Part IV: Solar

Part IV of our energy series, takes a look at solar energy throughout history to the present. There is also a link to the United States Department of Energy~~Renewable Resources Site which has everything you would ever want to know about solar energy, and the big part it can play in providing energy independence for our Nation. There is also a great deal of information available from Wikipedia, ASES (American Solar Energy Society), www.eia.doe.gov/kids/energyfacts/sources/renewable/solar.html (which is a great resource for children, who may want to learn about solar energy), and SEIA (Solar Energy Industries Association), which is a National trade association for all solar businesses and enterprises in the fields of photovoltaics. They all have easy to understand information available, some of which is in this post, so my thanks to them all.

We shall begin with a little history:
We have always used the energy of the sun as far back as humans have existed on this planet. As far back as 5,000 years ago, people "worshipped" the sun. Ra, the sun-god, who was considered the first king of Egypt. In Mesopotamia, the sun-god Shamash was a major deity and was equated with justice. In Greece there were two sun deities, Apollo and Helios. The influence of the sun also appears in other religions - Zoroastrianism, Mithraism, Roman religion, Hinduism, Buddhism, the Druids of England, the Aztecs of Mexico, the Incas of Peru, and many Native American tribes.
We know today, that the sun is simply our nearest star. Without it, life would not exist on our planet. We use the sun's energy every day in many different ways.
When we hang laundry outside to dry in the sun, we are using the sun's heat to do work -- drying our clothes.
Plants use the sun's light to make food. Animals eat plants for food. Decaying plants hundreds of millions of years ago produced the coal, oil and natural gas that we use today. So, fossil fuels is actually sunlight stored millions and millions of years ago.
Indirectly, the sun or other stars are responsible for ALL our energy. Even nuclear energy comes from a star because the uranium atoms used in nuclear energy were created in the fury of a nova - a star exploding.
Let's look at ways in which we can use the sun's energy.
In the 1890s solar water heaters were being used all over the United States. They proved to be a big improvement over wood and coal-burning stoves. Artificial gas made from coal was available too to heat water, but it cost 10 times the price we pay for natural gas today. And electricity was even more expensive if you even had any in your town!
Many homes used solar water heaters. In 1897, 30 percent of the homes in Pasadena, just east of Los Angeles, were equipped with solar water heaters. As mechanical improvements were made, solar systems were used in Arizona, Florida and many other sunny parts of the United States.
By 1920, ten of thousands of solar water heaters had been sold. By then, however, large deposits of oil and natural gas were discovered in the western United States. As these low cost fuels became available, solar water systems began to be replaced with heaters burning fossil fuels.
Today, solar water heaters are making a comeback. There are more than half a million of them in California alone! They heat water for use inside homes and businesses. They also heat swimming pools.
Panels on the roof of a building, contain water pipes. When the sun hits the panels and the pipes, the sunlight warms them.
That warmed water can then be used in a swimming pool.

Solar energy can also be used to make electricity.
Some solar power plants use a highly curved mirror called a parabolic trough to focus the sunlight on a pipe running down a central point above the curve of the mirror. The mirror focuses the sunlight to strike the pipe, and it gets so hot that it can boil water into steam. That steam can then be used to turn a turbine to make electricity.
In California's Mojave desert, there are huge rows of solar mirrors arranged in what's called "solar thermal power plants" that use this idea to make electricity for more than 350,000 homes. The problem with solar energy is that it works only when the sun is shining. So, on cloudy days and at night, the power plants can't create energy. Some solar plants, are a "hybrid" technology. During the daytime they use the sun. At night and on cloudy days they burn natural gas to boil the water so they can continue to make electricity.
Another form of solar power plants to make electricity is called a Central Tower Power Plant, sunlight is reflected off 1,800 mirrors circling the tall tower. The mirrors are called heliostats and move and turn to face the sun all day long.
The light is reflected back to the top of the tower in the center of the circle where a fluid is turned very hot by the sun's rays. That fluid can be used to boil water to make steam to turn a turbine and a generator.
This experimental power plant is called Solar II. It was re-built in California's desert using newer technologies than when it was first built in the early 1980s. Solar II will use the sunlight to change heat into mechanical energy in the turbine.
The power plant will make enough electricity to power about 10,000 homes. Scientists say larger central tower power plants can make electricity for 100,000 to 200,000 homes.

We can also change the sunlight directly to electricity using solar cells.
Solar cells are also called photovoltaic cells, or PV cells for short, and can be found on many small appliances, like calculators, and even on spacecraft. They were first developed in the 1950s for use on U.S. space satellites. They are made of silicon, a special type of melted sand.
When sunlight strikes the solar cell, electrons are knocked loose. They move toward the treated front surface. An electron imbalance is created between the front and back. When the two surfaces are joined by a connector, like a wire, a current of electricity occurs between the negative and positive sides.
These individual solar cells are arranged together in a PV module and the modules are grouped together in an array. Some of the arrays are set on special tracking devices to follow sunlight all day long.
The electrical energy from solar cells can then be used directly. It can be used in a home for lights and appliances. It can be used in a business. Solar energy can be stored in batteries to light a roadside billboard at night. Or the energy can be stored in a battery for an emergency roadside cellular telephone when no telephone wires are around.
Some experimental cars also use PV cells. They convert sunlight directly into energy to power electric motors on the car.
But when most of us think of solar energy, we think of satellites in outer space, and solar sails, like those on the space lab, hubble telescsope, and other satellites.
Here is just of the more promising "new" technologies to convert sunlight more efficiently.
On December 20, 2007 this article from gizmag stated: The inefficiency of solar cells in converting the sun’s rays into electricity is a key contributor to the high costs of solar energy, but new research into a novel shape of semiconductor nanostructures known as "nano flakes" may revolutionize the process and help improve the viability of clean energyhttp://en.wikipedia.org/wiki/Green_energy derived from the sun.
Details of the research by Martin Aagesen, a PhD from the Nano-Science Centerhttp://en.wikipedia.org/wiki/Science_center and the Niels Bohr Institute at University of Copenhagenhttp://en.wikipedia.org/wiki/University_of_Copenhagen were recently published in nature nanotechnology.
If his "future solar cells" meet expectations, they may be a huge step towards boosting the world’s exploitation of solar energy. Aagesen believes that the nano flakes have the potential to convert up to 30 per cent of the solar energy into electricity and that is roughly twice the amount that the average solar cell converts today.
The discovery was made during Aagesen’s work on his PhD thesishttp://en.wikipedia.org/wiki/Dissertation when he found a new and untried material. “I discovered a perfect crystalline structure. That is a very rare sight. While being a perfect crystalline structure we could see that it also absorbed all light. It could become the perfect solar cell,” he said. The technology has the potential to reduce the solar cell production costs which rely on expensive semiconducting silicium. At the same time, the "future solar cells" will exploit solar energy more effectively and lessen the loss of energy.
Aagesen is also director of the company Sunflake Inc. which is pursuing development of the new solar cell.
Other recent efforts to address the issue of solar cell efficiency include a breakthrough from SANYO in June this year which saw the company broke its own record for the world's highest energy conversion efficiency in practical size crystalline silicon-type solar cells by demonstrating an efficiency of 22%. In December last year Spectrolab achieved a world record in terrestrial concentrator solar cell efficiency, using a photovoltaichttp://en.wikipedia.org/wiki/Photovoltaics cell to convert 40.7 percent of the sun's energy into electricity. More recently, Global Warming Learning-to-Love-Global-Warming Solutions announced the development of new solar energy conversion technology based on a special coating that can be applied to existing solar cells.
There are many other companies working on this problem, trying to come up with better, more efficient designs, to utilize solar power, and more information in available at the United States Department of Energy Link Below.

Part V: Wave Energy is on tap for tomorrow. Have A Great Monday!!


link to usdoe solar resources page

Part III: Wind

Harnessing the wind is one of the cleanest, most sustainable ways to generate electricity. Wind power produces no toxic emissions and none of the heat trapping emissions that contribute to global warming. This, and the fact that wind power is one of the most abundant and increasingly cost-competitive energy resources, makes it a viable alternative to the fossil fuels that harm our health and threaten the environment.
Wind energy is the fastest growing source of electricity in the world. Global installations in 2005 reached more than 11,500 megawatts (MW)–a 40.5 percent increase in annual additions compared with 2004–representing $14 billion in new investments. In the United States, a record 2,431 MW of wind power was installed in 2005, capable of producing enough electricity to power 650,000 typical homes. Despite this rapid growth, wind power is still a relatively small part of our electricity supply–generating less than one percent of both the and global electricity mix. But thanks to its many benefits, and significantly reduced costs, wind power is poised to play a major role as we move toward a sustainable energy future.

Wind power is both old and new. From the sailing ships of the ancient Greeks, to the grain mills of pre-industrial Holland, to the latest high-tech wind turbines rising over the Minnesota prairie, humans have used the power of the wind for millennia. In the United States, the original heyday of wind was between 1870 and 1930, when thousands of farmers across the country used wind to pump water. Small electric wind turbines were used in rural areas as far back as the 1920s, and prototypes of larger machines were built in the 1940s. When the New Deal brought grid-connected electricity to the countryside, however, windmills lost out.

Interest in wind power was reborn during the energy crises of the 1970s. Research by the U.S. Department of Energy (DOE) in the 1970s focused on large turbine designs, with funding going to major aerospace manufacturers. While these 2- and 3-MW machines proved mostly unsuccessful at the time, they did provide basic research on blade design and engineering principles. The modern wind era began in California in the 1980s. Between 1981 and 1986, small companies and entrepreneurs installed 15,000 medium-sized turbines, providing enough power for every resident of San Francisco. Pushed by the high cost of fossil fuels, a moratorium on nuclear power, and concern about environmental degradation, the state provided tax incentives to promote wind power. These, combined with federal tax incentives, helped the wind industry take off. After the tax credits expired in 1985, wind power continued to grow, although more slowly. Perhaps more important in slowing wind power's growth was the decline in fossil fuel prices that occurred in the mid-1980s.

In the early 1990s, improvements in technology resulting in increased turbine reliability and lower costs of production provided another boost for wind development. In addition, concern about global warming and the first Gulf War lead Congress to pass the Energy Policy Act of 1992–comprehensive energy legislation that included a new production tax credit for wind and biomass electricity. However, shortly thereafter, the electric utility industry began to anticipate a massive restructuring, where power suppliers would become competitors rather than protected monopolies. Investment in new power plants of all kinds fell drastically, especially for capital-intensive renewable energy technologies like wind. America's largest wind company, Kenetech, declared bankruptcy in 1995, a victim of the sudden slowdown. It wasn’t until 1998 that the wind industry began to experience continuing growth in the United States, thanks in large part to federal tax incentives, state-level renewable energy requirements and incentives, and–beginning in 2001–rising fossil fuel prices.

In other parts of the world, particularly in Europe, wind has had more consistent, long-term support. As a result, European countries are currently capable of meeting more of their electricity demands through wind power with much less land area and resource potential compared with the United States. Denmark, for example, already meets about 20 percent of its electricity demand from wind power. Wind generation also accounts for about six percent of the national power needs in Spain, and five percent in Germany. Serious commitments to reducing global warming emissions, local development, and the determination to avoid fuel imports have been the primary drivers of wind power development.

