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From the point of view of net consuming nations, the resulting price increases could accelerate an economically disruptive wealth transfer from consumers to producers. While the dependence of the U. Finally, fossil fuels pollute the atmosphere when burned, and they have other adverse environmental effects as well. While emissions of SO x , NO x , particulates, and other atmospheric contaminants have been reduced albeit with an increase in solid, liquid, or recyclable wastes, including ash residuals , little has been done so far to address carbon dioxide CO 2 emissions.

Of that amount, 43 percent came from petroleum, 36 percent from coal, and 21 percent from natural gas EIA, c. By market, the largest source was electric power generation using coal and natural gas ; it emitted some 2. Transportation, dominated by petroleum but also including some natural gas, accounted for 2 Gt CO 2. The remainder of the emissions resulted from industrial 1 Gt CO 2 , residential 0. Thus the future of fossil fuels presents a serious dilemma for energy policy.

On the one hand, because fossil fuels are well adapted to the needs of the market, a huge energy infrastructure has been put in place to take advantage of their value. The existing stocks of vehicles, home and business heating systems, and electric power stations were created with the expectation that petroleum, natural gas, and coal would be readily and reliably available.

On the other hand, the. The downturn in the world economy apparent at the time of this writing will mitigate demand growth for a while, but the underlying determinants of demand remain in place. Note that while electric power is used in industrial, residential, and commercial settings, it is aggregated under electric power generation. A crucial question, therefore, is whether this existing energy infrastructure can be supplied with liquid, gaseous, and solid fuels in the future at acceptable levels of such risks.

If so, much of it can remain in place. If not, the embedded capital stock of technologies for energy production and use will need to change through a combination of market forces and policy choices. Other chapters of this report discuss alternative pathways for providing the energy services that modern society demands.

For example, the chapter on alternative transportation fuels Chapter 5 provides an assessment of the technologies and environmental impacts of liquid fuels derived from biomass feedstocks, coal, or natural gas. This present chapter focuses on alternative ways of using fossil fuels to serve the existing energy-use infrastructure. Specifically, it explores:. The extent to which the U.

New technologies that may become available for producing the desired form of fossil fuels. The focus in particular is on the generation of electricity from coal and natural gas with sharply reduced emissions of greenhouse gases, especially CO 2.

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Technologies and geologic settings suitable for the storage of CO 2 produced from electricity generation and other industrial processes. Given constraints on time and resources, the AEF Committee chose not to address issues relating to the current energy infrastructure, for example, the status of natural gas pipelines, oil refineries, rail and barge transportation for coal, and liquefied natural gas terminals. Worldwide, the amount of oil, gas, and coal that can ultimately be produced is very large. Estimates of ultimately recoverable resources are uncertain, however, because they include not only those that are discovered though not yet economically or technically recoverable but also those that are yet to be discovered.

Roughly 3. By comparison, in , world consumption of these resources was about 30 billion barrels of crude oil and Tcf of gas. See Tables 7. Resources that are discovered, recoverable with current technology, commercially feasible, and remaining in the ground are classified as reserves. The size of. TABLE 7. Reserves c. Annual consumption c. Annual production c. British Petroleum has reported that proved reserves of oil in amounted to billion barrels and that proved natural gas reserves were Tcf British Petroleum, World coal reserves were billion tonnes, which is about times the world coal consumption British Petroleum, Technology plays an important role in turning speculative resources into proved reserves.

Sophisticated exploration and production methods for recovery of oil and natural gas are already commercially available, and the private sector is developing advanced versions of these techniques. The cumulative effect of continuing advances in exploration and production technology for oil and gas is that over the next 20 years much of the current resource base will become technically recoverable.

See Table 7. As noted previously, world reserves are annually producing about 30 billion barrels of oil and The United States is the third-largest oil-producing country and the second-largest natural gas producer. Nevertheless, this country imports about 56 percent of its oil and about 14 percent of its natural gas.

For this reason, the capacity to maintain or increase domestic production is. Virtually all of the natural gas that the United States imports comes from Canada. Technologies allowing a continuing increase in the number of strategically placed horizontal wells will allow a much greater commercial access to reserves. Multiply placed drainholes from a main wellbore will further extend commercial access to reserves. The ability to place drain holes to within feet of every hydrocarbon molecule in the formation allows the ultimate recovery.

The combined technologies including the four immediately below allowing us to see, access, and move the hydrocarbons in the optimum way will bring a big increase to recoverable reserves. Extending current technology to include simultaneous inversion of all measurements with a forward model. Combining reserve scale measurements pressure, seismic, electromagnetic, and gravity in a joint inversion, with uncertainty and without bias.

A full representation and control of the full system subsurface and surface allowing true optimization. Measurement and control of the CO 2 flood front is critical to successful implementation. Technologies to perfect and optimize SAGD operations including the use of ASPs will be key to widespread economic exploitation of heavy oil. Ice scouring of the seafloor surface presents a huge challenge to conventional approaches to subsea and subsea-to-beach operations.

Technical, environmental, and economic uncertainties, however, constrain the pace at which domestic oil and gas production can or will be increased. Accordingly, the following sections focus on the ability of domestic oil, natural gas, and coal sources to maintain or increase production. Tables 7. While Table 7. In some cases, the estimates are for oil that is yet to be discovered. These estimates are obviously less certain than for those resources already discovered. Table 7. The wide ranges of estimated costs reflect considerable uncertainty; costs vary widely, depending on the location, size, and depth of the resource and on many other factors.

Finally, Table 7. Here again, there is considerable uncertainty because of costs and other limitations, such as access to drilling or mining and environmental impacts. The resources listed in Table 7. Whereas conventional oil recovery processes primary production under the natural pressure in the reservoir and water injection typically recover about a third of the oil in place, this resource estimate is based on an assumption that total recovery in fields suited to CO 2 injection would reach 50 percent. The total amount recovered in some reasonable time period is likely to be lower than the total listed, however.

Not all fields will be large enough to warrant the investment required, and sufficient CO 2 may not be available. Even so, the experience gained in operating CO 2 EOR projects in west Texas over the last three decades has advanced the technology significantly. EOR projects can now be undertaken with confidence that high-pressure injected CO 2 can displace oil efficiently in the zones that it invades.

Oil Reserves annual U. Conventional light oil proved reserves b. Natural gas liquid proved reserves c. Light oil EOR d. Heavy oil EOR b. Residual zone EOR c. Undiscovered conventional onshore b. Undiscovered conventional offshore b. Undiscovered EOR onshore b. Undiscovered EOR offshore b. Reserve growth conventional recovery b.

Reserve growth EOR b. Tar sands b. Oil shales e. An extensive infrastructure of pipelines in west Texas delivers CO 2 to numerous oil fields. Much of that CO 2 is transported by pipeline from natural CO 2 sources in Colorado and New Mexico, though there are also significant EOR projects in west Texas, Wyoming, and Colorado that make use of CO 2 separated from natural gas instead of venting it to the atmosphere. The pipeline infrastructure demonstrates CO 2 transport technology that would be needed to support large-scale geologic storage of CO 2.

These projects also allow assessment of whether injected CO 2 has been retained in the subsurface Klusman, For example, measurements of CO 2 seepage at the surface above the Rangely Field in Colorado indicate that the rate of CO 2 escape from the storage formation is very low less than tonnes per year over an area of 72 km 2. If CO 2 were more widely available in the future at a reasonable distance from existing oil fields as a result of limits on CO 2 emissions, more widespread use of CO 2 EOR could be.

