in the coming decade and to invest hundreds of millions of dollars in oil-related research and development centers at Brazilian universities [58]. Given the scale of the task, the predominant role played by Petrobras, and local-content requirements, operational challenges introduce a nontrivial amount of uncertainty into projections of Brazil's liquids production.

Brazil's pre-salt discoveries represent some of the most promising oil finds, and its role as an oil producer will grow in the coming decades. The extent of that expansion is uncertain, however, given the financial, regulatory, and operational challenges involved in such a large-scale undertaking.

U.S. lower 48 onshore production of crude oil continues to grow through 2035, primarily as a result of increased application of EOR techniques. In 2035, EOR accounts for 37 percent of total onshore production in the Reference case. The rate of growth in domestic crude oil production depends largely on assumptions about world oil prices and improvements in technology, because remaining onshore resources typically require more costly secondary or tertiary recovery techniques. On the other hand, if carbon dioxide emissions were captured and sequestered in the future, the availability of relatively plentiful and inexpensive supplies of carbon dioxide could spur additional EOR activities that would make onshore production more economical.

U.S. unconventional liquids production becomes more significant as world oil prices rise, with domestic production of biofuels increasing from 0.7 million barrels per day in 2008 to 2.2 million barrels per day in 2035 in the Reference case. Although advances in coal liquefaction technology have made CTL fuels commercially available in other countries, including South Africa, China, and Germany, the technical and financial risks of building what would be essentially a first-of-a-kind facility in the United States have discouraged significant investment thus far. In addition, the possibility of new legislation aimed at reducing U.S. greenhouse gas emissions creates further uncertainty for future investment in CTL. Similarly, although ongoing improvement in oil shale technology leads to the start of commercial production in 2029 in the Reference case and a rapid increase to 1.1 percent of total U.S. liquids supply in 2035, oil shale development also would have to overcome environmental, technical, and financial uncertainties similar to those for CTL.

Canada's production of conventional liquids declines slowly in the Reference case, by a total of just under 20 thousand barrels per day from 2008 to 2035. However, increased production of unconventional petroleum liquids from oil sands more than offsets the decline in conventional production. As a result, Canada's total liquids production increases from 3.4 million barrels per day in 2008 to 6.6 million barrels per day in 2035.

Russia and Kazakhstan are the other key players in non-OPEC production growth. However, the non-OECD Europe and Eurasia region is prone to territorial disputes, transportation blockages, contractual changes, and political intervention. After declining to 9.0 million barrels per day in 2014, Russia's liquids production begins a slow increase to 11.4 million barrels per day in 2020 in the Reference case, as uncertainty about tax regimes lessens. In addition, annual increases in the world oil price in the IEO2011 Reference case spur liquids development that boosts Russia's production to 13.3 million barrels per day in 2035. Although exploration in eastern Siberia and the Arctic is expected during the projection period, Arctic exploration does not contribute much to production in the Reference case. Across the five IEO2011 scenarios that assume different levels of economic access granted to investors in the long term, Russia's total liquids production in 2035 ranges from 13.3 to 15.3 million barrels per day. In the Low Oil Price case, as access to resources is opened up, production in 2035 totals 14.1 million barrels per day—more than in the Reference case but less than in the Traditional Low Oil Price case, because worldwide demand for liquids is lower.

In Kazakhstan, mid-term growth in liquids production depends predominantly on the resources of the Kashagan and Tengiz oil fields, as well as the ability of investors to transport production from those projects to the world market. Although known and potential resources are sufficient to support the growth of liquids production in Kazakhstan, they could be undermined by a lack of easy export routes. Currently, exports are limited to six routes: the CPC pipeline, Atyrau-Samara pipeline, and railway shipments can transport a total of 0.8 million barrels per day to Russia; another pipeline can move 0.2 million barrels per day to China; and two barge routes allow shipments of about 0.1 million barrels per day to Azerbaijan and Iran.

Kazakhstan's export potential is affected strongly by its geographical position. Attaining the production levels projected in the Reference case depends not only on resource availability and production but also on the construction of export routes—a task requiring regional cooperation that has not been easy to achieve in the past. A number of possible projects to expand Kazakhstan's capacity for liquids exports have been proposed over the past several years. The most likely expansions in the near term are capacity increases in the pipelines to Russia and China [59].

In addition to the problem of transportation capacity, Kazakhstan has previously reopened legal contracts with private foreign investors, forcing renegotiation of investment returns and making companies reluctant to increase their investment in the country's energy sector. Across the five IEO2011 oil price cases (including the Reference case), Kazakhstan's production in 2035 ranges from a low of 3.1 million barrels per day to a high of 3.5 million barrels per day.

