U.S. Energy: Present State and Future Perspective Elwyn Roberts, PhD. MBA; Visiting Professor, USC Abstract Adequate energy supply to the United States is vital to the economic well being of every citizen. This paper outlines the relationship between energy supply, energy use and climate change. In particular, increasing dependence on energy imports, and consequent threats to security of supply, from the 1970’s onwards, is highlighted. A path forward is presented for energy security and energy sustainability in the US while at the same time mitigating the impact of energy use on climate change. It is suggested that a national policy on energy be developed requiring unprecedented commitment. 1 Contents Executive Summary and Recommendations p3 Introduction and Background p6 Energy security Energy Sustainability p8 p11 Fuel Supply and Demand p11 Introduction p11 Coal p11 Petroleum (Oil) p12 Natural gas p14 Alternative transportation fuel p16 Fuel Cells p22 Overview p22 Alternative cells for transportation p25 Effect of Energy Use on Climate Change p30 Background p30 Power generation p34 Transportation p40 Summary and Discussion p47 Table 1: Example of Possible LDV On‐road Portfolio in 2035 and Fuel Resources Required p54 Table 2: Resources and CO2 emissions from possible on‐road fleet portfolio in 2050 p58 Table 3: Feed‐stock and Generating Capacity Requirements for FCEV’s and PEV’s in 2050 p60 2 Executive Summary and Recommendations Energy is the life blood of modern economies and the United States has been in the forefront of developing energy, and using it in all its forms, for more than a century. Energy, powers our factories, heats our homes, mobilizes our transportation, and generates our electricity. Without the useful harnessing of this energy, life would be no different today from that of our ancestors a few centuries ago. The United States uses more energy per capita, than any developed country in the world. Such energy use is strongly related to the quality of life and national wealth as measured by Gross Domestic Product. Despite adequate natural resources and matching technical skills, however, the United States has become increasingly dependent on imported oil during the last few decades. This dependency has an adverse effect on the economy and adds more than one half a trillion dollars per year to the trade deficit. Additionally, because of political instability in the some oil producing regions, and increasing demand from developing countries, considerable uncertainty exists with the future supply and price of imported oil. The time is opportune to reverse this trend. With the recent technology breakthroughs for recovering natural gas from shale deposits and oil from deep off‐shore locations, together with the vast natural resources of coal, the United States has the ability to become energy independent in one to two decades. The recent surge in renewable power generation and US leadership in nuclear power further strengthens this opportunity. In pursuit of this goal, the United States must also be mindful of its international obligations to control the emission of Green House Gases and to ultimately limit their release to no more than 17% of the 2005 level by the year 2050. Achieving this additional goal will be considerably more difficult than achieving energy independence. One major consequence will be to shift the burden of energy production from the petroleum industry to the electric power 3 generating sector where carbon, the major constituent of GHG’s, can be more readily captured. To achieve the goals of sustainable energy and energy security, while mitigating climate change, the major areas (as highlighted in this paper) will need to be addressed over the next few decades: • Most conventional internal combustion engine power trains for transportation will need to be phased out over the next two decades and replaced with electric motor drives that are up to three times more efficient in fuel consumption. Fuel cells and re‐chargeable batteries should be developed to replace the internal combustion engine as the main source of power by 2035. • High energy intensity batteries demonstrating at least 2 kilowatt hours per pound weight will need to be developed for commercialization over the next decade; this will result in a power to weight ratio comparable to that of a gasoline fueled vehicle. • Fuel cells need to be developed to their full potential by 2020 and be capable of operating on both liquid and gaseous fuels. Processes for capturing Green House Gas emissions from fuel cells using hydrocarbon fuels need to be developed and implemented in the next ten years. • Importing crude oil can be phased out over the next one to two decades. This will increase the US economy by $500B/annum and assure energy independence and security of supply. • Production of domestic natural gas to liquid (NGTL) and coal to liquid (CTL) fuels for transportation should replace all imported oil by 2030. Oil usage by 2050 should decrease to less than 50% of current domestic production. • Development of commercial processes for producing ethanol(eq), or alternative advanced liquid bio‐fuels, from cellulosic feed‐stock will need increased emphasis. High priority should be given to producing a minimum of 21 billion gallons of advanced cellulosic liquid fuel by 2035 and 36 billion gallons by 2050. • The technology for carbon capture and sequestration (CCS) will need to be developed sufficiently to assure safe, reliable operation for hundreds of years. Commercialization of CCS processes needs to be introduced by 2020. By 2050, up to 2,000 MMT of CO2 will need to be captured from 4 •
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the power generation and chemical industries and permanently sequestered every year. The chemical and refining industries should plan on producing by 2050 over 20 million metric tons of hydrogen per annum (using coal, natural gas and bio‐mass as feedstock) or the equivalent in liquid fuels specifically designed for fuel cell operation. All GHG emissions will need to be captured. Conventional coal fired power generating plants will need to be phased out of service by 2020. From this time onwards, all new fossil fuel plants—coal and natural gas—will need carbon capture and sequestration capability and older coal fired plants will need to be retro‐
fitted. Non‐hydro renewable power generation will need to be implemented at a faster pace than presently planned. By 2050 the installed capacity of non‐hydro renewable power must be 450 GWe. Concurrent with the building of new renewable power units, the US grid needs to be upgraded to address energy storage and maintain stability due to large power surges from intermittent power supplies. New nuclear power plants need to be constructed at a considerably greater pace than at present. From 2020 onwards, up to four new 1000 MWe nuclear plants per year need to be brought on line. By 2050, nuclear capacity needs to be more than twice the present level. To assure that these goals for energy usage and GHG mitigation are met, and that focus is maintained, it is recommended that a National Energy Policy be developed and appropriate legislation be defined. The policy should detail a pathway to assure success in a timely manner; it should also provide for suitable back‐up strategies in the event that unforeseen developments prevent progress. Carbon sequestration and growth of low carbon power generation capacity are regarded as being the most uncertain. To assure the investment of trillions of dollars from the private sector for large capital facilities, power grid and gas line upgrades, and thousands of miles of high pressure piping for carbon dioxide sequestration, appropriate government incentives must be offered. Because of its complexity, the Energy Policy should assure coordination between the major industries; additionally it is imperative that the public should be kept informed and involved. Success of this plan will depend heavily on public acceptance of the desired outcome. 5 Introduction and Background Energy use in the United States US is approximately 100 quadrillion BTU’s (Quads) per annum. (According to US Government reports, actual energy consumption was 98.16 Quads in 2011) On a per capita basis such use is the highest in the world (except for oil rich countries). Most of the energy used comes from carbonaceous fuel formed in the ground by vegetation which has decayed over millions of years—so called fossil fuel; coal, oil (petroleum) and natural gas. These three sources of energy A BTU is the quantity of heat required to raise the constitute approximately 84% of energy use in the United temperature of 1lb of water by 10F. I Quad is 1015 BTU States today, Figure 1. Petroleum (oil) is the most versatile fossil fuel because it has high energy density per unit volume and it is liquid at ambient temperatures which makes it highly portable. It can also be distilled into a variety of liquid fuels, for different applications, as illustrated in Figure 2. Of all of the products derived from oil, 46% is gasoline, primarily for light duty vehicles. Coal, while also possessing high energy density, is solid and is used primarily in stationary devices for electric power generation (although it was used extensively in the recent past in heavy locomotives and ships to generate steam).Natural gas has low energy density but is readily transportable through pipelines; it is also used primarily in stationary devices for heat and power as well as for chemical feed‐stocks. Figure 3 provides a summary of the principal supply of, and demand for, energy in the United States. Note that petroleum products constitute 94% of the energy used in transportation fuels (27 quadrillion BTU’s); natural gas contribution to transportation at the present time is only 3%. Later In this paper, this deficiency will be addressed and alternatives will be suggested. Note also that the demand sources column in Figure 3 relates to the quantity of energy used, not the actual energy produced or consumed. For electrical energy, 38.6 Quads of energy was consumed in power generation, while only 13.65 Quads (~4,000 6 Terawatt hours, TWh) of electrical energy was actually generated, the difference being due to energy losses in generation and transmission) A Terawatt is 1012 watts
A watt is the power created by a current of 1 amp dropping across an electrical potential of 1 volt.
The supply and use of energy has been the subject of much debate in recent years. First, and perhaps most importantly, there is the question of energy security. Will fuel be available when it is needed? Will the price of fuel remain stable? This is a major concern for countries which do not have a significant indigenous energy supply. Second, since these fuels are in limited supply, (they can only be used once), there has been for many years the long standing question of sustainability. Will the fuel be available for use by future generations? Finally, there is the issue of environmental impact, particularly climate change, which has received increasing global attention in recent years. Energy, extracted from fossil fuels, results in the formation of carbon dioxide which is a major contributor to global warming through the greenhouse effect. The greenhouse effect is due to infra­
All three of these issues are interdependent and none red rays from the sun being reflected and absorbed by various gases in the is clearly separated. Nonetheless, in this paper, an attempt earth’s atmosphere thus restricting is made to separate them and highlight specific issues in their escape back into space. each area in attempt to maintain clarity. Thus the first Without such a phenomenon, the earth would be 59F cooler. section addresses energy security. The second and largest section addresses energy sustainability. This section is further subdivided into two major areas. The first of these subsections reviews the current state of supply and demand for fuel. The second subsection focuses on developments of alternative fuels for transportation, since this is a field of great uncertainty and future change, and on fuel cells for both stationary and mobile applications. The third section builds on the prior two sections and addresses the issue of climate change and how this will likely affect future energy use. In conclusion, the report attempts to integrate these major topics and present a path for the future of energy supply and use in the United States. 7 Energy Security Energy security is a major concern for many industrial economies and developing countries. The United States is a world leader in fossil fuel energy supply and demand. The United States has the largest coal reserves in the world and has the greatest output, producing approximately 1.1 trillion tons in 2010. It is the third largest producer of oil, following Saudi Arabia and Russia, as shown in Figure 4. It is marginally the top producer of natural gas, closely followed by Russia, Figures 5. The United States is also the lead country in the world for nuclear power, as is illustrated in Figure 6, and has now become one of the lead countries for wind power, second only to China. Until recent decades, the United States produced enough primary energy to match consumption. This is demonstrated in Figure 7 which illustrates the production and use of energy in the US over the past 60 years. Through the middle of the last century, the growth of consumption, which had risen to approximately 40 quadrillion BTU’s (quads) per annum by 1960, was matched by the growth of domestic production. In the 1960’s however, consumption increased rapidly, and from 1970 onwards, when consumption had increased to a total of 65 quads per annum, consumption started to progressively outpace growth. As is evident from Figure 7, by the turn of the century the total energy consumed in the United States had risen to a little under 100 quads/annum, while domestic production remained relatively flat at approximately 71 quads per annum. Thus, from 1960 to the turn of the century, the United States had gone from being a country which was self sufficient in energy to a country that imported roughly 30% of the energy it consumed. Even though the total energy produced in the United States grew slightly after 1980, energy production in various segments varied considerably. This is illustrated in Figure 8. As evident from this figure, from 1980 to 2010 the annual output of coal and nuclear increased by a total of 10‐12 quads/year while non‐
8 hydro renewable energy grew by about 3 quads/year. Although production of natural gas initially declined from the mid‐ 1980’s onwards natural gas production increased slightly so that by the turn of the century natural gas output was close to that of 1980, about 20 quads/year.(19 trillion cubic feet). This is further illustrated in Figure 9. Note in Figure 9 however, that natural gas consumption exceeded production from 1985 onwards so that by the turn of the century the short fall in annual production was approximately 4 quads per year. Projections as recently as the year 2007 suggested that this difference was anticipated to increase further. Recent technology improvements, however, are now reversing this trend as will be discussed later. Most of this deficit in production was accommodated by importing natural gas (via pipelines) from Canada. Presently Canadian natural gas contributes roughly 15% of the natural gas consumed in the United States. Since 1970 the greatest fall off in domestic energy production was in the crude oil sector. This is further illustrated in Figure 10 which shows over‐all crude oil usage and oil source. Figure 10 shows that domestic crude oil production in the US declined by 44% over the period 1970‐2010. Over the same time frame, crude oil consumption increased by approximately 60%. A summary of the import/domestic production history for all liquid fuels, including non‐petroleum derived fuels, is illustrated in OPEC ­­ the Organization of Figure 11. Details of the sources of liquid fuels, and Petroleum Exporting Countries—is made up of 12 future projections, are provided in Figure 12. Note from countries that hold 79% of the Figure 11 that from 1970 to 2005, the total quantity of world’s crude oil reserves liquid fuel imported into the US, mainly from OPEC countries, has more than tripled. In the past several years, however, this margin has improved slightly, due to the combined effects of reduced demand from the 2009 recession and increased domestic production. Over the past several years the quantity of imported liquid fuels has fallen from a peak of 60% of consumption in 2005 to slightly less than one half at the present time. By the year 2035 the margin is expected to be further reduced to 36% due to improved knowledge of domestic reserves and better technology. 9 The relationship between energy imports and total energy usage is illustrated in Figure 13. The difference between US energy consumption and domestic production, which was reduced to approximately 20 quads in 2010, is due almost exclusively to liquid fuels, with only a small fraction from natural gas imports which are mainly from Canada. Over the next fifteen years, this difference in total energy usage is expected to be halved. None‐the‐less, the US is projected to still depend heavily on imported oil by 2035. Energy security in the US, particularly security of supply of oil (petroleum products) for transportation, is thus a major issue. To compound this situation oil has become a major global commodity in contrast to other energy products such as natural gas, since it is readily transported across the oceans. This is illustrated in Figure 14 which shows how oil prices have both increased and fluctuated widely during the past 40 years primarily due to unstable events in the Middle‐