Heavy oils are difficult to displace; hence, typical primary recovery of oil from such reservoirs is much lower than that of lighter oils. Heavy oil is typically recovered by injecting steam, which warms the oil and reduces its viscosity so that it can flow more easily into production wells. Steam for injection is typically generated by burning a portion of the oil produced or by burning natural gas in areas where air-quality restrictions limit use of the crude oil as a fuel.

This technology is now relatively mature and has been applied widely in heavy-oil fields in California, for example. Dissolving CO 2 in heavy oil also reduces its viscosity, but the use of CO 2 to recover heavy oil has not been tested in field projects. Residual zone EOR refers to the possibility that some of the oil that is found in the transition zone between water and oil at the base of a reservoir can also be recovered by CO 2 injection.

This process is less well proven and likely more expensive than CO 2 injection in zones that have less water and more oil present. The estimates of undiscovered conventional and EOR resources in Table 7. The estimates shown for technically recoverable resources are 33 percent of those amounts for conventional recovery and an additional 17 percent for EOR.

Reserve growth refers to the observation that the amount of oil listed as proved reserves often increases over time; information obtained through development drilling in the field is used to refine initial estimates of oil in place. There is currently no significant production of oil from tar sands in the United States, as the U. There is a much larger resource of tar sands in Canada, however, and it has shown significant growth in production. The largest oil resource listed in Table 7. The estimated overall resource is very large 1. There is currently no production of oil from shale in the United States, though a new process for in situ retorting based on electric.

Environmental impacts associated with mining, limitations on availability of water for processing, and potential demand for electricity to be used for in situ retorting must be assessed before better-constrained estimates of recoverable quantities of oil from shales can be assembled. Also, current cost estimates for shale oil recovery are not well defined. In the absence of CO 2 capture and storage, production of oil either by enhanced oil recovery methods or by conversion from tar sands or oil shales emits more CO 2 than does conventional oil production.

This is shown in Figure 7. As an example, fuels from tar sands may ultimately emit about 40 percent more CO 2 than do fuels from conventional oil, 7 though the ranges of estimated emissions indicate that there are significant uncertainties in the values reported.

These emissions can in principle be mitigated by large-scale carbon capture and storage CCS , as noted above, or by the use of low-carbon technologies for process heat and hydrogen production. In addition, both surface mining and in situ production of tar sands disrupt large land areas, as would surface mining of oil shales, and the amounts of water required to process the fuels will also be a constraint in some areas. Thus, there are significant environmental issues associated with the recovery and processing of some of the unconventional hydrocarbon resources.

Although the U. One is the decline in production from existing fields. The decline rate varies from field to field, but it is everywhere significant. For example, the EIA assumes that currently producing fields decline at the rate of 20 percent per year. New fields are assumed to peak after 2 to 4 years, stabilize for a period, and then decline at the 20 percent rate EIA, b. While the National Petro-. For a discussion of emissions associated with various fuel conversions, see Chapter 5. Emissions of CO 2 result from the use of significant quantities of natural gas to provide process heat for separating the hydrocarbons from the sand and for making the hydrogen needed to upgrade the oils.

These emissions could be reduced significantly in the future if nonfossil sources of electricity and process heat, such as nuclear, were used in the recovery and conversion processes. The other factor that determines production is the ability to develop the resources listed in Table 7. This, in turn, depends on three key variables:. The pace at which technology can access increasingly challenging types of resources.

After , the application of new methods will be required to offset the inevitable decline in production from existing large fields in the United States. NPC cites 11 significant technologies under development that should be available between and to meet this need see Box 7. The expansion of CO 2 EOR is technically feasible, but it will depend on the availability of significant additional quantities of CO 2 see the discussion on carbon capture from power plants, for example, elsewhere in this chapter and on whether the infrastructure to deliver that CO 2 to the oil fields can be built.

Developing U. The domestic resource base is lodged in geologic formations that make extraction more difficult, and they are often smaller and therefore harder to find than the more easily developed fields of the past. Substantial advances in technology have been made in the past few years, however.

For example, deepwater offshore oil production has compensated for declines in shallow water offshore and in Alaska production. Natural gas production from unconventional resources now accounts for more than half of total domestic production. And the shift from two-dimensional to three-dimensional seismic technology has increased exploration-drilling success rates by 50 percent over a year period Bohi, This trend toward more sophisticated technology must continue if domestic production rates of oil and gas are to be maintained, much less increased.

Because essentially all of the technology that will be relevant before is being developed by the private sector, the AEF Committee has not conducted an independent assessment of the oil exploration and production technology. The critical technology need in oil production is the ability to manage fluids in complex underground reservoirs.

These fluids involved are both the crude oil itself and materials such as CO 2 that are used in enhanced oil recovery. In the view of committee members familiar with oil exploration and production, this summary table and the more detailed discussion in the topic paper is a reasonable reflection of the status of development.

In general, it appears that these technologies, if developed successfully, will support the pace of resource development shown in Table 7. In the case of natural gas, the chief technical challenge is to develop the resources contained in gas shale and other low-porosity formations. The necessary technologies involve the ability to drill horizontal wells and to fracture the shale formation to allow the natural gas to flow to the bore hole. These technologies advanced very significantly in the early years of this decade, which led to substantial increases in natural gas production from shale.

Economic feasibility. The cost of exploiting alternative resources increases as they become more challenging essentially from the top to the bottom of Table 7. Oil prices are set in a world market, even though the world price may be influenced by the actions of major producers, and historically, oil prices have been quite volatile. Such volatility can be a disincentive to the large and long-term investments needed to find and produce oil from technically challenging and increasingly costly resources.

Access to resources. Although predicting the level of domestic production that results from the confluence of these factors could be considered speculative, the EIA has estimated how oil production might be affected by changes in them. Notwithstanding the considerable uncertainties involved in these estimates, it seems clear that the level of net domestic oil production is relatively insensitive to favorable developments in technology, higher world prices, and access to new resources.

This is not to say that these factors are unimportant. Rather, it seems appropriate to conclude that because of the decline in currently and future producing oil fields, maintaining domestic production at something like current levels is a very challenging assignment. As a result, reducing consumption is likely to be the most important factor in decreasing domestic dependence on oil as an energy source. Considerable caution should be used in interpreting Table 7.

For one thing, the cases are not additive. In some instances, they involve arbitrary changes to parameters in the reference case, and assumptions about physical properties are not explicit. The high-oil-price case is not built up from a cumulative supply curve in the EIA estimating procedure and thus should not be thought of as representing actual economics. Other sources offer different projections, but because the EIA reference case appears to lie near the middle of the range it is useful for comparison purposes. EIA Alternative Cases a. See Appendix E of each document for a description of assumptions.

For the foreseeable future, U. Although this committee has not attempted to evaluate non-U. These uncertainties are reflected in the range of production estimates from various publicly available sources. According to an NPC review of estimates for , world oil production could range from 90 to million barrels per day, as compared with about 85 million barrels. Other publicly available projections are consistent with these EIA estimates. See, for example, IEA a. Data from private-sector sources oil companies and consultants available in the NPC data warehouse are, if anything, somewhat less optimistic.

The World Energy Outlook reference scenario projects oil production at million barrels per day IEA, b. In any case, countries that have much larger production potential than the United States does can more easily increase or decrease oil production by the amount potentially obtainable from U. It is for this reason that this country is more likely to be a price taker than a price setter. Unlike the situation with oil, the United States currently produces most of the natural gas it consumes see Table 7. Moreover, its imports are almost entirely from Canada, with the result that North American production is able to meet North American demand.

If increased U. If not, natural gas imports would increase and at some point could result in significant economic and security risks, much like those that presently exist in the oil market. As noted in the following discussion, whether the United States can or cannot increase its domestic production of natural gas is not yet clear. Significant conventional gas resources are located both offshore and onshore, although much of the offshore resource is in deep water.