OPEC production

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In the IEO2011 Reference case, total liquids production from OPEC nations increases from the 2008 level of 35.6 million barrels per day at an average annual rate of 1.0 percent, resulting in the production of 46.9 million barrels of liquids per day in 2035. Of the total OPEC increase, 11.0 million barrels per day originates in the Middle East (Figure 37).

Throughout the projection period, Saudi Arabia remains the largest liquids producer in OPEC, with total production increasing from 10.7 million barrels per day in 2008 to 15.4 million barrels per day in 2035, as prices stabilize at historically high levels and world consumption continues to grow. Seventeen percent of the increase (0.8 million barrels per day) is expected to be NGPL production related to expansion of natural gas production. The total production increase equates to an average annual growth rate of 1.4 percent, based on the assumption that Saudi Arabia will continue with its current plan to maintain spare production capacity at levels between 1.5 and 2.0 million barrels per day.

Iraq increases its liquids production by 3.7 percent per year in the IEO2011 Reference case, the largest annual average growth in total liquids production among all OPEC members. The projection assumes that political, legislative, logistical, investment, and security uncertainties in Iraq will be resolved in the long term, and that OPEC constraints and resource availability will be the factors with the strongest influence on Iraq's willingness and ability to increase production.

In addition to political and legislative uncertainty, import and export infrastructure also are expected to limit production growth in Iraq to 0.6 million barrels per day from 2008 to 2015. If the country is able to achieve long-term political and economic stability and expand the capacity of import and export routes as projected in the Reference case, investment in production capacity could rise by an average of 4.2 percent per year from 2015 and 2030 before slowing to a more modest 3.0 percent per year from 2030 to 2035. The fact that Iraq has the resources necessary to support such growth in the long run, yet produced only 2.4 million barrels per day in 2008, illustrates the significant impacts that the political environment and other above-ground constraints can have on production projections.

Qatar has the second-highest average annual growth rate in total liquids production among OPEC nations from 2008 to 2035 in the Reference case, at 2.7 percent, with total volumes increasing from 1.2 million barrels per day in 2008 to 2.5 million barrels per day in 2035. About 55 percent of the increase consists of crude oil and lease condensate production; NGPL production contributes another 0.3 million barrels per day; and GTL projects add just over 0.2 million barrels per day. Despite the current negative outlook for many previously announced GTL projects around the world, the return and persistence of historically high oil prices in the Reference case supports the operation of Qatar's Pearl facility (0.1 million barrels per day capacity) and expansion of its Oryx facility (adding another 0.1 million barrels per day).

Total liquids production in Iran is restricted by political rather than resource-related factors in the IEO2011 Reference case. The political factors include the effectiveness of the national oil company's operations, the ability of the government and foreign investors to agree on contractual terms, and continuing financial sanctions. In the Reference case, Iran's oil production declines from 2008 through 2035 because of both financial and political constraints on the development of new oil and natural gas prospects. In addition, the amount of natural gas available for improving oil recovery through natural gas reinjection is limited in the projections by natural gas demand for domestic electric power and heat production. Political factors and investment constraints affect Iran's liquids production so severely that production in 2035 varies by 3.5 million barrels per day across the IEO2011 projections, from 2.7 million barrels per day in the Traditional High Oil Price case to 6.3 million barrels per day in the Traditional Low Oil Price case.

In the OPEC nations of Western Africa, total liquids production increases from 4.2 million barrels per day in 2008 to 5.4 million barrels per day in 2035 in the Reference case. Angola expands production to 2.3 million barrels per day in 2020—almost entirely by increasing crude oil and condensate production from offshore projects—before entering a slow but steady resource-driven decline in the long term. Nigeria's liquids production is likely to be hampered in the short term by conflict and infrastructure difficulties; in the long term, however, a higher level of known resources enables its liquids production to grow by an average of 1.7 percent per year, from 2.2 million barrels per day in 2008 to a total of 3.4 million barrels per day in 2035.

Recent history suggests that Venezuela's national government reacts to high oil prices by tightening the terms for foreign direct investment and limiting access to its reserves. As a result, in the Reference case, with prices rising in real terms through 2035, further mandated changes in contractual terms, along with threats of actions to recapture upside returns from potential investors, are likely to hinder Venezuela's production potential in the short term and discourage investment in and development of additional projects in the long term. The trend is particularly evident in the mature conventional oil basins, with conventional production declining by 0.3 million barrels per day over the projection period from 2008 levels of 2.0 million barrels per day. However, development of several extra-heavy oil projects in the Orinoco belt offsets some of the decline in conventional liquids production.