east and increased competition from emerging markets. Such oil price shocks have a major adverse effect on the US economy as illustrated in Figure 15. Over the past decade, crude oil prices have quadrupled. China, as a prime example of an emerging market, shows a rate of growth in oil demand that will more than quadruple in the first quarter of this century. Over the same time frame oil consumption in the United States is expected to decrease. Since the known reserves of oil in China are very small, the growth in oil consumption will actually exceed that of domestic production by more than 200%. Globally, the International Energy Agency (IEA) predicts that during the first quarter of this century oil consumption will increase by approximately 40% and to accommodate this increase, most of the supply will come from OPEC countries. Thus, continued US dependency on oil imports constitutes a serious threat to the security of energy supply for the future. 10 Energy Sustainability Fuel Supply and Demand Introduction From about 1980 onwards there has been considerable effort to address energy sustainability, primarily through exploration of renewable fuels. In its broadest sense, energy sustainability relates to the obligations and commitment of the current generation of mankind to provide adequate energy resources, or alternatives, for future generations. As is evident in Figure 1, approximately 7% of total energy use in the United States at the present time is renewable; hydro‐
power and bio‐mass are the greatest contributors. Over the next 20 years, renewable fuels are expected to roughly double, as shown in Figure 8. Wind power, solar power and bio‐mass will likely be the major contributors to electric power generation, while bio‐fuels will be a contributor to the transportation sector. Nuclear power, used exclusively for electric power generation, will likely not grow sufficiently fast with Business as Usual (BAU) to make a major impact for several decades, though in principle, nuclear power could at least double, given appropriate investment and favorable regulatory response. The Electric Power Research Institute (EPRI) believes that nuclear power could contribute a third of the energy to the electric power sector by 2050 (see next section of this paper). Thus, for the foreseeable future, fossil fuels will still be a major source of energy in all economic sectors in the United States. Because of their importance, fossil fuels will be discussed in more detail in the following sections of this paper. Coal 1 US ton is 2,240 lb. 1 metric ton, 1MT, is 106 grams=2202.6 lb. Coal energy has been the work horse of the United States for many years. For the last thirty years coal has generated more than 40% of the US electric power and it is forecast to be a major contributor for the foreseeable 11 future. Coal reserves in the United States are the largest in the world, constituting approximately 25% of the world’s reserves at approximately 500 billion tons. In a 2007 recommendation to the US Secretary of Energy, the National Coal Council (NCC) indicated that if required, the US coal industry 1 barrel = 42 US could more than double production output by 2025, to a total 2.5 gallons billion tons/year, and maintain that level of output for more than 100 years. Additionally, the NCC advised the Secretary that the coal industry could provide enough feed stock to produce 2.6 million barrels/day (MMBD) liquid fuels and 4 trillion cubic feet of gas a year (equivalent to the amount of Canadian imported natural gas). This proposal (taken from the NCC report) is summarized in Figure 16. Adequate reserves of coal exist to maintain this level of output in the US for several generations. In recent years concern has been increasing at global government levels regarding the impact of combusting fossil fuel to extract energy. During combustion, carbon oxidizes to carbon dioxide, a gas with adverse green house gas (GHG) effects. Coal is the worst fossil fuel offender for carbon dioxide emissions since it is almost pure carbon. Oil and natural gas, which are hydrocarbons, also emit carbon dioxide during combustion but to a slightly lesser extent for a given release of energy. As a consequence of this rising concern for GHGs, government regulations are evolving requiring the capture of carbon dioxide from stationary devices, such as power stations and chemical processing plants, which will substantially increase the cost of energy generation from fossil fuels. While the effect of GHG emissions will be discussed later in this paper, it is important to note here that the impact of these regulations will likely limit new uses for coal in the United States for at least the next ten years, despite the assured sustainability of supply for decades. For the short term, natural gas will likely replace coal in new power generating stations. Petroleum Petroleum derivatives—gasoline and diesel‐‐are used almost exclusively, not only in the United States, but throughout the world, as the fuel of choice for transportation. Over the past decade, vehicular traffic has almost doubled such 12 that today roughly more than one billion vehicles are in use globally. This growth in transportation is projected to increase considerably over the next half century as peoples of the world strive to increase their quality of life. Petroleum (oil) is the dominant form of energy usage in the United States. Approximately 36% of our energy comes from petroleum, as shown in Figure 1. At the present time, 94% of US transport is dependent on petroleum, Figure 3. With current laws for mileage improvement, but recognizing population growth, the US DOE‐Energy Information Administration (EIA) estimates that between 2009 and 2035, total transportation fuel usage will increase by approximately 23% as shown in Figure 17. Almost one half of this increase, 1 million barrels per day (MMBD), will be due to increased heavy duty truck use, as shown in further detail in Figure 18. Demand for light duty vehicles is projected to increase by 1.3 MMBD By the year 2035, with current laws specifying improvements in consumption and assuming the improvement in domestic liquid fuels production, as illustrated in Figures 10 and 11, the total quantity of liquid fuel which must be imported will fall below 40% of total, ie to approximately 7.4 MMPD. A recent study by the National Petroleum Council provides a detailed report on oil resources in North America (Both United States and Canada). The state of the art for recovery of conventional oil deposits (ie liquid oil) and unconventional oil (ie not naturally occurring liquid) is discussed. The report indicates that current domestic (North America) oil production rates over the next 20‐30 years can probably be maintained. Such production will depend heavily on US off‐shore (conventional) resources, estimated at between 40‐100 billion barrels and Canadian oil sands (unconventional) estimated between 150‐300 billion barrels. The report emphasizes that economic recovery of oil from these resources will require cooperation of federal regulators (eg relaxation of off‐shore moratorium) or US production will decline. Thus, some uncertainty exists in the sustainability assumptions for liquid fuels. Figure 18 highlights high potential sources of North American oil (US plus Canada) for the near and intermediate term while Figure 19 illustrates the production potential. Note that by the year 2035 a substantial fraction of 13 projected oil production assumes the successful economic recovery of oil from unconventional sources. Recovery of oil from these non‐conventional resources will require significant development. Thus, the sustainability of US domestic production of liquid fuels is very tenuous. The NPC report concludes that US energy independence in the liquid fuels sector is not realistic in the foreseeable future. Natural Gas At the turn of the twentieth century, US domestic natural gas was thought to be limited supply. Figure 21, taken from an IEA report as recently as 2008, illustrates that the US reserves known at the time would last a little over ten years at current rates of production. By contrast, reserves in the Middle East were expected last at least 200 years. In the US between the years 2000 and 2005, the annual domestic production rate of natural gas fell by 1‐2 trillion cubic feet a year below estimated levels and the well head price more than doubled. To compensate for the short‐fall, extensive plans were developed for importing liquid natural gas (LNG). As is evident from Figure Natural gas becomes 22, (which was published by the EIA 2007 Annual Energy liquid at ­1620C and a pressure of 3 bars. The Outlook), it was estimated that by the year 2030, approximately liquid occupies 1/600th 6.5 trillion cubic feet a year of natural gas would have to be of the volume of the gas. imported into the US, mainly in the form of LNG. By 2004, approximately 1 billion cubic feet of LNG was being imported into the US, and several new terminal facilities were planned to increase import capacity beyond 1.6 trillion cubic feet per annum, as illustrated in Figure 23. By 2008, some 13 LNG import facilities were operational in the US, six more were under construction and 19 more were approved. Most of these new facilities are unlikely to be built, however. Due to vast improvements in horizontal drilling techniques, and a technique known as hydraulic fracturing, as first demonstrated at the Barnett “plays” in Texas and now being applied to newly established shale deposits in the United States, LNG imports fell to 9% of available capacity in 2008. Domestic production of natural gas from shale “plays” meanwhile had increased enormously. By the year 2010 14 shale plays were contributing 23% of total production, as illustrated in Figure 24. Because of the new technology, shale “plays” are now projected to contribute almost one half of total NG production, which is projected to be some 27.9 trillion cubic feet by the year 2035. The importance of horizontal drilling, along with other technological improvisation such as hydraulic fracturing, has vastly improved the prospects for a sustainable natural gas supply. In a 2011 MIT report it was concluded that given adequate financial resources, and appropriate federal regulations, current demand rates at current well head prices can be met for at least the next quarter century. (Note that prices are at the lowest on record this decade) This is illustrated in Figure 25. For the “High Resource Technology Case”, the range of technically recoverable natural gas is determined to be between 1,900 and 3,600 trillion cubic feet, which is roughly 25% of the global natural gas resources. Assuming current rates of demand are maintained, sufficient domestic natural gas exists to satisfy US requirements for many decades. This is illustrated in Figure 26 taken from a 2011 National Petroleum Council (NPC) publication (entitled “Prudent Development”). This latter publication also indicates that after the year 2020, this supply of natural gas can be maintained exclusively from on‐
shore resources, 60% of which would come from shale, Figure 27. The NPC report also examines the effect of increased demand for natural gas over a several year time frame. The effect of a 50% increase in demand over a nine year interval is illustrated in Figure 28. The figure illustrates that even with this increased demand, sufficient natural gas resources exist for a few decades, after which other sources, such as off‐shore or LNG would be Conversions: required. Figure 29 shows that most of this increased 1 metric ton of coal = 2.78x107 BTU domestic supply would come from shale “plays”. 1 barrel oil = 5.5x106 BTU 1 cu ft NG = 1,020 BTU With these recent projections of the potential for increased natural gas supply by 2025, it is worthy of note that the energy content of the incremental capability is roughly equal to 80% of the energy of imported liquid oil (16.33 Quads) estimated for that year. Thus, if domestic natural gas was used to replace imported liquid fuels, the US 15 could be energy independent, at least for a few decades until alternatives were developed. Alternative Transportation Fuel Over the past decade, vehicular traffic has almost doubled such that today roughly more than one billion vehicles are in use globally. This growth in transportation is projected to increase considerably over the next half century as peoples of the world strive to increase their quality of life. The global population, which exceeded the six billion mark at the turn of the century, is projected to exceed ten billion by the year 2050. Consequently, global demand for petroleum will continue to grow exponentially, threatening both security of supply and sustainability to the US for the foreseeable future. To reduce the demand in the US for petroleum, several initiatives are underway, primarily addressing the efficiency of fuel use. Note that while substantial effort has been invested in new technologies, such as fuel cells and hybrid vehicle designs, the National Petroleum Council, in their recent report on Future Transportation Fuels, stated that the internal combustion engine (ICE) will likely be the principal means of powering vehicles for the foreseeable future. Figure 30 illustrates major energy losses in vehicles. For the short term, the US DOE EERE has developed industry partnerships addressing improvement in the efficiency of ICE vehicles through strategies such as engine downsizing, using variable compression ratios, lean fuel burning technology etc. A 25% improvement in the efficiency of ICE LDV’s is targeted for 2014. The approach of several strategies is illustrated in Figure 31. To further reduce the US dependency on petroleum products, increased use of alternative fuels is also targeted. Alternative fuels for ICE vehicles will therefore be the focus of this section of the paper. To be successful, transportation fuel must have high energy density, be easily contained and be readily portable. A number of likely candidates are 16 summarized in Figure 32. All of these alternative fuels emit less GHG than gasoline or diesel. Unfortunately, all have lower energy intensity than the petroleum product they replace (gasoline or diesel). Important on‐board characteristics are also summarized in Figure 32. The preferred candidates to replace gasoline in spark ignition engines are low pressure gas (LPG) –propane, butane—natural gas (NG), methanol, ethanol and hydrogen. Biodiesel and dimethyl ether (DME) are the preferred candidates to replace diesel in compression ignition engines. With the recent discovery of vast shale natural gas deposits, and new recovery techniques, NG, LPG’s, DME and methanol, (since it can be readily processed from natural gas) assume increased importance, at least for the near future. Of these, considerable attention is being given to the possibility of using natural gas in the transportation sector. Approximately 11 million natural gas vehicles are used in the world, especially in Pakistan, Iran, and South America. Most vehicles that use natural gas are bi‐fuel design (can use NG or gasoline), and use natural gas compressed (CNG) to about 3,600 psi. Because of the low energy density of natural gas, the tank size limits the range of vehicles to about one quarter of gasoline powered vehicles for the same tank size. The last two columns of Figure 32 provide a comparison of tank size and tank mass required in order to receive the same mileage range as a conventional gasoline powered vehicle with a 15 gallon tank. For compressed natural gas, the tank size would have to be 360% larger than a gasoline tank to yield the same mileage range. For liquid hydrogen, the volume would be larger than that of a LNG tank. In the US, Honda is the only manufacturer of CNG vehicles and produces a modified Civic design. The vehicles are prohibitively expensive however, and modifications to existing gasoline powered vehicles cost several thousand dollars. Tax credits may provide some relief in the future as Bills have been introduced in the both the US House of Representatives and the Senate to address alternative fuel credit. A new bill to address credit for all fuels—so called Open Fuel Standard—is also being considered. A recent analysis by MIT of cost tradeoffs for vehicle modifications is illustrated in Figure 33. As one example, the figure shows that for a gasoline 17 T