Nonassociated conventional resources are not physically mingled with oil deposits. Unconventional gas resources are of three types. Tight gas sands and gas shales are formations with low porosity and thus require technology to fracture the structures for the gas to flow to producing wells. Coal-bed methane is natural gas trapped in coal deposits. Natural gas hydrates not included in Table 7.

Estimates of the total global resource range from 1 to times the world resource of conventional natural gas NPC, , Topic Paper 24; Ruppel, Hydrates are materials in which water molecules form cages that can contain a guest molecule, in this case methane. Forming at temperatures above the freezing point of water and at high pressures, they are found in many ocean sediments around the world and in locations in the Arctic where land temperatures are low. Methods for recovery of hydrates are under investigation. Whether any recovery method can produce at rates large enough to allow commercial production over an extended period and with acceptable environmental.

Source: EIA, b, Table Does not include Alaska or off-limits OCS areas. A for additional discussion. Thus, while the resource is potentially large, it is unlikely to contribute significant production of natural gas by unless significant progress is made on developing economically feasible and environmentally acceptable recovery processes.

As is the case with oil, natural gas production levels are constrained by the tension between declining production from existing fields and the difficulty of bringing on new production. The EIA estimates that declines in natural gas fields are typically 30 percent per year, somewhat greater than the estimate for oil.

And as with oil, the issues of technology, economics, and access determine the ability to bring on new production. Included in the proved reserves and estimates of technically recoverable resources are significant amounts of natural gas from unconventional geological formations tight gas sands, gas shales, and coal-bed methane. Better than half of current natural gas onshore production comes from these resources, and they will remain the principal source of new production for the foreseeable future see Figure 7.

Producing from these formations does require advanced technology, though many of the methods being developed for oil production also are useful for natural gas production. Especially important for natural. Energy Information Administration reference case for U. The price of natural gas has been volatile and will likely remain that way. This committee has not been able to develop a supply curve for natural gas production from publicly available data.

However, it appears that at the lower end of the recent natural gas price range the production of gas shales and perhaps of some deepwater offshore resources is not economic. At the high end of the range, the private sector seems willing to invest in all of these types of gas resources. Potential natural gas reserves have until recently been off-limits along the Atlantic and Pacific coasts and in the eastern Gulf of Mexico.

Their current status is in flux. Because limited data are available for evaluation of these areas, estimates of future production are necessarily uncertain, as with any estimate of undiscovered resources. Natural Gas Production trillion cuibic feet in Various Years. Note: These estimates are subject to the same cautions as those regarding the earlier estimates for oil.

Note also that private-sector estimates reported in the NPC database seem somewhat less optimistic. For example, the maximum estimate for among international oil companies is See Appendix E of each document for a description of the case assumptions. Although the level of domestic production resulting from the confluence of these factors remains speculative, the EIA has estimated how natural gas production might be affected by changes in them.

According to these EIA estimates, maintaining domestic natural gas production, much less raising it above current levels, is challenging. However, resources in the OCS and new gas shale formations may have a significant upside production potential. Technology has recently made feasible the production of natural gas from shale formations in the Rockies, Mid-Continent, and Appalachian regions. Wood Mackenzie data Snyder, , for example, suggest a possible increase on the order of 3 Tcf per year by , a level that can be maintained for several years. Note that Figure 7. Shale gas is projected to contribute 3.

This represents a doubling of shale gas production from Table A1 of the update shows declining natural gas imports between and , suggesting that domestic supplies are robust over the period. Unlike oil, U. But there is a growing world market in LNG, and if growth in domestic demand for natural gas exceeds growth in supply even with expanded natural gas production from gas shales, for example , the United States may find itself beholden to that global market. In that case, increases in domestic demand would have to be satisfied, increasingly, by imports. Most of these imports would likely be in the form of LNG, which would require large capital investments in port facilities and regasification infrastructure.

Moreover, global movements of LNG would increasingly result in a globally determined price for natural gas. Oil and gas exploration and production have been off-limits in some parts of the United States for a variety of policy reasons. Some 12 percent of U. In late , the president and Congress removed restrictions on access to previously restricted sections of the U.

But how quickly offshore development will proceed, if it proceeds at all, is difficult to determine. For one thing, Congressional or Executive Branch action to reimpose the access ban remains a possibility. For another, individual states can intervene in development programs even without overriding a federal approval of a project—by preventing the oil or gas from coming on shore, for example. And the cost and technical difficulty of developing many of these resources can be significant Durham, Thus the offshore access issue may remain an open policy question, at least for a while.

Accordingly, this section provides background to help address that question. Recent prices in Japan have also been influenced by shutdowns of nuclear power plants pending review of earthquake safety. It is not clear how long these shutdowns will continue and what the natural gas price will be if demand for natural gas for electric power generation in Japan declines as a result of nuclear power plants going back on line. Inaccessible a. Accessible with restrictions a. Accessible standard lease a.

Total resources a. Source: See www. The NPRA estimate 9. Comparison of these numbers with the scale of oil use is instructive: world oil consumption was about 85 million barrels per day 31 billion barrels per year ; U. For natural gas, the corresponding numbers are world natural gas consumption at Tcf, U.

The estimated undiscovered oil resources, which total The total gas resources listed, however, are not included in the natural. The resources listed as inaccessible are those that are estimated to lie within areas where exploration and production have been prohibited. These include lands that cannot be leased as a result of congressional or presidential action including national parks, national monuments, and wilderness areas ; lands that are not available for leasing based on decisions by the federal Bureau of Land Management historical sites and endangered species habitats, for example ; lands that are undergoing land-use planning or National Environmental Policy Act review; and areas that can be leased but with no surface occupancy directional drilling might be able to access some resources, in which case they are included in the category of accessible with restrictions.

Restrictions may include limits on drilling during a portion of the year or stipulations that require mitigation plans or exclude some areas within the lease from drilling. Operations in areas for which standard lease terms apply must observe pertinent environmental laws and regulations. The largest undiscovered resources are estimated to be located in the restricted portions of the federal OCS. These estimated gas resources are in addition to those listed in Table 7. The estimated oil resources in Table 7. The combined estimates of conventional onshore and offshore oil in areas that are now inaccessible or have been so until very recently comprise 32 percent 19 billion barrels onshore oil [ Table 7.

As Table 7. The estimates of undiscovered gas resources in the inaccessible areas 94 Tcf onshore [ Table 7. There is considerable uncertainty in these estimated volumes, as with any figures that purport to measure undiscovered resources. Geophysical data used to refine such estimates were last collected 25 or more years ago for the Pacific coast, the Atlantic coast, and portions of the eastern Gulf of Mexico.

Since then, significant advances have been made in seismic technology, which could allow more accurate estimates of the size and location of potential accumulations. There is similar uncertainty in the rate of production that might be obtained from these areas if exploration and production were permitted. Offshore developments in deep water typically require extended time periods during which to begin production 5—7 years or more if exploration is successful and more time to ramp up to full-scale production.

But even without considering new producing provinces, the substantial technology development for production in deep waters of the OCS—where leasing and drilling have been under way for some time—is projected to have a significant impact on U. For example, in its reference case, the EIA projects that deepwater Gulf of Mexico conventional oil production will increase from about 1 million barrels per day in to a peak of 2 million barrels per day sometime between and , declining thereafter to 1.

These quantities are similar to those being contemplated for production of liquid fuels from coal or biomass—see Chapter 5. That increase in production, in turn, leads to a projected increase in total U. Thus the increase in deepwater production more than offsets continuing declines in Alaska production and shallow offshore production, but only for a time. If leasing and development proceed in OCS areas that were previously off-limits, the technology improvements that have proved successful in deepwater Gulf of Mexico areas could be applied in those OCS areas as well.