The Wind Resource
The wind resource–how fast it blows, how often, and when–plays a significant role in its power generation cost. The power output from a wind turbine rises as a cube of wind speed. In other words, if wind speed doubles, the power output increases eight times. Therefore, higher-speed winds are more easily and inexpensively captured.

Wind speeds are divided into seven classes–with class one being the lowest, and class seven being the highest. A wind resource assessment evaluates the average wind speeds above a section of land (usually 50 meters high), and assigns that area a wind class. Wind turbines operate over a limited range of wind speeds. If the wind is too slow, they won't be able to turn, and if too fast, they shut down to avoid being damaged. Wind speeds in classes three (6.7 – 7.4 meters per second (m/s)) and above are typically needed to economically generate power. Ideally, a wind turbine should be matched to the speed and frequency of the resource to maximize power production.


link to all about wind energy and charts


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Wind power is capable of becoming a major contributor to America’s electricity supply over the next three decades, according to a report by the U.S. Department of Energy. The groundbreaking report, 20% or more if a monumental effort is put forward for Wind Energy by 2030 or sooner: Increasing Wind Energy’s Contribution to U.S. Electricity Supply, looks closely at one scenario for reaching 20% wind energy by 2030 and contrasts it to a scenario of no new U.S. wind power capacity.

This DOE report includes contributions from
• U.S. Department of Energy (DOE) − Office of Energy Efficiency and Renewable Energy (EERE), Office of Electricity Delivery and Energy Reliability (OE), and Power Marketing Administrations (PMAs) − National Renewable Energy Laboratory (NREL) − Lawrence Berkeley National Laboratory (Berkeley Lab) − Sandia National Laboratories (SNL) Black & Veatch engineering and consulting firm American Wind Energy Association (AWEA) − Leading wind manufacturers and suppliers − Developers and electric utilities − Others in the wind industry
Wind power can play a major role in meeting America's increasing demand for electricity, according to a groundbreaking technical report, 20% Wind Energy by2030: Increasing Wind Energy's Contribution to U.S. Electricity Supply, prepared
by the U.S. Department of Energy with contributions from the National Renewable Energy Laboratory, the American Wind Energy Association, Black & Veatch and others from the energy sector.

The report explores one scenario for reaching 20% wind electricity by 2030 and contrasts it to a scenario in which no new U.S. wind power capacity is installed. It examines costs, major impacts and challenges associated with the 20% Wind Scenario. It investigates
requirements and outcomes in the areas of technology, manufacturing, transmission and integration, markets, environment
and siting. The report finds that the Nation possesses affordable wind energy resources far in excess of those needed to enable a 20%
scenario.

To implement the 20% Wind Scenario, new wind power installations would increase to more than 16,000 MW per year by 2018, and
continue at that rate through 2030, as shown in Figure A. Wind plant costs and performance are projected to improve modestly over the
next two decades, but no technological breakthroughs are needed. In the 20% wind scenario, 46 states would experience significant wind
power development.

The report finds that, during the decade preceding 2030, the U.S. wind industry could: support roughly 500,000 jobs in the U.S., with an annual average of more than 150,000 workers directly employed by the wind industry; support more than 100,000 jobs in associated industries (e.g., accountants, lawyers, steel workers, and electrical manufacturing);

support more than 200,000 jobs through economic expansion based on local spending; increase annual property tax revenues to more than $1.5 billion by 2030; and increase annual payments to rural landowners to more than $600 million in 2030. Using more domestic wind power will diversify the nation's energy portfolio — adding wind-generated electricity at stable prices not subject to market volatility
— and strengthening national energy security through reduced reliance on foreign sources of natural gas. The 20% Wind Scenario would alter U.S. electricity generation as shown in Figure B. In this scenario, wind would supply enough energy to displace about 50% of
electric utility natural gas consumption by 2030. This amounts to an 11% reduction in natural gas across all industries. Also, coal consumption would be reduced by 18%. In addition, electric utilities are learning how to accommodate wind's variability while maintaining system reliability.


Carbon dioxide (CO ) is the principal GHG in the earth's atmosphere. Approximately 40% of total U.S. CO emissions come from power generation facilities. Since substantial amounts of coal and natural gas fuels would be displaced, the 20% Wind Scenario could
reduce CO emissions in 2030 by 825 million metric tons – 25% of the CO emissions from the nation's electric sector in the no-new-wind scenario. As shown in Figure C, this reduction could nearly level projected growth in CO emissions from electricity generation.

The report examines siting issues and effects that an increase in wind power facilities may have on compatible land uses,
water use, aesthetics, and wildlife habitats. Wind energy avoids many of the undesirable environmental impacts from
other forms of electricity production, such as impacts from fuel mining, transport and waste management.

Unlike fossil-fuel and nuclear generation, which use significant quantities of water for power plant cooling, wind
power generation consumes no water during operations. Generating 20% of U.S. electricity from wind would reduce
water consumption in the electric sector in 2030 by 17%.

Costs incurred by the 20% Wind Scenario exceed those of theno-new-wind scenario by about 2%. Although the 20% wind
scenario would incur higher initial capital costs, a large portion of those costs would be offset by $155 billion in lower
fuel expenditures. The estimated incremental investment would be $43 billion (net-present-value basis; 2006$). This corresponds to about
0.06¢/kWh of total generation, or about 50¢ per month for the average household. These monetary costs do not reflect other potential offsetting positive impacts. Major challenges along the 20% Wind Scenario path include these:

Investment in the nation's transmission system is needed so that the electricity generated is delivered to urban centers that need the increased supply; Developing larger electric load balancing areas, in tandem with better regional planning, are needed so that regions can depend on a diversity of generation sources, including wind power;

Significant growth is needed in the manufacturing supply chain, providing jobs and remedy the current shortage in parts for wind turbines; Continued reduction in wind capital cost and improvement in turbine performance through technology advancement and improved manufacturing capabilities is needed; and Addressing potential concerns about local siting, wildlife, and environmental issues
within the context of generating electricity is needed.

The 20% Wind Scenario is not likely to be realized in a business-as-usual future. Achieving this scenario would involve a major national commitment to clean, domestic energy sources with minimal emissions of GHGs and other environmental pollutants.

Tomorrow is Part IV: Solar. Have A Nice Sunday!!

Part 2 of Part II: Coal

Here is Part 2 of Part II: Coal, and a look at the latest "clean" coal technologies:

As We Have Seen Over The Last Few Years With Fuel Prices Climbing Ever Higher, Oil Dependency Has Become Hazardous to Our Economic Health!
Over half of the oil that fuels America's economy is now sold to us from foreign sources . Growing Foreign Dependence, But these sources may not always be reliable.
In 1973 and 1979, America experienced dual "oil shocks" -- cutoffs of supply that provided an important warning about our vulnerability to foreign disruptions. Those crises should have served as lessons about dependence on unreliable offshore sources. Instead, our dependence on foreign sources stands at an even higher level today than it did during the embargoes that plunged America into serious recessions in the past.
Today, America is vulnerable.

An Important Step
Toward Reducing Our Vulnerability
One logical alternative is coal. American coal and waste coal reserve estimates vary wildly . World Recoverable Oil Resoucres~~Pennsylvania, a prime coal state, is estimated to have 34 billion tons of in ground reserves.
But until recently, environmental concerns about coal posed a large obstacle to attaining greater U.S. self-sufficiency in energy. The environmental impact of mining and burning more coal was considered by many people to be too great to justify.
Today, new technology has made it possible for us to turn back to domestic energy sources -- and to do it cleanly. Coal gasification/coal liquefaction will now allow us to tap the abundant energy stores within our own borders -- without compromising our standards of environmental quality. In fact, these technologies may be our best hope for environmental progress in future years.
Using more of our domestic energy reserves would free us from reliance on potentially unstable sources and the economic drain that results from buying oil from overseas. It would result in greater stability in fuel pricing, jobs and job security, and enhance our national security by lessening our dependency on foreign sources.
The "US Geological Survey estimates the total identified coal resources as being 1,600 billion tons. Another 1,600 billion tons of unidentified resources are postulated." Currently the US produces approximately 1.06 billion tons of coal annually.
If the US were to produce, from coal alone, the amount of oil equivalent to what the US imports, the US would consume an additional .912 billion tons annually.

Total coal production/consumption would then = 1.972 billion tons annually. (Not even considering the benefits of energy efficiency, biomass, renewables, high mileage vehicles etc., all of which would significantly extend our energy reserves.)
1,600 billion tons of coal / 1.972 = 811 years of fuel reserves.
Given these new conversion technologies the US is, in effect, sitting on a minimum of 811 years of worth of fuel reserves.
To the extent this message becomes clear to off shore oil suppliers, the perception of a sellers market should diminish and the US would be positioned to purchase oil on its own terms.
Coal Gasification/Liquefaction Link
Coal conversion technologies - - such as Coal Gasification / Liquefaction Coal Gasification/Liquification-- are process technologies adapted from proven production methods that have been in use for decades.
In sum, the process utilizes carbonaceous matter -- coal, coal waste, biomass, refinery waste and other materials -- to produce liquid fuel products that are environmentally friendly, known as Ultra Clean Fuels.
Ultra Clean Fuels are zero-% nitrogen, low in aromatics
with a high cetane (energy density) number.
Fuels meeting these criteria are already required in some areas of the country with strict emissions standards. Ultra Clean Fuels would not only be plentiful, they could also play a large role in helping us meet the new goals for energy efficiency and cleaner air.
In addition, the production process extracts sulfur and other materials which can be used for other manufacturing and commercial purposes.

Economic Benefits Of
Choosing Ultra Clean Fuels Technology
Making a commitment to Ultra Clean Fuels Technology will have substantial and long-lasting benefits, according to a study by the Center for Forensic Economic Studies. Among them:
Adoption of Ultra Clean Fuels Technology would re-energize the domestic coal production industry (Anthracite, Bituminous, Sub Bituminous, Lignite).

Construction and operation of Ultra Clean Fuels production facilities would create high-quality jobs, improve job security and productivity, and result in numerous spin-off benefits throughout the economy.

Reliance on domestic coal resources would revitalize communities in coal producing regions across the country.

Lessening dependence on foreign oil sources would improve the U.S. balance of payments dramatically and reduce the outflow of dollars to overseas suppliers.

Diversifying our sources of energy would reduce the threat of war or economic blackmail by foreign powers that control a portion of oil reserves, with potential savings of billions of dollars and thousands of lives.

Environmental Benefits Of Choosing
Ultra Clean Fuels Technology
Ultra Clean Fuels are cleaner both in production and consumption than standard fossil fuels.

Utilizing Ultra Clean Fuels would reduce the overall amount of greenhouse gases introduced into the atmosphere.

Ultra Clean Fuels are generally more environmentally friendly than the production of electricity for electric "non-polluting" cars.

Coal wastes that have blighted the landscapes of coal producing regions for decades would be utilized for production, resulting in wholesale reclamation of those regions.

The Private/Public Partnership
Moving Ultra Clean Fuels Technology from the drawing board into production will require an enormous effort and sizable startup costs. For this reason, the Private / Public Partnership for Ultra Clean Fuels Technology represents the best means for making Ultra Clean Fuels Technology commercially viable in the near future.
In this partnership, private industry would be responsible for financing and construction as well as operation of the production facilities.
The public sector role would center around adoption of tax incentives that help offset the enormous capital expenditures required to make plants operational. This step will ensure a more reasonable level of risk for commercial financing purposes.