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vehicle averaging 30 mpg, and traveling 12,000 miles a year, a $3,000 investment would be paid off in five years, assuming a $1.50 gallon of gas equivalent (gge) savings for CNG over the price of gasoline; this is a reasonable assumption recognizing current well head NG prices of less than $4 per 1000 cubic foot and gasoline prices of about $3.50/gallon. To improve the range vehicles can travel between refueling stops the use of LNG over CNG is preferred. The relative benefit of LNG over CNG is illustrated in Figure 32, previously discussed. For LNG the fuel tank mass and volume is only 80% larger than that of a conventional gasoline vehicle, while for CNG the tank volume and mass would have to be quadrupled. However, for LNG auxiliary equipment is required to maintain cryogenic temperatures, and for this reason LNG becomes impracticable for use with LDV’s. LNG requires a temperature of ‐162C and a pressure of 3 bars to remain liquid, and requires a double walled tank to provide the necessary insulation. For large trucks, however, which require frequent refueling, weight (and boiling off) is not an issue and there is mounting interest for LNG in the trucking industry. Recently, diesel engine manufacturer Cummins started building LNG engines and truck manufacturers Peterbilt and Navistar have started manufacturing long distance heavy vehicles fueled by LNG. Recent estimates by the Natural Gas vehicle industry indicate that at current LNG prices the incremental cost for LNG vehicles will be recovered in less than a year of highway travel. Such a change requires a corresponding change to the refueling infrastructure along interstate highways. To accommodate this requirement, Clean Energy Corporation has announced plans to develop over the next few years a $450 million network for providing LNG refueling facilities at major interstate routes across the United States, as shown in Figure 34. Having such an infrastructure is key to the success of using LNG in the long‐haul trucking industry. Because of the recent success with new shale plays, adequate reserves exist to fuel the entire trucking industry with natural gas. The National Petroleum Council concludes that if all HDV’s on the interstate were fuelled with natural gas, an increased production of 16 billion cubic feet/day would be required. As noted 18 earlier, Figure 28, this production output could be readily achieved over a 5‐10 year period. Of the alternative liquid fuels being considered, methanol (and DME to replace diesel) possesses very attractive properties as a transportation fuel for LDV’s, as illustrated in Figure 32. It has a high octane value which translates to efficient combustion. Its major detractor is that it has only one half of the energy content of gasoline per unit volume, and requires an onboard storage tank roughly double that required for gasoline. Methanol can be made from cellulose bio‐feed stocks such as solid waste, wood, corn stover and switch grass, and fossil feed stocks such as coal and natural gas. With the recent well head prices for natural gas, and current projected reserves, methanol is a potential alternative to gasoline. In a recent MIT White Paper, methanol was selected as being the fuel of choice of liquid fuels derived from natural gas, as illustrated in Figure 35. As illustrated in Figure 36, based on current (and projected) natural gas prices, methanol can be produced in the US at very attractive prices, with roughly $1 saving per gallon of gas equivalent (gge). Adequate supplies of natural gas apparently exist to provide feedstock for methanol, and replace gasoline, in the US for several decades. Cellulosic waste can also be used. The MIT paper recommends that future Flex Fuel Vehicles be designed to operate on methanol. According to a 2010 MIT report on methanol, considerable experience exists with using methanol as a transportation fuel in the US. In the 1990’s, approximately 21,000 flex fuel production vehicles (FFV) capable of being fueled with either M85 methanol, or gasoline, were operating in the US, mostly in California. Some 200 million miles of excellent performance was accumulated. The vehicles performed better or equal to their counterpart on all‐gasoline vehicle models. The program waned early in the new millennium, however, not because of operational difficulties, but because of low priced readily available gasoline, and lack of interest in developing the necessary infrastructure. Ethanol became the oxygenated fuel of choice over the past decade, primarily because of ease of processing corn by fermentation (in contrast to thermo‐chemical 19 processing of wood chips for methanol), and consequent carbon neutrality status for GHG emissions. This preference for ethanol occurred despite the strong advocacy of George Olah, the Nobel Laureate, for methanol over ethanol. Note however, that methanol is still the preferred fuel of choice for high powered vehicles such as race cars. Methanol, blended with gasoline, is more popular than ethanol in several countries, in particular China. The government of China has declared this preference because of concern for diverting food (cereal) as a feedstock for fuel. Blending standards for M15 and M85 methanol have been developed and automobile manufacturers are tooling up to make methanol fueled vehicles in China. Most of the methanol in China is made from coal and new chemical refineries are under construction. Similarly, several European countries, particularly in Scandinavia where wood forests abound, have shown considerable interest in building chemical facilities for methanol production from cellulosic feed stock. Hydrogen is also an alternative fuel that has received great attention over the past decade, particularly from the US Department of Energy, the European Union and Japan. On‐board characteristics of hydrogen are given in Figure 32. Note that as a liquid, hydrogen requires a massive tank, with cryogenic capability to maintain a temperature of ‐253C and a pressure of 5 bars. The volume of the tank would need to be approximately four times larger than that of a gasoline tank and up to two times heavier. For practical reasons, hydrogen on board storage for LDV’s is presently limited to the gaseous form at a pressure of 10,000 psi, and a tank size roughly double that of a gasoline tank. The Hydrogen Initiative was announced early in the Bush administration, in 2002, with the FreedomCAR project. The long term emphasis was on fuel cell vehicles with hydrogen as the primary transportation fuel. Hydrogen is unlikely to be used in ICE vehicles, but for completeness, hydrogen production will be discussed in this section of the paper. Hydrogen exists in abundance in nature but is mainly chemically bound with oxygen (water), carbon (hydrocarbons) or with both carbon and oxygen (carbohydrates) and can only be produced in its pure 20 form through either electrolysis or thermo‐chemical reforming, both of which require additional energy. Figure 37 illustrates the most likely feed‐stocks for hydrogen production. In the initial announcement of the Hydrogen Economy, it was proposed that much of this extra energy for hydrogen reforming could come from a new nuclear power initiative, as illustrated in Figure 38. It was proposed that by building next generation high temperature gas cooled nuclear reactors, the process heat could be used to thermally break down complex hydrocarbons, and thus produce a carbon free transportation fuel. As is illustrated in the figure, a 75% growth of nuclear power, over current levels, would be sufficient to replace 25% of gasoline use, and thus contribute to US energy independence. This proposal for high temperature reactors, however, is essentially on hold and the approach has been replaced for the short term by using more proven technologies, such as natural gas steam reforming at modest temperatures. Figure 39 illustrates the process flow proposed for converting natural gas to hydrogen at distributed sites. This is the approach in the US being advocated by the US‐DOE; however, note that in a recent publication, the National Petroleum Council (NPC) considers the central production of hydrogen (at refineries) to be the most viable. Note the substantial energy losses in the steam reforming and subsequent compression processes highlighted in Figure 39. The approximate break down of cost contributors is illustrated in Figure 40 and Figure 41illustrates the current status of distributed hydrogen production costs as determined from ongoing DOE sponsored programs. Comparing the production costs for hydrogen in Figure 41 with the cost of methanol in Figure 36, it is interesting to note that the cost of hydrogen, on an energy equivalent basis, is three to four times greater than that of methanol. To summarize, of the alternative transportation fuels examined Note that at the for ICE vehicles, liquid natural gas appears a viable option for heavy present time Shell is building a large $6B long distance trucks and this approach is gaining momentum. GTL plant in Qatar However, DME is probably a better candidate for such vehicles but this does not appear to be under consideration, probably because significant investment would be required for a large Gas‐to‐Liquids (GTL) plant. Compressed natural gas is an alternative for LDV’s but the cost appears to be prohibitive. A better and more attractive alternative for LDV’s is methanol. This 21 should be actively pursued; however, note that in the recent NPC report on Future Transportation Fuels, liquid fuels from natural gas did not come under serious consideration. Ethanol is also a suitable alternative fuel, but production of corn based ethanol is limited to 15 billion gallons a year until cellulosic technology is fully developed. The use of ethanol will be discussed in more detail in later sections of this report since by 2050 ethanol may be produced in sufficient quantities to contribute up to one third of the US liquid fuel supply. Hydrogen does not appear to be a viable alternative fuel for ICE vehicles based on cost and refueling range considerations. Hydrogen will be discussed in more detail in the fuel cell section of this report. Fuel Cells Overview Fuel cells were discovered in 1839 by William Grove but their value has not been appreciated until recent years. Fuel cells have considerable potential for reducing fuel usage and thus increasing energy security and energy sustainability. A fuel cell is similar to an electric battery cell except it does not run out of power so long as fuel is constantly supplied. A simple schematic diagram of a fuel cell is illustrated in Figure 42. The fuel cell converts the electrochemical energy in the fuel into electrical energy. The cell consists of two electrodes—an anode and a cathode—separated by an electrolyte. Fuel is fed continually to the anode and the oxidant is fed continually to the cathode. The electrolyte conducts the ions between the cathode and the anode, while a separate conduit completes the circuit and permits movement of electrons carrying the energy released. Heat engines, such as internal combustion engines, convert heat into work, and thus are limited in efficiency of output as described by the second law of thermodynamics. Fuel cells however, have no such limit, since the energy released is purely electro‐chemical. Thus, fuel cells can be more efficient than internal combustion engines. An example of the efficiency of a fuel cell for automotive transmission is illustrated in Figure 43. Note from this figure, the overall efficiency in the fuel cell vehicle is double that of the combustion engine vehicle. Through effective development and application of fuel cells, therefore, 22 T
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the security and sustainability of energy supply in the United States can be considerable enhanced. Fuel cells can use a variety of fuels and have a large number of applications as illustrated in Figure 44. Several types of fuel cells are presently in use as illustrated in Figure 45. A brief description of each type follows. Using the nomenclature given in the first column of Figure 45, in the PEFC and PAFC, hydrogen cations are formed at the anode, which then diffuse through the electrolyte to combine with the oxidant at the cathode. Electrons generated at the anode travel through a separate conduit to the cathode forming an electric current to complete the electro‐ chemical process. The PEFC normally operates at temperatures below 100C while the PAFC operates around 200C. In the SOFC, the AFC and the MCFC, the oxidant ionizes at the cathode and the anion diffuses through the electrolyte to combine with hydrogen, or other reducing species (eg CO) at the anode. Note that the SOFC normally operates over the temperature range 600‐1,000C while the MCFC and AFC operate at lower temperatures. In the PEFC and the PAFC the exhaust gas, the product of the electro‐chemical reaction, is ejected at the cathode while in the SOFC, the MCFC and the AFC the exhaust gas is ejected at the anode. All of the fuel cells can use both the same fuel and the same oxidant. However, for the PEFC, the PAFC and AFC, if the fuel contains hydrogen in combined form, for example as a hydrocarbon (eg natural gas), the fuel must first go through a chemical breakdown known as “reforming” to create the pure hydrogen needed at the anode. For the SOFC and PAFC no such reforming is necessary since the temperatures are sufficient for internal auto‐reforming to occur. An exception to the PEFC, not requiring hydrogen reforming, is the DMFC, the Direct Methanol Fuel Cell, which uses methanol as the fuel. In this fuel cell, a special anode allows the hydrogen in the methanol to be extracted directly without a separate reformer. This fuel cell has excellent application in providing electrical backup power to portable electronic devices such as note book computers used in remote locations. Toshiba manufactures such a device under 23 the trade name Dynario. In this design, the fuel cell maintains the charge on a small Li ion battery so that power is always available. DMFC’s are also becoming popular as on‐board charging systems for material handling equipment (MHE). A total of 75 OorjaPac 1.5kw DMFC systems installed on material handling equipment are presently being monitored by DOE through the American Recovery and Reinvestment Act (ARRA) program. Results to date are very encouraging and show considerable increase in productivity due to doubling of the run time between service outages and the potential for increased battery life. The benefits are summarized in Figure 46. For stationary power generation, the most dominant fuels are either natural gas, syngas produced from coal, or methane produced from bio‐
degradation. Stationary fuel cells range in size from less than a kilo‐watt to several mega‐watts. An excellent example of micro‐fuel cell application is provided by the Tokyo Electric Company which started a program of providing combined heat and power (CHP) to several thousand small homes and apartments in Japan using either LPG (propane) or “town” (methane) gas. The gas passes through a reformer to produce hydrogen which in turn provides 750 watts of electric power from a fuel cell. Waste heat from the reformer also provides hot water for domestic use. In the US large PAFC fuel cells are being used for CHP in many stationary applications, such as providing back up power to industry or providing power to large facilities such as supermarkets. An example of the UTC PureCell Model 400, a 400 kw unit powered by natural gas which provides CHP at a total efficiency of 90%, is illustrated in Figure 47. Clearly, considerable potential exists for this type of application, with considerable fuel savings, in the future. For the central stationary generation of electric power, the US DOE, in cooperation with the coal industry and the electrical supply industry, has been conducting extensive research and development over the past decade on large solid oxide fuel cells under the Solid State Energy Conversion Alliance (SECA) program. The intent of the program is to develop large fuel cells, which can operate at efficiencies around 60%, to generate electricity from syngas‐‐mainly hydrogen, methane and carbon monoxide—derived from coal, without a separate reformer. Syngas is the same fuel as is used in the modern Integrated Gas Combined Cycle (IGCC) coal fired power station. One additional goal of the SECA 24 program is to use considerably less water than current technology, thus making the fuel cell attractive for areas prone to draught. It is intended that large scale fuel cells, generating 600 MW of power, will be commercially available from the year 2020 onward. A schematic diagram of a solid oxide powered generating station is illustrated in Figure 48. Projected costs, in proportion to standard coal IGCC combustion process, are illustrated in Figure 49. Note that in this figure, the efficiency of the Integrated Gas Fuel Cell is projected to be approaching 60% compared to 30% for the modern IGCC coal fired unit. Note also that the levelized cost of electricity from the SOFC (which includes capital cost amortization) is projected to be only two thirds of the cost from the IGCC reference plant. Progress against these SECA goals appears to be on target, with a 5 MW full scale module demonstration scheduled for the year 2015. Full scale commercial application is expected by the year 2020. Many smaller SOFC systems already in use either for distributed or auxiliary power. One notable example is illustrated in Figure 50. This figure illustrates Wärtsilä’s WFC20 (20 kw) fuel cell unit which in 2010 was installed onboard the ’Undine’ ship, a car carrier, owned by Swedish Wallenius Lines. The SOFC is powered by methanol which is readily available at Note that the electric