It is important to recognize that these estimated increments reflect both the increased production in the specified areas and the declines in production elsewhere. EIA estimates made in EIA, showed somewhat larger estimated production for ANWR, with assumed production starting in and peaking at , barrels per day in While any additional oil production has some impact on oil price, as well as an obvious impact on the amount of oil imported into the United States, most observers have argued that the impact on oil price of net incremental U. Projected total production increases are modest compared to world demand about 85 million barrels per day at present ; they are projected by the EIA to grow to 96 million barrels per day in and million barrels per day in EIA, d.

Oil prices are set in a global market, and both supply and demand depend on price, though supply responds slowly to high prices and demand usually responds faster. Short-term oil price volatility observed in recent months is a reflection of this dynamic, at least in part. But it is not known whether remote or offshore production will compete on costs with other sources of supply around the world, nor whether such resources will be developed in the first place, given the uncertainty as to future oil prices supporting development.

Similar reasoning suggests that the impact of increased OCS production on world oil price in the long term would also be small. It is possible that natural gas markets, which are becoming more global but still maintain regional differences, will respond differently to the potentially higher production quantities, although the magnitude of any response is uncertain Baker Institute, The EIA estimates summarized in Table 7.

A related discussion is under way concerning the potential environmental risks of developing oil or gas resources in locations such as the ANWR area, the National Petroleum Reserve, or the formerly restricted OCS. Technology improvements such as long-reach directional drilling have reduced the area required by surface facilities for drilling and production, but some surface impact is inevitable. Similarly, the use of subsea completions for deepwater oil and gas production, pipeline delivery of fluids to shore in place of tankers, and attention to modern MMS environmental regulations governing platforms have reduced the potential for adverse impacts in offshore production.

However, there will always remain some risk, whether at the platform or at the land end of the undersea pipeline. In addition, close-in platforms have visual impacts. In addition to the OCS and federal land resources discussed in this section, the increased interest in natural gas production from shale formations may create a need to balance energy and environmental values regarding this resource.

Large shale formations in the mid-Continent and the Gulf Coast e. Infrastructure exists in these areas, and public opinion is probably open to additional gas production. However, the Marcellus shale in Appalachia is spread over a wide area, where lack of infrastructure and fragmented land ownership make production from this area more challenging Snyder, Anthracite and bituminous coals have the highest energy and carbon content, whereas subbituminous coals and lignites have lower energy content and larger moisture and ash content NRC, , Box 4.

The table indicates that the United States has about 20 years of reserves in active mines, but a much larger resource would be available for production if new mines could be opened and if the rail infrastructure required to deliver coal—or, alternatively, if sufficient long-distance transmission lines for delivery of electricity generated at the mine mouth—could be put in place.

Costs of coal production vary widely with geographic setting and the type of mining, but it is clear that costs are low enough that substantial quantities of coal can be produced at current coal prices. Coal Annual U. Production: 1 billion tons a. Recoverable reserves in active mines a. Recoverable reserves a. Demonstrated reserve base a. Identified resources a. Proved Reserves b. It concluded that:. Federal policy makers require accurate and complete estimates of national coal reserves to formulate coherent national energy policies.

Despite significant uncertainties in existing reserve estimates, it is clear that there is sufficient coal at current rates of production to meet anticipated needs through Future policy will continue to be developed in the absence of accurate estimates until more detailed reserve analyses—which take into account the full suite of geographical, geological, economic, legal, and environmental characteristics—are completed. Even given the uncertainties in resource estimates, the United States likely has sufficient coal to meet projected needs.

However, of all the fossil fuels, coal produces the largest amount of CO 2 per unit of energy released by combustion—about twice the emissions of natural gas, but can vary depending on coal rank—and mining has significant environmental impacts, which will limit its suitability for some locations. In any case, the estimates in Table 7.

The United States is not running out of oil anytime soon, but domestic oil pro duction rates are unlikely to rise significantly. However, U. Even with new technology, higher prices, and access to currently off-limits resources—none of which is certain—maintaining current production levels will be challenging. The United States is not running out of natural gas anytime soon, and with favor able circumstances, domestic production could meet most of the domestic natu ral gas demand for many years. Unconventional sources of natural gas are technically recoverable and appear to be large enough to meet domestic demand for several years.

Doing so, however, would require both relatively high prices and moderate demand growth. Unconventional oil from U. A large oil shale resource exists in some of the western states, but production from these reserves awaits technology demonstration and is highly unlikely before Crude oil production from Canadian tar sands is feasible now and likely to grow before , but this resource has a larger carbon footprint than conventional resources have. Canadian tar sands production was 1. But with current technology, fuels derived from tar sands ultimately emit 15—40 percent more CO 2 than do fuels derived from conventional crude oil see Farrell and Brandt, Coal is abundant in the United States.

Despite significant uncertainties in existing reserve sizes, there is sufficient coal at current rates of production to meet anticipated needs through and well beyond. More detailed analyses will be required, however, to derive accurate estimates of the impact of enhanced production on reserve life. There are also geographical, geological, economic, legal, and environmental constraints on the future use of coal. Changes in U. Because U. However, because U. Greater domestic natural gas demand could boost U. If gains in production of natural gas from shales are not sufficient to meet heightened U.

Eventually, LNG imports could grow to a point that linked the U. Although domestic coal reserves are ample to and beyond, upward price pressures may exist. Growth in demand for electricity from coal-fired power plants, potential use of coal for producing liquid and gaseous fuels, the cost of opening new mines, and growth in export markets are examples of such pressures. According to the EIA, U. The EIA has also made a projection of electricity generation in using its computer models, assuming a continuation of trends that were evident as of The EIA reference scenario is not a prediction.

The agency has published data showing its performance over the years in projecting actual generation EIA, e , and the committee has reviewed this record for year electricity projections. But these projections were made dur. Total emissions of all such gases were just over 7 gigatonnes of CO 2 equivalents, of which CO 2 itself accounted for about 85 percent; methane and nitrous oxide accounted for most of the rest. CO 2 emissions associated with energy consumption as distinct from agricultural and other sources accounted for 80 percent of all U.

CO 2 emissions from electricity generation were dominated by coal 83 percent , but overall, the burning of coal for electricity accounted for only 27 percent of all U. Dividing the figures in Table 7. Investor-owned utilities and independent power producers face difficult choices at present. They must invest in new power-generation assets to meet future demands for electricity and to replace some portion of the existing fleet of power plants as they are retired, but they must also consider what will happen if constraints.

Financial institutions are wary of lending for coal-fired power plants that do not include provisions for capturing CO 2 , and some states have recently indicated that they will not approve the construction of coal-fired power plants without CCS. But some public utility commissions, which see their role as protecting consumers from unwarranted price increases, are reluctant to include the cost of such facilities in the rate base, absent a regulatory requirement.

Construction costs have risen rapidly in recent years, thereby increasing the capital cost of any power plant. Department of Energy DOE -sponsored project FutureGen, which was to have demonstrated a coal gasification plant with carbon capture, was canceled at this writing because of high projected costs in favor of an alternative vision of supporting incremental carbon capture projects at several plants. At present there are no obvious choices as to the best designs for CO 2 capture. Meanwhile, although capital costs for natural gas plants are a fraction of those for coal or nuclear plants, the price of natural gas has increased substantially above historic levels and has shown some of the volatility of recent oil prices.

