AN ANALYSIS OF THE EIA REPORT “FEDERAL FINANCIAL INTERVENTIONS AND SUBSIDIES IN ENERGY MARKETS 2007”

 

Ben Parry

Brian Perusse

Scott Siler

 

The intent of this paper is to rebut specific findings in the Energy Information Administration's (EIA) report, "Federal Financial Interventions and Subsidies in Energy Markets 2007," which analyzes federal subsidies to electricity producers. The report provides a thorough review of federal subsidies allocated to electricity producers in 2007, based on the scope of the original request by Senator Lamar Alexander. However, the limited focus of the report ignores two relevant ideas: the economic rationale for subsidies and their impact on the evolution of the electricity industry in the United States.

 

The EIA states federal subsidies to the energy sector more than doubled from 1999 to 2007. Domestic energy production however, barely increased. The report also concludes renewable technologies receive more assistance relative to technologies such as coal, natural gas, and petroleum on a per kilowatt-hour (kWh) basis. The limited scope and the methodology the EIA uses to frame its findings may force readers to conclude the production is not increasing because the government excessively subsidizes renewable technologies, which generate fewer kWh per subsidy dollar. However, this comparison is misrepresentative for a number of reasons.

 

This report argues the federal government's incentives have done little to increase overall energy production because the government focuses the majority of its subsidies on mature technologies while it should allot the majority of its incentives to nascent technologies. To illustrate this point, holes in the EIA's analyses will be exposed and alternatives to the agency's analyses will be presented. The main explanations are as such:

 

First, a subsidy, if at all justifiable, should be used to assist new, beneficial technologies accelerate to commercialization and self-sufficiency. In theory, all mature technologies should be free of subsidies and governmental support. This report examines historical levels of installed capacity and electricity output to confirm that coal, nuclear, petroleum, hydroelectricity, and natural gas are mature technologies while other renewable technologies, such as wind and solar are less mature. Given this segregation, technologies like coal and nuclear should receive fewer subsidies than renewable technologies. However, according to the EIA, subsidies from the federal government to the coal industry (not including refined coal) are 68 times greater than subsidies to the nascent industries like solar and geothermal, and subsidies to the nuclear industry are 90 times greater.

Second, subsidies and other incentives do not make an immediate impact. The EIA compares 2007 subsidies across technologies by measuring the dollars of federal support per kilowatt-hour produced in 2007. However, subsidies allotted in 2007 may take several years to increase production. Therefore, any production increases in 2007 may be the result of previous years' subsidies. To improve upon this, this report examines EIA subsidy data from 1999 and 2007 and devises a new and more relevant metric.

Also, energy consumption increased by 4.6% from 1999-2007, while production only increased by 0.1%, according to EIA data. With domestic energy consumption increasing at a faster rate than domestic energy production, the US will either face energy shortages or be forced to increase its reliance on foreign imports. Because the government does not have unlimited resources to support this growth in energy production, it must implement policy wisely to provide the best return per subsidy dollar. To achieve this goal, the government must allocate money to high growth nascent technologies. On other hand, mature technologies that have reached a plateau require large sums of money for minimal growth. This report presents data that demonstrates the large fiscal cost to grow mature technologies in comparison to younger technologies. For example, the government is spending approximately $3,200 million for every 1% growth in coal electricity production and $2,500 million per 1% growth in nuclear electricity production, while only spending $5.5 million per 1% growth in solar electricity production.

Finally, federal assistance is only one relevant issue. Legislators, academics, and businesspersons seeking to compare incentives and subsidies across technologies must attempt to quantify other factors to reach a valid comparison. This report, like the EIA report, will exclude state and local subsidies because of inherent difficulties with examining such data. It will also ignore any environmental and other benefits from subsidizing clean technologies

THE ARGUMENT FOR SUBSIDIES AND INFANT INDUSTRIES

 

To fully evaluate the efficacy of the federal subsidies to the energy sector, it is important to understand the economic theory behind subsidies and their intended purpose. This section will analyze the economic reasoning behind subsidies and the idea of infant industries, as it relates to different energy technologies within the United States.

 

A classical definition of a subsidy is a form of financial assistance either to a business or industry within an economic sector, which without the financial assistance, the business or industry would otherwise fail or not occur. While differing opinions regarding subsidies exist, many economists and academics believe the existence of subsidies helps the development and maturation process. Koplow describes the benefits of energy subsidies specifically.

 

"Justifications for energy subsidies include social welfare, protection and promotion of jobs or industries, rural development, and energy security."(Koplow, 2004)

 

Included with these benefits, this report argues that subsidies, when implemented properly, assist certain immature, or infant, industries in order to make them more competitive amongst their peers. Regarding infant industry states, Baldwin summarizes the economic theory behind state intervention in said industries:

 

"The essential point stressed by infant-industry proponents since Hamilton (1791) and List (1856) first wrote on the subject is that production costs for newly established industries within a country are likely to be initially higher than for well-established foreign producers of the same line, who have greater experience and higher skill levels."
(Baldwin,1969)

 

While Baldwin compares the competitive environment betweens firms located in different countries, the environment is analogous to those competing within domestic industries. The key factor is the infant or mature stage of each firm. Baldwin goes on to explain why this factor is essential:

 

"…Over a period of time new producers become 'educated to the level of those with whom the processes are traditional' (Mill, 1909,); and their cost curves decline."

 

The infant industry argument states that at a certain point government intervention is necessary and Baldwin proposes that immature industries are in the greatest need of state intervention. While Baldwin's paper criticizes the effectiveness of infant industry protection even he concedes the strength of the economic theory behind it:

 

"I will not deny that there are unique factors affecting new industries which may require market intervention by public authorities if a socially efficient allocation of resources is to be achieved."

 

While the industries this report considers infant are not necessarily "new" when compared to other technologies, these industries should be treated as such. For example, Thomas Cochran of the Pew Center on Global Climate Change writes of nuclear subsidies:

 

"These proposed subsidies are unjustified in my view, promoting both negative economic and environmental consequences relative to more benign renewable energy generating technologies. Moreover, nuclear power is a mature industry that has already benefited from tens of billions of dollars in government subsidies over many decades and should sink or swim of its own accord without additional taxpayer assistance." (Cochran, 2004)

 

Cochran takes this idea further writing:

 

"Since most existing nuclear plants are economically competitive with fossil-fueled plants in terms of forward costs, energy generating companies will continue to extend the licenses and operate the existing U.S. fleet of nuclear plants over the next several decades."

 

Essentially, Cochran believes nuclear and fossil-fuel plants are currently mature and economically competitive. Additionally, he proposes that any federal subsidies to these plants would not create new facility production and therefore no new growth because energy generators will use existing plant capacity for a long time to come.

 

Cochran's statements will be supported further by our analysis; however, the message is apparent. At certain points in an industry's maturation process the additional inflow of cash has little or no effect on its growth. Koplow supports Cochran's statements when discussing oil and gas subsidies:

 

"The fiscal cost of these subsidies is evident, especially in sectors such as oil and gas where historically high prices alone should provide sufficient incentives for expanded production."

Cochran also argues it may even be irresponsible to commit large subsidies to those energy technologies where the environmental consequences are much greater than the more benign alternatives. Again, Koplow supports Cochran's statements. "Indications are that, as we extract more dilute, deeper, and dirtier energy sources, the energy subsidy required to extract and upgrade the new sources increases."

It is clear given the existing academic evidence, that the arguments behind subsidies are strong. As a form of financial assistance to a business or industry, a subsidy can help expedite growth. However, a subsidy best achieves this from the infant stage and has diminishing returns towards a more mature stage. Building on Cochran's argument, this report will empirically illustrate a disproportionate amount of subsidies is allotted to mature domestic energy technologies, rather than more infant technologies that would receive greater benefit from the subsidy cash inflow.

 

                DEVELOPMENT OF THE TECHNOLOGIES

 

In order to differentiate between nascent and mature industries, this report tracks the development of different technologies over the past century using two methods. The first method examines the name plate installed capacity of each power generator in terms of megawatts (MW) and aggregates them over time. The second approach tracks the yearly output of each technology in terms of kilowatt-hours (kWh) and compares them along their life-cycles. Individually, the methodologies have their own idiosyncrasies which prevent one hundred percent accuracy. The problems with each methodology will be discussed in further detail below. However, when viewed together, the installed capacity and electricity generation output methods provide an accurate picture of the size of each respective market. This report uses EIA data to track each technology over a set timeframe.

 

Method 1: Tracking Industry Growth by Installed Capacity

 

The first method measures the maturity of different energy technologies by graphing the cumulative installed capacity of each technology over a given timeline. However, comparing different energy technologies by their respective levels of installed capacity does have pitfalls, as described below.