motor is approximately three times more most docks. The system is proving to be very efficient with efficient in energy use than a minimum emissions. Recently, Wärtsilä entered into a gasoline combustion engine. partnership with Vesta, a US company that manufactures planar solid oxide fuel cells. Alternative cells for transportation In the late 1990’s, major US automobile manufacturers, with support from the US government, undertook extensive effort to develop more efficient power trains for vehicles. At the same time Toyota and Honda introduced a modified transmission design for LDV’s whereby the internal combustion engine provided energy to a battery which in turn drove an electric motor that propelled the vehicle. This design is known as the hybrid electric vehicle (HEV). Subsequent upgrades to this concept over the past decade are the plug‐in hybrid vehicle (PHEV) and the all‐electric battery vehicle (BEV). Early in 2002, the Bush administration announced the FreedomCAR as described earlier, which was mainly focused on fuel cell vehicles (FCV’s). In 2009 the name 25 of the program was changed to U.S. DRIVE (Driving Research and Innovation for Vehicle efficiency and Energy sustainability) and the direction was modified to provide an extensive portfolio of advanced automotive and energy infrastructure technologies, including batteries and electric‐drive components, advanced combustion engines, and lightweight materials, in addition to hydrogen and fuel cell technologies. In recent years billions of US dollars have been committed, either in loan guarantees or in grants, to assure the success of these vehicles. Electric vehicles which can be charged from the US power grid, so called “plug‐in‐vehicles” (PEV’s) are now being marketed by most automobile manufacturers. Figure 51 illustrates the present state of commercial offerings. The Chevy Volt, a PHEV, has been demonstrated to travel 40 miles on a single battery charge. The all electric (BEV) Nissan Leaf can travel 70 miles at highway speeds on a single charge. This vehicle is powered by a 80 kwatt electric motor powered by a 24 KWh lithium ion battery. These vehicle designs are intended to reduce the consumption of petroleum and thus contribute to energy sustainability. The detractors for these vehicles are the mileage range per charge, the battery energy density (weight), the vehicle cost, (particularly the battery), and the time required for recharging. These limitations are expected to decrease significantly in the coming years. Considerable effort is underway with PEV’s to develop suitable recharging systems. Three systems are currently favored: the L1 which uses 120v ac mains voltage; the L2, which uses 240v ac mains voltage, and a high voltage 450v direct current (DC) system which requires special dedicated stand alone equipment. All three systems require vehicle on‐board receiving equipment with built in safety protection. A chart showing charging times for all three systems, recently calculated by EPRI and published by the NPC in the 2012 report on “Future Transportation Fuels”, is illustrated in Figure 52. The figure shows that for the PEV 40, (PEV with 40 mile range) such as the Chevy Volt, a fully discharged battery will require 6 and 11 hours re‐charging time with a L1 home system. For an L2 system, more likely for an office or commercial building, the re‐charging time can be reduced to less than 4 hours. With a high power DC system, (for example located at a shopping center), the charging time can be reduced to under one hour. Figure 53, taken from a recent EPRI article, shows a DC ultra‐rapid charge system being tested with a Nissan Leaf; this system, if proven successful, could reduce the charging time to minutes. 26 In anticipation of future demand for PEV’s the Electric Power Research Institute (EPRI) has estimated the effect PEV’s would have on the demand of the power grid. This is illustrated in Figure 54 for several PHEV designs (assumed battery ranges from 10 to 40 miles on a single charge). The figure assumes the average vehicle mileage is 12, 000 miles per annum. For the PHEV 40 design, which is similar to the Chevy volt being marketed today, EPRI estimates that the average annual power demand in 2050 would increase by 2,024 kwhrs per vehicle. Note that in the calculations, EPRI has estimated that the mileage for the standard hybrid vehicle (HEV), such as the Toyota Prius, will be 46 mpg, while the conventional gasoline LDV will be 30 mpg. and that the efficiency of the electric motor is 255 whrs/mile for all three PEV vehicles Thus, given these mileage assumptions, if 150 million vehicles of the PHEV 40 design (approximately 50% of total LDV’s in the US) were operating in the year 2050, the extra energy demand of the power grid would be approximately 300 TWh, or ~7.5% of the total projected load. More recent calculations by EPRI, based upon on‐road experience with the Plug‐in Toyota Prius (PHEV10), the Chevy Volt (PHEV40) and Nissan Leaf (BEV 100), have revised these estimates upward somewhat. For the PHEV 10, the revised electrical efficiency is 290 wh/mile, for the Chevy Volt (PHEV 40) the efficiency is 360 wh/mile and for the Nissan Leaf (BEV100) the efficiency is 340 wh/mile. Even with these revised numbers, however, the impact on the power grid is relatively modest as is illustrated in Note for carbon free Figure 55 for a mix of PEV’s. For the year 2050, assuming one power, this demand is equivalent to 72% of half of the vehicles on the road are PEV’s, EPRI estimates that present day nuclear the maximum impact will be an 18% increase in power capacity
demand. That is, for given the maximum impact, installed electrical generating capacity will need to be increased by about 190GWe. If all vehicles are charged at off‐peak times, however, the impact can be reduced to a mere 2% of capacity, or ~22GWe, as is evident in the figure. In reality, for 100 million PEV’s on the highway,(roughly one third) it would be reasonable to assume that the most likely impact will be about a 10% increase in total capacity. The ultimate success of the PHEV, or the BEV, will depend on batteries being developed with higher energy densities so that vehicles can travel greater 27 distances between recharging without the burden of extra weight. According to a recent Pew article, the energy density of gasoline is about 13 KWh per kg compared to current lithium‐ion batteries of approximately 200 Wh per kg. That is, gasoline presently has an energy density ratio advantage of 65:1 over lithium –
ion batteries. Significant development effort is underway, however, to reduce this ratio, the most promising apparently being a lithium metal‐air battery. This new battery design appear to have the potential of increasing the energy density to approximately 4 KWh per kg, which is a considerable improvement on presently available batteries. Thus, when such batteries become available, the potential for reducing vehicle weight will be very significant and considerable improvements in vehicle design will result. For the FreedomCar, the DOE goal is to develop by 2017 a (PEM) fuel cell system in a power pack of 80KW net output, such that the manufacturing cost is not greater than $30/KW(roughly In 2000, Daimler­Chrysler equivalent to the cost of ICE power system). Additionally, the successfully demonstrated system must have a demonstrated endurance of at least 5,000 the methanol fueled Necar hours of uninterrupted operation. Major DOE goals and status are 5 FCV. The vehicle carried five passengers, had an illustrated in Figure 56. To date, fuel cell production cost average range of 312 estimates appear to be on target, with a current level of $49/KW miles, and a top speed of demonstrated, as illustrated in Figure 57. 94mpg on a trans US continental trip The fuel cell is intended to operate on pure hydrogen stored onboard the vehicle. Several approaches for containment have been considered, including liquid hydrogen, metal hydrides and carbon adsorption devices such as nano‐tubes. Methanol has also been considered as a hydrogen carrier. On a volume basis, methanol contains 40% more hydrogen than liquid hydrogen and is considerably safer. For the immediate future, use of a large fiberglass tank, capable of sustaining a pressure of 10,000 psi to contain the hydrogen, is preferred in the US. To provide the same range between refueling stops as a gasoline powered vehicle, however, LDV’s fueled by hydrogen at this pressure will require a fuel tank approximately 2.5 times that of a gasoline tank. To accommodate the large volume requirements of the fuel cell and storage tank, a platform design of the power train is necessary. The overall layout of a GM FCEV, showing high pressure fuel tanks positioned longitudinally along a “skate board” chassis, is illustrated in Figure 58. Several prototypes of LDV’s and HDV’s (buses) are already operating and the US DOE is in process of collecting 28 operational experience. Figure 59 provides examples of several vehicles at refueling stations. Many obstacles remain with this approach however, not‐the‐least acceptance by the public since the initial costs will be extremely high. Many fuel suppliers are also expressing concern for the high cost of capital investment that will be required to develop a suitable infrastructure. It is not clear how the costs will be shared between the US government, fuel suppliers and the consuming public. In Japan, a consortium has been formed to enable deployment of 100 hydrogen stations by 2015 and 1,000 stations by 2025. Japan plans to have 2 million FCEVs operating by 2025. The Federal Republic of Germany has a similar program. However, recognizing the volume design constraints of the fuel tank, and the relatively small number of refueling stations currently planned, the initial market for new vehicles must necessarily be confined to a small mileage range and thus will probably be limited to fleet vehicles such as taxis etc. In this context, a recently published DOE report indicates that for local transportation in large cities, where infrastructure for refueling poses no difficulties, fuel cell powered buses appear to be performing well and are gaining popularity. Zero emission from these vehicles is considered to be a significant advantage in high population zones. DOE reports that the fuel economy in city FCEV’s has reached a level of 7.4 mpg (DGE), which is close to the target of 8 mpg(DGE). Recognizing the extreme competition between the different technologies—
improved ICE vehicles, HEV’s, PHEV’s, BEV’s, FCEV’s etc—it is likely that only a few of the technology options will emerge as being most accepted by the public. Figure 60, from a recent Pew article, references the results of a study recently undertaken by MIT. This figure illustrates that moderate size ICE vehicles –turbo spark ignition gasoline engines and advanced diesel engines—are expected to have sufficiently improved efficiencies by 2035 that approximately 50mpg will be achieved. Hybrid electric vehicles and plug‐in hybrid vehicles are expected to achieve 76 mpg and 102mpg respectively. By comparison, the FCEV is expected to achieve 107 miles on one gallon of gas equivalent energy in the form of hydrogen. The preference for internal combustion engines over hydrogen fuel cells by the American public is further emphasized in the 2012 NPC report on “Future Transportation Fuels”. In this report some 2,988 case studies of different fuel types and transmission power trains were undertaken for LDV’s which have the 29 potential to achieve wide scale commercial production by 2050. A major conclusion of this very detailed analysis, illustrated in Figure 61, shows that more than 80% of vehicles on the road in 2050 will have internal combustion engines (ICE), some of which will be in combination with electric power from batteries (HEV, PEV). Less than 10% of the vehicles are projected to be powered by fuel cells (FCEV’s). Thus, according to the NPC study, fuel for LDV’s is projected to be dominated by liquid fuels (oil or bio‐fuels), as illustrated in Figure 62, and estimated to be in the range of 45‐65% of the total. ICE vehicles operating on compressed natural gas (CNG) are projected to be in the next highest category and use somewhere between 20 and 40% of the total fuel energy. Effect of Energy Use on Climate Change Background For more than two decades concern has been mounting over increasing levels of green house gases (GHG’s) in the atmosphere and their impact on unacceptable global warming. Figure 63 summarizes the global warming potential of several important gases (normalized to a 100 year period) relative to carbon dioxide. Note that fluorocarbons have extremely high potential relative to carbon dioxide. None‐the‐less, the major concern is for carbon dioxide, the product of energy release from combusting 1000 MMT of CO2 occupies a volume of 18 trillion cubic feet at carbon with oxygen, because of the large volumes normal temperature and pressure. created. Figure 64 illustrates the CO2 emitted from each This compares to the volume of of the main three fossil fuels: coal, fuel oil and natural natural gas produced annually in the US, which in 2010 was 21 gas. Coal (anthracite) emits the most CO2 per unit of trillion cuft energy output, some 103.1 MMT/Quad. Fuel oil, being a high hydrocarbon emits approximately 70.9% of the this CO2 for the same energy output, while natural gas, which is almost pure methane, emits approximately 51.5% of the CO2 level. Carbon dioxide in the atmosphere dissociates very slowly (ie over 100 years) and as its concentration increases in the atmosphere, infra‐red rays from the sun are increasingly reflected back to earth causing a greenhouse effect. Although some controversy still exists, there is general agreement by the United 30 Nations Committee on Climate Change (UNCCC) that most of the rise in carbon dioxide level in the atmosphere is anthropogenic. Figure 65 shows the global rise of GHG emissions, normalized to carbon dioxide equivalent values, discharged to the atmosphere, from various sources of human activity, over the past four decades. Note that roughly 57% of the total emission is due to carbon dioxide from the combustion of fossil fuels, while the remainder is due to other gases such as methane (from decaying forests), etc. Note also, the high CO2 (eq) value from nitrous oxide, emitted from fertilizer use in agriculture, which has been progressively increasing in recent years due to the expansion of the use of bio‐
fuels. In 2011 the global annual total emission of carbon dioxide from the combustion of fossil fuels was approximately 30,000 MMT. Of this total, the United States contributed 5,634 Million Metric NOAA recently reported tons (MMTs), approximately 22%, as illustrated in Figure 66. In that the average temperature for the this figure, note the fall off in emissions due to the US recession contiguous US in 2012 was in 2008‐2009. The figure also projects the expected emissions 3.3oF above the 20th through 2035 given no further change in US policies and century average and 1oF practices ie Business As Usual (BAU). The relative contribution above the previous hottest year of 1998 of major economic sectors to the total US GHG emissions is illustrated in Figure 67; note that 74% of the emissions are due to the power generation and transportation sectors. The change in carbon dioxide concentrations in the atmosphere are illustrated in Figure 68. For more than 800 million years prior to the industrial age the concentration was close to 280 ppm. In the past few decades, however, the levels have increased sharply and are just under 400 ppm today. The correlation between global atmospheric temperature rise and carbon dioxide levels in the atmosphere is illustrated in Figure 69. Over the past few decades the rate of change of temperature appears to be accelerating at roughly the same rate as the change in GHG emissions. In the US, NOAA reports that the average annual temperature has increased by 1.50F since 1895, 80% of the temperature rise having occurred since 1980. 