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In 2017, a group of the world’s largest publicly traded oil and natural gas producers added more hydrocarbons to their resource base than in any year since 2013, according to the annual reports of 83 exploration and production companies. Collectively, these companies added a net 8.2 billion barrels of oil equivalent (BOE) to their proved reserves during 2017, which totaled 277 billion BOE at the end of the year. Exploration and development (E&D) spending in 2017 increased 11% from 2016 levels but remained 47% lower than 2013 levels. Of the 83 companies, 18 held more than 80% of the 277 billion BOE in proved reserves at the end of 2017. Although many of these companies have global operations, some are national oil companies with reserves concentrated in their home countries, including Russia, China, and Brazil. Proved reserves change from year to year because of revisions to existing reserves, extensions and discoveries of new resources, purchases and sales of proved reserves, and production. Organic additions to proved reserves, or reserves added through improved recovery and extensions and discoveries, are linked directly with capital expenditures in E&D. Proved reserves acquired through purchases do not represent E&D capital investment but rather reflect transfers of assets between companies. Revisions to proved reserves are usually more significantly influenced by changes in crude oil and natural gas prices than by E&D investment. Of the 17.7 billion BOE in organic proved reserves added in 2017, slightly less than half (8.5 billion BOE) were in the United States, while Russia, Central Asia, and the Asia-Pacific region accounted for 24% (4.3 billion BOE). Canada (which includes oil sands and synthetic crude oil), Latin America, and the Middle East and Africa regions each added more than 1.1 billion BOE. Regionally, Europe accounted for the fewest organically added proved reserves for the sixth consecutive year, adding 0.3 billion BOE (2% of world total) of proved reserves in 2017. Global E&D spending by region was similarly distributed. Of the $285 billion companies spent on E&D in 2017, 33% ($95 billion) was in the United States, with the Russia, Central Asia, and Asia-Pacific region accounting for 30% ($85 billion) and all other regions each accounting for 10% or less. Changes in nominal year-over-year E&D spending varied across regions, increasing by 36% in the United States and by 15% each in Canada and the Russia, Central Asia, and Asia-Pacific region. Spending declined by 24% in Europe, 16% in the Middle East and Africa, and 15% in Latin America. Because of a disparity between the timing of companies’ capital expenditures and the formal reporting of changes to their proved reserves, standard practice is to average the results over several years. Analyzed this way, E&D costs declined significantly on a per BOE basis from the 2012–2014 average to the 2015–2017 average. Three-year average E&D capital expenditures per BOE of organic proved reserves additions decreased in all regions except Latin America. On an annual basis, 2017 represented the lowest E&D capital expenditures per additional BOE to proved reserves during the 2012–2017 period at $16.12/BOE. First-quarter 2018 capital expenditures for this set of companies were 16% higher than in first-quarter 2017, suggesting that many of these companies have increased their E&D budgets, which will likely contribute to further organic proved reserves additions in 2018.

While most fossil fuels in the United States are burned, or combusted, to produce heat and power, EIA estimates that the equivalent of about 5.5 quadrillion British thermal units of fossil fuels were consumed for non-combustion purposes in the United States in 2017. Over the past decade, non-combustion consumption of fossil fuels has typically accounted for about 7% of total fossil fuel consumption and about 6% of total energy consumption in the United States. Fossil fuels can be consumed, but not combusted, when they are used directly as construction materials, chemical feedstocks, lubricants, solvents, waxes, and other products. Common examples include petroleum products used in plastics, natural gas used in fertilizers, and coal tars used in skin treatment products. In 2017, about 13% of total petroleum products consumed were for non-combustion use. Natural gas non-combustion use accounted for about 3% of total natural gas, while coal was less than 1%. In 2017, carbon dioxide (CO2) emissions would have been 196 million metric tons (about 4%) higher if non-combustion fuel use would have been combusted. Estimation of fossil fuels for non-combustion consumption is essential to calculate total U.S. carbon dioxide emissions. In the non-combustion use of these fuels, some (but not all) of the carbon is sequestered and not included in the fuel consumption values for emissions calculations.

Petroleum products account for about 86% of non-combustion consumption. Hydrocarbon gas liquids (HGL) such as ethane, ethylene, butane, butylene, isobutane, isobutylene, propylene, and natural gasoline and petrochemical feedstocks such as naphthas are important components for making plastics. HGL are used as intermediate products, while petrochemical feedstocks are used directly at chemical plants. Other petrochemical feedstocks are used to make synthetic fabrics, such as Kevlar, synthetic rubbers, detergents, and other chemical products. Many other petroleum products are consumed for non-combustion uses other than plastics. Asphalt and road oils are used for roofing and paving construction. Lubricants, which include motor oil and greases, are used in vehicles, machinery, and various industrial processes. Petroleum coke is used as a chemical catalyst, while special naphthas are used in petroleum-based paints. Other petroleum products include distillate and residual fuel oils used as chemical feedstocks as well as polishes and waxes. Relatively small amounts of natural gas are consumed for non-combustion use in the industrial sector. Natural gas is used as feedstock to make nitrogenous fertilizers and a range of chemical products including ammonia, hydrogen, and methanol. Only small amounts of coal are used for non-combustion purposes in the industrial sector. Among the byproducts of the process to produce metallurgical coke are coal tars, which are rich in aromatic hydrocarbons, such as benzene, and are used as feedstocks in the chemical industry to make sealcoats for pavement, synthetic dyes, and paints. Some anti-dandruff shampoos and other medical skin care products contain coal tars. Monthly and annual estimates of non-combustion consumption of fossil fuels are available in both physical units and energy units (British thermal units) in Tables 1.11a and 1.11b of EIA’s Monthly Energy Review.