Conclusion
The benefits of applying Ultra Clean Fuels Technology are substantial:
better utilization of domestic coal and other carbonaceous feedstock

an alternative to continued dependence on unreliable oil imports Energy Dependency

rebuilding our energy industry Energy Independence

creation of new high-quality jobs

reclamation of the nation's coal regions

economic benefits of lessening foreign debt burden incurred from imports
These factors are only the highlights of a program that will have an enormous positive impact on the living standards and quality of life of the American people.
Implementing Ultra Clean Fuels Technologies through a Private/Public Partnership represents a true "win-win" for the economy and the environment.
The time to act is now.

And here is how coal is seen from the prespective others, with this assessment from the World Nuclear Association:
Clean Coal Technology:
Coal is a vital fuel in most parts of the world.
Burning coal without adding to global carbon dioxide levels is a major technological challenge which is being addressed.
The most promising "clean coal" technology involves using the coal to make hydrogen from water, then burying the resultant carbon dioxide by-product and burning the hydrogen.
The greatest challenge is bringing the cost of this down sufficiently for "clean coal" to compete with nuclear power on the basis of near-zero emissions for base-load power.
Coal is an extremely important fuel and will remain so. Some 23% of primary energy needs are met by coal and 39% of electricity is generated from coal. About 70% of world steel production depends on coal feedstock. Coal is the world's most abundant and widely distributed fossil fuel source. The International Energy Agency expects a 43% increase in its use from 2000 to 2020.
However, burning coal produces about 9 billion tonnes of carbon dioxide each year which is released to the atmosphere, about 70% of this being from power generation. Other estimates put carbon dioxide emissions from power generation at one third of the world total of over 25 billion tonnes of CO2 emissions.
New "clean coal" technologies are addressing this problem so that the world's enormous resources of coal can be utilised for future generations without contributing to global warming. Much of the challenge is in commercialising the technology so that coal use remains economically competitive despite the cost of achieving "zero emissions".
As many coal-fired power stations approach retirement, their replacement gives much scope for 'cleaner' electricity. Alongside nuclear power and harnessing renewable energy sources, one hope for this is via "clean coal" technologies, such as are now starting to receive substantial R&D funding.
Managing wastes from coal
Burning coal, such as for power generation, gives rise to a variety of wastes which must be controlled or at least accounted for. So-called "clean coal" technologies are a variety of evolving responses to late 20th century environmental concerns, including that of global warming due to carbon dioxide releases to the atmosphere. However, many of the elements have in fact been applied for many years, and they will be only briefly mentioned here:
Coal cleaning by 'washing' has been standard practice in developed countries for some time. It reduces emissions of ash and sulfur dioxide when the coal is burned.
Electrostatic precipitators and fabric filters can remove 99% of the fly ash from the flue gases - these technologies are in widespread use.
Flue gas desulfurisation reduces the output of sulfur dioxide to the atmosphere by up to 97%, the task depending on the level of sulfur in the coal and the extent of the reduction. It is widely used where needed in developed countries.
Low-NOx burners allow coal-fired plants to reduce nitrogen oxide emissions by up to 40%. Coupled with re-burning techniques NOx can be reduced 70% and selective catalytic reduction can clean up 90% of NOx emissions.
Increased efficiency of plant - up to 45% thermal efficiency now (and 50% expected in future) means that newer plants create less emissions per kWh than older ones.
Advanced technologies such as Integrated Gasification Combined Cycle (IGCC) and Pressurised Fluidised Bed Combustion (PFBC) will enable higher thermal efficiencies still - up to 50% in the future.
Ultra-clean coal from new processing technologies which reduce ash below 0.25% and sulfur to very low levels mean that pulverised coal might be fed directly into gas turbines with combined cycle and burned at high thermal efficiency.
Gasification, including underground gasification in situ, uses steam and oxygen to turn the coal into carbon monoxide and hydrogen.
Sequestration refers to disposal of liquid carbon dioxide, once captured, into deep geological strata.
Some of these impose operating costs without concomitant benefit to the operator, though external costs will almost certainly be increasingly factored in through carbon taxes or similar which will change the economics of burning coal.
However, waste products can be used productively. In 1999 the EU used half of its coal fly ash and bottom ash in building materials (where fly ash can replace cement), and 87% of the gypsum from flue gas desulfurisation.
Carbon dioxide from burning coal is the main focus of attention today, since it is implicated in global warming, and the Kyoto Protocol requires that emissions decline, notwithstanding increasing energy demand.
Capture & separation of CO2
A number of means exist to capture carbon dioxide from gas streams, but they have not yet been optimised for the scale required in coal-burning power plants. The focus has often been on obtaining pure CO2 for industrial purposes rather than reducing CO2 levels in power plant emissions.
Where there is carbon dioxide mixed with methane from natural gas wells, its separation is well proven. Several processes are used, including hot potassium carbonate which is energy-intensive and requires a large plant, a monoethanolamine process which yields high-purity carbon dioxide, amine scrubbing, and membrane processes.
Capture of carbon dioxide from flue gas streams following combustion in air is expensive as the carbon dioxide concentration is only about 14% at best. This treats carbon dioxide like any other pollutant and as flue gases are passed through an amine solution the CO2 is absorbed. It can later be released by heating the solution. This amine scrubbing process is also used for taking CO2 out of natural gas. There is an energy cost involved.
The Integrated Gasification Combined Cycle (IGCC) plant is a means of using coal and steam to produce hydrogen and carbon monoxide (CO) which are then burned in a gas turbine with secondary steam turbine (ie combined cycle) to produce electricity.
If the IGCC gasifier is fed with oxygen rather than air, the flue gas contains highly-concentrated CO2 which can readily be captured by amine scrubbing - at about half the cost of capture from conventional plants. Ten oxygen-fired gasifiers are operational in the USA.
Development of this oxygen-fed IGCC process will add a shift reactor to oxidise the CO with water so that the gas stream is basically just hydrogen and carbon dioxide. These are separated before combustion and the hydrogen alone becomes the fuel for electricity generation (or other uses) while the concentrated pressurised carbon dioxide is readily disposed of.
Currently IGCC plants have a 45% thermal efficiency.
Capture of carbon dioxide from coal gasification is already achieved at low marginal cost in some plants. One (albeit where the high capital cost has been largely written off) is the Great Plains Synfuels Plant in North Dakota, where 6 million tonnes of lignite is gasified each year to produce clean synthetic natural gas.
Oxy-fuel technology has potential for retrofit to existing pulverised coal plants, which are the backbone of electricity generation in many countries.
Storage & sequestration of CO2
Captured carbon dioxide gas can be put to good use, even on a commercial basis, for enhanced oil recovery. This is well demonstrated in West Texas, and today over 3000 km of pipelines connect oilfields to a number of carbon dioxide sources in the region.
At the Great Plains Synfuels Plant, North Dakota, some 13,000 tonnes per day of carbon dioxide gas is captured and 5000 t of this is piped 320 km into Canada for enhanced oil recovery. This Weyburn oilfield sequesters about 85 cubic metres of carbon dioxide per barrel of oil produced, a total of 19 million tonnes over the project's 20 year life. The first phase of its operation has been judged a success.
Overall in USA, 32 million tonnes of CO2 is used annually for enhanced oil recovery, 10% of this from anthropogenic sources.
The world's first industrial-scale CO2 storage was at Norway's Sleipner gas field in the North Sea, where about one million tonnes per year of compressed liquid CO2 separated from methane is injected into a deep reservoir (saline aquifer) about a kilometre below the sea bed and remains safely in place. The US$ 80 million incremental cost of the sequestration project was paid back in 18 months on the basis of carbon tax savings at $50/tonne. (The natural gas contains 9% CO2 which must be reduced before sale or export.) The overall Utsira sandstone formation there, about one kilometre below the sea bed, is said to be capable of storing 600 billion tonnes of CO2.
West Australia's proposed Gorgon natural gas project from 2009 will tap natural gas with 14% CO2. Capture and geosequestration of this will reduce the project's emissions from 6.7 to 4.0 million tonnes of CO2 per year.
Injecting carbon dioxide into deep, unmineable coal seams where it is adsorbed to displace methane (effectively: natural gas) is another potential use or disposal strategy. Currently the economics of enhanced coal bed methane extraction are not as favourable as enhanced oil recovery, but the potential is large.
While the scale of envisaged need for CO2 disposal far exceeds today's uses, they do demonstrate the practicality. Safety and permanence of disposition are key considerations in sequestration.
Research on geosequestration is ongoing in sevaral parts of the world. The main potential appears to be deep saline aquifers and depleted oil and gas fields. In both, the CO2 is expected to remain as a supercritical gas for thousands of years, with some dissolving.
Large-scale storage of CO2 from power generation will require an extensive pipeline network in densely populated areas. This has safety implications.
Economics, R&D
The World Coal Institute notes that at present the high cost of carbon capture and storage (US$ 150-220 per tonne of carbon, $40-60/t CO2 - 3.5 to 5.5 c/kWh relative to coal burned at 35% thermal efficiency) renders the option uneconomic. But a lot of work is being done to improve the economic viability of it, and the US Dept of Energy (DOE) is funding R&D with a view to reducing the cost of carbon sequestered to US$ 10/tC (equivalent to 0.25 c/kWh) or less by 2008, and by 2012 to reduce the cost of carbon capture and sequestration to a 10% increment on electricity generation costs.
More recently the DOE had announced the $1.3 billion FutureGen project to design, build and operate a nearly emission-free coal-based electricity and hydrogen production plant. The FutureGen initiative would have comprised a coal gasification plant with additional water-shift reactor, to produce hydrogen and carbon dioxide. About one million tonnes of CO2 (at least 90% of throughput) would then be separated by membrane technology and sequestered geologically. The hydrogen would have been be burned in a 275 MWe generating plant and in fuel cells.
Construction of FutureGen was due to start in 2009, for operation in 2012. The project was designed to validate the technical feasibility and economic viability of near-zero emission coal-based generation. In particular it aimed to produce electricity with only a 10% cost premium and to show that hydrogen can be produced at $3.80 per GJ, equivalent to petrol at 12.7 cents per litre.
In December 2007 Mattoon Illinois was chosen as the site of the demonstration plant. However, in January 2008 the DOE announced that it would pull its funding for project, expressing concerns over escalating costs. The DOE has said that funding would be made available to assist other projects that aim to add carbon capture and storage (CCS) to existing coal plants, but will no longer include hydrogen production as part of the project.
In the UK a competition was launched by the UK government in November 2007 to support a coal-fired power plant demonstrating the full chain of CCS technologies (capture, transport, and storage) on a commercial scale. The winning project bid will need to demonstrate post-combustion capture (including oxyfuel) on a coal-fired power station, with the carbon dioxide being transported and stored offshore. The project will have to capture around 90% of the CO2 emitted by the equivalent of 300MW-400MW generating capacity. The successful project bid should demonstrate the entire CCS chain by 2014. The winning project bid will be chosen by May-June 2009.
In Denmark a pilot project at the 420 MWe Elsam power plant is capturing CO2 from post-combustion flue gases under the auspices of CASTOR (CO2 from Capture to Storage). Flue gases are passed through an absorber, where a solvent captures about 90% of the CO2. The pregnant solution is then heated to 120°C to release pure CO2 at the rate of about one tonne per hour for geological sequestration. Cost is expected to be EUR 20-30 per tonne.
A 2000 US study put the cost of CO2 capture for IGCC plants at 1.7 c/kWh, with an energy penalty 14.6% and a cost of avoided CO2 of $26/t ($96/t C). By 2010 this is expected to improve to 1.0 c/kWh, 9% energy penalty and avoided CO2 cost of $18/t ($66/t C).
Figures from IPCC Mitigation working group in 2005 for IGCC put capture and sequestration cost at 1.0-3.2 c/kWh, thus increasing electricity cost for IGCC by 21-78% to 5.5 to 9.1 c/kWh. The energy penalty in that was 14-25% and the mitigation cost $14-53/t CO2 ($51-200/tC) avoided. These figures included up to $5 per tonne CO2 for transport and up to $8.30 /t CO2 for geological sequestration.
Gasification processes
In conventional plants coal, often pulverised, is burned with excess air (to give complete combustion), resulting in very dilute carbon dioxide at the rate of 800 to 1200 g/kWh.
Gasification converts the coal to burnable gas with the maximum amount of potential energy from the coal being in the gas.
In Integrated Gasification Combined Cycle (IGCC) the first gasification step is pyrolysis, from 400°C up, where the coal in the absence of oxygen rapidly gives carbon-rich char and hydrogen-rich volatiles.
In the second step the char is gasified from 700°C up to yield gas, leaving ash. With oxygen feed, the gas is not diluted with nitrogen.
The key reactions today are C + O2 to CO, and the water gas reaction: C + H2O (steam) to CO & H2 - syngas, which reaction is endothermic.
In gasification, including that using oxygen, the O2 supply is much less than required for full combustion, so as to yield CO and H2. The hydrogen has a heat value of 121 MJ/kg - about five times that of the coal, so it is a very energy-dense fuel. However, the air separation plant to produce oxygen consumes up to 20% of the gross power of the whole IGCC plant system. This syngas can then be burned in a gas turbine, the exhaust gas from which can then be used to raise steam for a steam turbine, hence the "combined cycle" in IGCC.
To achieve a much fuller clean coal technology in the future, the water-shift reaction will become a key part of the process so that:
C + O2 gives CO, and
C + H2O gives CO & H2, then the
CO + H2O gives CO2 & H2 (the water-shift reaction).
The products are then concentrated CO2 which can be captured, and hydrogen. (There is also some hydrogen from the coal pyrolysis), which is the final fuel for the gas turbine.
Overall thermal efficiency for oxygen-blown coal gasification, including carbon dioxide capture and sequestration, is about 73%. Using the hydrogen in a gas turbine for electricity generation is efficient, so the overall system has long-term potential to achieve an efficiency of up to 60%.
Present trends
The clean coal technology field is moving very rapidly in the direction of coal gasification with a second stage so as to produce a concentrated and pressurised carbon dioxide stream followed by its separation and geological storage. This technology has the potential to provide what may be called "zero emissions" - in reality, extremely low emissions of the conventional coal pollutants, and as low-as-engineered carbon dioxide emissions.
This has come about as a result of the realisation that efficiency improvements, together with the use of natural gas and renewables such as wind will not provide the deep cuts in greenhouse gas emissions necessary to meet future national targets.
The US DOE sees "zero emissions" coal technology as a core element of its future energy supply in a carbon-constrained world. It has in place an ambitious program to develop and demonstrate the technology and have commercial designs for plants with an electricity cost of only 10% greater than conventional coal plants available by 2012.
Australia is very well endowed with carbon dioxide storage sites near major carbon dioxide sources, but as elsewhere, demonstration plants will be needed to gain public acceptance and show that the storage is permanent.
In several countries, "zero emissions" technology seems to have the potential for low avoided cost for greenhouse gas emissions.