31 The UNCCC concludes that if no changes are made in the future in the way industrial and developing nations use fossil fuels, ie BAU, global temperatures might increase by as much as 60C (~110 F) by the year 2100. While this temperature increase might seem small in absolute terms, it is estimated that such a change will cause ice caps to melt, sea levels to rise, glaciers to disappear, lands to suffer draught, permafrost to melt, species to disappear and many nations to experience famine. Figure 70 illustrates the relationship between global temperature change and projected effects on the eco‐system and food supply. In general, there is global agreement in principle that in order to prevent catastrophe, carbon dioxide emissions must be cut drastically in the future. There is, however, no universal agreement on how this will be achieved. The Kyoto accord, sponsored by the United Nations, was signed by many countries in December 1997. This protocol was aimed at reducing greenhouse gas emissions for each of the affected countries in the periods 2008‐2012 to an average of 5% below the 1990 levels. Most of the OECD countries were signatories and agreed to the mandated reductions; developing countries, however, in particular China, India and Brazil were not given mandates. The United States agreed initially to the Kyoto accord: however, it failed to be ratified by the US congress, even though it was tentatively agreed to by the executive branch of the US government. In more recent years there has been considerable effort by the UNCCC to reach international agreement on continued efforts for GHG abatement after the Kyoto agreement expires in 2012. At the recent contentious United Nations meeting on Climate Control in Copenhagen in December 2010, agreement was sought to limit GHG emissions such that the global temperature rise would peak at 20C by the year 2050. To achieve this, the IEA estimated that the concentration of carbon dioxide in the atmosphere must be limited to 450 ppm. With no change in government policies throughout the world (BAU), carbon dioxide emissions are predicted to reach 550 ppm by 2050 and eventually rise to approximately 750 ppm a hundred years later thus resulting in unacceptable temperature rise. 32 To respond to this goal the United States administration tentatively agreed to a specific revised level of domestic GHG reduction. It was proposed that the US would reduce GHG emissions by 17% of the 2005 level by 2020 and 83% of the 2005 level by the year 2050. However, note that this proposal has yet to be approved fully by congress; also, note the proposed reductions fall short of the levels originally agreed to in the Kyoto accord. The proposed reductions are dramatically illustrated in Figure 71. Note how the CO2 emissions in the US have increased from near zero 150 years ago to near 6,000 MMT per annum today. As is evident in the figure, with the new proposals, the US would need to reduce energy related emissions six‐fold over the next forty years. The magnitude of this task increases exponentially when it is realized that the population continues to increase from the present day number of near 300 million to an estimated 420 million over the same time frame. Despite no legally binding US federal policy for GHG abatement, progress has been made in several areas. Figure 72 illustrates the improvement in emission intensity, as a function of population and GDP growth over recent decades and projected for the future. Separately, several attempts have been made to assure improvement through legislation. The Waxman‐Markey Bill H.R.2454 entitled “The American Clean Energy and Security Act”, introduced in 2009, attempts to introduce legislation to regulate emission of GHG’s through market based mechanisms, efficiency programs and economic incentives. The Bill mainly addresses the electric power generating industry and requires that GHG emissions be reduced by 17% by the year 2020 and 83% by 2050. The Bill, passed by the House in June 2009, introduces a “Cap and Trade” policy, similar to the European Trading Scheme (ETS) that places a cap on the price of carbon emissions. A comparable policy for controlling sulfur and nitrous oxide emissions in the US power generation industry has worked successfully in the US since 1970. As illustrated in Figure 73, sulfur dioxide and nitrous oxide emissions have decreased progressively over a 40 year period despite a more than doubling of coal fired power generated. Projections of results from enforcement of the Waxman‐Markey Bill are illustrated in Figure 74. Note that CO2 reductions in the power generation sector 33 are projected to be reduced by approximately 1,300 MMT (a 56% reduction from 2010 levels) by 2030, and the price of CO2 emissions has risen from zero at the start of the enforcement to $65 per metric ton over this time period. The bill has little effect on projected vehicle emissions. Despite the house bill, however, a sister bill in the Senate, introduced by Senators Lieberman and Kerry, entitled the “American Power Act” has been stalled in Committee for several years and has not yet made it to the Congressional Note the state of California recently increased their Calendar. Thus, the US has no legal binding requirement for goals to 30% renewable carbon emission reductions at the present time, although power generation by the some technical progress is being made. year 2020 Power generation In the absence of clear legislation for reducing GHG emissions, many states have taken their own initiative to reduce GHG’s in the electric power industry. As illustrated in Figure 75, through a renewable portfolio standard (RPS), many states have placed a requirement that renewable energy (essentially zero carbon or carbon neutral resources) must play a major role in new power generation in the near future. To this end, remarkable progress has been made, as illustrated in Figure 76. Of these renewable sources, wind power has grown the most rapidly to date. With the recent government issue of permits for seventeen solar energy zones on federal lands in the western states, however, potential now exists for the growth of an additional 2.3 GW of solar power in the future. Solar power and wind power are expected to grow henceforth at roughly the same rate. In 2010, renewable energy contributed 10% of total power generated; by 2035 (with current rules) it is expected to grow to 16% of the total. In addition to the individual state RPS’, such progress has been facilitated considerably by Federal policies such as the Federal Production Tax Credit (PTC) and Federal loan guarantees. As is evident from the figure, from 2009 to 2035, the growth of non‐
hydro renewable power generation is projected to triple. Note however, that the use of renewable power such as wind and solar creates many challenges to the electric grid because of the intermittent nature of power supply. To address this 34 issue, as well as address increasing load fluctuations due to changing demand, considerable effort is underway to provide power stability to the grid through innovations such as electric energy storage and smart grid controls. In the absence of Federal regulations the EPA have declared that CO2 emissions fall within the province of the Clean Air Act, and as such, responsibility for regulation falls within the EPA charter. Though not directly related to CO2 emissions, recent clean air standards developed by the EPA for pollutants other than CO2 will have significant impact on the coal power industry. Figure 77 illustrates the impact of new regulations for SO2, NOx, Hg, coal residuals and water use on generating capacity over the next decade; more than 90% of the coal fired electric power fleet totaling hundreds of giga‐watts is affected. EPRI estimates that with some flexibility on behalf of the EPA, and technological innovations, 288 GW of capacity can be readily retrofitted, as illustrated in Figure 78 while 25 GW of current capacity will be retired and 4GW may be refitted to provide for alternate fuel (eg biomass). The cost to the consumer for these changes are estimated to be in the vicinity of $100 billion, which will increase the retail price of electricity by up to 8% in 2015 and an additional 6% by 2020. Separately the EPA has proposed a standard for CO2 emissions of 1000 pounds per MWh (450 gm/kwhr) of energy generated; this new standard is presently under review. This effectively means that no new coal plant will be able to meet the requirement. Figure 79 provides a list provided by EPRI of CO2 output by plant type. The new combined cycle natural gas power plants (NGCC) will just meet this new requirement, however, so all new fossil fuel plants –except those presently under construction‐‐will be exclusively natural gas units for at least the next decade. As is evident from Figure 80, the total carbon dioxide emission for the new high temperature combined cycle natural gas plant is projected to be 1024 pounds per megawatt hour of electricity generated compared to almost 2,000 pounds for the new super‐critical pulverized coal fired unit. Because of these actions by the EPA, and the recent successes in the economic recovery of natural gas from shale “plays”, as discussed earlier, utilities are cancelling existing orders for new coal fired plants, and replacing them with 35 U
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natural gas units. As a result, approximately 60% of new generating capacity expected by 2035 is now projected to be fueled by natural gas, as illustrated in Figure 81. Note that in Figure 81 the projected capacity increase in non‐hydro renewable power generation is roughly one half that of natural gas. The total energy output (TWh) generated from new renewable power, however, will be much less than that generated from natural gas units because of capacity factor differences. Wind power, for example will have capacity factors around 30% while NGCC plants will have capacity factors more than double this level. While this move by the electric power industry to increase the capacity of natural gas units appears reasonable, it is appropriate to reflect on the possible risk this entails. In the past, the price of natural gas has been highly variable, as is illustrated in Figure 82. The price has only stabilized over the past few years because of the successful extraction of natural gas from shale deposits. As discussed earlier, there is ample natural gas available from shale deposits so supply is not an issue. However, it is prudent to consider the possible impact of future EPA rulings that may develop over the years, such as the effect of recovery from shale on clean water supply, which will impact the cost. Natural gas electric power units, unlike nuclear or coal fired units, are sensitive to the price of the fuel. A price increase of $1 per MMBTU at the well head will affect the price of electricity by $6 per MWh at the retail level. Thus, a balance in the portfolio of energy sources needs to be maintained while meeting the reduced GHG goal. The projected CO2 reductions in the electric power sector, as outlined above, will make substantial contributions to achieving the 2020 goal of 17% reduction in GHG emissions. However, for the 2050 goal to be achieved, substantial additional change will be required. In addition to improving the efficiency of power generation, and using alternate fuels (and processes such as the solid oxide fuel cell), it will be necessary to capture and to permanently sequester the carbon dioxide emissions. To this end, significant effort has been underway for the past decade, under the leadership of the US Department of Energy and the Electric Power Research Institute (EPRI). Processes are being developed for the capture of carbon dioxide at stationary central power stations and the technology is well advanced. For the near term the focus is on capturing 36 carbon dioxide after combustion so that processes can be retrofitted to existing plants. For the long term, carbon will likely be separated prior to combustion. Figure 83 illustrates the various paths available for CO2 capture. In a recent study by EPRI, a super‐critical pulverized coal unit operating on self powered cryogenically separated oxygen with CO2 capture and compression (for piping to storage and/or enhanced oil recovery) was determined to have The volume of CO2 output identical overall thermal efficiency to a comparable plant operating from the present day power on air. Note also that the integrated gas solid oxide fuel cell plant, sector, in a compressed super critical phase, would be as discussed earlier, is especially suited to separating out the carbon roughly equal to 2.5x the dioxide. volume of oil consumed daily For the future, using coal to generate hydrogen from steam is being considered. The hydrogen will be fed to the turbines (or fuel cells) to generate electricity while the CO2 would be captured and piped to deep permanent storage. A schematic of the futuristic FutureGen plant is illustrated in Figure 84. A demonstration project, funded jointly by DOE and industrial partners, is already underway in Illinois. The technology is targeted to be commercially available by the early 2020’s. For sequestration of CO2, several pathways exist as illustrated in Figure 85. Carbon dioxide is already being successfully used to displace, and recover, tight methane from coal beds, as well as enhancing oil recovery from depleted oil fields. The Weyburn project, in which compressed carbon dioxide is dispatched via pipelines from the North Dakota coal fields to the oil wells in Saskatchewan, is the most notable example of this technology; here, more than one million tons/year of carbon dioxide, compressed to 5,000 psi, have been injected into depleted deep oil wells resulting in more than a doubling of oil production. For the long term, burial in deep saline aquifers is preferred, recognizing the large quantities of CO2 being considered. Figure 86 illustrates the location of suitable geologic formations in the US. The capacity of the aquifers is estimated to be in the vicinity of 4,000 Gtons, sufficient for several hundred years. In the US, nine large projects are presently underway with regional partnerships, costing more than six billion dollars. The major uncertainty being tested is the 37 permanency of the storage although other concerns are also being addressed. Note that while the US has 4,000 miles of piping currently utilized for pumping compressed CO2, it is estimated that by 2030 some 15,000‐60,000 miles of high pressure piping will be required over the long term. Such changes to capture and permanently sequester the carbon dioxide emissions will require expensive capital investments. To drive this change, it will be necessary to place a price on carbon emissions, similar to that proposed in the Waxman‐Markey Bill, or a carbon tax. In Europe, The levelized cost of carbon has been successfully traded for the past decade on the electricity includes capital depreciation, maintenance stock exchange, (the European Trading Scheme). The cost of CO2 and operating costs avoidance at a coal fired plant in the US is estimated to be $60‐80 a metric ton. To recover the costs, the price of electricity to the consumer will undoubtedly rise, and for this reason, any future bill in congress will be contentious. Figure 87 illustrates the projected levelized cost of electricity, from various sources of generation, from a study conducted by the National Academy of Sciences. To implement carbon capture and storage in power generation, the cost of electricity will likely increase by 30‐40%. Conversely, for renewable fuel, such as solar PV, the cost is already extremely high and would be unacceptable without the implementation of offsetting government incentives. For the long term, nuclear power generation must play an increased role, in reducing GHG emissions. One example of the beneficial effect of nuclear power on CO2 emissions is illustrated in Figure 88. When France introduced nuclear power as a major source of electrical power in the late 1970’s, CO2 levels fell drastically as is evident in the figure. France presently generates 70% of its electrical power from zero carbon nuclear generators and correspondingly has one of the lowest emissions in the OECD countries. Although nuclear power in the United States contributes only 20% of the total domestic electrical energy at the present time, operational experience in the US with nuclear power exceeds that of any other country in the world. Figure 6, discussed previously, illustrates that in 2011 United States commercial nuclear 38 power plants generated 790 billion kwhr of electrical energy, exceeding the total output of France, Russia and Japan combined. Of all carbon free power generated in the US during 2011, nuclear power contributed more than 80% of the total. According to the World Nuclear Organization some 434 nuclear plants are currently operating globally generating 373 GWe power. Additionally, 64 new plants are under construction and 160 more are planned. These nuclear plants will substantially contribute to reducing global carbon emissions. Of these China has the most ambitious plan, where some 26 new reactors are under construction and 51 more are planned. Many of these plants will use US technology. In the United States, two new reactors are currently under construction and 26 are in various stages of planning for license application. When built, these new plants will have a power generating capacity of nearly 40 GWe. A map of planned/proposed new nuclear plants in the US is illustrated in Figure 89. Recognizing the need for carbon free generation in the electric power sector in the future the Electric Power Research Institute (EPRI) has developed a model to project the likely mix of energy sources. Figure 90 illustrates two EPRI energy portfolios depending on the state of technology and regulatory requirements. Both portfolios address the electric power industry reducing CO2 emissions from near 2,400 million metric tons per annum in 2010 to roughly 300 million metric tons over the next forty years. In the limited portfolio model, the major assumptions are that CCS is not available for fossil units, that existing nuclear plants do not have life extensions beyond sixty years and that no new nuclear plants are ordered beyond those currently under construction. For this scenario, by 2050 essentially all power must come from renewable sources, with considerable emphasis on biomass and solar which does not become sufficiently developed to take an adequate burden for at least a decade. Furthermore, the model assumes that electricity use will be reduced by 30% compared to current projections. For the full portfolio model, EPRI assumes that 90% of new fossil plants commissioned after 2020 will have CCS capability, 80% of currently operating nuclear plants will have life extensions to 80 years, and new nuclear plants will continue to be ordered (total capacity of ~200 GW, compared to ~ 130 GW with current license applications). With these assumptions, the model shows 39 a more balanced portfolio, with fossil, nuclear and renewable each providing roughly one third of energy output. The EPRI full portfolio model suggests that wind will provide the dominant growth of renewable energy for the immediate decade and must roughly double the rate of new installations, after which it will reach saturation levels. Solar, geothermal and biomass will slowly gain momentum and in total will roughly equal that of wind power by 2050. Hydropower is considered by many to have already reached saturation in the United States. Coal power, while decreasing over the next decade, is expected to regain momentum with the implementation of CCS technology after 2020 and eventually surpass natural gas which will also requires CCS technology. However, many challenges yet remain in proving the acceptability of the CCS technology and considerable effort is required before the industry will be ready to implement this on a commercial scale. Until this situation is clarified, the future direction of the carbon free electric power industry is highly uncertain, even though adequate natural resources are available. Transportation Transportation is a major contributor to GHG emissions, approximately 94% of which is CO2. Of these emissions, 78% is due to on‐road transportation as illustrated in Figure 91. Moreover, light duty vehicles (LDV’s) and class 8 heavy duty vehicles (HDV’s) constitute roughly 90% of on‐road transportation, as illustrated in Figure 92. Despite improvements in vehicle design, direct GHG emissions increased from 1489 MMT CO2(eq) per annum in 1990 to 1724 MMT CO2(eq), in 2009, as illustrated in Figure 93 an increase of approximately 16%. Note the graph relates to “Tank to Wheels” or “direct” emissions. Well to Wheel Emissions, a more correct method of presenting emissions level, will be discussed later in this section. The tank to wheels emissions will continue to grow in the future, as illustrated in Figure 94, if no further change in policy or technology (BAU) is implemented. The relationship between energy use for different transportation modes and direct CO2 emissions is illustrated in Figure 95. Note that most of the growth is due to LDV’s and trucks. 