 

When a power plant is installed, it must register the name plate or installed capacity of production. These ratings are a measurement of power and are often rated to the largest power output that can be produced under an optimal situation. It must be noted however, that ten 20 MW solar power plants do not produce the same amount of electricity as a 200 MW coal fired power plant.

 

Coal power plants only produce 70% of the potential electricity output (known as capacity factor) over the course of a year due to a number of factors such as maintenance, spinning reserves, or limited demand. Solar is inherently different in that the sun is exposed for a set period of time each day and the intensity of the available sunlight varies during the day. Also, the solar potential in the southwestern part of the United States with greater sun exposure is significantly greater than the solar potential of those areas with less exposure. Of the projects that were listed in the EPA's Emission & Generation Resource Integrated Database (eGrid), the average solar installation has a capacity factor of 20%. (EPA, 2008) To put this in perspective, we would need 700 MW of solar installation to roughly equal the output of a 200 MW coal power plant. However, capacity factors are not the same as efficiency nor should they be used to compare if one technology is "better" than another.

 

Capacity factors are important solely for the purpose of understanding how different nameplate capacity ratings vary from each other. This report does not directly use the capacity factor during the analysis because this data will be stress-tested when compared to a second method that tracks net electricity generation.

 

Exhibit 1 below looks at the cumulative installed nameplate capacity for different technologies in the United States, from 1915 till 2006. The 2007 data is not included in this report since it has yet to be published. At first glance, three major trends are apparent in this chart. First, natural gas and coal are the two most prevalent technologies to date, having over 75% of the cumulative installed capacity.

 

Second, many technologies appear to have plateaued beginning in 1990 and show little or no added capacity in the last fifteen years. These technologies include coal, nuclear, hydro power, and fuel oil (diesel, etc). Only natural gas and wind appear to be adding capacity in any significant manner in the last five years.

 

Third, most of the technologies have been in existence for over 40 years, with the majority of the technologies growing significantly between 1955 and 1985. To better evaluate how and when each technology gained a significant foothold in the market place, the y-axis (installed capacity) scale was adjusted by a factor of 10.

 

Exhibit 1: Cumulative Installed Capacity in U.S. from 1915 to 2006

 

Exhibit 2 below focuses on the growth period of each technology by changing the y-axis scale and observing data between zero and 50,000 MW installed capacity. This is the same graph as in Exhibit 1 on a different scale.

 

The capacities of hydroelectric power, coal, natural gas, nuclear, and to lesser extent fuel oil drastically increased between 1915 and 1975. Wind power is also notable since it is just beginning to experience the same exponential growth as it begins to gain a foothold in the market place. Solar, geothermal, and biomass have yet to experience the rapid growth other technologies experienced in earlier years.

 

Exhibit 2: Cumulative Installed Capacity in U.S. from 1915 – 2006, altered y-axis

 

 

Method 2: Electricity generation

The second method for categorizing each technology measures the respective output in terms of kilowatt-hours (kWh). This method negates the problem of determining a capacity factor for each technology as previously discussed. It is advantageous because it only measures the output of each technology and attempts to standardize it across the industry.

 

The major drawback of tracking actual electricity generation is that many power plants have a useful life of thirty to forty years. This means a natural gas plant installed in 1955 would no longer be in commission and subsequently omitted from this study. This omission would favor older technologies since any omission of previous generation would make the older technology appear newer in their overall lifecycle.

 

In Exhibit 3, the graph shows that coal provides the majority of the electricity generated in the United States. It has been in production for over 60 years and due to a plethora of domestic sources, this technology serves as a base load in most areas; nuclear also serves as a base load for power generation. However over the past 10 years, the overall output from nuclear power has plateaued. As seen earlier in Exhibit 1, natural gas has the largest installed capacity. Now, however, we observe that natural gas provides less than half of the electricity generated by coal power plants. This difference exists because a majority of natural gas plants were built as peaking power plants. These plants generally operate only during times of high demand. As well, the exhibit illustrates that hydroelectric power and petroleum have decreased from their previous peaks. Once again, wind and solar only make up a small portion of electricity generation, but these technologies are 35 to 40 years younger than their counterparts.

 

Exhibit 3: Net Electricity Generation from 1949 - 2006

 

 

Exhibit 4 below provides a more focused look at the net power generation of each technology during the first couple of decades they were in operation. Three areas specifically, should be looked at in greater detail.

 

First, petroleum generators have been used for power generation since before 1949, but their acceptance into the market place appears to be staggered. Between 1949 and 1964, there are numerous peaks and troughs in the growth of the technology before it became commercially viable. More notably, the technology is in rapid decline from 1979 until now.

 

Second, wind power is just beginning to reach commercial viability and its trajectory is similar to nuclear in 1970.

 

Third, solar and geothermal energy are still nascent technologies and must be given the correct economic stimulus to push them towards commercial viability.

 

Exhibit 4: Net Electricity Generation from 1949 -2006, altered y-axis

 

 

Based on the information from the nameplate installed capacity and the net electricity generation, we are able to identify coal, nuclear, hydroelectric, natural gas, and petroleum as mature technologies. However, natural gas continues to expand in terms of installed capacity because of the positive economics for peaking power electricity production. It is also clear that wind is at a critical point in the lifecycle and close to full commercialization as long as it receives proper incentives. Lastly, solar, biomass, and geothermal technologies are still nascent and need further incentives to reach commercial acceptance.

 

ANALYSIS AND COMPARISON

 

The report discusses earlier that subsidies should help infant industries reach maturity, and mature industries no longer need as much support as immature industries. The report also specifies coal, nuclear, hydroelectric, natural gas, and petroleum as mature technologies and wind, solar, geothermal, and biomass as nascent technologies. In theory, coal, nuclear, hydroelectric, natural gas, and petroleum should receive fewer subsidy dollars than solar, geothermal, and biomass. Exhibit 5, reproduced below from the EIA report, shows this is not the case.

 

According to Exhibit 5, subsidies from the federal government to the coal industry (not including refined coal) are 68 times greater than subsidies to the nascent industries like solar and geothermal, and subsidies to the nuclear industry are 90 times greater. This mix does not seem to meet the objective of using subsidies to help grow nascent industries, as nascent industries like solar, geothermal, and biomass receive tiny amounts of subsidies compared to mature technologies like nuclear and coal. In fact, all renewables combined, including hydroelectric and wind, receive fewer subsidies than nuclear and half the subsidy dollars of refined coal.

 

The federal government is not using tax dollars wisely because it is sending more incentives to mature technologies than to nascent technologies. In fact, the EIA report states that federal subsidies to the energy industry doubled while production remained unchanged between 1999 and 2007. According to the EIA's data, these subsidies increased 102.4% over that time period, and production increased by less than 0.1%.

 

This disconnect between subsidies and production is a problem especially because energy consumption increased by 4 quadrillion Btus, or 4.6%, from 1999-2007. With domestic energy consumption increasing faster than domestic energy production, the US will either face energy shortages or be forced to increase its reliance on foreign imports. If the federal government is seeking to decrease reliance on foreign imports while meeting domestic energy needs, it needs to devise an incentive strategy that effectively employs its budget to increase energy production.

 

An issue with assessing which strategy is best aligned to meet the country's energy needs is how to measure the cost effectiveness of prior strategies and forecast the cost effectiveness of new strategies. This portion of the report will analyze two different arguments about the government's incentive strategy. Statistics from the EIA report imply subsidizing nascent renewable technologies is costly. This report poses a counter argument to the EIA's premise by showing the cost of growing mature technologies to meet US energy needs is higher than the cost of growing nascent technologies, and the federal government would use tax dollars more effectively by subsidizing these nascent energy technologies.

 

Analysis of EIA Table

The EIA attempts to measure the cost effectiveness of prior strategies in one of its central tables that compares subsidies per unit of electricity production.

 

This EIA table, found in the executive summary of the EIA report and reproduced below, implies subsidizing wind and solar is more expensive than subsidizing most other technologies on a per kWh basis. But the main problem with this table, which the EIA does recognize, is it assumes subsidies in 2007 directly translate into production in 2007. We previously argued the point of subsidies is to help grow nascent industries and not to make an immediate positive impact on the industry of the government's choice. Technologies like coal, petroleum, and nuclear have such low subsidies per unit of production because these technologies are mature and have high net generation values after benefiting from years of incentives. Natural gas's growth has not slowed like other mature technologies including coal, nuclear, and oil, but has achieved a solid foothold in the market. Therefore, it no longer requires as many incentives. Wind and solar are still in the infant stage relative to other technologies and therefore these technologies look very expensive per unit of production.