Tomorrow is Part III: Wind!!

Part II: Coal

In Part II we shall explore coal, and all of the things that it can do for this country as a resource toward the ultimate goal of energy independence. As with the post on oil I will give some attention to the negative aspects of coal on the environment and the people who live with its' use, but the primary exercise of this post is to explain one more valuable tool for this nation to use, until better, cleaner energy sources can be exploited.

So we shall start with the damaging aspects of coal on us and our neighbors to the north, with special thanks to the IEN for this information:

IEN (Indigenous Environmental Network)INFORMATION SHEET:
ENERGY: FOSSIL FUELS
And Impacts to Indigenous Peoples
Statement of Fact on Energy Policy and its Impact to Indigenous Communities of North America
Indigenous peoples in Canada, the United States and throughout the Americas hold valuable land and water resources that have long been exploited by the provincial, state and federal governments and by corporations trying to meet the energy needs of an industrialized world. Indigenous peoples have disproportionately suffered impacts due to the production and use of energy resources - coal mining, uranium mining, oil and gas extraction, coal bed methane, nuclear power and hydropower development - yet are among those who benefit least from these energy developments. Indigenous peoples face inequity over the control of, and access to, sustainable energy and energy services. Territories where Indigenous peoples live are resource rich and serve as the base from which governments and corporations extract wealth yet are areas where the most severe form of poverty exists.
FACTS ON THE IMPACTS OF FOSSIL FUELS
Fossil fuels supply over 80% of the world’s energy needs. All fossil fuels, whether solid, liquid, or gas, are the result of organic plant materials being covered by successive layers of sediment over the course of millions of years.
Human consumption of oil, gas, coal bed methane and coal (fossil fuels) increases the production of greenhouse gases - carbon dioxide (CO2) that is a major cause of climate change, global warming and changes in weather patterns.
Oil drilling and related activities fragment the landscape, leading to increased symptoms of neo-colonization, development, and deforestation. It also pollutes the land and water causing irreparable damage to fragile ecosystems.
The mining and drilling of coal, oil, gas, and other minerals result in substantial local environmental consequences. This includes severe degradation of air, forests, watersheds, rivers, oceans, fisheries, agricultural lands and biodiversity. Cultural impacts of fossil fuel development include the loss of access to traditional foods, the forced removal of people, land appropriation, the destruction of sacred and historical significant areas, the breakdown of Indigenous social systems, and violence against women and children. Fossil fuel development in these areas results in the accelerated loss of biodiversity, traditional knowledge, and ultimately in ethnocide and genocide.
Coal burnt to generate electricity produces toxic material and acid rain that severely pollutes the air, soil and water. It also releases mercury into our lakes where it contaminates our fish, traditional crops, wild rice, other aquatic life and traditional food systems. The burning of fossil fuels for energy is a major source of air pollution, contributing in particular to acid rain and the greenhouse effect contributing to climate change and extreme weather events.
Coal is the single largest source of electricity in the United States. Coal-fired power plants provide fifty-three percent of the electricity used in the United States. The United States contains some of the largest coal deposits in the world. Coal is the United States most abundant fossil fuel. Coal deposits are found in 38 of the 50 states of the United States as well as on several Indigenous territories, for example, the Navajo (Dine’) and Crow territories.
Coal mining on Indigenous lands in the United States causes environmental and human rights violations. Coal mining in the Hopi and the Navajo territories has forced Navajo and some Hopi Indigenous peoples to be relocated, to leave homelands that have sustained them for generations. Coal mining operations cause the displacement of communities, destruction of natural habitat, disruption of sacred sites,water depletion from surface, subsurface and aquifers, as well as the diversion of water away from our communities. Several Indigenous Peoples are also being approached to develop projects for the production of coal bed methane gas, which is associated with additional, long-term groundwater depletion and contamination problems.
Oil companies continue to seek development within Indigenous peoples’ territories and within biological regions that sustain Indigenous peoples. In the United States arctic region, the Arctic National Wildlife Refuge, home to the Gwich'in peoples and the porcupine caribou herd, is threatened with oil development. Oil drilling and development of a petroleum industrial infrastructure within the pristine and fragile arctic ecosystem would devastate the calving grounds of the caribou and the lives of the Gwich'in. Gwich’in peoples’ relationship with the caribou is beyond food subsistence. The relationship is both cultural and spiritual as well.

UNITED STATES
The United States is home to 4% of the world's population, yet consumes 26% of the world's energy. The United States is currently the largest energy market in the world and is right behind Canada when it comes to per capita consumption.The United States uses about 17 million barrels of oil every day, fossil fuels account for nearly 80% of United States energy, with natural gas, a third form of fossil fuel, accounting for roughly 23% of the United States energy usage. I t takes the equivalent of 7 gallons of gasoline per day for every man woman and child to keep this country running at its current pace.
The United States consumes one quarter of the world’s total oil production, but controls a mere 3 percent of known oil reserves. Oil comprises about 40 percent of the energy Americans consume and 97 percent of U.S. transportation fuels.
The United States Energy Plan proposes 1,300-1,900 new power plants, 38,000 miles of new gas pipelines, consider new nuclear-power plants, build new refineries and open new areas to oil exploration. Almost all of these power plants generate electricity by using fossil or nuclear fuels to heat water to produce the steam that spins the generators. While the exploration for new sources of fossil fuel, particularly natural gas, is currently underway, the availability of both water and water rights may actually be the key and limiting factor in the operation of new energy generation plants.