40 To meet the goals proposed by the US administration, these annual direct emissions must be reduced by 83% of 2005 levels, ie approximately 2,000 million metric tons, during the next forty years. This is a very significant undertaking. However, note that after the oil crisis in the early 1970’s, a similar undertaking by the auto industry was achieved successfully as illustrated in Figure 96. This action was taken primarily to reduce oil consumption and dependence on foreign oil. Note, as is evident from the figure, very little additional change occurred after 1980 until very recently (when new laws were introduced). While carbon capture, and subsequent sequestration, in the power sector can take advantage of the fact that energy consumption is confined to large stationary units, this is not readily achieved with mobile units. The major thrust for light duty vehicles and trucks (LDVs), the largest contributors, is two‐fold for the short term. The first of these approaches is to focus on efficiency improvements for internal combustion engine (ICE) powered vehicles, as discussed earlier in this report, to reduce gasoline consumption. The second short term approach is to reduce GHG emissions directly by progressively replacing gasoline (and diesel) either with renewable bio‐fuels which are carbon neutral or to replace the liquid fossil fuel with electric power stored in batteries. For the latter, both hybrid (energy from braking) and plug‐in (energy from the power grid) are choices, although plug in energy will not contribute much to total GHG emissions until fuel sources for power generation are also low carbon. For the long term, fuel cells operating on low carbon fuel are considered to provide the optimum power pack able to replace the internal combustion engine. The leverage to improve fuel efficiency in LDV’s is exerted through the US Federal Corporate Average Fuel Economy (CAFÉ) regulation. The development of CAFÉ regulations is an ongoing process which was actually started in 1975, to address energy security, after the Arab oil embargo in 1973. The regulation has been revised several times since it was introduced. This regulation provides the incentive for manufacturers to improve design through internal combustion engine power pack and transmission efficiencies. Penalties are imposed if manufacturers do not meet the requirements. The present CAFÉ target, established by the US administration in 2009, is for LDV’s manufactured from 41 T
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2012 onwards, to have a fleet average improvement of 4% a year, (from the current 25 mpg) such that by 2016 the fleet average of new LDV’s would be 34.8 mpg. This is illustrated in Figure 97. These standards apply to cars and pickup trucks less than 8,500 lbs. gross vehicle weight rating (GVWR), and sport utility vehicles and passenger vans less than 10,000 lbs. GVWR. In 2011, the National Highway Traffic Safety Administration proposed standards for LDV model year 2017 through 2025. These standards are also illustrated in Figure 97 and tentative agreement has now been reached with major automobile manufacturers to increase corporate fleet average requirements for cars to 54.5 mpg by the model year 2025. The proposed regulation will likely be made law in 2013. In parallel with the NHTSA, the EPA has proposed that the direct average CO2 emission output of the 2025 LDV fleet be 163 gCO2/mile. Note, however, that this substantially falls short of Japanese and European LDV goals. The US goal is more comparable to that already being achieved by these countries, as is illustrated in Figure 98. Consequently, to achieve the US goal of 83% reduction in emissions by 2050, increased efficiency of gasoline usage in vehicles will have to continue at the rate of 4‐5% a year well into the future. That is, by 2035 it will be necessary to have CAFÉ rules stipulating a target mileage of about 75 mpg for new LDV fleet averages and direct GHG emissions of about 120 gm/mile. The suggested CAFÉ rules for LDV’s suggested above translate to approximately 2300 BTU (of gasoline)/mile for the MY 2025 fleet average and 1670 BTU/mile for MY 2035. The values are overlaid on Figure 99 which illustrates the effect of future power train design on petroleum use in medium size LDV’s. The figure shows that present day LDV fleets averaging 24.5 miles per gallon use about 5,000 BTU per mile of gasoline. Future hybrid electric vehicles use less than one half of this gasoline energy while plug‐in hybrid vehicles use even less gasoline. Future vehicles running on hydrogen made from alternative fuels, or full battery operated vehicles, use virtually no gasoline. Assuming an average vehicle lifespan of 17 years, these proposed CAFÉ rules should result in the average fuel consumption for LDV’s on the highway in 2035 being comparable to the target for MY 2026‐2027. That is, by 2035 42 petroleum consumption should be reduced by at least 50% compared to present day. From the data presented in Figure 18 this translates to a reduction in oil usage of 5.1 mb/d for LDV’s. Given a similar improvement in HD vehicle efficiency, the total reduction in petroleum usage will be almost equal to the level of liquid fuel imports, which is projected by the AEO 2012 report for 2035 to be 7.4 mb/d. As is evident from Figure 99, this result can be achieved readily for LDV’s if all such vehicles in commercial production after 2025 use electric motor transmission technology or are ICE vehicles using alternative fuels. Carbon neutrality implies The leverage for use of renewable fuels is defined by that all CO2 emitted will be the renewable fuel standards (RFS) requirement in the subsequently absorbed by new plant growth due to Energy Independence and Security Act (EISA) of 2007. photo­synthesis. If plant Additionally, manufacturers are allowed CAFÉ credits (from growth is restricted eg during draught, carbon the Alternative Motor Fuels Act of 1988) for producing flex‐
emissions will increase fuel vehicles that can use both gasoline and ethanol. Renewable clean fuels, such as ethanol, do not contribute to improved internal combustion engine efficiencies—in fact they detract from it. The energy intensity of several LDV renewable fuels, in comparison to petroleum based fuels, has been previously discussed (Figure 32). A vehicle with a 300 mile range on a full tank of gasoline will only travel 213 miles on a full tank of E85 (85% ethanol) fuel. Bio‐fuels do contribute to the goal of reducing green‐house gases since they are carbon neutral. Enforcement of the RFS is the responsibility of the EPA, as is enforcement of the Clean Air Act. For the year 2011, the EPA issued the requirement for blending 13.95 billion ethanol equivalent gallons with gasoline in concentrations up to 15% (E15). This replaces 9.3 billion gallons of gasoline (ie approximately 3% of total liquid fuel consumed) and thus reduces carbon emissions for LDV’s slightly. Most of the renewable fuel processed to date is corn based ethanol. For the long term, the corn based renewable fuel output is mandated to peak at 15 billion gallons/year because of concern for impact on food supplies. The near 43 term focus is to develop the technology necessary to obtained comparable output of bio‐fuel from cellulosic feed stock such as corn stover and switch grass. Ultimately, the DOE goal is to process one billion tons of dry bio‐mass a year, sufficient to make 85 billion gallons of ethanol(eq) a year. Progress in this area is slower than expected and recent EIA estimates show that the RFS goal of reaching 36 billion ethanol equivalent gallons by 2022 (24 billion gallons of gasoline equivalent, approximately 7% of total consumption) will be not be reached for an additional 10 years as shown in Figure 100. By 2035, bio‐fuels—including imports—are projected to provide 11% of total liquid fuel consumption. Over the past decade shifts in the GHG emission calculation methodology using “Well To Wheels” (WTW) rather than “Tank to Wheels” (TTW) analysis suggests that in the US, use of bio‐fuels, particularly corn based ethanol, will not have the intended benefit in reducing GHG’s as originally anticipated. The WTW methodology, as schematically illustrated in Figure 101, better represents the true impact of transport usage on GHG emissions. The figure illustrates for both bio‐fuels and petroleum gasoline, carbon dioxide emissions occur at several processing steps between harvesting the raw feed stock and consumption of the final product. In the WTW methodology for corn based ethanol, other sources of GHG’s, such as nitrous oxide from fertilizer, must also be taken into account as are illustrated. As a result of this methodology, calculations show that GHG emissions from corn based ethanol are not carbon neutral but rather comparable to those emitted from natural gas. Nonetheless, use of corn based ethanol in transportation will still contribute greatly to energy security. A methodology known as GREET (Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation), which is used to calculate WTW GHG emissions, has been developed over the past decade at Argonne National Laboratory. Application of the GREET model to the LDV power train choices previously discussed in Figure 99 is shown in Figure 102. Note that for WTW emissions natural gas HEV’s are estimated to emit slightly less GHG that FCEV’s when hydrogen is produced from distributed natural gas. Also, note that vehicles operating on E85 corn based ethanol are comparable to NG vehicles (despite their carbon neutrality status). Overlaid in this figure are the WTW emissions 44 The 2050 cumulative WTW emission target for LDV’s is 255 MMT CO2eq which is 17% of the 2005 level of 1,500 MMT CO2eq . This equates to an “on­road” target emission level of 50 gm CO2e/mile requirements that match the CAFÉ rule requirements for MY 2025 LDV’s and MY 2035 LDV’s. Using the new methodology, these emissions are calculated to be 185 grams CO2/mile for MY 2025 and 135 grams CO2/mile for MY 2035 respectively. Included in Figure 102 is the target “on‐road” emission value for 2050. By comparing Figures 99 and 102 it now becomes clearly evident that while many vehicle power train choices will meet the requirement for gasoline efficiency, by 2035 few will meet the requirements for meeting the GHG emission goals. By 2050, even fewer choices remain. From Figure 102 it would appear that in order to meet the 2025 MY goal for GHG emissions, 2025 MY vehicles would have to be either hybrid vehicles using bio‐fuel (E85) EIA estimates that the total LDV miles or natural gas, or plug‐in vehicles using traveled in 2035 will be 4.05.1012. Given a recharging power from low carbon sources. 50% reduction in total GHG LDV (Note in Figure 102 the US grid mix is assumed emissions compared to the year 2005, the average emission per vehicle in 2035 will to have 11% reduced GHG emissions (ie BAU) be 185 gm CO2/mile. This approximates compared to 2010). FCEV’s fueled by hydrogen to the target emissions for MY 2025 given a vehicle lifetime of 17 years processed from distributed natural gas just exceeds the 2025 goal. For the 2035 goal, essentially all 2035 model year vehicles would have to use some form of electric motor with either bio‐fuel processed from cellulosic feedstock, plug‐in vehicles using very low carbon sources or fuel cell vehicles using centrally produced hydrogen from bio‐mass or fossil fuel with sequestration. (Note, the “on‐road” vehicle fleet in 2050 will include vehicles manufactured from 2033 onwards). Thus the task of meeting the GHG emission requirements in the future becomes more difficult than that of meeting mileage requirements from CAFÉ rules and the choices of vehicle power train designs become more limited. Eliminating the need for oil imports without concern for GHG emissions would be a much simpler task. In their recent analysis of “Future Transportation Fuels” the National Petroleum Council came to the conclusion that, despite the fleet requirements for 45 GHG emissions suggested by the GREET model, by 2050 a large fraction of LDV’s operating on the highway would still use conventional internal combustion engines and that gasoline would still be the fuel of choice. These conclusions were previously discussed in reference to Figures 61 and 62. Using the ANL GREET model for WTW GHG emissions the NPC concluded that with this fleet portfolio, the cumulative total GHG emission for LDV’s would be roughly three times the target level. That is, the NPC estimates that the cumulative emissions would be in the range 750 to 1,000 MMT CO2 compared to the target of 255 MMT CO2. The results are summarized in Figure 103. The magnitude of the problem is well illustrated in Figure 103. For BAU, the cumulative emissions are projected to increase from 1,500 MMT of CO2e in 2005 to approximately 2,700 MMT CO2e in 2050. This because the total miles traveled by LDV’s will have roughly doubled as a result of the increase in population. Thus, the actual reduction in emissions calculated by the NPC corresponds to more than a 70% reduction from the projected level for 2050 with BAU. Put differently, the total reduction in GHG emissions is estimated to be nearly 2,000 MMT CO2e which is actually 33% more than the total WTW LDV emissions for the reference year 2005. The NPC conclusion clearly shows that meeting the cumulative goal of 83% reduction in GHG’s (relative to 2005) for LPD transportation sector will be not be possible without drastic change. Since LDV’s emit approximately 20% of the total cumulative GHG emissions in the US, this result can have devastating consequences. The excess GHG emission in the LDV transport sector will be almost 500 MMT of CO2e which is 50% of the total cumulative goal of GHG emissions in 2050 from all sources. Furthermore, comparable conclusions were also reached by the NPC in their analysis of the HDV long haul trucking transportation sector. In the HDV sector, improvements from using LNG were offset by the increased mileage projected for 2050. Taking the NPC result from the combined LDV and HDV sectors, the cumulative GHG emission is projected to be in the range 1,100 MMT CO2e to 1,250 MMT CO2e which considerably exceeds the total targeted from all sources. Thus, in order for the transportation sector to meet the goal of 83% reduction in GHG emissions, considerable effort will be 46 required by US industry. Investments totaling trillions of dollars will be required to design and manufacture the necessary vehicles, and above all, provide the low carbon fuel in the quantities required. These needs will be discussed further in the next section. Summary and Discussion Energy is produced from a variety of resources. Fossil fuels—coal, oil and natural gas—provide 84% of the US energy used. Coal