 

Exhibit 5: Reproduction of Table ES5 in EIA Report

 

 

 

 

Alternative Analyses of EIA Data

To better assess the cost effectiveness of the federal government's incentive strategies, we created a new metric that compares subsidy levels to the production growth rates of each energy technology. Specifically, the calculation is:

 

Subsidy and support in USD ÷ Compound annual growth rate

 

However, the metric we have devised is not without flaws similar to the metric the EIA uses. The inherent problem is subsidy data is only available in snapshots and cannot be compared over a series of years. However, this new metric provides a better representation of how effectively the government has used its subsidy budget, and more importantly, how it should allocate the budget in the future.

 

We used data from the EIA incentive report as our measure of federal subsidies and assumed the incentives in 1999 and 2007 were representative of a typical year. We used EIA databases to measure production growth rates for each energy technology from 1999-2007. We used this time frame because of data limitations and because we wanted growth rates to partially reflect the effect of 1999 subsidies while providing an idea of how production will grow moving forward.

 

Comparing the levels of subsidies in terms of dollars to the growth in production levels gives an idea of how much money the government spends to grow energy production and capacity. For example, in 1999, the federal government spent $740 million on subsidies and incentives to nuclear energy. Energy generation from nuclear plants grew by an annual rate of 1.26% from 1999-2007, so the federal government is spending $553 million ($740 million / 1.26%) to increase energy production from nuclear plants by 1% annually, based on the 1999 snapshot.

 

The tables below display this metric for all energy production and incentives in 1999 and 2007, and for electricity production and incentives in 2007. Reliable information on subsidies to electricity is not available for 1999.

 

1999 Energy Subsidies

Exhibit 6: Subsidies to Energy ($ millions) in 1999 vs. 1999-2007 Annual Growth in Production

 

 

 

 

 

 

In this table above, which looks at energy subsidies and energy production, not just electricity subsidies and electricity production, coal looks relatively expensive compared to most other technologies. According to the 1999 numbers, the government is spending $5.7 billion for every 1% growth in coal production. It has spent billions of dollars on natural gas and petroleum, which the EIA lumps into one category, only to achieve negative growth. Because this table represents total energy production, petroleum, which has been experiencing negative production growth, is more heavily weighted than natural gas, which has been growing more rapidly than most energy technologies.

 

Renewables without hydro included are much less expensive, at only $370 million per 1% growth in production. Subsidies to nuclear are between coal and non-hydro renewables at $585 million per 1% production growth.

 

2007 Energy Subsidies

 

Exhibit 7: Subsidies to Energy ($ millions) in 2007 vs. 2002-2007 Annual Growth in Production

 

 

 

 

 

 

 

The 2007 data tells a story similar to the 1999 data. Coal is again the most expensive at $5 billion per 1% production growth, and natural gas & petroleum production growth was negative from 2002-2007. Nuclear production was less expensive to grow than coal, receiving $1.9 billion for every 1% growth in production, but more expensive than non-hydro renewables, which received just $622 million per 1% growth.

 

2007 Electricity Subsidies

Exhibit 8: Subsidies to Electricity ($ millions) in 2007 vs. 2002-2007 Annual Growth in Production and Capacity

 

 

 

 

 

 

 

 

 

(6) Time series production and capacity data for refined coal not available

 

Unfortunately the EIA did not separate electricity subsidies from energy subsidies in their 1999 report, so we only have the 2007 data. Even so, this set of data provides another interesting view on how wisely the federal government is spending its money.

 

According to the data from the EIA, the government is spending $3.2 billion for every 1% growth in coal electricity production and $2.5 billion for every 1% growth in nuclear production. At the other end of the spectrum are natural gas at $64 million and various renewables at $47 million and below. Solar is the least expensive, at $5.5 million per 1% production growth.

 

The capacity statistics are similar. Coal capacity is decreasing, despite receiving $3 billion in subsidies, and the government is spending $3.3 billion for every 1% growth in nuclear capacity. Solar is again the lowest, receiving only $3.1 million in subsidies for every 1% growth in capacity.

 

It is not fair to say the government needs to spend $3.2 billion to increase coal production by 1% and only $5.5 million to increase solar production by 1%. The 2007 subsidies will not necessarily lead to the same growth rates each technology experienced from 2002-2007.

 

However, it is apparent from the data that the government is using its money more effectively when subsidizing nascent technologies instead of mature technologies. Earlier in the paper, we stated the mature technologies are coal, petroleum, nuclear, hydro, and to a lesser extent, natural gas. Each of these technologies is more 'expensive' to subsidize than the nascent renewable technologies. In fact, when looking at broader categories, the government is spending $1.5 billion for every 1% growth in fossil fuel production, $2.5 billion for every 1% growth in nuclear, and $174 million for negative growth in hydro. Meanwhile, the government only spent $148 million for every 1% growth in non-hydro renewables.

 

One argument to the analysis above may be that it is not fair to compare 2002-2007 growth to 2007 subsidy levels. We agree to an extent, although we do believe recent growth is as good of an indicator of future growth as any other predictor. However, comparing 2007 subsidies to the EIA's production forecasts, done in the table below, does not change the story. Mature technologies still appear to be more expensive to subsidize than nascent technologies. Nuclear costs almost $10 billion per 1% production growth, while renewables only cost $266 million.

 

Exhibit 9: Subsidies to Electricity ($ millions) in 2007 vs. 2008-2015 Annual Growth in Production and Capacity

 

 

 

 

 

 

    (7) Time series production and capacity data for refined coal not available

 

The table above shows that the US needs over 500 TWh of additional electricity production to come on line in the next eight years. The government will most likely play a large role in helping the energy industry meet this demand. If this is the case, the government needs to focus on the most cost effective subsidies, especially with its strained budget. The federal government needs to spend money on high growth nascent technologies, not mature technologies that have reached a plateau and require huge amounts of money to grow. Expanding subsidies to mature industries just does not make sense.

 

Conclusion

If the goal of the government is to incentivize the investment necessary to create additional electricity capacity and simultaneously reduce the country's reliance on energy imports, it will need to further examine the cost effectiveness of its energy strategy. Currently, the government inefficiently uses tax dollars by subsidizing mature technologies rather than supporting more nascent technologies. This report shows that coal, petroleum, nuclear, hydro, and natural gas have reached commercial viability, while solar, wind, geothermal, biomass, and a number of other new technologies have yet to reach this threshold, and that the former technologies currently receive greater cash inflows. However, according to the new metric discussed, the government spends $1.5 billion per 1% growth of fossil fuel generation, $2.5 billion for every 1% growth in nuclear and only $148 million for every 1% growth in renewable technologies (excluding hydro). Therefore, given these growth comparisons the government must expend on high growth nascent technologies. Because these technologies have greater growth potential per subsidy dollar as opposed to their counterpart, tax dollars would most efficiently be spent on these industries. If the government is determined to use subsidies as a strategic investment, it must focus more on technology growth rates over time rather than subsidy dollar per output of each technology.

 

 

                        REFERENCES

 

Baldwin, R. E., "The Case against Infant-Industry Tariff Protection", The Journal of Political

Economy, Vol. 77, No. 3 (May – Jun., 1969), pp. 295-305

 

Cochran, T. B., "Critique of 'The Future of Nuclear Power: An Interdisciplinary MIT Study'", "The

10-50 Solution: Technologies and Policies for a Low-Carbon Future", The Pew Center on Global Climate Change and the National Commission on Energy Policy

 

Environmental Protection Agency (EPA). (2008). The Emissions & Generation Resource Integrated

Database (eGrid) [Data file]. Retrieved from http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html

 

Gilliland, M. W., "Energy Analysis and Public Policy", Science, New Series, Vol. 189, No. 4208 (Sep.

26, 1975), pp. 1051-1056

 

Koplow, D., "Subsidies in the US Energy Sector: Magnitude, Causes, and Options for Reform", Earth

Track, Inc., (Cambridge, MA), November 2006, www.earthtrack.net

 

EIA Statistics by subject:

 

Historical electricity generation statistics

Energy Information Administration, Annual Energy Review 2007. Table 8.2a & b Net Generation: Total (All Sectors), 1949-2007. [Data file]. Retrieved from http://www.eia.doe.gov/emeu/aer/elect.html .

Historical electricity capacity statistics

Energy Information Administration, Annual Energy Review 2007. Table 8.11a Electric Net Summer Capacity: Total (All Sectors), 1949 – 2007 [Data file]. Retrieved from http://www.eia.doe.gov/emeu/aer/elect.html .