Ecuador rejoined OPEC in October 2007, after having suspended its membership in 1999. Ecuador is a relatively small oil producer in comparison with other OPEC members, producing 0.5 million barrels of oil per day in 2008. Liquids production in Ecuador declines through 2015 in the Reference case, as uncertainties associated with the country's Hydrocarbons Law make foreign companies reluctant to investment in Ecuador's oil sector [60]. After 2015, although investment in the country's oil sector continues to be hindered by high investment risk, development of its ITT heavy oil field in the Amazon helps to stabilize its production. Consequently, liquids production in Ecuador rebounds to 0.7 million barrels per day in 2025 and remains fairly flat through 2035.

OPEC investment decisions regarding additional new production capacity are the primary difference between the Traditional High and Traditional Low Oil Price cases. In the IEO2011 High and Low Oil Price cases, non-OECD demand is also an important market determinant. In the Low Oil Price case, OPEC production increases to 53.7 million barrels per day in 2035, representing a 47-percent share of total world liquids production. The Low Oil Price case assumes that OPEC members will increase investment either through their own national oil companies or by allowing greater economic access to foreign investors, depending on the country. It also assumes that OPEC members will expand production capacity in an attempt to maximize government revenue through increased production. OPEC production in the Traditional Low Oil Price case increases by 32.4 million barrels per day from 2008 to 2035, to 68.0 million barrels per day or approximately 52 percent of total world liquids production in 2035.

In the High Oil Price case, high demand and high prices encourage development of expensive non-OPEC resources. As a result, OPEC supports only a 37-percent market share of total world liquids production, with a production level of 45.7 million barrels per day in 2035, less than the Reference case level of 46.9 million barrels per day. Alternatively, in the Traditional High Oil Price case, OPEC member countries maintain record high prices by restricting production targets to a smaller share of world total liquids production each year. As a result, OPEC production accounts for 32 percent of the world total in 2035. Production totals 34.8 million barrels per day in 2025, and after 2026 it begins a slight decline to 34.1 million barrels per day in 2035.

Unconventional liquids production

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Unconventional liquids play an increasingly important role in meeting demand for liquid fuels over the course of the IEO2011 projections. In the Reference case, 12 percent of world liquids supply in 2035 comes from unconventional sources, including 1.7 million barrels per day from OPEC and 11.4 million from non-OPEC sources. Although the volume and composition of unconventional production vary across the IEO2011 price cases (from 19.2 million barrels per day in the Traditional High Oil Price case to 10.8 million barrels per day in the Low Oil Price case), the geographic origin of each unconventional liquid type is relatively constant across the cases, usually being limited to countries where projects currently are underway or advertised. Because world oil prices largely determine whether relatively expensive unconventional supplies are developed, there is little difference between the volumes of unconventional resources supplied in the Low Oil Price case and in the Traditional Low Oil Price case. The same is true of the two high oil price cases (Figure 38).

OPEC unconventional production

OPEC's unconventional production consists predominantly of extra-heavy oil production in Venezuela (from the Orinoco belt) and GTL production in Qatar. In the IEO2011 Reference case, Venezuela's extra-heavy oil production rises from 0.7 million barrels per day in 2008 to 1.4 million barrels per day in 2035, and Qatar's GTL production increases from a negligible amount in 2008 to 0.2 million barrels per day in 2035. Although the resources to support production at those levels abound in the two countries, large investments will be required to bring them to market, and the timing of such investment is uncertain.

There are four major projects currently operating in Venezuela's Orinoco belt, but they have been suffering from poor maintenance and lack of investment. Venezuela's ability to increase its extra-heavy oil production will depend on the level of foreign investment and expertise it is able to attract for extraction and upgrading projects. In the Reference case, only two Orinoco belt projects are developed over the course of the projection—Junín 4 (operated by a consortium of Chinese companies) and Junín 6 (operated by a consortium of Russian companies). The two projects add 0.4 million barrels per day of production capacity each.

In the Low Oil Price case, Venezuela improves contract terms and stabilizes its investment climate to attract more foreign investment in the development of Orinoco resources, including Junín 2 and the Carabobo area, which contribute 0.2 and 1.2 million barrels per day, respectively. In addition, several other development projects are undertaken in the long term.