is used almost exclusively for electric power production while 93% of transportation fuel comes from oil. Nuclear power provides 9% of the energy (all for electric power) while renewable resources provide 7% of the energy. The US consumes more energy than any country in the world; it uses approximately 25% of the world’s annual energy production, though it has only 5% of the world’s population. On a per capita basis the United States is one of the highest energy users in the world. Prior to 1970, the US was self sufficient and produced as much energy as it consumed. From 1970 onwards, the US progressively imported increasing amounts of energy to match consumption. Most of the imported energy was oil though a small amount was natural gas from Canada. The US remains self sufficient in other energy forms (despite increased consumption), namely coal, nuclear and renewable fuels and their sustainability and security of supply is assured. The growth of oil imports from 1970 onwards roughly matched the growth in US total energy demand. Most of the increase in oil consumption was accompanied by a simultaneous decrease in domestic production, probably because of low oil prices. From 1970 to 2010 domestic liquid fuel production fell 44% while consumption increased 60%. In 2010 liquid fuel imports were more than 150% greater than domestic production. The consumption of energy in the US is directly related to economic output as measured by the Gross Domestic Product (GDP). For the most part, prices are established on the principle of supply and demand. Electricity and natural gas prices for domestic consumption are monitored by public utility commissions 47 (PUC) which are domestically controlled. Natural gas prices, while highly volatile at the turn of the century, are now at an all‐time low because of recent technology breakthroughs and domestic explorations. Oil however, is an international commodity and the prices and production levels are strongly influenced by OPEC. Over recent years, oil supply has been strongly affected by political events and rising demand from developing countries. In the past ten years, oil prices have increased more than fourfold and oil price shocks have substantially impacted the US economy. In 2008, the cost to the economy of imported oil was estimated to be $500 billion, made up from $350 billion in wealth transfer and $150 billion in lost GDP. As a consequence, many have expressed the desire to be independent of foreign oil. Several administrations have attempted over the past several decades to formulate a national energy policy addressing energy security and energy sustainability. None have been successful. There is no clear direction on the future supply of energy. Pathways for supplying energy are frequently contentious. For example, in the late 1960’s there was considerable support for nuclear generation of electric power. Excessive construction and licensing delays, cost overruns, and the Three Mile Island accident, however, quickly destroyed public enthusiasm and many new nuclear power plants were cancelled. The subsequent successful operation of nuclear plants over the past few decades, however, has increased public confidence and nuclear power is slowly gaining acceptance despite the recent Fukushima disaster. Note however, that this momentum will quickly change again if the issue of long term spent fuel waste is not satisfactorily resolved. Coal power has had issues with acid rain, mercury and other pollutants. Construction of new coal fired electricity generating plants is now limited because of environmental concerns and many plant orders have been cancelled. Today, natural gas is the favored fuel for large central power stations. At the turn of the 21st century, however, natural gas was avoided because of the lack of reliable supplies and high price volatility. Oil drilling, particularly in deep off‐shore sites such as the Deepwater Horizon Macondo well in the Gulf of Mexico, is currently in moratorium even though the US continues to import unprecedented quantities of expensive oil from OPEC countries. Wind power has 48 issues with land use, noise levels and impact on scenic views. Bio‐fuel, particularly corn based ethanol, has issues with the impact on food supply and water usage; destruction of rain forests to grow sugar cane and palm trees has resulted in boycotts of bio‐fuel imports, particularly in Europe. Biomass requires large volumes of water which is unpredictable and frequently in short supply. Hydropower has issues with silt deposits and adverse 5,000 MMT of CO2 per impact on fisheries and as a result is considered to have annum is comparable in reached saturation level in the US. Photo voltaic solar volume to five times the panels require very large areas for modest output and are current domestic production of natural gas. very expensive. Surplus panel dumping from China now faces contentious tariffs. Concentrated solar power is limited to hot arid deserts. Consequently, as a result of this plethora of issues, government policies addressing energy supply, at both the federal and local levels, tend to be short term rather than visionary. Developing policies for energy end use are equally contentious but have generally been more successful. Regulations for conservation and improved efficiency, such as improved mileage for vehicles, home appliance electricity usage, home insulation, etc; have been accepted by the public because over the long term they reduce consumer cost. Thus, the EIA currently projects the energy intensity per dollar of consumer spending to fall by 50% over the next twenty five years. Nonetheless, regulations such as CAFÉ rules for vehicles still appear to evolve because of short term concerns rather than because of long term policy for energy security. In recent years concern for global warming has become a major issue affecting energy policy discussions. The UNCCC is pressuring all developed countries to significantly reduce green house gas (GHG) emissions, particularly carbon dioxide, a product of combustion from fossil fuels. There is general global agreement that GHG emissions must be reduced to near zero by 2050 if catastrophic climate events are to be avoided. The present US administration has tentatively agreed to reduce energy related GHG emissions by 83% (of 2005 levels) by 2050 though the UNCCC is pressing for even greater cut backs. Major economies such as the US, China and India have expressed reluctance to agree to 49 any legally binding agreements for the cutbacks though considerable international pressure will likely prevail in the long haul. The major points of contention are the cost, the consequent effect on the economy and the sheer scale of implementing change. To meet the US obligations, the US must prevent 5,000 million metric tons of CO2 per annum, generated from energy use, from reaching the atmosphere by the year 2050. Of this amount, roughly 3,000 million metric tons per annum must be eliminated in 25 years. Essentially all GHG energy related emissions in the US are due to the combustion of fossil fuels, which by far are the largest contributors of energy in the US. The major sectors contributing to GHG emissions are power generation and transportation, which collectively contribute three quarters of the total emissions. Efforts to reduce emissions in these sectors are well underway though ultimate success will require new legislation; attempts to reach agreement on new laws, thus far, have been contentious and unsuccessful. Nonetheless some technical progress has been achieved. For the power generation sector, the Electric Power Research Institute and others (such as Stanford University) have developed plans that requires the growth of new low carbon generating capacity over the next forty years, and the phasing out of old fossil fuel plants. Plant emissions by 2050 will need to approach 65 gm CO2/kwhr. The EPRI plan requires a doubling of current nuclear capacity by 2050, with most new plants coming on line after 2020. That is, recognizing the need to retire older plants, from 2020 onwards, at least 4 new nuclear plants will need to be brought on line each year. The plan also requires a tenfold increase in non‐hydro renewable power capacity (mainly wind with solar in later years) between 2010 and 2050, and roughly a 40% cut‐back in the fossil fuel industry. Note that Most of the older coal fired power stations are predicted to close after 2020, but with expected progress in CCS technology, coal fired power plants are expected to gain increased market share after 2025. By 2050, electric power generation will be rough equally split between three sectors: renewable, nuclear and fossil with CCS. Note however, that while CCS is undergoing intensive development, any dependence on its success at this time is somewhat tenuous. 50 The EPRI plan requires that during power generation, even with the much reduced contribution from fossil fuels, approximately 1,000 MMT of CO2 per annum must be successfully captured and sequestered by the year 2035. By 2050 the quantity of CO2 captured will have risen to approximately 1,800 MMT due to increasing contribution from new coal fired plants. Such capture and sequestration will reduce the efficiency of power generation and will raise the cost of electricity by as much as 50%. The increased cost is due to the amortization of expensive capital equipment, reduction in plant efficiency due to the carbon capture process and compression of the CO2 to ~ 5,000 psi accompanied by pumping of the compressed gas through thousands of miles of high pressure piping. An acceptable process for offsetting this cost increase has not yet been resolved. Some have suggested a carbon tax for high CO2 emitters while others have suggested a carbon trading scheme. Note however, that the increased cost for CCS will bring the cost of electricity from fossil fuels closer to that projected for renewable resources. Failure to demonstrate acceptability of CCS technology will result in profound changes in the energy supply industry. Natural gas will become the dominant fossil fuel for power generation for the foreseeable future, because of its lower carbon content, while the vast resources of the US coal reserves, the largest in the world, will become dormant. Such a consequence is clearly unacceptable. Bio‐mass for power generation will also likely be in greater demand, competing directly with the demand for bio‐mass for advanced cellulosic ethanol and hydrogen production for the transportation sector. Thus it becomes clear that the utmost priority for the coal industry is the development of CCS technology. While carbon capture appears to be feasible, many questions remain regarding sequestration and it may be some time before sufficient experience has been gained with the technology for implementation to become standard practice. To this end, a national energy policy, with appropriate legislation, becomes paramount for the security and sustainability of US energy supply. For the transportation sector, considerable uncertainty also exists, but some of the problems are different. For this sector there are two major issues: 51 reducing dependence on foreign oil and reducing GHG emissions. Pathways for each are being pursued but achieving both limits the options. Developments to match the proposed CAFÉ rules for 2025 model year LDV’s, together with continued improvements of 4‐5% per annum through 2035, should roughly double the fleet average mileage (mpg) of on‐road vehicles by 2035, assuming an average lifespan of 17 years per vehicle (ie 54 mpg for MY 2025, compared to 21 mpg fleet average for 2005, the reference year). Recognizing the increased LDV mileage expected for 2035, as indicated by the EIA, this should have the effect of reducing petroleum demand for LDV’s by approximately 5 MMBD over current BAU projections. Additionally, the coal industry has indicated a capability of providing 2.5 MMBD of liquid fuels. Adding to these gains, the natural gas industry has indicated the possibility of providing up to 11 trillion cubic feet on natural gas a year, which is considerably more than that required to fuel the entire trucking industry, projected with BAU to be 3.1 MMBD by 2035. Thus elimination of the projected 7.4 MMBD of oil imports should be readily achievable by 2035, if not several years earlier. With dedication, this goal could possibly be achieved by 2025. Setting efficiency goals by the CAFÉ rules, of course, does not in and of itself guarantee success. So how will compliance with the CAFÉ rules be achieved? There are two methods by which this can be accomplished. The first is improvement in vehicle efficiency. The second is by replacing gasoline with alternative fuels such as bio‐fuels or natural gas in ICEV’s, hydrogen in FCEV’s, or electricity, in PEV’s. Methanol offers unique characteristics as an alternative fuel in that it can be used in both ICEV’s and FCEV’s, thus facilitating transition as developments progress. This possibility was not considered in the recent National Petroleum Council study. Considerable effort is already in progress to improve LDV efficiency. According to a recent PEW article, which emphases research in progress at MIT, conventional gasoline engine vehicles are expected to have a 62% improvement in efficiency in the foreseeable future compared to 2005 levels. The major improvements are due to streamlining of vehicle design, improved tire design to 52 reduce road friction, reduced transmission losses, turbo‐charging, use of lightweight materials, etc. Many of these enhancements in efficiency, of course, will also directly apply to all vehicle designs such as HEV’s, PHEV’s etc. Furthermore, most of these improvements in vehicle design can be likely be implemented in the next few years. According to the MIT/PEW analysis, by 2035 the HEV could demonstrate an outstanding efficiency of 75.9 mpg, which approximates the likely CAFÉ target suggested for this year, as discussed earlier. For alternative fuels, or power train systems, it is instructive to evaluate the impact of change on domestic resources, particularly the impact on electric power generation, the fossil fuel and cellulosic bio‐mass industries, and ultimately, the oil industry. To this end, one example of a possible fleet portfolio for 2035 is summarized in Table 1 which is based on the estimate that 4.05 trillion miles will be traveled by 260 million LDV’s in 2035. This portfolio is one of many that are possible but is intended to show the effect of continued heavy reliance on liquid ICEV’s consistent with the NPC conclusion. (Note also that the numbers listed for Table 1 were derived using the DOE GREET values). One key anchor in Table 1 is the DOE goal for bio‐fuel production. It is expected that by 2035 approximately 2.3 MMBD (36 billion gallons a year) ethanol equivalent will be available. Assuming this quantity of bio‐fuel is in the form of E‐85 fuel this translates to 21% of the total population for LDV’s by 2035. Note that for these E‐85 flex fuel ICE vehicles a small amount of gasoline will also be used as illustrated in the table. 53 Table 1: Example of Possible LDV On‐road Portfolio in 2035 and Fuel Resources Required Vehicle Type Population Resources Ethanol, Oil, MMBD MMBD NG, Tcuft Elec TWh ICE‐gasoline 20% 1.6 ICE‐ethanol E85 21% 2.3*
0.4 HEV‐gasoline 15% 0.8 CNG‐HEV 19% 1.9 PEV‐gasoline 15% 0.5 218 FCEV 10% 0.8 TOTAL 100%LDV 2.3+
3.3+ 2.7 218 *Assumes 36 billion gallons a year. Ethanol, equal amounts from corn and cellulose +Averages 47mpg for liquid fuel, and 80mpg for gasoline ++Averages 245 gm CO2/mile vs target of 185 gm CO2/mile for “on‐road” fleet average +++Assumes only 11% improvement by 2035 in GHG emissions from power generation CO2 Total LDV MMT 275 190 142 142 164+++ 81 994++
In the portfolio it is assumed that 20% of the vehicles in 2035 will be conventional ICEV’s running on gasoline, while 34% will be HEV’s. For the HEV’s it is assumed that 15% will run on gasoline while 19% will be CNG‐HEV’s. For PEV’s it is projected that by 2020 as many as 10% of new vehicles will be of this design and that this number will grow progressively in the following years. Thus it is assumed in Table 1 that by 2035, 15% of the total LDV’s operating on the highway will be PEV’s. These vehicles will use approximately 0.5MMBD of gasoline and 218 TWh of electricity for battery charging. This power requirement will place a demand on the power sector roughly equal to 6% of present day capacity (ie ~60GWe) if battery recharging occurs PEV’s use 360 wh/mile. If randomly throughout the day. The capacity requirement will be 15% of on­road vehicles in 2035 are of the PEV reduced to ~ 12 GWe if recharging occurs mainly during off‐