Historical energy production statistics

Energy Information Administration, Annual Energy Review 2007. Table 1.2 Primary Energy Production by Source, 1949 – 2007 [Data file]. Retrieved from http://www.eia.doe.gov/emeu/aer/overview.html .

 

Projections

Energy Information Administration, Annual Energy Review 2008. Table 8. Electricity Supply, Disposition, Prices, and Emissions [Data file]. Retrieved from http://www.eia.doe.gov/oiaf/aeo/graphic_data.html .

Renewable Generation Stats

Energy Information Administration, Renewable Energy Consumption and Electricity Preliminary Statistics, 2007. Table 3 Electricity Net Generation from Renewable Energy by Energy Use Sector and Energy Source, 2003-2007 [Data file].

Historical electricity capacity statistics

Energy Information Administration, Annual Energy Review 2007. Electricity Net Generation: Electric Power Sector, 1949-2007, [Data file]. Retrieved from http://www.eia.doe.gov/emeu/aer/elect.html .

Electricity Generating Units

Energy Information Administration. Existing Electric Generating Units in the Unites States, 2006 [Data file]. Retrieved from http://www.eia.doe.gov/cneaf/electricity/page/capacity/capacity.html.

 

Michael Weber

 

 

Figure 1 – Schematic diagram of possible CCS systems showing the sources for which CCS might be relevant, transport of CO2 and storage options p4

Introduction

Carbon capture and storage (CSS) is a technique for trapping carbon dioxide (CO2) as it is emitted from large point sources, compressing it, and transporting it to a suitable storage site. CCS has over the past few years increasingly become regarded as a serious option for reducing atmospheric emissions of CO2 from human actions. The 2008 European Commission proposals, for example, also known as the EU Energy and Climate Package, envision greater use of CCS technologies in Europe but also internationally. However, CCS should not only be seen as a European Initiative. The United States and even countries in the Arab-Persian Golf region have been in support of this mitigation technique for climate change. Amongst other initiatives, Saudi Arabia, Kuwait, Qatar and the United Arab Emirates announced at the OPEC summit in November 2007 that they would pledge US$ 750 million to a new fund that would support and promote cleaner and more efficient petroleum technologies such as CCS. Partially, CCS has found support amongst these countries because it would allow for the continued utilization of fossil fuel energy sources while at the same time it could secure substantial reductions in carbon emissions.

CCS, however, is in a relatively early phase of development. Uncertainties remain about its technologies, its attractiveness versus other low carbon opportunities, its environmental effects, its timing and especially about its costs. This report aims to analyse the prospects for CCS. For this purpose, we will assess CSS technologies and especially the costs for CO2 capture, transport and storage. While costs are likely to be initially very high, they can be expected to fall over time through a learning-by-doing process and technological improvement. Nonetheless, the range of potential costs is large and depends on various factors such as future energy prices which are hard to predict. It will be argued that CCS is technically feasible and under certain circumstances economically attractive.

The rest of this paper will be structured as follows. The next section will look at the different existing CCS technologies. After that, we will in greater detail look at the costs of CCS. The last section will conclude.

 

CCS Technology

CO2 is emitted into the atmosphere whenever fossil fuel is burnt, if in large combustion units such as used in power generation or in smaller sources such as vehicle engines. Resource extraction or certain industrial processes especially steel and cement production or oil refining also lead to great quantities of emissions. A scientific consensus has been established that higher CO2 concentrations in the atmosphere combined with incoming solar radiation trap heat and influence earth's temperature. Under the United Nations Framework Convention on Climate Change, governments have agreed to stabilize 'greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system'. Since then, an amount around 500 ppm has become the target. However, even this benchmark requires a 50% reduction from the business-as-usual emissions within about half a century.

CCS aims to prevent the CO2 generated by large stationary sources to enter the atmosphere. Current technology is believed to be able to capture around 90 percent of CO2 emissions from these sources. The basic process of CCS consists of three stages: capturing the CO2 emitted from these sources, transporting it to a suitable storage location, and storing it there permanently. Figure 1 on the cover illustrates these three components. While technologies used in each stage can be found in industrial operation today, CCS as an overall integrated system is by far not as mature as some of its components. Capturing CO2 requires separating it from other gaseous products. Existing separation technologies exist that can either be used to capture carbon after combustion or to decarbonize the fuel before it. Before CO2 is transported to a storage site, usually through pipelines, it usually needs to be compressed to a high density. Storage methods include injection into underground geological formations, into the Deep Ocean or industrial fixation in inorganic carbonates. The first large scale CCS project to be initiated has been the coal fired power plant Schwarze Pumpe in Germany in September 2008.

 

Capture Technology

During fossil fuel combustion, the fuel consisting of a mixture of hydrocarbons with some impurities is oxidized with the help of an oxidant, usually air or O2, to release a large amount of energy, the heat of the combustion, and a mixture of combustion reaction products, the flue gas. The composition of the flue gas depends on the fuel and oxidant used and the reaction conditions. CO2, however, is an unavoidable product of the reaction as a result of the large amount carbon in all fossil fuels.

Carbon capture is the most complex and as we will see the most costly component of CCS. The purpose of CO2 capture is to produce a concentrated stream of CO2 at high pressure that can readily be transported. The choice of a suitable technology for the separation and capture of CO2 depends on the characteristics of the gas stream from which the carbon needs to be separated, which mainly depends on the power plant technology. Three main approaches to capturing the carbon generated from a primary fossil fuel (coal, natural gas or oil) or biomass exist: post-combustion, pre-combustion and oxyfuel combustion. Each has its own advantages and disadvantages and neither should be seen as superior to another. A common problem is that they are all very energy intensive and relatively expensive. Which of the technologies is chosen, often depends on local circumstances and the fuel used. Figure 2 shows a schematic diagram of the main technologies.

 

Figure 2 – Schematic representation of capture systems

 

 

Post-combustion

Post-combustion systems separate CO2 from the flue gases produced by the combustion of fossil fuels or biomass in air, for centuries the most economic technology to extract and use the energy contained in the fuel. After the combustion of the primary fuel, the flue is not discharged into the atmosphere but instead passed through equipment which separates most of the CO2. While the separated CO2 can be fed to a storage site, the remaining flue gas is discharged into the atmosphere. The combustion of fossil fuels in air leads to a flue gas that is a dilute stream of CO2 mixed together with a large amount of N2 and some other gases. The CO2 can be captured through a process referred to as flue gas scrubbing. It is based on chemical absorption of CO2, using a monoethanolamine-based (MEA) solvent. Generally, 75%-95% of CO2 is captured using this technology.

The separation of the CO2 from the other components of the flue gas usually takes place through a continuous scrubbing system. The two main elements of such a system are firstly an absorber in which CO2 is absorbed into a solvent, and secondly a regenerator in which CO2 is released in concentrated form and the original solvent is recovered. Once the CO2-rich solution leaves the absorber, it is passed through a heat exchanger and then further heated in a reboiler, using low-pressure steam in order to break down the CO2 solvent compound and then to regenerate the solvent and to produce a concentrated CO2 stream. While the hot solvent can be returned to the heat exchanger, where it is cooled and then sent back to the absorber, the CO2 can be transported to a storage site.

The post-combustion technology is well understood and is used for example by Statoil to store CO2 from the Sleipner West gas field. Also, several commercial CO2 capture plants were constructed in the United States in the 1970s, largely in order to use the CO2 produced for other industrial applications such as the carbonation of brine or the production of dry ice. Although these applications are still in operation today, they are significantly smaller than a typical power plant application.

 

Pre-combustion

As is nicely shown in figure 1, pre-combustion systems process the primary fuel in a reactor with steam and air or oxygen. This produces a mixture consisting mainly of carbon monoxide and hydrogen, that is 'synthetic gas'. Gasification technology that converts cheap and dirty fuel such as coal into synthetic gas has been around for more than hundred years and is frequently used in the chemical and fertilizer industries. The gasifier is a high-pressure vessel into which the fossil fuel is fed along with a controlled quantity of O2 (or air) and steam (or water). Chemical reactions at high pressure lead to the partial oxidation and dissociation of the fuel to form the syngas. The hot syngas is then cooled and filtered in order to remove particulate matter. The result is a clean fuel gas that is then taken to a second reactor, called the 'shift reactor'. In this high temperature reactor, the CO in the fuel gas is converted to CO2 with the help of steam and a catalyst to create shifted syngas. The resulting mixture of hydrogen and CO2 can then be separated into two streams: one CO2 gas stream and one consisting of hydrogen. The CO2 can then be transported to a storage site and the hydrogen is a carbon-free energy carrier that can be combusted to generate power. Pre-combustion systems would generally be used at power plants that employ integrated gasification combined cycle (IGCC) technology.