EIA projects that trends in coal production in the United States could range from flat to continuing declines through 2040. Electric power generation accounts for more than 92% of U.S. coal demand, and domestic coal production has declined significantly over the past decade as coal has been displaced by natural gas and renewables in electric generation. EIA’s Annual Energy Outlook 2017 (AEO2017) includes cases with alternative assumptions about U.S. environmental policy and levels of oil and natural gas resource development and technological advancement. Across these cases, the outlook for coal can vary considerably based on its relative economics compared with natural gas and renewables in the power sector. The AEO2017 also presented a version of the Reference case without the effects of the Clean Power Plan (No CPP case). After the release of AEO2017, EIA developed an additional case without the Clean Power Plan under High Oil and Gas Resource and Technology assumptions. The AEO2017 Reference case, which is designed to apply all current laws and regulations (including the CPP), forecasts U.S. coal production declining from 740 million short tons (MMst) in 2016 to 620 MMst in 2040. By 2040, U.S. coal production drops to roughly half the level of peak coal production reached by the United States in 2008. Coal generation and production are significantly higher in the No CPP case, which otherwise applies the Reference case resource and technology assumptions, as the existing fleet of coal-fired generators can be more fully utilized and fewer coal-fired generators are retired. As a result, in the No CPP case, coal production stabilizes at about 900 MMst from 2025 through 2040. The adoption of High Oil and Gas Resource and Technology assumptions, which reflect a more optimistic outlook for natural gas supply—assuming lower natural gas prices compared with baseline resource and technology assumptions—lowers projected coal use. In the High Oil and Gas Resource and Technology case with the CPP, EIA forecasts that coal production declines to 500 MMst in 2040 as natural gas-fired generation outcompetes coal-fired generation in all years. As shown by the smaller difference between the solid and dotted lines in the right-hand panel of the generation graphic than in the left-hand panel, the CPP is projected to have a smaller effect on coal-fired generation under high resource and technology assumptions than under Reference case resource and technology assumptions. Under the high resource assumptions, natural gas prices are considerably lower, making natural gas more likely to displace coal regardless of whether or not the CPP takes effect. These projections are also helpful in assessing the separate impacts of lower natural gas prices and the implementation of the CPP on coal-fired generation. Projected coal-fired generation under Reference Case resource assumptions with the CPP (solid line in left-hand panel) is quite close to its level under High Resource and Technology assumptions without the CPP (dotted line in right-hand panel), indicating that lower natural gas prices could result in a similar reduction in coal use as the reduction due to the emission constraints of the CPP. In the High Oil and Gas Resource and Technology case without the CPP, natural gas and renewable generation remain similar to the case with the Clean Power Plan. However, because electricity prices are lower, total electricity generation is higher in the High Oil and Gas Resource and Technology case without the CPP, and most of this increase is provided by coal-fired generation. Nuclear generation is also somewhat lower in this case through 2040, as the absence of the Clean Power Plan moves more coal into the lower-cost segment of the dispatch order. Market-clearing dispatch prices, which are already held down by low natural gas prices, fall even lower, leading to some additional retirements of nuclear power plants. To the extent that operators decide not to retire additional nuclear capacity, the higher amount of coal generation that occurs in the absence of the CPP would be partially offset by reductions in natural gas and renewable generation, as occurs in the absence of the CPP under Reference case resource assumptions. In the Reference case, about 96 gigawatts (GW) of the existing fleet of 265 GW of coal-fired electric generating capacity in 2016 is projected to retire or convert to natural gas by 2040, very close to the 93 GW of coal-fired capacity projected to retire or convert under high resources and technology assumptions without the CPP. Projected retirements or conversions of coal-fired capacity are higher, about 124 GW, in the High Oil and Gas Resource and Technology case that includes the CPP, and lowest in the No CPP case, where most occur prior to 2025. In the Low Oil and Gas Resource case, shown in the middle panel of the generation graphic, oil and natural gas development is projected to be slower as higher development costs result in higher natural gas prices to the power sector. Natural gas generation is displaced by a combination of increased zero-emission generation from renewables and nuclear as well as coal-fired electricity generation, which remains near or slightly higher than its 2016 level. In this case, coal production remains near 800 MMst from 2025 through 2040. Few coal-fired power plants have been added in recent years, and in all of the AEO2017 cases, no new coal-fired generating capacity is added. In all cases, annual coal production remains below the 1,000 MMst level last seen in 2014. Detailed production data by year, region, and coal type are available through the Annual Energy Outlook 2017 Interactive Table Viewer.