type they will require 218 Twh of grid energy peak periods. To complete the portfolio in Table 1 it is assumed that 10% of LDV’s operating on the highways by 2035 will be FCEV’s running on hydrogen produced from natural gas. This number of vehicles will require slightly over 5 MMT of hydrogen/year which in turn will require 0.8 Tcuft/yr of natural gas as feed stock. 54 By comparing the data presented in Table 1 to those presented in Figure 18, it is evident that the suggested portfolio of vehicles in this example shifts the burden of fuel for LDV’s from oil to other resources. That is, the projected level of oil use for LDV’s in 2035 changes from 10.2 MMBD of oil (with BAU), to 3.3 MMBD oil plus 2.3 MMBD ethanol (5.6 MMBD total liquid fuels) together with 2.7 Tcuft/yr natural gas (12% of present day output) and 218 TWh of electrical energy (6% of present output). That is, with this fleet portfolio the total demand for oil for LDV’s will be reduced by roughly the same amount as is projected to be imported with BAU (7.4 MMBD). Note also that with the LDV fleet portfolio in this example, the average mileage for all LDV’s on the highway in 2035 is 47 mpg (for liquid fuel), which is close to the new CAFÉ requirement for MY 2025 LDV’s. This shift in energy use for LDV’s over the next twenty five years is certainly achievable though major challenges need to be overcome. For PEV’s the major challenges are battery energy intensity (energy to weight ratio), longevity and cost. For FCEV’s, the major issues are fuel cell degradation, durability and cost. For both FCEV’s and NGV’s, two major issues are fuel compression and public acceptance of vehicles with high pressure fuel tanks. Also, bio‐mass resources and infrastructure will need to be carefully managed, since the sustainability of this energy source is yet to be proven: bio‐mass will be in demand for power generation, bio‐fuels and hydrogen production. Similarly, natural gas will be in great demand for power generation, CNG vehicles and hydrogen production for FCEV’s. Natural gas may also be in great demand as an alternative fuel for HDV’s, particularly class 8 HD vehicles. As noted earlier, considerable effort is already underway to develop a refueling infrastructure for long distance vehicles. Vehicle manufacturers are already retooling to replace diesel fueled engines with LNG tanks and NG engines. While diesel may still be the fuel of choice for HDV’s, and efficiency improvements are certainly possible, market forces do suggest that by 2035 a considerable number of LNG HDV’s may be on the highway. Thus, if we assume that 50% of all HD vehicles in 2035 operate on LNG, (replacing 1.6 MMBD of oil) the additional quantity of natural gas required will be approximately 3.3 Tcuft/year. As a consequence, the total 2035 demand for natural gas for the 55 highway transportation sector may be as high as 6 Tcuft/year, more than 25% of current production. Such an increase in demand for natural gas for the transportation sector, in addition to the known impact on the power generation sector, will have a great effect on the natural gas supply infrastructure. The total increase in demand may well reach the limit of 11 Tcuft/yr suggested in Figure 28. Furthermore, this limit is projected to last only for a few decades and has its origin almost entirely in the new technology for recovering natural gas from shale “plays”. For longer time‐
frames, alternative sources of natural gas will need to be exploited. For this demand of natural gas, many thousands of miles of new high pressure pipelines will be required, together with compression and cryogenic equipment, requiring the investment of billions of dollars. Substantial changes in land use, and associated litigation, will also be required. As a result, it is clear that the growth of the natural gas industry must be carefully coordinated to maintain consistency of supply and avoid excessive cost escalations as in the past. The effect of new vehicle power trains and the use of alternate fuels on reducing the US dependency on imported oil is compounded by the need to also reduce GHG emissions. This is further illustrated in Table 1 which shows that meeting the CAFÉ requirement is relatively easy in comparison to meeting the GHG emission goal. For the fleet portfolio example shown in Table 1 the average mileage for liquid fuels was deduced to be 47 mpg; for gasoline only, the mileage was approximately 80 mpg. GHG emissions from LDV’s as summarized in Table 1 totaled 994 MMT/yr, some 244 MMT/yr greater than the suggested target for 2035. Note however, that the quantity of CO2 predicted for PEV’s from the GREET analysis can be reduced by at least 70 MMT if the power generating sector make a 50% improvement in emissions (rather than the 11% assumed in GREET) by this year. By modifying the fleet portfolio mix, for example by reducing the ICE‐
gasoline vehicle population and increasing the FCEV population accordingly, the emission target of 750 MMT of CO2 could be more readily attained. 56 Going beyond 2035 and looking forward to meeting the ultimate goal of 83% carbon emissions reduction in the transportation sector by 2050, very significant challenges become apparent. By 2050 LDV’s are estimated to travel a total of 4.9 x 1012 miles (an increase of 80% over 2005). Thus, to meet the goal of 83% reduction in GHG emissions, compared to 2005, the on‐road LDV average emission target for 2050 must be approximately 50 gm CO2eq/mile. This value is overlaid in Figure 102 which illustrates the magnitude of the problem; very few vehicle power train designs will meet this requirement, particularly when it is recognized that this emission level is the average of the on‐road fleet having a life expectancy of 17 years!. By 2050, the “on‐road” fleet portfolio of LDV’s must be made up of HEV’s running on cellulosic ethanol, FCEV’s with hydrogen produced from either bio‐
mass or fossil fuel with CCS and PEV’s with battery charging on ultra‐low carbon sources. Given that the power generating industry follows the plan outlined by EPRI, emissions from the power industry should approach 65 gm CO2eq/KWh by 2050. Thus, BEV’s charged from the electric grid at this time should emit approximately 23 gm CO2eq per mile. Based on current projections it is reasonable to assume that by 2050, some 51 billion gallons of bio‐fuel will be available, 35 billion gallons of which will come from advanced sources such as cellulosic feed stock, and 15 billion will continue to come from corn. This will be sufficient to fuel approximately one third of LDV’s on the highway in 2050. Using this as a base point, and assuming that remaining on‐road vehicles are equally divided between BEV’s and FCEV’s, a simple vehicle fleet portfolio would be as shown in Table 2. 57 Table 2: Resources and CO2 emissions from possible on‐road fleet portfolio in 2050 Vehicle type # Vehicles, Million; Energy/quantity CO2 captured Annual Miles, 1012 MMT HEV‐ethanol E85 107:1.63 51billion gals/ethanol(eq); oil,0 .65MMBD FCEV 107:1.63 Hydrogen, 21MMT 239 BEV 107:1.63 Electricity, 586TWh 108 Total 321: 4.9 Total liquid fuels: 247 3.3 MMBD ethanol, 0.65 MMBD oil + Assumes by 2050 that corn and cellulosic ethanol have comparable GHG release ++ Assumes 85% CCS efficiency +++Assumes GHG release of 63 gm/KWh CO2 released MMT 147+ 42++ 37+++ 226 Given this portfolio, it is instructive to determine the likely impact on fuel resources and infrastructure. We assume for simplicity in Table 2 that by 2050 the ethanol is used exclusively in E85 HEV’s. We further assume that the hydrogen is produced from a variety of feed‐stocks, namely 40% from bio‐mass, 40% from natural gas with CCS and 20% from coal with CCS. Finally, we assume that all the PEV’s are of the BEV type, and that electricity is generated according to the EPRI proposal of roughly one third renewable, one third nuclear and one third fossil with CCS. Given that emissions per vehicle type and energy use per mile remain unchanged from 2035 predictions of the GREET model, the data given in Table 2 show the total GHG emission that will be released into the atmosphere, estimated to be 226 MMT CO2 is now slightly better than the goal of 255 MMT CO2. The table also shows that 247 MMT of CO2 would need to be captured by the CCS processes. By comparing the data in Table 2 to those presented in Table 1, it should become apparent that 2035 signals a year for major accomplishments and change in the auto and fuel industry. From 2035 onwards US auto manufacturers would need to produce approximately 7 million vehicles per year of each of E85‐HEV, FCEV and BEV designs to obtain the portfolio in 2050 of on‐road vehicles proposed in Table 2. At the same time the liquid fuel industry would need to have substantially reduced oil refining while increasing the production of cellulosic bio‐
fuels. Oil consumption for LDV’s is projected to decrease from 9.4 MMBD in 2005 58 to 0.65MMBD in 2050, an 93% reduction despite a near doubling of miles traveled; in contrast bio‐fuel consumption is expected to increase from near zero in 2005 to 3.3 MMBD in 2050. The impact on the fuel supply chain of the proposed portfolio contribution of FCEV’s and PEV’s for 2050 is illustrated in Table 3; cellulosic bio‐mass is presumed to originate from the 1 billion tons of dry bio‐mass forecast by the DOE and will not be considered further. (Note however that the technology for making advanced bio‐fuels from cellulosic feed stock is presently still in its infancy). For hydrogen production, the DOE data in Figure 34 were used to estimate the quantity of feed stock required given the assumed distribution of bio‐mass, coal and natural gas. Similarly for the BEV the required power generating capacity listed is based on the EPRI proposal for 83% carbon reduction. For completeness, the quantity of coal and natural gas required for their contribution to fossil power generation is also listed. The data presented in Table 3 suggest that the quantity of feed stock material required is actually quite modest relative to current capacity, particularly for coal and natural gas. Of greater concern is the quantity of GHG emissions that must be captured as shown in Table 2. For hydrogen production from coal and natural gas it is estimated that 239 MMT of CO2 must be captured and stored; for electricity production 108 MMT of CO2 must also be sequestered. This quantity of CO2 is in addition to the ~1,800 MMT of CO2 from “base” electric power sector. Thus, it is clear that the need to have reliable commercial operation of CCS facilities in both the electric power and chemical industry sectors becomes a mandate for limiting the GHG emissions by 2050. 59 Table 3: Feed‐stock and Generating Capacity Requirements for FCEV’s and PEV’s in 2050 Vehicle type FCEV PEV Total Percent Present day Raw Material Bio‐mass Coal 105MMT 105MMT 50% 56MMT 27MMT 83MMT 7.7% Natural Gas 1.3 Tcuft 0.9 Tcuft 2.2 Tcuft 10% Electric Power Capacity Wind/solar
Nuclear Coal ‐ 56 GWe 56GWe 120% ‐ 25GWE 25 GWe 25% ‐ 16GWe 16GWe 5% Natural Gas ‐ 16GWe 16GWe 4.5% Total capacity 7GWe 113GWe 120GWe 11.6%+ Assumed feed‐stock distribution for hydrogen: 40% bio‐mass, 40% natural gas, 20% coal. For 100% generating capacity factor (CF), 1GWe produces 8.76 Twh of electrical energy per annum; assumed CF’s are: Nuclear 90%, wind/solar 40%, fossil 70% Note EPRI determined for 30% PEV penetration in 2050 that an 8% increase of capacity would be required for ubiquitous anytime home re‐charging. This could fall to 2% if all re‐charging occurred during off‐peak periods. Even with this CCS implementation it is apparent from Table 3 that carbon free electric power –both nuclear and renewable‐‐must grow considerably to accommodate the transportation sector. The capacity of non‐hydro renewable power generation must double the present day installed capacity (wind is presently at 50GWe) while the capacity of nuclear must increase by 25% over current levels. Thus, the need to have essentially carbon free transportation in the LDV sector transfers considerable burden to the electric power generation and chemical industry sectors. Additionally, the need to acceptably demonstrate in the next few years CCS technology for quantities of CO2 far in excess of those quantities currently experienced for oil and natural gas production, becomes paramount. While cumulative GHG emissions for HDV’s are smaller than for LDV’s, considerable challenges to reduce the emissions prevail. From the recent NPC report on “Future Transportation Fuels”, HDV’s are still expected to release by 2050 a cumulative annual total GHG emission of up to 500 MMT of CO2. While electric motors (PEV’s and FCEV’s) are favored for LDV’s, they have not been seriously considered for HDV’s, primarily because of range between recharging/refueling stops. However, hydrogen fuel cells do appear to have an application for buses operating on a relatively confined circuit which allows for easy access to refueling stations. For long distance hauling, no serious change to 60 HDV drive trains, other than modification to use of LNG or bio‐diesel fuel, appears to be under review. None‐the‐less significant reductions are possible in the HDV transportation sector through use of electric motors. The major issue to be addressed with HDV’s is not the technology for electric drives such as PEV’s or FCEV’s, but rather the range such vehicles will have between recharging/refueling stops. While the energy requirement for HDV PEV’s might still be an obstacle for battery development, no such obstacles exist with fuel cells which can run on high energy density fuels such as liquid hydrocarbon fuels or LNG. Fuel cells, such as Solid Oxide Fuel Cells (SOFC) currently nearing commercial implementation for stationary devices could have a direct application for vehicles used for long‐haul transportation. Because of their efficiency, which is approximately 60%, use of such fuel cells will result in further dramatic decreases in GHG emissions, even if petroleum based fuels are still used. The major issues opposing such application are space requirements and the need to maintain steady load because of their high operating temperature. None‐the‐less, such fuel cells have considerable potential for use in heavy vehicles in the future. Additionally, replacement of conventional engines in rail road locomotives and ships by SOFC’s offers intriguing possibilities. Solid oxide fuel cells have considerable advantage over internal combustion engines for the capture of GHG emissions. As stated earlier, and as is readily apparent from Figure 42, solid oxide fuel cells provide for excellent separation of oxidation products (CO2 and H20) from large volumes of nitrogen in the air intake. Thus, if space is available in vehicles, on‐board collection and compression of CO2 emissions should be easily accomplished with solid oxide fuel cells. On long distance haulage HDV’s, locomotives and ships, the space can actually be made available by replacing larger tanks (required for low energy LNG) with smaller fuel tanks (for high energy liquid fuels). Thus, one can envisage in the future, when such vehicles stop for refueling they will be able to simultaneously load up one tank with fuel while at the same time discharge a second tank, containing the compressed sub‐critical CO2, into holding tanks awaiting ultimate sequestration. 61 By implementing such change, heavy transport vehicles of all types will have significantly reduced GHG emissions. In summary, meeting the goal of energy independence in the next one to two decades, while virtually eliminating GHG emissions by 2050, offers many challenges to the power generation and transportation economic sectors. These sectors presently account for two thirds of all energy used and more than three quarters of all energy related GHG emissions in the United States. However, the United States possesses both the resources and the technology to accomplish these goals given adequate resolve. For energy independence, imported petroleum should be replaced with natural gas, electric power and bio‐fuel in the next one to two decades. This will add approximately $500 billion per annum to the US economy. Fossil fuel consumption must be reduced in all sectors. In the power generating sector, use of renewable power (eg solar and wind) and nuclear resources must be accelerated. Carbon capture and sequestration will become imperative for fossil power plants, chemical process plants and refineries. Thousands of miles of high pressure piping and large capital facilities costing trillions of dollars will be required. In the transportation sector internal combustion engines must be replaced with electric motors powered by batteries re‐charged through fuel cells or the main power grid. Battery re‐charging from the main grid will facilitate reduced GHG emissions but significantly shift the burden of energy production from the petroleum industry to the power generation sector. Thus, the power generation sector will likely be the most impacted over the long term. Many solutions to the issues exist and many pathways are possible. However, a clear path forward needs to be established and backup strategies, particularly for carbon sequestration, need to be developed. As we move forward a price structure for carbon emissions will likely be needed to provide incentive for change. Future costs will increase and an acceptable process for implementation will need to be established. Close coordination will be required between electric power utilities, the oil, coal and gas industries, the biomass and agriculture industries, the chemical industries and petroleum refineries, the automobile industries and of course the various branches of government. Decisions will have an impact on the entire energy industry for generations to come. Consequently, a comprehensive national energy policy and implementation plan with clear milestones is essential. The challenge will require a national commitment of public and private partnership at an unprecedented level. 62