Non-OPEC unconventional production

Outside OPEC, unconventional liquids production comes from a much more diverse group of countries and resource types. As a whole, non-OPEC unconventional liquids production in the IEO2011 Reference case increases by 8.2 million barrels per day, from 3.2 million barrels per day in 2008 to 11.4 million barrels per day in 2035. OECD countries account for 71 percent of total non-OPEC unconventional liquids production in 2035. By volume, the countries making the largest contribution to the increase in non-OPEC unconventional liquids are Canada (an increase of 3.3 million barrels per day), the United States (2.3 million barrels per day), Brazil (1.2 million barrels per day), and China (0.9 million barrels per day).

In each of the five oil price cases, Canada's bitumen (oil sands) production makes up more than 40 percent of total non-OPEC unconventional production, ranging from 3.1 million barrels per day in the Low Oil Price and Traditional Low Oil Price cases to 6.5 million barrels per day in the High Oil Price and Traditional High Oil Price cases. Bitumen production in the two high price cases ramps up quickly in the short to mid-term then begins to slow in the long term, closely following the assumed world oil price path in high price cases. In the low oil price cases, production growth stagnates because the price is too low for new projects to be economical. Over time, however, reductions in the cost of the technology lead to an overall increase in production.

Biofuels production in the Reference case increases from 1.5 million barrels per day in 2008 to 4.7 million barrels per day in 2035, at an average annual growth rate of 4.3 percent. The largest increase in biofuels production over the projection period comes from the United States, where production grows by 1.6 million barrels per day, from 0.7 million barrels per day in 2008 to 2.2 million barrels per day in 2035. The growth in U.S. biofuels production is supported by the Energy Independence and Security Act of 2007, which mandates increased use of biofuels. Strong growth in biofuels consumption is also projected for Brazil, where production grows by 1.2 million barrels per day from 2008 to 2035.

Government policies provide the primary incentive for non-OPEC biofuels production. Biofuels are used as a means to reduce greenhouse gas emissions, promote energy security, and support local economic development. To achieve those goals, many countries set mandates for the amount of biofuels to be used and give tax credits to biofuel producers. The United States, for example, mandates 36 billion gallons of biofuels by 2022 under the Energy Independence and Security Act of 2007. The European Union mandates that biofuels must make up 10 percent of the liquid fuels market by 2020, according to the European Union Biofuels Directive [61]. Canadian producers receive payments or operating grants based on output, and the Chinese government has a flexible subsidy scheme with payments based on plant profitability [62]. The Canadian and Chinese tax credits are designed to expire over time as the cost of production falls and oil prices rise.

Despite the wide range of biofuels incentive programs, some recent studies suggest that biofuels may not be as effective in reducing greenhouse gas emissions as previously thought. As a result, many countries have relaxed or postponed renewal of their mandates. For example, Germany reduced its biofuels quota for 2009 from 6.25 percent to 5.25 percent [63]. The global economic recession has also dampened investment in biofuels development. Consequently, world biofuels production in 2030 is 40 percent lower in the IEO2011 Reference case than was projected in the IEO2009 Reference case and essentially the same as in the IEO2010 Reference case.

In the IEO2011 oil price cases, as in the Reference case, biofuels become more competitive with conventional oil products over time; however, the level of competitiveness depends on the oil price assumption. In the low price cases, only the cheapest and most cost-effective feedstocks and production technologies are competitive with gasoline and diesel fuels. In the high price cases, more feedstocks and production processes are competitive. Total biofuel production in 2035 ranges from 3.5 million barrels per day in the Low Oil Price case to 6.2 million barrels per day in the Traditional High Oil Price case. The growth of biofuel production slows in all cases from 2008 to 2015, as the current generation of crops reach their economic potential, then accelerates after 2016 with the advent of new technologies that use cellulosic feedstocks.

China is the primary CTL producer in all the IEO2011 cases, with 2035 production levels ranging from 0.2 million barrels per day (or 50 percent of the world total) in the two low oil price cases to 2.1 million barrels per day (51 percent of the world total) in the two high oil price cases. Other major producers are the United States and South Africa, which produce about 0.5 and 0.3 million barrels per day, respectively, in the Reference case; 1.6 and 0.3 million barrels per day in the High Oil Price and Traditional High Oil Price cases; and about 0.1 million barrels per day each in the Low Oil Price and Traditional Low Oil Price cases.