 

Oxyfuel Combustion

Using oxyfuel combustion is a more recent procedure compared to the previous two. As can be seen from figure 2, in comparison to the post-combustion system oxyfuel combustion uses oxygen instead of air for combustion of the primary fuel. The resulting flue gas stream consists mainly of water vapour and CO2. After heat is extracted from the flue gas, it is sent to a precipitator, a cyclone, or a bag filter for particulate removal. A portion of the flue gas is recycled back into the boiler so that excessively high temperatures in the boiler are prevented by diluting the O2. The rest of the flue gas is sent to a compression and refining unit where the moisture, inerts and other impurities such as SOx and NOx are removed. The high pressured CO2 stream that is left over is ready to be transported.

Although oxyfuel combustion is a promising option for CO2 capture from power plants, it is in its earlier stages of development compared to post- and pre-combustion systems. While parts of the system are commercially available, only laboratory studies using this technology have been conducted so far.

 

Emerging technologies

One of the most promising emerging technologies is the application of membranes. Membranes are believed to be able to be used to separate CO2 from other components or gases. It is argued to have large potential in offering energy savings and a low-cost solution to CO2 separation and capture in each of the systems explained above. However, at this stage, membrane-based processes are still at an early stage of development.

A wide range of further techniques is being developed. However, an explanation of all of these is beyond the scope of this paper. Such technologies include chemical looping combustion, the Clean Energy System, Biomass gasification with CO2 capture, the development of better solid adsorbents and absorbents, and electrochemical processes for the separation of CO2 from flue gas or for the concentration of CO2 from syngas.

 

Transport

Unless plants are directly at or above geological storage sites, the captured CO2 must be transported to a storage site. Transport is likely to be the least problematic of the three stages of CCS. Pipelines are usually the primary option although shipping is also possible. For transport in pipelines, gaseous CO2 is usually compressed to 8 MPa to avoid two-phase flow regimes and to increase the density of the CO2. This makes transport easier and cheaper. Pipeline transport of CO2 is already successfully being done. In the US, for example, over 2,500 km of pipelines transport more than 40 MtCO2 per year. For transport in ships, CO2 is carried in insulated tanks at a temperature well below ambient and at lower pressures. Transport by ships might be more economically when the CO2 has to be moved over a long distance or to the middle of the ocean. Shipment of CO2 would resemble that of liquefied petroleum gases such as propane and butane.

 

Storage

CO2 can either be stored in deep, onshore or offshore geological formations or in the Ocean. For both, various options are possible. Public opinion has generally been more in favour of geological storage as ocean storage is perceived as riskier.

 

Geological storage

The primary options for geological storage are depleted oil and gas fields, deep saline aquifers, i.e. natural underground formations containing salty water, and unminable coal beds. All options require CO2 to be injected in dense form into a rock formation below the earth's surface. Figure 3 offers a nice overview of geological storage options. As can be seen, storage can occur in onshore as well as offshore sedimentary basins, meaning natural large-scale depressions in the earth's crust that are filled with sediments. Enhanced oil and gas recovery and enhanced coal bed methane recovery refers to techniques for increasing the amount of oil, gas and methane respectively that can be extracted from oil and gas fields or coal beds through the injection of CO2.

Geological storage might not be technologically as advanced as CO2 transport but it is ongoing in smaller industrial-scale projects in the Sleipner project in the North Sea, the Weyburn project in Canada and the In Salah project in Algeria. EOR techniques are applied in Texas, USA. The injection of CO2 in geological formations is based on many technologies that are used in the oil and gas exploration and production industry. What is of real concern is that it is guaranteed that the injected CO2 remains locked underground and does not leak over time.

 

Figure 3 – Overview of geological storage options

 

CO2 storage is generally injected at depths below 800m where it has a liquid-like density due to prevalent pressure and temperature in those depths. Storage space in geological formations can thus be optimized. The injected CO2 is believed to fill space by partially displacing present fluids. In order for the CO2 to remain trapped, rock of very low permeability needs to lie over it to serve as an upper seal. Because totally closed off sites rarely exists, some migration of CO2 is often unavoidable. Geochemical trapping, i.e. the reaction of CO2 with in situ fluids and the host rock, limits these movements. Amongst other things, CO2 dissolves in the in situ water, thereby becoming denser and sinking down in the formation over time. What is more, chemical reactions between the CO2 and rock minerals form ionic species and convert to solid carbonate minerals. This process, however, takes millions of years. Coal bed storage can take place at shallower depths. CO2 is hereby absorbed on the coal.

CO2 usage for EOR involves the injection of captured CO2 into an oil reservoir so that it literally pushes oil out of the pores of the rock. Injected CO2 expands underground and thereby pushes oil towards a production well (Figure 4). At the same time, CO2 can also thin oil by dissolving in it and thereby lowering its viscosity. The result is an improved flow rate of the oil. EOR depends on reservoir temperature, pressure and crude oil composition and thereby resulting behaviour of CO2 with crude oil mixtures. Some of the injected CO2 returns with the produced oil but could be captured again and re-injected.

 

Figure 4 - EOR

 

Similarly, enhanced coal bed methane recovery (ECBM) is a method that produces additional coalbed methane from a source rock by injecting CO2 into a bituminous coal bed where the CO2 then displaces methane. The great advantage of EOR and ECBM is obviously the additional revenue from the extra recovery of oil in EOR and methane in ECBM. Both therefore present potentially a viable option especially for oil producing states.

Risks due to leakage from storage of CO2 exist for humans, ecosystems and groundwater. The IPCC has estimated that the fraction of CO2 retained underground will exceed 99% over 100 years with a probability of 90 to 99%. Over 1000 years, it is still very likely that more than 99% of the injected CO2 is kept enclosed.

 

Ocean Storage

Ocean storage could be done by injecting and dissolving CO2 into the deep ocean at depths greater than 1000m where most of the CO2 is argued to be isolated from the atmosphere for centuries. This can be done via a fixed pipeline or a moving ship. Additionally, CO2 can be deposited onto the sea floor at depths below 3000m where the CO2 is denser than water and is expected to form a 'lake'. This way dissolution of the CO2 into the surrounding environment is delayed. The deeper the CO2 is injected, the more it is believed will be retained. Ocean storage and the environmental impacts are still in the research phase. One of the downsides of this storage option is the likely increase in water acidity. This could have severe impacts on the marine ecosystems. Dissolving alkaline minerals such as limestone have been proposed in order to neutralize the acidic CO2. This, however, would require large amounts of energy.

 

As we have seen, components of CCS are in various stages of development. But an entire CSS system could be built from existing technologies that are used in the production of fossil fuels or electricity. The state of development of the overall system, however, is less than most of its components. As yet, little experience exists about combining CO2 capture, transport and storage into a fully integrated system. The economic feasibility of such efforts is often questioned. For this reason, we will now assess the costs of CCS.

 

CCS Cost Analysis

In comparison to the costs for normal large installations emitting CO2 such as power plants or cement and steel producing factories, CCS adds four additional costs:

• Capture equipment needs to be installed.
  
• The capture process needs to be powered which requires additional energy and therefore further fuel costs.
  
• A transport system has to be built.
  
• And, the CO2 has to be stored and necessitates monitoring afterwards.
  

Cost estimations for CCS are difficult tasks given the many uncertainties that bedevil the technologies explained above. Site-specific sectors such as the design, operating and financing characteristics of power plants or industrial facilities are an extremely crucial factor that accounts for the great range of costs for CCS that is given in the literature. What is more, the type and cost of the fuel used, the distances and terrains of transport and the type and characteristic of storage are all factors that influence the overall cost of CCS. Given all these cost influencing factors, cost-analysis is preferable done for specific projects rather than for the overall system. Nonetheless, in order to compare the economic feasibility of CCS to competing technologies such as for alternative energies, it seems useful to establish a price range for CCS. Each of the three components of an integrated CCS system - that is capture, transport and storage - all incur costs. From these, CO2 capture accounts by far for the greatest part which is why we will focus on it here. However, scientists maintain that the cost of CCS, especially the capture component, will decline over time as a result of a learning-by-doing process and further R&D.

Table 1 summarizes the costs for capture from different power plants and industrial sources, for transport and for storage (also including monitoring).

 

Table 1 – 2002 cost ranges for the components of a CCS system for a large-scale, new installations

The table clearly shows the great cost range especially for CO2 capture. Capture for industrial sources has a wider range as a result of R&D focus largely only on the power sector. Additionally, industrial sources greatly vary in size. The smaller the plant is the greater the cost of US$/tCO2 captured because of economies of scale. Table 2 combines the component costs to offer some range of what total costs of CCS are likely to be for three different power plant systems with transport and geological storage options.