Thus, the best choices among options for generating electricity are not at all clear at present. The answers to the following three questions will determine the future of fossil-fuel power in the United States over the coming decades:. Will the United States undertake a large effort to reduce CO 2 emissions? Will the domestic natural gas price be close to its highest recent value or its lowest recent value?

By , decision makers will probably have sorted out the first question. It is inconceivable that CCS will prosper if there is not a large effort to reduce CO 2 emissions, because unless a significant cost is imposed on CO 2 emissions at a power plant it will nearly always be less expensive to vent the CO 2. The committee assumes here that government will formulate policies to reduce CO 2 emissions, thereby spurring already-existing technologies for generating electric power with reduced CO 2 emissions. The committee focuses here on pathways that deploy such technologies.

With a significant suite of demonstration plants, the country can also sort out the second question. Not enough is known yet to demand that all new plants be equipped with CCS, but much can be learned in the next decade. The answer to the third question depends in part on the extent to which the U. That, in turn, depends, again in part, on the future role of natural gas in electric power generation.

Thus the future mix of uses of natural gas and coal for electric power generation will depend sensitively on a combination of the constraints on carbon emissions, the costs of fuels, and the costs of conversion technologies. In particular, whether coal plays a larger or a smaller role in future electric power generation will depend strongly on whether CCS can be applied at the scale of many large power plants. To examine these questions, the committee considers below three types of power plants: supercritical pulverized coal PC , integrated gasification and combined cycle IGCC coal, and natural gas combined cycle NGCC.

For large U. The committee focuses on coal here but notes that biomass can be substituted for limited quantities of coal in PC and IGCC plants without major changes in plant design. This approach can help alleviate limits on biomass conversion plant size arising from the need to collect biomass over a wide area and from seasonal availability.

Biomass can also be used as a feedstock. PC plants use boilers to produce steam, which drives turbines to produce electricity. In its current form, this technology has been in use for over 50 years and continues to be improved. PC technology has progressed from subcritical to supercritical to the latest ultrasupercritical boilers; this is a designation that refers to the temperature and pressure of the steam, with higher values bringing higher efficiencies. As power plant conversion efficiencies increase, the amount of CO 2 emitted per unit of electricity generated declines.

Figure 7. Efficiency improvements of 1—3 percent are also possible through modernization at existing coal plants, but the required capital investment may not be attractive given other priorities. A succinct discussion of these and other variations. In either case, any CO 2 captured and stored leads to a reduction in atmospheric CO 2 concentration because the carbon present in the biomass was removed from the atmosphere by photosynthesis. A power plant that uses a mix of coal and biomass can therefore have zero net carbon emissions, or even negative net emissions.

In principle, CO 2 can be captured from any of these PC power plants. Doing so requires use of some of the energy that would otherwise have been used to generate electricity; this fact is reflected in a reduction of the conversion efficiency of the plant. The diverted energy is used to separate CO 2 from the solvents used to capture it, to compress the CO 2 , and for the power needed to move CO 2 and solvents through the plant.

See Annex 7. A for a description of some of the processes used to capture CO 2 from power plant combustion-product gases. The second approach, IGCC, is a technology for electricity generation that produces gas from coal to drive a high-efficiency gas turbine, whose hot exhaust then drives a smaller steam cycle similar to that of PC.

The high-efficiency gas turbine process, which evolved from jet engine technology, can use either air or oxygen; the separation of oxygen from air at the front end creates a gas stream. Thus, for capture plants, there is no nitrogen to separate from the CO 2. Coal is converted in a reducing atmosphere to a gas known as synthesis gas, or syngas, which contains carbon monoxide CO , CO 2 , hydrogen H 2 , water vapor H 2 O , and traces of other components such as H 2 S arising from the sulfur in coal.

The two gases are then separated, power is obtained from a gas turbine burning the H 2 with a diluent added to reduce the combustion temperature , while the CO 2 is pressurized and sent off-site for storage. Oxygen gas from an air separation unit can also be used to burn pulverized coal directly, a process that is known as oxyfuel combustion.

In that case, the combustion products from electric power generation are CO 2 and water, plus small amounts of contaminants. In effect, the cost of air separation at the front end to produce O 2 for combustion is traded off against the cost of separation of CO 2 from N 2 at the back end. Both separations require additional capital and reduce net electricity generation. Removing the N 2 from the flow reduces the amount of flue gas, but some recycling of CO 2 is required to control combustion temperature.

Another option, known as chemical looping, is also being investigated as a way to separate O 2 from N 2 and thus to avoid a subsequent separation of CO 2 from N 2 see Annex 7. A for a description of this approach. At present, the separations are thermodynamically rather inefficient, and they represent the largest component of the incremental costs for CCS Dooley et al. A for examples that compare capture costs with those of compression, CO 2 transportation, and injection.

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Because there is significant potential for improving the efficiency of capture and reducing both the costs and the energy penalties associated with capture, this area is an important component of research on CCS. For example, the current DOE program for research to improve separation technologies includes work on improved solvents, materials for mem-.

Gasification can also be the first step toward the production of synthetic transportation fuels synfuels or synthetic natural gas SNG. In these cases, the shift reactor is used to tune the H 2 :CO ratio for optimal synthesis. See Chapter 5. In an NGCC, natural gas is combusted in a high-efficiency gas turbine and the hot exhaust gases raise stream that is used to run a steam turbine. The committee chose those comparisons as a way to simplify a multifaceted discussion and because more cost data are available to support the analysis for PC and IGCC plants compared with, say, oxyfuel plants.

The question of whether and how much to charge for resource use is a key issue for the policy maker. Certain national resources, such as geothermal and hydro, are held in trust for the benefit of the populace. To allow their development without receiving payment from the developer may prove a political impossibility in some jurisdictions yet it is the energy users in the populace who, in fact, are paying for the resource use, although indirectly.

Moreover, the government will have expenses in establishing a resource regulatory regime. By establishing a payment requirement on the developer the government may be able to fund these regulatory costs - again at the price of imposing an indirect tax on the electricity user. The policy maker should be mindful, however, that any solution which imposes different costs on different classes of energy generators will change the competitive cost of delivered power.

What fiscal incentives to promote renewable resource development are available to the legislative drafter? The following are some of the legislative mechanisms that can be promoted depending upon the structure of the electricity system and the goals and objectives within a country. Impose a tax on sales of electricity generated from carbon-based fuels with resulting tax revenues dedicated to development of renewable resources.

Carbon-based tax. One option may be to tax sales of electricity generated by polluting fossil fuels and use the revenue to pay a premium to generators utilizing non-polluting renewable energy sources. Collaborative financing approaches. The government may also elect to step up efforts to assist private developers in securing financing or credit support from the multilateral development agencies. These agencies recognize the need to encourage the development of non-polluting and indigenous sources of electricity in emerging nations. With the participation of the large multilaterals, governments may be able to induce local lending institutions and capital markets to participate in financing.

The more participants in a project, the more risks are shared. In market regimes which do not enable long-term power contracts, the lending community sees significant risk. One can envision a renewable energy, merchant plant project finance scheme in which venture capital provides 30 percent equity and 70 percent debt is shared among a consortium of local banks thus significantly reducing local currency exchange issues and more traditional lending sources. This approach could include guarantees by a partnership between the national government and one or more multilateral development agencies.

Guarantees by the development agencies, which are, in fact, created to provide funding for risk situations others will not finance, will go a long way towards making such financing of merchant plants possible. Increase the role of the government in convincing multilateral development agencies to play a more active role in the financing of renewable energy projects.

Credit mechanisms. Revolving funds consist of a dedicated pool of monies contributed by the government for the purpose of providing debt or equity capital for investment in renewable resources projects. As funds are invested and repaid including a rate of return which approximates market conditions the fund grows, thereby facilitating financing of more projects. Create a national guarantee fund or revolving fund which is available as credit support to all qualified developers of renewable energy facilities.