CANADA
Canadians consume more energy per capita than any other country. Canadians use more total energy than the 700 million people of Africa. Canadians are the third-largest per capita producers of greenhouse gases in the world. Each year the Alberta (Canada) Energy and Utilities Board processes more than 20,000 applications for new wells, pipelines and gas plants.
Canada's greenhouse gas emissions are increasing. Energy consumption grew about 13 per cent between 1990 and 1998, while emissions rose at a rate of 1.5 per cent annually, 17 per cent since 1990.
Canada’s energy plan proposes to expand oil and gas production, particularly in the Alberta oil sands. The primary source of climate changing emissions is the burning of fossil fuels- oil, gas, and coal. Canada’s emissions have risen 15 percent due to increased oil and gas production and increased coal-fired electricity production. The Alberta Tar Sands refinery (which produces 150,000 barrels of oil a day) releases the same amount of CO 2 per year as 1.35 million new cars.
Alberta Canada currently supplies more than 12 percent of American natural gas use. New pipelines designed to carry Canadian power south to United States markets are in all stages of development across the western boreal region - from Alaska, the Yukon and Northwest Territories to British Columbia, Alberta and Saskatchewan. Very few, if any, of these projects will be assessed for their social and cultural costs or their cumulative environmental and health impacts, which would cause critical fragmentation of the boreal forest, disruption to Indigenous cultural life-ways and the production of greenhouse gases.
The social, ecological and cultural risks involved in a Canadian-United States northern oil and gas pipeline are huge. Alaska's North Slope holds an estimated 35 trillion cubic feet of known reserves. The Mackenzie Delta holds about nine trillion cubic feet. The exploration potential is even larger, with an estimated 65 trillion cubic feet waiting to be discovered in Alaska and a similar volume in the Northwest Territories of Canada. Athabascan tribal members are concerned about mega-p ipeline developments linking Arctic gas along the Mackenzie Valley from the Beaufort Sea to Alberta, Canada. This development is planned by some of the largest energy companies in the world.
The Lubicon Lake Cree are an Indigenous peoples living deep in the boreal forest zone of Canada's Alberta province that have been living for decades with the impacts of oil and gas drilling on their traditional lands. Like other Indigenous peoples across the Americas, the Lubicon Cree have been battling for years to receive recognition of their land rights and compensation for stolen wealth and environmental damage. They have struggled to halt and reduce the rapid pace of exploration and excessive destruction by roads and pipelines. The traditional homelands of the Lubicon Cree, near Peace River, Canada are now surrounded by 1,000 oil and gas wells.
Historically, energy development activities in Indigenous communities have been based upon western values of monetary profit to raise gross domestic product at the expense of the rights of Indigenous peoples and the recognition of our basic human rights. Indigenous values teach us that money cannot fully compensate for cultural losses, losses of traditional lands, debilitating illnesses, death, impure water, threats to long-term food security, or diminished economic autonomy.
FOSSIL CONNECTION TO CLIMATE JUSTICE its Impact on Indigenous Peoples
The burning of oil, gas, and coal, known collectively as fossil fuels is the primary source of human-induced climate change. By burning these fuels, humans are releasing carbon that has been sequestered in the ground for hundreds of million of years and are emitting carbon dioxide into the planet’s thin and chemically volatile atmosphere at an unprecedented rate.
For over 150 years, industrial societies have been releasing carbon from underground coal and oil reserves, adding about 175 billion tons of CO2 to the atmosphere since the beginning of the industrial revolution. Another 6 billion tons are being added each year, resulting in a 31% increase of CO2 in the atmosphere since 1750.
Within the next 20 years, temperatures over land areas of North America, Europe and Northern Asia will increase as much as 5 to 15 degrees Fahrenheit over today's normal temperatures, well in excess of the global average (IPCC Report 1998).
Climate change, if not halted, will result in increased frequency and severity of storms, floods, drought and water shortage, the spread of disease, increased hunger, displacement and mass migration of people and ensuing social conflict.
The grave damages caused by a changing climatethe pollution and the loss of our Indigenous territories, deterioration and destruction of our forests, our food security and our rich and diverse ecosystems. Climate change crisis is very evident in arctic regions where ice is thinning, thus affecting the land-based subsistence cultures of the Indigenous peoples. The climate change crisis is also most evident in low-lying coastal regions and in small Pacific Islands that are being flooded.
The United States energy plan not only promotes the increased burning of CO2-producing fuels, it also plans to open pristine forests for drilling stations, pipelines, transmission lines and roads - a process that would increase global warming by releasing the carbon currently locked securely in the living trees and soil. The increasing demand and use of fossil fuels continues to impact vital areas through deforestation and pollution from drilling operations and ultimately forest degradation from the global climate imbalance.
What We Need to Do
The people of the Earth have too much of an reliance on fossil fuels, natural gas, coal, coal bed methane and oil. In order to halt the damages resulting from their use, we must find more ecologically sound and sustainable sources that do not threaten the Indigenous way of life or the entire Circle of Life. Sustainable energy can be defined as energy with minimal impact on the healthy functioning of the local and global ecosystem. Sustainable energy is energy with very few negative social, cultural, health and environmental impacts, and which can be supplied continuously to future generations on earth.
We must respect our traditions and responsibility to protect the sacredness of our Mother Earth.
We must get involved in federal energy legislation and oppose any legislation that supports the continued dependence on fossil fuels to supply the countries energy needs.
Governments, utility and environmental regulators, energy producers, and energy resource tribes must shift energy supply away from fossil fuels, mega-hydro dams and nuclear power and toward clean renewable energy sources such as solar, wind, and fuel cells. This must be done in ways that create living-wage jobs and build community wealth.
Tell your Tribal government/First Nations to carefully consider the environmental and cultural consequences when looking at, or continuing any fossil fuel energy development (oil, gas, coal mining, coal-fired power plants, coal bed methane) on, or near Indigenous lands. We also know that local fossil fuel energy activities impact far and wide, even in other countries.
Industrial countries of United States and Canada must immediately start phasing out its national dependence on a fossil fuel economy, support policies to immediately reduce carbon dioxide (CO2) emissions and seek legislative action for a just transition of workers, Tribes/First Nations, and communities that are impacted from a phase-out and reduction of CO2 emissions.
Support tree cover and improved management of forests, energy efficiency and conservation initiatives, and increased fuel economy standards. Innovative, affordable and prudent solutions are available to help reduce the severity of climate change.
Support and invest in our Tribes/First Nations to pursue clean renewable energy projects where the abundant wind and solar resources can meet the growing demand for clean, renewable energy.
Governments, industry and multi-lateral institutions should adopt and abide by a precautionary principle in all energy development decisions and policies, recognizing that each decision will have impacts on the future generations of all Peoples.
We must tell the fossil fuel and coal mining industries to take corporate responsibility for their polluting ways.
overnments must impose a legally binding obligation to restore all areas already affected by oil, gas, dams, coal exploration and exploitation by the corporations or public entities that are responsible. This restoration must be done such that Indigenous peoples can continue traditional uses of their lands.
Governments must integrate external costs, such as human illness, environmental illness, cultural and spiritual degradation, and long-term cumulative effects into energy policy and pricing decisions and regulations. The governments must compile and compare the true costs of national energy policy and data for energy policy and planning purposes.
Governments and utility regulators must adopt electricity-restructuring policies that offer affordable and stable electricity rates to Indigenous communities and local communities and eliminate subsidies to nuclear and fossil fuels, and expand cleaner energy solutions.


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And now to the OUTLOOK for coal in 2008 and beyond, with thanks to the NMA for their assessment:
NATIONAL MINING ASSOCIATION FORECAST
THE OUTLOOK FOR COAL IN 2008
Production of coal will return to near record levels in 2008 reaching 1.160
billion tons, just 2 million tons shy of the record set in 2006 and 1.1 percent
higher than the 1.147 million tons produced in 2007. Coal production is
driven by the demand for affordable and reliable coal that electric generators
will use to produce half the electricity expected to be used in the United
States this year. There continues to be a strong interest in coal as a base
load fuel, and the National Mining Association expects that over the long
term coal production and use will frequently set annual records as coal is
used not only for electricity but also finds new markets in the industrial,
commercial and transportation sectors through gasification and liquefaction.
In 2008, U.S. coal production is expected to total 1.160 billion tons, 1.0
percent more than the 1.148 billion tons mined in 2007. Production in the
East, including Appalachia, Illinois, Indiana and West Kentucky, will
approximate 480 million tons, essentially unchanged from the 482 million
tons produced last year. Production in the West, including the Powder River
Basin, will total 680 million tons, up 2.1 percent from the 666 million tons
mined in 2007. The increases in production will meet new demand for coal
by utilities and for export. Production and transportation capacity to handle
these levels of production are fully adequate.
Demand for U.S. coal for use within the United States and for export to
Canada and overseas destinations, will reach 1.209 billion tons, 15 million
tons, or 1.3 percent, more than the record demand of 1.194 billion tons set
in 2007. Because inventories on a national basis are at adequate levels,
there will be little demand in 2008 for coal for inventory build , putting coal
supply (that includes production and imports) and demand in balance for the
first time in several years.
Imports of coal, which have increased significantly this decade, remained
level at 36.5 million tons in 2007and are not expected to change in 2008.
Approximately 70 percent of the coal imported into the U.S. is from
Columbia. Venezuela, Indonesia and Canada account for another 25 percent.
There shares are expected to be approximately the same in 2008.
Almost 95 percent of the coal used in the United States is consumed for the
purpose of generating electricity (this equates to approximately 93 percent of
domestic production). In 2007, electric generators used 1.050 billion tons of
coal to produce 50.1 percent of the electricity sold through the grid.
Commercial and industrial consumers used another 27 million tons to
generate electricity for their own use. Coal use for electricity generation was
2.9 percent higher than in 2006 due to higher overall demand for electricity
caused in part by stronger than expected economic activity and in part by
the warmer than normal fall. Overall, the demand for electricity increased by
2.9 percent in 2007 versus the 0.2 percent increase experienced in 2006.
In 2008, given more normal weather patterns and taking slower economic
growth into account, electricity production is expected to increase in the 1.3
– 1.7 percent range. Should economic growth be lower than forecast (NMA
is assuming a growth rate of just less than 2 percent), electricity demand
could be lower than forecast.
Consumption of coal will increase at a lower rate in 2008, or by 0.7 percent
to 1.157 billion tons, and coal’s share of the market will decline slightly to an
even 50 percent. Coal generation, especially in the Western grid, is nearing
a peak, and there is little potential for increase without new capacity. Two
coal plants will come on line in 2008—the 90 MW Black Hills unit in Wyoming
and the 203 MW unit begin built by Newmont Mining in Nevada. This follows
the addition of three units in 2007: the Hardin Generator Project Unit 1 in
Montana, the Springerville Unit 2 in Arizona and the Cross Unit 3 in Iowa.
Nuclear generation performed at top levels in 2007 and is expected to do the
same in 2008. Nuclear generation should remain at 2006 – 2007 levels this
year. There are no uprates expected, and 2008 is a year of refueling for
many units. However, the return of Brown’s Ferry #1 to full operation will
more than offset any reduction in production due to refueling. Generation
with natural gas is expected to increase in 2008 as new generating capacity
comes on line.
Demand for metallurgical coal for use at steel mills showed a small decline in
2007 as steel production declined slightly. Although steel production is
expected to decline again in 2008, demand for metallurgical coal should
increase by one-half million tons and is forecast to be 23.5 million tons. A
new coke oven is coming on line in Ohio, and any decline in demand for
coke, should there be a decline, will be met with a decline in imports.
Industrial coal use, led by an increase in coal use at cement plants and at
new ethanol plants, will total 36.5 million tons, 4.3 percent above the 35
million tons used by industry in 2007.
Exports—the story for 2007—will remain strong into 2008. Last year, despite
a decline in shipments of both metallurgical and steam coal to Canada,
exports increased by 17 percent. Exports to overseas destinations totaled 40
million tons in 2007, 34.7 percent, or 10.3 million tons, more than in 2006.
The U.S. coal export industry clearly benefited from increased demand, a
weak dollar and production issues in other supplier countries. Strong world
demand for coal persists. China has rapidly moved from a net exporter of
both steam and metallurgical coal to a net importer. Production and
logistical problems continue in many supplier countries, and the U.S.
continues to benefit from a weak dollar. As a result, export of U.S. coal to
overseas destinations is expected to increase again in 2008 – although at a
slower rate. Metallurgical coal shipments to overseas destinations are
expected to increase to 34 million tons (30 million in 2007), and steam coal
shipments are expected to increase to 11 million tons (10 million in 2007).
Thus total shipments of U.S. coal to overseas destinations is expected to be
45 million tons in 2008, 12.5 percent higher than shipments in 2007. There is
an upside potential to this forecast, especially for high grade U.S.
metallurgical coal, and exports could be more. Shipments of coal to Canada
will return to more normal levels—15 million tons steam coal and 4 million
tons of met coal.
Coal inventories, which increased sharply in 2006 after several years of
decline, increased again in 2007, but at a lower rate. Inventory build totaled
8.2 million tons in 2007. Because electric utility inventories—on a national
basis—are at or near desired levels, NMA does not expect demand for coal
for inventory build this year. As a result coal demand for actual use and
export will approximately equate with coal supply—or with coal production
and imports.
The outlook for coal remains positive for 2008, despite our expectations for
slower economic growth. In 2007, most analysts believe U.S. economic
growth, as measured by real GDP, will approximate 2.2-2.3 percent.
Economic growth was, however, stronger in the first three quarters than in
the fourth quarter. At the time this forecast was prepared (late November
2007), most analysts were forecasting that year-on-year economic growth in
2008 would be in the range of 1.9 – 2.4 percent. These forecasts were
completed before the release of 4th quarter 2007 data, which will certainly be
affected by slower than expected spending over the holiday period as well as
the continued financial pressures caused in part by the sub-prime mortgage
crisis.
Economic growth in 2008 will continue to be affected by the same factors
that caused a reduction in economic activity in the 4th quarter of last year,
and the costs of energy, and now higher costs of food, will certainly put a
damper on consumer spending. It remains to be seen whether the
administration and the Congress can agree on a short-term stimulus package
to push consumer spending to higher levels.
Globally, economic growth is expected to be lower in 2008 than in 2007. The
Economics Intelligence Unit has forecast that globally economies will grow by
4.5 percent in 2008 as compared with an estimated economic growth of 5.1
percent in 2007. This growth is led by China, expected to grow its economy
by 9.9 percent, and India, which has a projected growth rate of 7.7 percent.
Forecasts for inflation (as measured by the Consumer Price Index) are in the
2.5-3.5 percent range, and forecasts for unemployment have increased to
approximately 5 percent, although worker shortages will still exist in some
industries, including mining.
And Finally We Shall Take A Look At Clean Coal Technology in Part 2 of Part II: Coal:

Part I: Why We Must Drill Here

As we begin Part 1 of the energy series with Why We Must Drill Here, I want to give the opposing view of drilling off shore and in ANWR from the Sierra Club, and some leading Democrats. There are more arguments out there for why we should not drill, but my overall view is that we should drill, so I am not going to be Fair and Balanced on this subject, "as my Favorite News Channel would be, because it is just too important to the survival of our Nation's energy needs, and possible independence to give much weight to naysayers, no matter how well meaning, as they are wrong!!

Here is the main statement from the Sierra Club from their website:
The Sierra Club says Protect Our Coasts
In 1981, Congress protected America's coasts, beaches, and marine ecosystems from the threats of oil and gas development by adopting the Outer Continental Shelf (OCS) Moratorium. The moratorium prevents the leasing of America's coastal waters for fossil fuel development. In the nearly thirty years since, Congress and successive presidents have recognized the value of America's coasts and have continued to ban new drilling off the Atlantic and Pacific coasts.
But now Senator John McCain and President Bush are calling on Congress to lift these important protections. Drilling our coasts will do nothing to lower gas prices, it will only line the coffers of Big Oil, which continues to break record profits. And it will threaten to shut down our favorite beaches with oil spills, pollution, and invasive infrastructure.

There is also a story at CNN.com about the reasons a number of Leading Democrats oppose opening more areas for drilling, and while they would be correct if we were talking about "just" allowing the Oil Companies to drill, they would be right, but in the context of Nationalizing the Oil Companies and actually doing the drilling, that I am advocating, they are just wrong!! Now you can just type in "why we must drill", "offshore oil","ANWR", or any number of combinations of this basic concept and will find all kinds of groups in favor or opposed, forums, discussion groups, and many useless threads, but just seeing the number of items "found" will give you a good indication that a lot of people do care about this issue, and if we can harness these passions to get something accomplished, we could do the equivalent of the Apollo program, Manhatten Project, and the New Deal, All at the same time!!

The main story behind all of these posts will be that we CAN become energy independent and wean ourselves off oil over the next decade IF we have the WILL to DO IT, and so far we have seen nothing to suggest that the politicians or our fellow citizens are going to do anything but whine about the problem, without the RESOLVE to do everything in our power to change it. So while I shall do a post about each energy method that we MUST utilize, I have little hope of it actually happening, thanks to the tree hugging liberals who don't care if we survive, and the dollar hugging bastards who only want oil or other profit producing energy source, as our main energy drug. I see the death of our nation by this suicidal course, as "everyone" knows what they know, and to hell with working toward a common end!! God will not help us, and we damn well seem Hell bent on not helping ourselves!!

Anyway on to the "other" side of the story for a moment and then on to the assessments of how much oil IS available!!

The Story:America's untapped oil
Lawmakers lay into big oil for leaving million of acres untouched while at the same time asking to drill in Alaska and off the coasts.
NEW YORK (CNNMoney.com) -- Oil companies and many lawmakers are pressing to open up more U.S. areas for drilling. But the industry is drilling on just a fraction of areas it already has access to.
Of the 90 million offshore acres the industry has leases to, mostly in the Gulf of Mexico, it is estimated that upwards of 70 million are not producing oil, according to both Democrats and oil-industry sources.
One Democrat staffer said if all these existing areas were being drilled, U.S. oil production could be boosted by nearly 5 million barrels a day, although the oil industry said that number is far too high and one government agency said it was impossible to estimate production.
Recent proposals to open up offshore coastal areas near Florida and California, as well as Alaska's Arctic National Wildlife Refuge, might yield 2 million additional barrels, according to estimates from various government sources that also stressed the difficulty in making forecasts. The United States currently produces 8 million barrels of oil and other petroleum liquids a day and consumes about 21 million.
Oil companies "should finish what's on their plate before they go back in line," said Oppenheimer analyst Fadel Gheit.
Some Democrats also charge that oil companies are deliberately not drilling on the land to limit supply and drive up oil prices.
"Big Oil is more interested in pumping up prices and pumping up their own profits rather than pumping more oil," said Rep. Edward Markey (D-Mass), who has co-sponsored a bill to charge oil companies a fee for land they hold that's not producing oil. "We should not even begin discussing handing over more public land to the oil companies until they first use [the land] they already hold."
But the oil industry says it pays millions of dollars for these leases, and that it would not make sense to purposely leave the areas untapped.
Rather, years of exploration is required before drilling can even begin. In some cases, no oil is found on leases they hold. In others, drilling the wells and building the pipelines takes years. It is especially hard now that a worldwide boom in oil exploration has pushed up the prices - and timelines - for skilled workers and specialized equipment.
"No one is sitting on leases these days," said Rayola Dougher, senior economic advisor for the American Petroleum Institute. "Those making those assertions don't understand the bidding and leasing process."
Gheit agrees that it's unlikely that hoarding is going on.
With prices at $135 dollars a barrel, everyone is trying to pump as much as they can, he said. But fearing oil prices will eventually fall, the industry is leery about making too many investments in the fields it has - many of which are in deepwater areas that can be pricey to develop.
Instead, they're holding out, hoping the government will open areas closer to shore that would be cheaper to work on.
The presumptive Republican candidate John McCain has come out in favor of lifting bans on oil-drilling off most of the East and West coasts of the United States. Added supply, the thinking goes, would ultimately bring down the price of oil. The bans were enacted in the 1970s following several coastal oil spills.
Critics say lifting the bans would do little to ease the nation's energy crisis in part because it would take years to produce meaningful amounts of oil, noting how much is currently going untapped.
Gheit hasn't seen the legislation proposed by Markey and others, but he thinks the government should revise the leasing process to encourage more drilling on existing areas before it puts more acres up for bid.


The assessments of ANWR, Oil Shale, and off shore potential follows, with thanks to the USGS (United States Geological Survey) their website is www.usgs.org, and they have information on "everything", and special thanks to anwar.com,api,eia.doe.gov for this information:

Geologists agree that the Coastal Plain has the nation's best geologic prospects for major new onshore oil discoveries. According to the Department of Interior's 1987 resource evaluation of ANWR's Coastal Plain, there is a 95% chance that a 'super field' with 500 million barrels would be discovered. DOI also estimates that there exists a mean of 3.5 billion barrels, and a 5% chance that a large Prudhoe Bay type discovery would be made.
High potential. The high potential for significant discoveries of oil and gas in ANWR has long been recognized. Early explorers of the region at the turn of the century, found oil seeps and oil-stained sands. However, since ANWR was established in 1960, exploration in the region has been restricted to surface geological investigations, aeromagnetic surveys, and two winter seismic surveys (in 1983-84 and 1984-85). No exploratory drilling has been accomplished in the area except for one well commenced in the winter of 1984-85 on Kaktovik Inupiat Corporation and Arctic Slope Regional Corporation lands southeast of Kaktovik on the Coastal Plain.
Location to big finds. Although little oil and gas exploration has taken place in ANWR, the Coastal Plain is believed to have economically recoverable oil resources. The Coastal Plain lies between two known major discovery areas. About 65 miles to the west of the Coastal Plain, the Prudhoe Bay, Lisburne, Endicott, Milne Point, and Kuparuk oil fields are currently in production. Approximately 1.5 million barrels of oil a day are produced from these fields, representing 25% of our domestic production. To the east of the Coastal Plain, major discoveries have been made in Canada, near the Mackenzie River Delta and in the Beaufort Sea.
U.S. Geological Survey - 1980. In 1980, the U.S. Geological Survey estimated the Coastal Plain could contain up to 17 billion barrels of oil and 34 trillion cubic feet of natural gas.
U.S. Department of Interior - 1987. After several years of surface geological investigations, aeromagnetic surveys, and two winter seismic surveys (in 1983-84 and 1984-85), the U.S. Department of Interior (DOI), in its April, 1987 report on the oil and gas potential of the Coastal Plain, estimated that there are billions of barrels of oil to be discovered in the area. DOI estimates that "in-place resources" range from 4.8 billion to 29.4 billion barrels of oil. Recoverable oil estimates ranges from 600 million barrels at the low end to 9.2 billion barrels at the high end. They also reported identifying 26 separate oil and gas prospects in the Coastal Plain that could each contain "super giant" fields (500 million barrels or more).
U.S. Geological Survey 1998. The most recent petroleum assessment prepared by the USGS in 1998 (OFR 98-34), increased the estimate for technically recoverable mean crude oil resources.
Only drilling will tell. The geologic indicators are very favorable for the presence of significant oil and gas resources in ANWR, but the limited data means that there is a high level of uncertainty about how much oil and gas may be present. Consequently, current estimates represent the best scientific guesses. However, most geologists agree that the potential is on the order of billions of barrels of recoverable oil and trillions of cubic feet of recoverable gas and that these resources may rival or exceed the initial reserves at Prudhoe Bay. The validity of these estimates can be proved only by drilling exploratory wells. Authorization for exploration must be given by Congress and the President.
In 1996 the North Slope oil fields produced about 1.5 million barrels of oil per day, or approximately 25 percent of the U.S. domestic production. However, Prudhoe Bay, which accounts for over half of North Slope production, began its decline in 1988, and no new fields have yet been discovered with the potential to compensate for that decline.