    Pulverized coal plants (PC) and natural gas combined cycle power plants (NGCC) both use post-combustion systems. The cost of CCS ranges from 0.019 to 0.047 US$/kWh for PC and from 0.012 to 0.029 US$/kWh for NGCC plants. Integrated coal gasification combined cycle power plants (IGCC) use pre-combustion capture. The CCS cost range is 0.01 to 0.032 US$/kWh. Using EOR can reduce the cost of CCS because EOR revenues can partly compensate for the CCS costs. For IGCC plants, CCS costs can in some circumstances turn negative, representing a profit. But it must be mentioned that although IGCC plants are projected to have the lowest CO2 mitigation cost, initial capital expenditure is greater. NGCC plants on the other hand have typically been found to have lower electricity costs. Therefore, there is no winner amongst any of the technologies regarding CCS costs. Also, as already mentioned a lot depends on local factors and the fossil fuel type that is being explored. One technique might be more practical than another for a certain coal type for example.

    Retrofitting existing plants is an option. However, research has not yet looked in great details at the costs involved. Generally, it is believed that CCS costs will be greater in this case and only worthwhile for younger plants.

    Research up to this date is lacking an in-depth study for non-power applications. The cost range for these plants is likely to be larger given the diversity of these sources in terms of CO2 concentrations and gas stream pressure. The higher the concentration of CO2 is the cheaper to separate and capture larger amounts. The lowest costs can be found for processes that already separate CO2 as part of their production.

 

Table 2 – Range of total costs for CO2 capture, transport and geological storage based on current technology for new power plants using bituminous coal or natural gas

It is important to notice that we have to accept these cost estimates with some hesitance as they make assumptions for example about fossil fuel prices that can greatly distort the reality. Fossil fuel prices in 2002 have been lower than in 2008. This is likely to increase the cost premium associated with emission mitigation for power installations with CCS as the capture and separation technologies require great amounts of energy. However, natural resource exporting countries such as most countries in the Arab-Persian Gulf region might not be hurt as much by higher fuel prices. CCS costs for these countries might therefore be lower.

    Economic potential for CCS systems exist to the extent that policies are in place whose aim it is to substantially limit GHG emissions. Given that the supply of primary energy will continue to be dominated by fossil fuels until at least the middle of the century and that the magnitude of emission reductions needed to stabilize CO2 concentrations in the atmosphere are so substantial, CCS must be an option as it is the only technology that allows continued business-as-usual use of fossil fuels but that at the same time can reduce the amount of CO2 emitted into the atmosphere. The IPCC as well as the consultancy McKinsey & Company agree that with greenhouse gas emission limits imposed and with substantial R&D investment, a large scale deployment of CCS systems can be viable. However, for this to happen either a tough cap on CO2 emissions must be mandated or CO2 must be priced effectively. Otherwise, only niche opportunities for CCS will be deployed such as CO2 captured from high-purity, low-cost sources coupled with CO2 storage in a value-added application such as EOR. The IPCC argues that a price of CO2 would have to exceed 25-30 US$/tCO2. McKinsey & Company believe a price of €30-45 per tonne might be necessary. Above everything, it seems necessary that a binding global environmental agreement with stringent commitments will be negotiated at the UN climate change conference in Copenhagen in 2009. So far, a price for carbon has only been effectively established in the EU through the EU emission trading scheme (EU ETS). The price per tone CO2 emitted in its first trading period varied from a peak of €30 per tonne CO2 in April 2006 to almost approaching zero from August to December 2007. While the price in late 2007 dropped because of an overallocation of allowances in the first trading period, futures for the second trading period price of CO2 remained roughly stable between €20 to €25. As of October 21 2008, the price of carbon is €21.22. Although this price is just below the estimated price needed, recently analysists from Deutsche Bank forecasted the carbon price per tonne in the EU ETS to range from €30 to 48 in the second trading period but also beyond it up to 2030. Without going into too much detail, it should be noted that such estimates are far from certain. The EU are currently discussing Commission proposals to implement necessary reforms of the EU ETS that would put the EU on the right path to an ambitious climate change policy that could guarantee an efficient internalization of the cost of carbon. However, member states' governments including Germany's Angela Merkel have recently increasingly taken side with industry demanding exemptions to EU climate rules. Unless the reform proposals pass through the EU's codecision procedure without major amendments, it is very likely that CO2 prices will not be sufficient for CCS systems to be installed at least in Europe. What is more, threats of a global recession will most likely also influence the price of carbon negatively and delay any further investment in R&D. At the same time, however, a decline or slower growth in production will decrease CO2 emissions. In sum, we can be certain that there is uncertainty. And uncertainty is not conducive to business investment. However, if governments agree on CO2 emission limits, it is argued that CCS systems are competitive with other large-scale mitigation options such as nuclear power and renewable energy technology. Including CCS in a mitigation portfolio could reduce the cost of stabilizing CO2 concentrations by 30% or more.

 

 

Conclusion

The only certain thing we can say about Carbon Capture and Storage is that it is naturally plagued by uncertainty. This goes as much for almost all of its technological components as for its costs. Although most of its technologies are somehow commercially used, the integration of the entire system is problematic and requires further research. Capturing and separating CO2 appears to be the biggest and most expensive component of CCS. However, new technologies such as membrane-based processes are likely to be able to improve the system and to reduce costs. Generally, cost projections vary greatly and are dependent on a variety of factors, many of them inherent to local circumstances. What is more, we believe that costs of CCS will decline over time through a learning-by-doing process.

    Overall, it was argued that CCS has economic potential but only when governments either mandate stringent emission limits of CO2 or when an efficient price for carbon is established that internalizes the true cost of CO2 to society. Great potential exists for the use of CCS, especially since it is cost competitive to nuclear power or alternative energy and because it offers a compromise between energy importing countries that have increasingly become concerned with climate change and oil exporting countries that want to guarantee a future income stream for their country through the continued use of fossil fuels. One of the biggest disadvantages of CCS is its low acceptance amongst a majority of the public. Safety and environmental concerns will have to be addressed further before it can become a viable option for the mitigation of climate change

Pre-Salt Production in Brazil:Challenges and Potentials

Ava G. Leone

 

In late 2007, the Brazilian oil giant Petróleo Brasileiro S.A., better known as Petrobras, announced the discovery of light sweet crude oil preserved under a canopy of salt in the Tupi field 290km off the coast of Rio de Janeiro. That announcement marked the beginning of what is proving to be a massive expansion of the country's energy producing capabilities. At the time of the Tupi discovery, Brazil's proven oil reserves were approximately 14Bbbl and the post-salt resources of the Campos Basin were nearing their end. Tupi, with estimated reserves between 5 billion to 8 billion barrels of 28°- 30° oil, increased Brazil's energy reserves by more than 50%, but Brazil's good fortune did not stop there. A few months later, in early 2008, Petrobras discovered reserves in another pre-salt field, Jupiter, just to the east of Tupi. Most recently, the National Petroleum Agency has announced an estimated 33Bbo in the Carioca field, also located in the Santos Basin. Although Petrobras and BG, who owns a share of the Carioca field, have both been more cautious in speculations about its reserve estimates, these wells and the thirteen other exploratory wells drilled in nearby areas have yielded oil of the same quality, pointing to the existence of one large chain of reserves in the Santos, Campos and Espirito Santos basins.

 

The Brazilian government seems particularly sanguine about the newfound resources and has abandoned earlier oil and energy plans to accommodate development of the new fields, 20% of which are thought to be natural gas. There is also much speculation that the new discoveries will transform Brazil into a major exporter of energy in just a few years' time. In all, Petrobras has drilled fifteen oil fields in the pre-salt sequence and each one has revealed oil and hydrocarbons. The exploration and identification of these fields is a technological triumph in and of itself, yet much more advanced technology and higher investments in the industry will be needed for Brazil to maximize the potential of its pre-salt reservoirs. This paper will describe the unique challenges facing production of Tupi and the surrounding fields, give a brief overview of the technical advancements that have already been made, and conclude by highlighting the significance of Brazil's new finds to its domestic and international politics.

The Significance of Brazil's Pre-salt Play

There have been many instances of overexcitement at the discovery of oil fields whose proven reserves ended up being far smaller than the initial estimates. Thus, it is important to consider the scope of Brazil's new finds as well as the accuracy of given reserve estimates. If the estimated reserves of the Tupi field at 5-8Bbbl are correct, covering a surface area of 200 x 800 kilometers it is the second largest field discovered in twenty years and the largest offshore field. Since the initial pre-salt exploration began in 2005, there have been several consecutive discoveries of light oil in the pre-salt sections of the Santos, Campos, and Espirito Santo basins. Most of the pioneering exploration has been done by Petrobras but international oil companies (IOCs) such as ExxonMobil, Royal Dutch Shell, BG Group Plc, and Galp Energia own 25% of the concessions in Tupi and the neighboring area, known also as the "Sugar Loaf." The ability to locate and assess these fields is itself a technical achievement, as their position underneath the salt shelf poses a particular obstacle to geologists and it has only been within the past decade or so that the technology to explore in such geological depths within deepwater has been developed.