Feebates or environmental dispatch. The difference between the pollution index and the feebate is that the pollution index is not necessarily revenue neutral. Both the feebate and environmental dispatch mechanisms can be instituted at either the state or national federal level and both are compatible with either a monopoly or market-based utility model. Both mechanisms affect all generation resources sold in the wholesale market, and internalize environmental costs in the short-term as well as the long-term market.

The challenge in establishing either of these mechanisms is the difficulty of agreeing on a set of specific pollution indices environmental externality values. Provide fiscal incentives that will allow renewables to compete in an open-market system. Fiscal incentives. Fiscal incentives will always serve to attract private investors. They make renewable energy projects more financeable by reducing the capital costs and thereby providing greater comfort to the lenders that there will be sufficient revenues to pay the debt.

Examples of fiscal incentives are: accelerated tax depreciation, removal or reduction of trade barriers on renewable energy equipment and investment-tax credits for capital costs. Government purchase. One of the strongest forms of influence is by example. If government entities such as schools, hospitals, government buildings and water districts, use electricity from renewable sources, this usage sets an important example for others. It also allows people to gain direct experience in working with various types of renewable energy facilities.

Require government agencies and institutions to purchase some or all of their power from renewable resources. Mandate that distribution companies have a minimum amount of their load met by renewable resources. Portfolio standard. The government may mandate that all distribution companies have a certain amount of renewable energy capacity in their portfolio by requiring them to enter into long-term power purchase agreements with renewable energy project sponsors. These contracts could be for a term of years, renewable at the option of the distribution company.

The distribution companies would be able to enjoy the economic benefits of a renewable project after its capital costs have been retired, a potentially valuable hedge in the event of an increase in the wholesale market price for electricity. Appendix D contains a more detailed explanation of the renewables portfolio standard approach.

Since regulators implement the law, regulatory actions become the framework within which electricity sector investments are made. The business community looks for a constant set of regulations and guidelines upon which investment decisions depend for their viability. This section deals specifically with economic regulation and the regulation of natural resource use. Environmental regulation can also affect the electricity sector, but is outside the scope of this paper.

When is Government regulation necessary in a competitive environment? Economic regulation. When some or all of the electric industry functions are privatized or capitalized, or where competition is otherwise introduced into one or more of the electricity functions, the need for independent regulation emerges. The goal of regulation is the promulgation and preservation of the public interest. Privatization and Capitalization. One can bring new private-sector money in to dean up, re-power, and replace an existing government-owned electricity system base by restructuring the electric sector to allow the sale, in whole or part, of existing faculties to private-sector investors.

Governments can either rely exclusively on the profit motive to ensure the desired upgrades, or they can couple the sale with the condition that revenue will in part be piled back into the requisite up-gradation. In either event, the sale of such facilities ends the existing government-monopoly structures.

Privatization may or may not involve me structural unbundling of the vertically integrated utility and may or may not introduce competition into the utility system. Privatization alters the means of monitoring managerial behavior. Privatization of a monopoly industry also involves development of a regulatory structure to correct market imperfections and to prevent abuse of monopoly power. The private investor administers or manages the new corporation as its single largest stock holder.

Under the capitalization scheme, the capital remains with the company and can be entirely channeled into new investment and production. This is a less commonly used mechanism than privatization. What type of government organization administers regulations? In many of the countries that are just introducing competitive markets into the electricity sector there is little regulatory experience. Experience indicates that in virtually every electricity sector that is attempting to move to a fully competitive market type, some independent system of regulation or oversight has been necessary to guide this new market to ensure competition actually develops.

Frequently governments determine that separate regulatory agencies are best suited to implement regulation. In theory, regulatory bodies are quasi-independent of the other branches of government, looking to legislatures for their broad scope of authority and funds, to the governor, minister or the people for appointment or election, and to the courts for support of appeals. In practice, such quasi-independent regulatory bodies, although susceptible to political pressure from a variety of sources, tend to be more independent and better informed about implementation issues than legislative bodies.

Regulatory commissions also serve as arbitrators who settle disputes that necessarily arise from time to time concerning contractual relationships among the key stakeholder groups. This Manual does not attempt to discuss all the aspects of developing an effective independent regulatory regime. Rather, the guiding principles are highlighted and regulatory activities specifically related to the development of independent investments in the electricity sector and specifically renewable generating facilities are noted.

How does the economic regulator design a regulatory regime to promote renewables while protecting other public interest issues? The policy strategist designs regulations to promote developmental investment in the renewable energy resources, while simultaneously establishing reasonable standards for the protection of the people and the environment of the country. In most cases the basic policy goals and directions are established through the legislative process then implemented through the regulatory process.

Workable rules and regulations coupled with training of regulators and their staffs are critical components of an effective regulatory regime. How does the resource regulator design a regulatory regime to promote renewable resource development? Every experienced investor understands that the laws of a country are only first-level indications. Sometimes, for example, a development incentive which has been established as a matter of policy - in a law - has never been implemented as a matter of practice - in a regulation.

Regulations must prevent waste and ensure the environmental integrity of the resources while they are being developed. What works in one country will not necessarily work in another. Regulations should not prematurely attempt to duplicate a regulatory system in place in a country which has extensive renewable resource development. Inspection and reporting requirements add to the costs of a project and thereby may dilute its economic viability. The following guidelines for developing renewable energy resource regulatory policy provide a reference for the policy strategist.

Clarify the policy position of the Government. In drafting regulations, the threshold step for the policy strategist is to articulate the goal of the legislation which underlies all implementing action. Then, in order to ensure that the legislative goal is enabled, it is essential that the policy strategist articulates a conceptual objective for the regulations consistent with the legislative goal.

In other words using a geothermal example , if it is dear that a safe and sound blowout prevention program is required, and if the conceptual objective is to minimize direct governmental participation, the regulations and norms may be directed to establishing compliance standards, penalties for non compliance, and bonding procedures for restitution in case of an incident rather than to establish on-scene, government oversight Other objectives produce different results.

Determine the organizational structure within the responsible agency. The renewable resource regime may provide a single ministry with the authority to promulgate regulations and to grant authorizations and concessions.

Within this context, it is essential to understand how the designated ministry allocates the promotional and the compliance regulatory functions between itself and its directorates; how the checks and balances - both formal and informal - have been instituted; and how the internal decision-making and appellate apparatuses function. Concomitantly, legislated interfaces among ministries need to be identified. In particular, fine-tuning the relationship between the ministry designated to oversee renewable resource development and other ministries is critical in the drafting of the regulations for the various renewable resources.

Identify other laws with potential bearing on the renewable resource regulations. For purposes of standardization, subject matter to be addressed in regulations should be carefully reviewed to ascertain their coverage in other laws and regulations. The renewable energy resources law and the proposed regulations should be scrutinized and a check list made of issues that may be the subject of other laws or regulations. Pertinant laws or regulations can be cross-referenced or pertinant provisions can be inserted into the renewable resources regulations in parallel language.

For example, such issues as determination of rights of way, establishment of a record registry, and provision of environmental standards may be the subject of other laws or regulations. Establish a policy of regulatory content in relation to subordinate rules. In most countries, regulatory authorities enjoy broad discretion as to the content of regulations and norms. A threshold understanding of the desired allocation of content among laws, regulations and norms will prevent needless over-drafting of regulations.

Draft regulations and subordinate rules as a single package. In many countries, a regulatory regime is a time-tiered system and a regulation must be in place before a subordinate rule is finalized. Nevertheless, for reasons of consistency and understanding of the regulatory concept, a total package should be drafted.