IN addition to ANWR there is:

North Dakota and Montana have an estimated 3.0 to 4.3 billion barrels of undiscovered, technically recoverable oil in an area known as the Bakken Formation.
A U.S. Geological Survey assessment, released April 10, shows a 25-fold increase in the amount of oil that can be recovered compared to the agency's 1995 estimate of 151 million barrels of oil.
Technically recoverable oil resources are those producible using currently available technology and industry practices. USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources.
New geologic models applied to the Bakken Formation, advances in drilling and production technologies, and recent oil discoveries have resulted in these substantially larger technically recoverable oil volumes. About 105 million barrels of oil were produced from the Bakken Formation by the end of 2007.
The USGS Bakken study was undertaken as part of a nationwide project assessing domestic petroleum basins using standardized methodology and protocol as required by the Energy Policy and Conservation Act of 2000.
The Bakken Formation estimate is larger than all other current USGS oil assessments of the lower 48 states and is the largest "continuous" oil accumulation ever assessed by the USGS. A "continuous" oil accumulation means that the oil resource is dispersed throughout a geologic formation rather than existing as discrete, localized occurrences. The next largest "continuous" oil accumulation in the U.S. is in the Austin Chalk of Texas and Louisiana, with an undiscovered estimate of 1.0 billions of barrels of technically recoverable oil.
"It is clear that the Bakken formation contains a significant amount of oil - the question is how much of that oil is recoverable using today's technology?" said Senator Byron Dorgan, of North Dakota. "To get an answer to this important question, I requested that the U.S. Geological Survey complete this study, which will provide an up-to-date estimate on the amount of technically recoverable oil resources in the Bakken Shale formation."
The USGS estimate of 3.0 to 4.3 billion barrels of technically recoverable oil has a mean value of 3.65 billion barrels. Scientists conducted detailed studies in stratigraphy and structural geology and the modeling of petroleum geochemistry. They also combined their findings with historical exploration and production analyses to determine the undiscovered, technically recoverable oil estimates.
USGS worked with the North Dakota Geological Survey, a number of petroleum industry companies and independents, universities and other experts to develop a geological understanding of the Bakken Formation. These groups provided critical information and feedback on geological and engineering concepts important to building the geologic and production models used in the assessment.
Five continuous assessment units (AU) were identified and assessed in the Bakken Formation of North Dakota and Montana - the Elm Coulee-Billings Nose AU, the Central Basin-Poplar Dome AU, the Nesson-Little Knife Structural AU, the Eastern Expulsion Threshold AU, and the Northwest Expulsion Threshold AU.
At the time of the assessment, a limited number of wells have produced oil from three of the assessments units in Central Basin-Poplar Dome, Eastern Expulsion Threshold, and Northwest Expulsion Threshold.
The Elm Coulee oil field in Montana, discovered in 2000, has produced about 65 million barrels of the 105 million barrels of oil recovered from the Bakken Formation.
Results of the assessment can be found at http://energy.usgs.gov.


There is this tidbit from API:
Who We Are
API is the only national trade association that represents all aspects of America’s oil and natural gas industry. Our 400 corporate members, from the largest major oil company to the smallest of independents, come from all segments of the industry. They are producers, refiners, suppliers, pipeline operators and marine transporters, as well as service and supply companies that support all segments of the industry.
Although our focus is primarily domestic, in recent years our work has expanded to include a growing international dimension, and today API is recognized around the world for its broad range of programs:
Advocacy
We speak for the petroleum industry to the public, Congress and the Executive Branch, state governments and the media. We negotiate with regulatory agencies, represent the industry in legal proceedings, participate in coalitions and work in partnership with other associations to achieve our members’ public policy goals.
Research and Statistics
API conducts or sponsors research ranging from economic analyses to toxicological testing. And we collect, maintain and publish statistics and data on all aspects of U.S. industry operations, including supply and demand for various products, imports and exports, drilling activities and costs, and well completions. This data provides timely indicators of industry trends. API’s Weekly Statistical Bulletin is the most recognized publication, widely reported by the media.
Standards
For more than 75 years, API has led the development of petroleum and petrochemical equipment and operating standards. These represent the industry’s collective wisdom on everything from drill bits to environmental protection and embrace proven, sound engineering and operating practices and safe, interchangeable equipment and materials. API maintains more than 500 standards and recommended practices. Many have been incorporated into state and federal regulations; and increasingly, they’re also being adopted by the International Organization of Standardization, a global federation of more than 100 standards groups.


API and a group of other oil and gas industry trade associations recently submitted testimony to the Oceans Commission on the potential associated with offshore oil and gas and why it is crucial to our nation's energy supplies. It concluded, "The energy resources of the oceans surrounding the U.S. offer the potential to seriously address the vital energy needs of the U.S. in the future. These resources can be developed in an environmentally sound manner. The OCS [Outer Continental Shelf] has already been a major source of U.S. supply for decades, technology has greatly expanded its potential, and the expansion of supply from the area represents a natural extension and continuation of an already proven supply process. In a volatile world, we simply cannot afford to deliberately allow secure domestic supply sources to atrophy. If we allow supply from the OCS to decline, it will constitute a deliberate policy choice, not a scarcity imposed by nature. As we consider this choice, we cannot afford to ignore the consequences of that action in terms of increased vulnerability to less secure supply sources elsewhere. This Commission faces the extremely timely challenge of finding the necessary means to guide these choices in a constructive manner. As it does so, we ask that it regard industry as a full partner in this effort."


The more than 4,000 oil and natural gas platforms operating in U.S. waters have an outstanding safety and environmental record. U.S. offshore exploration and production meet what could easily described as the world’s most stringent government regulations and industry standards. Protecting the environment is a national imperative, and oil and natural gas operations have established an impressive record of protecting our coastal waters.

Congress and past Presidents have placed moratoria on offshore drilling and development on the U.S. East and West Coasts, the Eastern Gulf of Mexico, and parts of Alaskan offshore waters. The consequence of these actions is to foreclose until at least 2012 any effort to explore for critical oil and gas resources that are estimated to lie beneath these areas. This section includes a map illustrating current offshore moratoria areas.


API developed, and the Minerals Management Service has endorsed, a recommended practice for employing a Safety and Environmental Management Program (SEMP). Designed to be flexible, responsive and become a permanent part of a company’s culture, objectives and operations, SEMP covers design, operation, and auditing to assure that company operations offshore are safe and protective.

And Finally, Legislation, History, and Other Information Pertaining to OIL:
Overview of U.S. Legislation and Regulations Affecting Offshore Natural Gas and Oil Activity
Legislation and regulations regarding natural gas and oil exploration, development, and production from U.S. offshore lands developed over many decades in response to a variety of concerns and disputes that were most often engendered by competing priorities. This article discusses the evolution of offshore developments and the major legislation and regulations that have affected the natural gas and oil industry in the past 50 years. The most common early disputes revolved around ownership of coastal waters. Eventually, as offshore activities became more abundant, more complicated issues arose over the need to ensure that operations are accompanied by safety, equity, and the protection of marine and coastal environments.
The Federal government did not largely regulate natural gas and oil exploration and development activities in the offshore regions of the United States from the 1880s, when offshore oil production first began, through the mid-1900s. During this time technological advances and increasing demand for natural gas and oil provided incentives for offshore exploration and the development of offshore natural gas and oil production infrastructure. By 1949 eleven offshore fields had been found and 49 production wells were operating in the Gulf of Mexico. By the 1950s the U.S. government began responding to increased concerns regarding offshore jurisdiction, environmental impacts of offshore activities, economic factors, and safety. Key legislative and regulatory initiatives were thereafter enacted that sought to balance the need for a reliable, safe energy supply with minimization of environmental impacts, at a fair price to all parties.
Offshore natural gas and oil exploration, drilling, production, and transportation have all been affected. Legislative action has ranged from imposition of a wide range of requirements on operations in the offshore to complete removal of access to offshore resources. Today natural gas and oil drilling is prohibited in all offshore regions along the North Atlantic coast, most of the Pacific coast, parts of the Alaska coast, and most of the eastern Gulf of Mexico. The central and western portions of the Gulf of Mexico therefore account for almost all current domestic offshore natural gas and oil production.
This article presents a summary of the legislative and regulatory regime that affects natural gas and oil exploration and production in offshore regions of the United States. It discusses the role and importance of these areas as well as the competing interests surrounding ownership, production, exploration and conservation. Questions or comments should be directed to Erin Mastrangelo at erin.mastrangelo@eia.doe.gov or (202) 586-6201.

The continental margins, the geographic region contiguous to and lying seaward of a coastline, have become increasingly important to the natural gas and oil industry over the past century. The continental margins consist of three portions: (1) the continental shelf which has shallow water depths rarely deeper than 200 meters (656 feet) and extends seaward from the shoreline to distances ranging from 20 kilometers (12.3 statute miles) to 400 kilometers (249 statute miles), (2) the continental slope where the bottom drops off to depths of up to 5 kilometers (3.1 statute miles), and (3) the continental rise which dips very shallowly seaward from the base of the continental slope and is in part composed of down-washed sediments deposited at the base of the slope .

The continental margins are of great importance for many reasons, not least of which is that they are presently the source of increasing amounts of the world's, and the United States', natural gas and oil supplies. H.L. Williams drilled the first offshore well in 1887 from a wooden wharf that extended 300 feet onto the continental shelf off Summerland, California. Early wells were limited to drilling in very shallow water since they were constrained to these shore-bound wharfs. The emergence of free-standing and floating platforms in the 1940s allowed drilling rigs to be moved ever-farther away from shore into deeper water. Today, there are around 4,000 platforms producing in Federal waters up to roughly 7,500 feet deep and up to 200 miles from shore. Furthermore, technological advances in recent years have offered the opportunity for greater exploration, higher production levels, and lower costs. Thus, the percentage of oil and dry natural gas production from water depths greater than 200 meters has steadily increased in the Federal Gulf of Mexico over the past decade.


Table 1: Share of Gulf of Mexico Federal Outer Continental Shelf Natural Gas and Oil Production from Depths Greater than 200 Meters, 1995 – 2003

Year Federal Gulf Of Mexico Production Share from Depths Greater than 200 meters (Percent)
Natural Gas Crude Oil
1995 7.8 26.4
1996 10.9 29.7
1997 11.0 36.0
1998 14.6 46.0
1999 22.5 54.2
2000 24.4 55.8
2001 27.4 62.2
2002 30.0 63.9
2003 35.1 69.3

The offshore has accounted for about one-quarter of total U.S. natural gas production over the past two decades and almost 30 percent of total U.S. oil production in recent years (Table 2). Although production has declined slightly in the past few years, the Mineral Management Service (MMS) reported that natural gas production in Federal offshore waters was 4.042 trillion cubic feet (Tcf) in 2004. This was about 21 percent of the total natural gas produced in the United States that year. MMS reported that Federal offshore oil production also slightly declined in recent years with 565 million barrels produced in 2004, which is 29 percent of the total oil produced in the United States that year. Furthermore, in 2003, MMS estimated that there was 406.1 Tcf of remaining undiscovered technically recoverable natural gas and 76 billion barrels of oil in U.S. offshore regions. These estimates represent the potential hydrocarbons of an area that can be produced using current technology, without any consideration to economic feasibility. Of these amounts, an estimated 232.5 Tcf of natural gas and 36.9 billion barrels of oil are located in the Gulf of Mexico.