In order to identify potential reservoirs, imaging must be reliable. Salt tends to absorb seismic energy thereby complicating the imaging process. The most advanced innovation in exploration technology is the use of a wider spacing in seismic acquisition. Combining the use of geochemical and geological data, 3D seismic imaging and 3D reservoir modeling, reserves have been confirmed in the Santos, Campos, and Espirito Santo basins. Jose Formigli, executive manager of the newly formed department of Pre-Salt Exploration and Production for Petrobras, has estimated that the combined cluster in the Santos basin will produce 1.126 million Bbbl by 2017, and this is not including nearby Jupiter Field. Marcio R. Mello of HRT & Petroleum in Rio de Janeiro estimates the Tupi reservoirs alone to be in the range of 10Bbbl.

The salt of the Santos, Campos and Espirito Santo basins reaches depths of 2,000 meters, and acts as a massive sealant working to preserve the liquid phase of the hydrocarbons. Because of the depth of the fields and their high temperature, there is a high likelihood of large gas reserves. According to Formigli, the Tupi field alone contains natural gas reserves ranging from 179 billion to 256 billion cubic meters, a figure well over 50% of Brazil's current reserves. Such an increase will have a major impact on the Brazilian economy and perhaps even on its relationship with other countries. Presently, Brazil imports approximately half of its total natural gas consumption from Bolivia but would likely decrease that dependence as the new gas is brought online. The volume of expected natural gas production has encouraged Brazil to concentrate efforts on finding more efficient ways of using the gas both domestically and on the international market. Petrobras' director for Gas and Energy, Maria das Gracas, has mentioned the possibility of offshore gasification plants to facilitate production. At last month's Oil and Gas Expo in Rio de Janeiro, Francisco Nepomuceno Filho, E&P corporate executive manager for Petrobras, said that Brazil planned to increase production by 350% and had completed construction of two new pipelines which have already led to a 25 million cu m/d increase.

Technical difficulties

Petrobras has proven itself to be capable of the advanced technology needed to drill, test and evaluate pre-salt rocks. In order to confront the difficulties associated with pre-salt production, it has created a new research department within the company and has begun to reach out to international partners. It is likely that the international firms who stand to benefit most are those that had pre-existing contracts with Petrobras, such as Halliburton. The technical challenges to pre-salt exploration are numerous but assessing the character of the reservoirs and identifying energy resources are among the most fundamental challenges associated with production. Tupi and its surrounding fields pose a unique technical and economic challenge to production due to the reservoirs' location beneath 2000-3000 meters of seawater, another 2000 meters of rock formations and finally another 2000 meters of salt. Petrobras is currently conducting one extended well test to monitor the reservoir's interior characteristics.

The offshore drilling conducted in the Gulf of Mexico (GoM) in sub-salt reservoirs offers some guidance as to how to best explore at such depths, but fundamental differences exist that make pre-salt exploration much more complicated. First of the all, the reservoirs in GoM are much younger (ranging from the Paleocene to Pleistocene eras) than the deposits in Brazil, which are shallow water cretaceous carbonate deposits. The salt formations differ as well. In GoM the salt basins are made up of allochtonous Jurassic age salt deposits, meaning that the salt has moved from its original position to create a canopy near to the surface with the oil left underneath. The cretaceous salt in Brazil, however, is authochotonous. In other words, it has not moved as far away and is mostly still attached to the place of its original deposition. Thus, the canopy formed over GoM's reservoirs makes them "sub-salt" while Brazil's reservoirs are located below both the salt and pre-formed rock.

The inability to predict geo-mechanics of the reservoirs complicates long- term production planning, as well. There has never been sustained production at the depths that characterize Brazil's pre-salt fields so no one can say with any degree of certainty what impact the depletion of oil from one reservoir will have on its neighbors. Due to the pasty consistency of the salt layer, well engineering in pre-salt fields also differs considerably. Complications arise from slow penetration in the sedimentary layer of the reservoir, deviation of wells once they penetrate the salt zone, and well-bore materials that are resistant to high CO₂ content. While rock is difficult to drill through, once the drilling has occurred the rock remains steady thereby allowing the drill head to maintain its position. Salt, though easy to penetrate, is soft and unstable. Recovery possibilities are also problematic to assess. There is a concern about whether or not pumping gas or water into the reservoirs is technically feasible. Hydraulic fracture, a method used to increase or restore the flow of oil from the reservoir to the well, may not be an option considering the pasty consistency of the salt layer.

Once the wells have been drilled, engineers will face additional challenges as they attempt to maintain consistent flows from pre-salt reservoirs. Because oil is preserved under the salt shelf, more pressure is required for extraction. Additionally, given the already high temperature of materials located so close to the earth's center, cooling will occur much more rapidly. Controlling the decomposition of hydrate is necessary to prevent blockage, but is made difficult due to the inability to precisely gauge temperatures. This rapid change of temperature as the oil moves up the pipes and begins to clear the rock layer will create paraffin that can clog up pipelines. Insulating or heating the pipes remedies this, but insulation materials may prove too heavy for pipes of the length that will be required by the pre-salt fields. A large build-up of paraffin could temporarily shut down production and be extremely costly for a firm who that has to replace pipes. Companies are now exploring titanium as an alternative, which may circumvent the weight issue but is a much more expensive substitute.

Issues of manpower and subsea engineering are factors, as well. Jose Formiglio has identified the eventual construction of DCUs (Dry Completed Units) as a key component of Petrobras' long term production plan, but for the time being Petrobras will rely on FPSOs (Floating, Production, Storage and Offloading vessels) in order to get the most flexibility in well-head positioning while the precise characteristics of reservoirs are still being determined. The company is currently working on plans for the construction of a plant to build the FPSOs domestically, and is seeking to hire petroleum engineers for FPSO production as well as highly skilled workers to build the new pipelines that will transport natural gas. In addition to human capital needs, there is a shortage of rigs capable of production in these deepwater areas. There are a limited number of rigs in the world capable of production at the depths required by the pre-salt fields. Petrobras has streamlined its process for the negotiation of long-term contracts in an effort to ensure that it has the rigs and services necessary to meet its pilot goal of bringing Tupi on-stream by 2010.

The plans for exploration in Brazil's pre-salt reservoirs has led to the development of new technology in several areas, including deep water, pre-salt, flow, high pressure-high temperature (HP/HT) and wells. There are very few countries producing in similar depths, and not many of them do so profitably. A rather surprising exception is the relatively small producer Oman, where Brazil has turned for guidance in developing new technologies. Nevertheless, there are major differences between Oman's production in pre-salt and those planned for Brazil. Although Oman is producing at a profit, it is doing so in very small quantities that will be dwarfed by planned exploration in Brazil's offshore basins. Further, Oman's production is in reservoirs that are much older geologically than that of Brazil, implying that certain adjustments in technology will have to be made.

Cost and Profit

The technological challenges are by no means insurmountable but will require Petrobras and the Brazilian government to make massive investments in research and development, which is already being done. In fact, if Brazil faces a prohibitive factor in its pre-salt production, it will be cost. When the quantities of reserves were being confirmed and made public, the price of oil on the international market was around or above $100 per barrel. The international financial crisis has already put downward pressure on oil prices, and it is likely that they will continue to fall in the face of a pending economic recession. In an initial assessment it was said that for Brazil to make a profit on pre-salt exploration and production the price of oil needed to remain above $30-$35 a barrel. More recently, Energy Minister Edison Lobao has mentioned $40-$50 a barrel would be the minimum threshold for profitability.

Naturally, estimates of production cost vary depending on the source. Due to several unknowable factors, (for example, long-term well behavior) it is impossible to pinpoint a precise figure but perhaps we can get a general idea of the scale of investments that will be undertaken by Brazil. The Espírito Santo reserves, such as Jubarte, are shallower than Tupi and thus will be less expensive to produce. Jubarte itself is located 4,550 meters below sea level and underneath 200 meters of salt, compared to Tupi's location of 6,000 meters under water and 2,000 meters under salt. One estimate of overall production costs for the Tupi field alone is $100 to $200 billion. If Carioca proves to be as large as many believe it is, the costs of production there could be much higher than Tupi. The good news is that costs have already decreased, just in the short time since Tupi was first tested. Petrobras spent an entire year and $240 million on the first exploratory well drilled into the reservoir. The most recent ones have been completed in just 60 days and cost approximately $60 million. It would seem that Brazil and Petrobras in particular are betting that oil prices remain above their minimum profit threshold. Only weeks ago, Petrobras announced the order of ten new platforms for deepwater exploration that is set to begin in the Santos Basin between 2013 and 2016. This will come on the heels of Tupi's pilot production, which is set to begin in 2010 and will mark the dawn of a new era for Brazil's economy.