The unconventional liquid product that consistently contributes the least to total unconventional production in each of the IEO2011 cases is GTL. In the Reference case and the two low oil price cases, GTL production is limited primarily to Qatar, although South Africa and Nigeria also produce small volumes. In the two high oil price cases, the United States rapidly becomes the world's third-largest GTL producer, accounting for 96 thousand barrels per day of the world's total of 400 thousand barrels per day in 2035.²⁰

World oil reserves

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As of January 1, 2011, proved world oil reserves, as reported by the Oil & Gas Journal,²¹ were estimated at 1,471 billion barrels—115 billion barrels (about 9 percent) higher than the estimate for 2010 [64]. According to the Oil & Gas Journal, 51 percent of the world's proved oil reserves are located in the Middle East (Figure 39). Just under 79 percent of the world's proved reserves are concentrated in eight countries, of which only Canada (with oil sands included) and Russia are not OPEC members (Table 5).

In 2011, the largest increase in proved reserves by far was attributed to Venezuela, as the country now reports its Orinoco belt extra-heavy oil in its totals [65]. As a result, Venezuela's reserves alone increased by 113 billion barrels from 2010 to 2011. Smaller but notable increases were reported for Libya, Uganda, and Ghana. Libya's proved reserves increased by almost 2 billion barrels (4 percent). Uganda, which previously did not report any oil reserves, now claims 1.0 billion barrels. Ghana's recent discoveries of the Jubilee, Tweneboa, and Owo fields, among others, raised its reserves from 15 million barrels in 2010 to 660 million barrels in 2011. The largest decreases in regional reserves were attributed to Europe, including notable declines for Norway, Denmark, and the United Kingdom, which in combination saw a 14-percent decline (1,485 billion barrels) in reserves from 2010 to 2011. Although several OPEC member countries in late 2010 reported large additions to reserves, the Oil & Gas Journal chose not to include the new figures, citing the "politics involved in reserves estimates as they relate to output targets" within OPEC [66].

Country-level estimates of proved reserves from the Oil and Gas Journal are developed from data reported to the U.S. Securities and Exchange Commission (SEC), from foreign government reports, and from international geologic assessments. The estimates are not always updated annually. Proved reserves of crude oil are the estimated quantities that geological and engineering data indicate can be recovered in future years from known reservoirs, assuming existing technology and current economic and operating conditions.

Companies whose stocks are publicly traded on U.S. stock markets are required by the SEC to report their holdings of domestic and international proved reserves, following specific guidelines. In December 2008, the SEC released revisions to its reserves reporting requirements in an attempt to provide investors with a more complete picture of the reserves held by reporting companies, by recognizing the technologies and reserve quantification methods that have evolved over time. Proved reserves include only estimated quantities of crude oil from known reservoirs, and therefore they are only a subset of the entire potential oil resource base. Resource base estimates include estimated quantities of both discovered and undiscovered liquids that have the potential to be classified as reserves at some time in the future. The resource base may include oil that currently is not technically recoverable but could become recoverable in the future as technologies advance.

Readers may notice that, in some cases in the IEO2011 projections, country-level volumes for cumulative production through 2035 exceed the estimates of proved reserves. This does not imply that resources and the physical limits of production have not been considered in the development of production forecasts, or that the projections assume a rapid decline in production immediately after the end of the projection period as reserves are depleted. EIA considers resource availability in all long-term country-level projections, the aggregation of which gives the total world production projection. However, proved reserves are not an appropriate measure for judging total resource availability in the long run. For example, despite continued production, global reserves historically have not declined as new reserves have been added through exploration, discovery, and reserve replacement.

In order to construct realistic and plausible projections for liquids production, and especially for petroleum liquids production, underlying analysis must both consider production beyond the intended end of the projection period and base production projections on the physical realities and limitations of production. The importance of approaching an assessment of liquids production in this way is illustrated by the recent history of U.S. reserve estimates. Whereas the United States reported 22.5 billion barrels of proved reserves in 1998, proved reserves of 20.7 billion barrels were reported in 2010—a decrease of only 1.8 billion barrels despite the cumulative 26.2 billion barrels of liquids supplied from U.S. reserves between 1998 and 2010.

Proved reserves cannot provide an accurate assessment of the physical limits on future production but rather are intended to provide insight as to company- or country- level development plans in the very near term. In fact, because of the particularly rigid requirements for the classification of resources as proved reserves, even the cumulative production levels from individual development projects may exceed initial estimates of proved reserves.

EIA attempts to address the lack of applicability of proved reserves estimates to long-term production projections by developing a production methodology based on the true physical limits of production, initially-in-place volumes, and technologically limited recovery factors. By basing long-term production assessments on resources rather than reserves, EIA is able to present projections that are physically achievable and can be supported beyond the 2035 projection horizon. The realization of such production levels depends on future growth in world demand, taking into consideration such above-ground limitations on production as profitability and specific national regulations, among others.