Once drafted, they can be refined in context of regulatory changes, but without seeing and reading a preliminary detailed package spelling out how a regulatory provision is to operate, the ultimate effectiveness of a regulatory concept is difficult to envision. A resources regulatory project designed to attract foreign investment typically includes the drafting of a definitive regulation and an accurate not definitive translation into other languages - English, Japanese, German, etc.

Encourage a team approach. The government of the policy strategist should be encouraged to incorporate persons from the private sector, from sister agencies, and from the legislative branch to participate in an advisory capacity on a regulatory drafting task force. There are potential risks with this approach - e.

Solicit input from industry. In the case of a law designed to promote private-sector development of a resource, the advice of the potential developers whom the law is designed to attract and whom the regulations are designed to regulate is invaluable to the policy maker. Step 9. Allocate sufficient time for the political process. Laws and regulations are not drafted in a vacuum. Political consensus and will to proceed is based on confidence, and confidence-building is a time-consuming exercise.

Sufficient time must be built into the project Step For example, the governments of two countries may concur mat blowout prevention in a geothermal site is an essential regulatory task; nevertheless, the concept of one government that its role as a protector of people requires a regulator to be on site for every well drilled may be at odds with the concept of another government mat the private-sector must be made responsible for self-regulation. What are resource concessions, and how are they granted through the regulatory process?

Viewed in its broadest context, a concession is any right or privilege which a private developer must secure from a government before engaging in a business activity. Governments consistently issue concessions to generate electricity, operate and maintain transmission or distribution systems or operate utility systems in discrete sectors of their country. In many countries governments grant concessions for the right to utilize a water resource or extract geothermal energy.

Some countries may require several concessions to construct, own and operate a generation project. For example, one may need a concession to explore a geothermal resource, and then another concession to utilize the resource for the generation of electricity. In the context of rural electrification, concessions may be offered to private investors allowing them to develop vertically integrated, privately owned electricity systems for geographic areas defined in the concession.

Establish objective criteria upon which the selection of the resource concession award will be based. In attracting private investment for renewable energy development, the structure of the concession is extremely important. For example, concessions may be structured so as to attract private investors, while at the same time the terms of the concession may be structured to assure that the entity holding the concession completes the proposed objectives e.

Regulations need to state objective criteria upon which the selection of the resource concession award will be based. The private investor looks for assurances that the process for granting concessions is fair. What determines the most qualified applicant depends on the nature of the concession and government objectives in granting the concession. In a competitive award process, an objective, qualified panel should apply the criteria. Establish objective, qualified panels or committees to oversee competitive awards. Temporary resource concessions allow candidates for permanent concessions to evaluate project commercial feasibility.

Where concessions are granted for the development of energy projects and include the right to construct, own and operate an electricity generating project, the process typically provides for granting a temporary concession prior to granting a permanent concession. It is in the interest of all parties to allow developers the time and support to conduct thorough project feasibility studies. The purpose of the temporary concession is to give the selected developer sufficient time to undertake more extensive feasibility studies so the developer can assure itself and its investors that the proposed project makes sense in the final analysis.

Temporary concessions, although time limited, are exclusive. For a given project, no more than one temporary concession should be outstanding at any one time. The holder of the temporary concession needs to be assured that it will be entitled to a permanent resource concession for the site, so long as it complies with the terms of the temporary concession. These measures are necessary to ensure that the concessionaire has the proper motivation to expend the funds necessary for a feasibility analysis which is sufficient to satisfy a project lender.

Utilize temporary concessions linked to a permanent concession to allow candidates for permanent concessions to evaluate project commercial feasibility. A concessionaire needs to know what its rights are and what it must do to maintain them throughout the period of the concession. A concessionaire needs complete access to the project site and to all information in the possession of the government regarding the site, so that it can adequately evaluate the project.

An investor will need confidence that if it obtains a permanent concession it will have the legal right to acquire, for fair market value, all land and other property such as riparian rights needed for attaining the objective of the concession. An investor will also look closely at the regulations to see if they provide for a quick and equitable way to resolve disputes between the land owners and the concessionaires regarding the determination of fair market values.

For example, a dispute resolution process may be put into place which allows the concessionaire to proceed onto the property if it places a bond or other security instrument as collateral for the ultimate determination of value. Failure to provide for eminent domain rights leads to situations where an isolated local landowner can unreasonably delay project development.

In the case where a law requires more than one concession to complete a project, the investor will want to know exactly what the process is for obtaining the subsequent necessary concession. Minimize the number of secondary permissions required in concessionary grants. Grants of concessions should minimize the number of secondary permissions required. Concessions are often supplemented by secondary instruments known variously as permits, licenses, warrants, etc. The project developer would like to be assured that, if its proposal conforms to the requirements of the concession offer, it will be able to obtain the necessary permits at all levels in a timely and cost effective manner.

Investors prefer laws which empower a single agency with comprehensive authority over all matters, including permits that are needed to proceed with the proposed project. In many countries multiple agencies require multiple permits and the rules for the issuance of such permits are random - without reference to government objectives in the energy sector.

Such situations have a chilling effect on investment. Non-exclusive reconnaissance permits can effectively attract developers to known resource areas. In resource concessions, establish both the best use of the resource and standards for determining which concession applicant will meet those needs. Governments are usually concerned that development make the best use of the available natural resources.

In some instances, equipment efficiency is the paramount issue, as in the case of hydro and geothermal generation. In other instances, there is a specific task to be performed, such as pumping water or running certain equipment, and so long as the task is accomplished at an acceptable price efficiencies may be a less important factor. The best use of the resource may also involve multiple uses. Country objectives for hydroelectric development may include energy production, flood prevention, irrigation and recreation.

Development of solar and wind projects may need to be consistent with the agricultural uses of the land on which they are located. It is incumbent upon the regulatory strategist to define in each concession what the government considers to be the best use of the resource and to develop standards for determining which concession applicant will best satisfy those defined uses.

While the concessionaire may be motivated by a date-specific commitment to provide electricity under a power sales agreement, the government may establish and monitor timelines. To assure that the concessionaire is working diligently towards construction of the project, the government may require that certain milestones be met by the concessionaire in order to retain its concession rights. It is generally acceptable to the international lending community that the government require security in the form of bonds or letters of credit to assure that the concessionaire is motivated to perform in a timely fashion.

Although viewed from different perspectives, the private investor objectives of a resource concession be met. A second critical element of any resource acquisition process is the power purchase agreement. How are on-grid, renewable projects best solicited in a state-owned or monopolistic utility system? By this method, the utility seeks a specific amount of capacity and purchases the associated energy in accordance with a per-kilowatt-hour formula that normally allows the project sponsor to recover its fuel cost.

The emphasis on fixed cost in all-source solicitations favors the economies of scale of large, stand-alone fossil plants and creates difficulty in comparing resources with dissimilar attributes. All-source bidding solicitations favor thermal projects because the costs associated with thermal projects can be readily determined and are normally not site specific. Thus, a private-sector bid to supply fossil-fired thermal generation can be prepared with comparatively little time and expense.

By contrast, renewable energy projects are normally very site-specific and can require many months of study before cost information can be developed to the point where a bid can be made. The criteria established to determine the winning bid in most all-source bidding programs typically fail to take into account the long-term benefits offered by renewable projects and the different cost patterns experienced in conventional thermal versus renewable projects.