What Pre-Salt Means for Petrobras, Brazil

The company deserving the lion's share of the credit for Brazil's potential oil bonanza is Petrobras, which was created in 1953 by the Brazilian government but has since seen a majority of its equity sold to the private sector although the government maintains the majority of voting shares and effectively controls the company. Petrobras maintained a monopoly over Brazil's energy sector until 1997 and is still one of the largest companies in the Americas. After putting up the initial capital to explore Tupi and other pre-salt areas, Petrobras now fears that the government will take actions that significantly reduce its market share. Almost immediately after Petrobras announced the Tupi discoveries, the Brazilian government removed 41 exploration blocks in the Tupi region from a planned auction signaling to IOCs that the rules of the game were going to change. Citing the need to invest heavily in education and health as well as the general maintenance of the country's economic resources, the government set up an inter-ministry committee to consider the best means of utilizing Brazil's increased revenue from the potential oil boom as part of the country's long term development plan. According to President Luiz Inácio Lula da Silva, the commission will present its findings and recommendations to him on October 31, 2008, at which time he will decide upon a course of action. If he opts for changes in the oil and energy laws, they will have to go through Congress, which could mean serious delays. ANP, the country's oil regulator, initially drafted a bill that would change energy laws, limiting the potential influence of outside investors in the new fields but the government has since been keen to reassure current investors that it will honor all existing contracts. It is likely, however, that new rules would restrict IOCs' ability to bid on new concessions.

There has been much speculation that the government will either increase its shares in Petrobras, nationalize the company altogether, or create an entirely new government-owned company to manage the pre-salt reservoirs. If a new firm is created, it will be subject to the approval of Congress, a consideration that may push the government to pursue other alternatives. The creation of a new firm is the most likely scenario if the government decides to pursue a production-sharing model whereby it owns the oil but pays companies from the proceeds. Under the current system, the companies own the oil they discover and produce but pay royalties and taxes to the government. It is also possible that the government opts to continue with the current system but raises the price of oil company concessions. In any case, another likely outcome is eventual Brazilian investment in off shore sovereign wealth funds.

The finds in Brazilian pre-salt clusters stand to have far reaching economic and political impacts. The strategic advantage increased natural gas reserves gives Brazil in its relations to politically unstable Bolivia has already been mentioned. Furthermore, it is likely that Brazil will join OPEC once production begins at Tupi in 2010. The need to protect the new fields has already led to a partnership with France, to whom Brazil turned for assistance with the construction of a nuclear-powered submersible that will defend the pre-salt basins from attack. Finally, reserves have been confirmed beneath salt shelves off the shores of Angola, Gabon and Congo. If Brazil continues to lead the drive in pre-salt technological development, exploration and production costs will fall, potentially spurring more widespread investment in West African plays as well as pre-salt exploration elsewhere. If this happens, a reigniting of the peak oil debate is inevitable.

 

 

Brazilian Basins Hosting Pre-Salt Oil Reserves

 

Appendix II.

Tupi's Salt Layers

 

    
 

 

 

 

 

 

 

 

 

 

 

 

 

Appendix III.

Map of Tupi Reservoir

 

 

 

 

 

 

 

Alexandre Rocha. "Arab technology in pre-salt layer." Brazil-Arab News Agency. 2 September 2008. <http://www2.anba.com.br/noticia_petroleoegas.kmf?cod=7653294>(1 October 2008).

Antonio Affonso Rocha Filho, Sr., Exploration Geophysicist for Petrobras America. affonso@petrobras-usa.com "Pre-salt plays in Brazil," 13 October 2008. Personal email (13 October 2008).

"Brazil announces more oil and gas proven reserves." Mercopress. September 28, 2008. <http://www.mercopress.com/vernoticia.do?id=14680&formato=pdf>(13 October 2008).

"Brazil reiterates no change to oil contracts." Offshore-technology.com. 10 October 2008. <http://www.offshore-technology.com/news/news43843.html> (13 October 2008).

"Brazil's Tupi to Cost $100-$200 Billion." Jim Kingsdale's Energy Investment Strategies. (Quoting a Reuters article. 8 March 2008. The $100-$200 billion number was produced by John Olsen of Houston Energy Partners. <http://www.energyinvestmentstrategies.com/2008/03/11/brazils-tupi-to-cost-100-200-billion/>. (10 October 2008).

"A Funny Kind of Reward." The Economist. 28 August 2008. <http://www.economist.com/world/americas/displaystory.cfm?story_id=12009864> (20 September 2008).

"Iran invites Brazil to join OPEC." 5 September 2008. The Iranian Ambassador has already made a formal offer of membership, a gesture that is within Iran's rights as a founding member of OPEC. <http://www.domain-b.com/industry/oil_gas/20080905_join_cartel.html>(10 October 2008).

Jeffrey A. Nunn, Louisiana State University Department of Geology and Geophysics. <gljeff@lsu.edu> "Pre-salt plays in Brazil." 14 October 2008. Personal email. (14 October 2008)

Jose Formigli. "Pre-salt Reservoirs Offshore Brazil: Perspectives and Challenges." Presented on behalf of Petrobras at the Energy Conference. November 2007. <www2.petrobras.com.br/ri/pdf/2007_Formigli_Miami_pre-sal.pdf> (1 October 2008)

Jose Formigli, in a presentation to the Rio Oil & Gas Expo and Conference. 15-19 September 2008. (Quoted in Nina M. Rach, Oil and Gas Journal. http://www.ogj.com/display_article/339799/120/ARTCL/none/DriPr/1/Petrobras,-IOCs-share-views-below-salt/> (1 October 2008)).

Jose Formigli. Interview by Upstreamonline. Upstreamonline. <http://www.upstreamonline.com/web_tv/>(10 October 2008).

Jose Formigli. "Pre-salt Reservoirs Offshore Brazil: Perspectives and Challenges." Presented on behalf Jennifer Pallanich. "Pre-salt promise buoys bustling market." Offshore Engineer. 18 June 2008. <http://www.oilonline.com/news/features/oe/20080618.Pre-salt.23314.asp> (10 October 2008).

Marcio R. Mello, speaking at the 2008 American Association of Petroleum Geologists Meeting. (Quoted in Offshore. <http://www.offshore-mag.com/display_article/332236/9/ARCHI/none/none/1/Subsalt-forms-core-of-AAPG-papers/> (7 October 2008)).

"Mulitple Oil Finds Continue String of Success in Brazil." <http://www.rigzone.com/news/article.asp?a_id=67319.>(10 October 7, 2008).

Nina M. Rach. "Petrobras, IOCs share subsalt, presalt exploration views." Oil and Gas Journal. September 17 2008. <http://www.mapsearch.com/news/display.html?id=339799> (13 October 2008).

Peter Howard Wertheim. "Brazil reserves soar on new find." Offshore. <http://www.offshore-mag.com/articles/save_screen.cfm?ARTICLE_ID=318223>(10 October 2008).

Peter Howard Wertheim. "Pre-salt discoveries continue in Brazil." Offshore. Vol 68, Issue 7. July 2008. (http://www.offshore-mag.com/display_article/334452/9/ARCHI/none/none/1/Pre-salt-discoveries-continue-in-Brazil/> (1 October 2008).

"Petrobras' Tupi has potential to be largest deepwater oil discovery." Pipeline and Gas Journal. Dec 2006. <http://findarticles.com/p/articles/mi_m3251/is_12_234/ai_n25016906> (7 October 2008).

"Petrobras to order 10 platforms for pre-salt." Brazil-Arab News Agency. 15 September 2008. <http://www2.anba.com.br/noticia_petroleoegas.kmf?cod=7690226&indice=10>.(1 October 2008).

"The Tupi Challenge" is available for viewing online. <http://www.petrobras.com/ptcm/appmanager/ptcm/dptcm?_nfpb=true&_pageLabel=petr_com_energia.> (10 October 2008).

"Tupi Oil Field, Brazil." Offshore-technology.com. <http://www.offshore-technology.com/projects/tupi/> (10 October 2008). To date, Petrobras is the only company to manage all three aspects of exploration.