Moreover, a tendency to take a fairly short-term view in weighing the relative costs and benefits of thermal versus renewable projects also impedes renewables. In the case of most conventional thermal projects, per-kilowatt capital costs are low when compared to the typical renewable project. On the other hand, a renewable project may have a zero fuel cost and very low variable costs, while thermal projects have comparatively high and often unpredictable variable costs. Despite these differences, utility power solicitations for renewable energy projects often proceed using the thermal model and base comparative evaluations on an imperfect view of the long-term costs and benefits of the various technologies.

The design of a bidding program will influence the ability of particular technology types to compete successfully. Solicitation and bidding models for renewable energy solicitation. When a utility has determined what it believes to be a fair price to pay for renewable energy, it can then initiate the process of attracting private investors to develop the available resources.

There are generally four solicitation models which have been used: the site-specific bid, the tariff-based solicitation, the site-specific tariff bid, which is a hybrid of the first two, and the negotiated solicitation. Site-specific bid models. In this model, the utility has a specific site or sites and a specific energy source in mind, and asks potential developers to enter a bid for the rights to develop the site -- the lowest bid wins the right to develop the resource. Unfortunately, experience has shown that this approach is not effective in attracting private developers of renewable projects.

Prefeasability studies performed by the host country are rarely specific enough for the developer to undertake more than a sketchy plan for the project. Those developers willing to participate in this kind of a solicitation are compelled to make assumptions based on worst-case scenarios which result in a very high bid price. In fact, most developers have simply elected not to participate in site-specific bid solicitations. The few that do participate submit bids that are either not creditworthy or so high as to be unacceptable to the host country.

This model has created many problems in the Philippines, which has been attempting to solicit firm bids for the development of several hydro sites. Tariff-based models A variation on this model has fueled dramatic increases in the development of renewable energy projects in the United States. In this model the utility undertakes its least-cost planning and determines the rate, or tariff, it is willing to pay for renewable energy resources.

It is critical that least-cost planning take into consideration all benefits and costs associated with various energy fuel sources. Predictably, the use of this model will establish rates which are different as between renewables and non-renewables as well as among the various types of renewables. Most importantly, the utility determines, on a reasoned basis, and after accounting for all benefits and costs, the value of its resources.

Once this price is established the utility offers to purchase a set amount of capacity for the various energy sources at the tariffed price. Assuming developers respond to the solicitation, they will submit applications to develop specific sites.

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The utility can then select the proposals which best meet the criteria established by the utility and award temporary concessions giving the developer the exclusive right to further investigate feasibility and commit to developing the resource. If the response to the solicitation fails to meet expectations, the utility must determine if it is willing to offer a higher price for the resource and issue another solicitation.

Or, the utility may conclude that the resource does not provide sufficient value in the current marketplace based on the originally established criteria and therefore abandon the particular resource until market conditions change. Hybrid, site-specific tariff bid models. Again the utility undertakes least-cost planning and determines the price it is willing to pay for a particular energy source.

This price can then be included in a solicitation for site-specific renewable projects, with the understanding that the price included in the solicitation will be the ceiling price. Developers can then submit bids based on a percentage of the ceiling price. However, this method presents similar problems associated with the first model: the feasibility studies supplied to investors may be based on unreliable or incomplete data, making it very difficult to develop firm bids.

The effort could ultimately prove futile if no bids are received or may even need to be repeated if the received bids turn out to be impracticable. This model begins with a pre-qualification process whereby the utility establishes transparent criteria for qualification. These criteria should include not only technical ability and experience, but factors related to financial capability and the ability to obtain necessary financing for the construction of the project.

pollution under environmental regulation in energy markets 6 lecture notes in energy Manual

Once the participants in the process have been pre-qualified, the utility can then prioritize the successful qualifiers according to another set of criteria. Once the qualified parties are ranked, negotiations can begin with those at the top of the list according to a strict schedule requiring progress on such negotiations. Negotiations must be transparent and arbitrary rankings would need to be prohibited. This model has been used successfully in some counties, but has recently come into disfavor because of perceived or real favoritism in the process.

A verifiable means of assuring transparency is critical to the success of this model. The pre-qualified bidders then submit proposals addressing a discrete set of project attributes and requirements. Bids are evaluated on the basis of price and non-price factors and the bidder with the highest score wins the bid. Certain energy projects are either too small to justify inclusion in a solicitation of utility-grade projects, or are able to deliver energy only on an intermittent basis, and special rules should be developed for these resources. Examples would include small wind machines or hydro projects having a capacity under kilowatts, or larger facilities that serve sizable industrial loads.

Electricity, not the renewable resource, is the product of value. What is the role of power purchase agreements in private-sector development of renewable resources? The success of a country in attracting private capital is directly related to its sensitivity to the way in which private investors generate investment capital in the world markets. In particular, the renewable resource industry uses project financing for grid-connected systems.

The single most important key to project financing is a power purchase agreement. In this agreement, the customer promises to pay a pre-negotiated rate for power and capacity over a period of years, assuming that the generation facility performs as promised. A geothermal energy investor, for example, has to spend money to explore for geothermal resources much the same way one does in prospecting for gold or oil - however, the geothermal prospector cannot export hot steam abroad.

Similarly, the hydropower energy investor has to spend money to create a reservoir and the biomass, wind and solar developers have to invest in technology that converts a source of potential natural energy into electricity. Therefore bankers must be assured that someone in the producing country will buy electricity at a price that will generate sufficient revenues to repay borrowed monies - or that the electricity will be exported and bought by a customer in a neighboring country.

Streamline and standardize the legal and regulatory procedures for power purchase agreements between the utility and private power producers to minimize costly delays and complications in contract negotiations. A power purchase agreement is a means to an end. If the policy objective is to enable private-sector entrepreneurs to develop renewable energy, grid-connected facilities to sell power in a country, a power purchase agreement is the most effective mechanism presently in use to allow financing of private-sector generation facilities.

Power purchase agreements are effective tools only in countries in which national legislation or practice allows entities other than the national utility to generate electricity. What is the role of power purchase agreements in the renewable energy context? Ideally, any purchaser of generating capacity and electricity which is soliciting power for addition to its grid - be that a utility.

The preparation of standard power purchase agreements will not only speed the post-award contract negotiation process, but will also place bidders on notice regarding the terms and conditions of the contract. Without a firm understanding of these factors, bidders will be forced to rely on guesswork in formulating their bids, undermining the entire bidding process. A power purchase agreement for renewables that has substantial monthly capacity payments can have fairly modest payments for delivered energy. What policy issues need to be considered by the government in the context of power purchase agreements for renewables?

In general, the legal and regulatory procedures for power purchase agreements between the utility and private power producers need to be streamlined and standardized to minimize costly delays and complications in contract negotiations. When preparing a standard power purchase agreement, utilities and other power purchasers should be aware that renewable facilities differ from conventional hydrocarbon-fueled projects in several ways. Failure to reflect these differences in the power contract will complicate, if not preclude.

Renewable projects tend to be far more capital-intensive than conventionally fired facilities. The typical renewable project will have a very high proportion of fixed cost - chiefly in the form of debt service - and a low proportion of costs that vary with the output of the plant. Given this cost structure, renewable projects seeking financing need to be able to demonstrate that the power contract will produce a very steady cash flow over the life of the financing. This demonstration of commercial viability can best be achieved by negotiating a power contract with some customer - be it a utility.

If the capacity payments are sufficient, then the payments for delivered energy payments per kilowatt hour of delivered energy can be fairly modest. This kind of payment structure presents a relatively low risk profile to investors, and the resulting lower debt service costs can be reflected in the prices paid by the utility under the power contract.

Given the higher value of electricity generated during peak demand, the cost difference between peak and off-peak electricity prices needs to be dearly defined. Alternative capacity payment and dispatching language can be developed and included for subsequent negotiation. What are the major source-specific considerations in developing a power purchase agreement?