Table 2: Federal Outer Continental Shelf Natural Gas and Oil Production as a Percentage of U.S. Production, 1990 – 2004
Year
Federal OCS Share of U.S. Total Production (Percent)
Natural Gas is the first number under each year
Crude Oil is the second number under each year as it would not format properly:
1990
27.0
11.3
1991
25.9
12.0
1992
25.4
13.3
1993
25.0
14.4
1994
25.0
15.3
1995
25.0
17.4
1996
26.1
18.6
1997
26.0
20.1
1998
25.5
21.8
1999
25.8
25.2
2000
24.8
26.7
2001
24.8
28.3
2002
23.1
29.1
2003
22.4
28.9
2004
20.5
28.9
Who Has Jurisdiction Over Offshore Regions?
As interest in the commercial development of natural gas and oil increased in the 1940s, control over these resources became a major issue, especially in the offshore regions. The most prominent dispute was between the United States and the State of Texas over 2.5 million acres of submerged land in the Gulf of Mexico (Sidebar 1). Congress eventually resolved this Texas tidelands dispute in 1953 by passing the Submerged Lands Act (SLA), which established the Federal Government’s title to and ownership of submerged lands located on a majority of the continental margin. States were given jurisdiction over any natural resources within 3 nautical miles (3.45 miles or 5.6 kilometers) of the coastline excepting Texas and the west coast of Florida where the SLA extends the States’ Gulf of Mexico jurisdiction to 9 nautical miles (10.35 statute miles or 16.7 kilometers).
Sources: U.S. Total: Energy Information Administration, Monthly Energy Review (May 2005). Federal Outer Continental Shelf production: Minerals Management Service, Royalty Management Program.

Sidebar 1: The Tidelands Controversy
Controversy over title to lands beneath the States’ navigable water emerged in the late 1940s when the oil and natural gas industries were beginning to expand into offshore regions. Federal officials and applicants for mineral leases began to assert Federal ownership over these lands in order to lower the costs of development. One of the greatest controversies of this nature involved title to submerged lands located off the coast of Texas up to 3 leagues (10.35 miles) from shore into the Gulf of Mexico, also referred as the tidelands. Texas first acquired this land when it established itself as an independent nation in 1836, and the United States recognized this maritime boundary when Texas entered the Union in 1845. Through the 1940s, even when the Supreme Court sided against California and other coastal States’ ownership rights, many Federal officials asserted that Texas was a separate issue since it came into the Union voluntarily as an independent country under terms that it would hold title to submerged lands up to 3 leagues from shore. Shortly after the 1948 election, however, President Truman filed suit against Texas and won a Supreme Court ruling that national sovereignty carried with it the transfer of offshore lands to the United States. Congress twice (1946 and 1952) passed bills restoring to the States the title to all submerged lands within their respective boundaries, but President Truman vetoed the bills. The matter became one of the foremost issues in the 1952 presidential campaign when Dwight Eisenhower declared in favor of State ownership, and said he would sign a bill enacted by Congress, which he then did on May 22, 1953. One last argument arose in 1957 when the U.S. Attorney General filed suit against Texas arguing that its legal boundary and ownership extended only 3 miles into the sea as opposed to 3 leagues. Texas won this suit in the Supreme Court in 1960 and therefore has a 3-league Gulfward boundary.


Passage of the SLA prepared the way for passage of the Outer Continental Shelf Lands Act (OCSLA), also in 1953. The OCSLA defined the Outer Continental Shelf (OCS), separate from geologic definitions, as any submerged land outside State jurisdiction and reaffirmed Federal jurisdiction over these waters and all resources they contain. Moreover, the OCSLA outlined Federal responsibilities for managing and maintaining offshore lands subject to environmental constraints and safety concerns. It authorizes the Department of the Interior (DOI) to lease the defined areas for development and to formulate regulations pertaining thereto as necessary. Between 1978 and 1998 the OCSLA was amended six times to account for changing issues. It remains the cornerstone of offshore legislation to this day (see next section).
Energy Information Administration, Office of Oil and Gas, September 2005 5
International boundaries were not formally established until 1983 when President Reagan declared the U.S. Exclusive Economic Zone (EEZ) in Proclamation Number 5030 which claimed rights for the United States to all waters up to 200 nautical miles (230 statute miles or 370 kilometers) from the U.S. coastline (Figure 2). About 15 percent of the U.S. EEZ lies on the continental shelf in shallow waters less than 200 meters (656 feet) deep and another 10 to 15 percent lies in water depths of 200 to 2,000 meters (656 to 6,560 feet). The remaining 70 to 75 percent of the EEZ reaches water depths of up to 5,000 meters (16,404 feet).

In 1994 the International Law of the Sea granted the same 200 nautical miles to all countries. Prior to this, countries had claimed jurisdiction to offshore areas in bilateral agreement with neighboring countries. For example, since 1978 the United States and Mexico have signed two treaties in order to fully define jurisdictional boundaries in the Gulf of Mexico (Sidebar 2). In some instances the International Law of the Sea provides that jurisdiction over natural resources extends beyond the 200-mile boundary to the edge of the geological continental margin based on geological factors such as sediment thickness and water depth. For this reason the boundaries associated with Alaska, parts of the East Coast and the Gulf of Mexico extend beyond 200 miles, but the Pacific coast has the standard EEZ boundary limits.
Source: Energy Information Administration.
Energy Information Administration, Office 6

Sidebar 2: U.S. and Mexico Boundary in the Gulf of Mexico
The United States and Mexico signed the Treaty on Maritime Boundaries in 1978 after a potential conflict arose over oceanic jurisdiction in the Gulf of Mexico. Prior to the treaty, both nations had extended their oceanic jurisdictional claims to 200 nautical miles from shore, creating an overlap of jurisdiction where the distance between the two nations’ shores was not enough to accommodate both countries. This treaty defined the maritime boundaries for the overlapping area in the Gulf of Mexico, but also left a triangular area, termed the western gap, where the respective boundaries did not meet (Figure below). Mexico ratified the treaty in 1979, but the United States failed to ratify it until 1997. Exploration and leasing activity increased in deepwater areas in the mid-1990s owing to new technology, new discoveries, and the 1995 Deepwater Royalty Relief Act. As the natural gas and oil industry moved further into deeper water, which extended into the jurisdictional gap, concerns grew over the uncertainty regarding boundary lines in the western gap. The United States ratified the 1978 treaty in 1997 in order to begin negotiating with Mexico on the western gap. In June 2000 the United States and Mexico signed a second treaty which defines the continental shelf boundary for the western gap area. Of the approximately 5,092 square nautical miles in the gap area, 38 percent went to the United States and 62 percent went to Mexico. The treaty also established a 1.4-nautical-mile buffer zone on each side of the new boundary to account for the possibility that an oil or natural gas reservoir might cross the boundary. The United States and Mexico also agreed to a 10-year drilling moratorium on the buffer zone in order to allow time to determine the geology and characteristics of the area.


The Basis of Offshore Legislation and Regulations
The Outer Continental Shelf Lands Act
As noted previously, the OCSLA is the primary governing legislation regarding U.S. offshore regions. When first passed in 1953 it required DOI to perform specific responsibilities in managing the OCS. An integral part of the OCSLA is the requirement that DOI manage an offshore leasing program for mineral development. In doing so DOI must ensure that the U.S. government receives fair market value for acreage made available for leasing, and it must enact regulations that guarantee resource conservation, environmental protection, and operational safety for anyone involved in the activities. Natural gas and oil lease sales are currently held annually on an area-wide basis for areas located in the western and central Gulf of Mexico. Lease sales for tracts located in the eastern Gulf of Mexico and offshore Alaska are less frequently held. Congress enacted the first amendments to the OCSLA in 1978. They provided guidelines for implementing the offshore natural gas and oil exploration and development program. The amendments required development of a 5-year leasing program that schedules all proposed lease sales during that 5-year period. According to Section 18 of the OCSLA, the decision to lease areas in the OCS is based on several factors. First, adequate information regarding the environmental, social, and economic effects of natural gas and oil activity on OCS resources must be considered. No new leasing should take place if this information is not available. Also, the timing and location of leasing must be based on geographic, geologic, and ecological characteristics of the region as well as location-specific risks, energy needs, laws, and stakeholder interests. The OCSLA also stipulates that the decision makers must seek balance between potential damage to the environment and coastal areas and potential energy supply. Areas with the greatest resource potential should have greater priority for development, particularly in areas where earlier development has proven a rich resource base. For every 5-year leasing program, MMS publishes a comprehensive document detailing the information and reasoning behind the leasing decisions. If a lease block is not included in the 5-year program, it may not be leased during the program.
The first 5-year leasing program was launched in 1980, revised in 1982, and concluded in 1985. The current 5-year program covers the years 2002 to 2007 and includes 20 natural gas and oil lease sales. It will expire on June 30, 2007, and the next proposed 5-year plan would extend until 2012.
The Federal Oil and Gas Royalty Management Act
In 1982 Congress passed the Federal Oil and Gas Royalty Management Act to ensure that all Federal lands in the offshore have proper accounting and enforcement mechanisms. This included a comprehensive system for determining, collecting and auditing all fees and payments for offshore leases in addition to conducting inspections and enforcing penalties. The increased responsibilities led the Secretary of the Interior to create the MMS within the Department to administer all responsibilities relating to natural gas and oil production on the OCS. They range from the scheduling of sales and the leasing of
Energy Information Administration, Office of Oil and Gas, September 2005 8
OCS tracts to approval and oversight of offshore operations and the conduct of environmental studies. Today the MMS collects and disperses billions of dollars in revenue from the sale of mineral leases. Offshore leases brought in revenues of $5.2 billion in 2000. This represents 73.1 percent of the $7.1 billion in revenues collected from all Federal and American Indian mineral leases that year.
Legislation and Regulations Related to Environmental Issues
A variety of environmental risks are associated with offshore natural gas and oil exploration and production, among them such things as discharges or spills of toxic materials whether intentional or accidental, interference with marine life, damage to coastal habitats owing to construction and operations of producing infrastructure, and effects on the economic base of coastal communities. During the 1960s increasing environmental awareness set the stage for the development of numerous environmental laws, regulations, and executive orders that have affected natural gas and oil activities on Federal offshore areas. All natural gas and oil activities must now pass through a large number of environmental reviews by Federal, State and local agencies. Federal agencies that play a role in regulating and coordinating environmental laws include the DOI, the Environmental Protection Agency (EPA), the Department of Commerce’s National Oceanic and Atmospheric Administration (NOAA), and the U.S. Fish and Wildlife Service (FWS). The following section describes the major Federal environmental legislation that has been enacted in the past several decades to safeguard the environment and protect coastal and marine communities.
National Environmental Policy Act of 1969
The National Environmental Policy Act, passed in 1969, requires the Federal Government to consider the environmental impacts of any proposed actions as well as reasonable alternatives to those actions. Through tools such as Environmental Assessments, Environmental Impact Statements (EIS), and Categorical Exclusion Reviews, parties who propose an offshore project can better understand and make decisions on how to manage for environmental consequences. An EIS is prepared for every lease sale held by the MMS.
Clean Air Act
All air pollutants resulting from industrial activities were first regulated at the Federal level by the Clean Air Act (CAA) passed by Congress in 1970. Proposed and existing natural gas and oil facilities must prepare, as part of their development plans and reporting procedures, detailed emissions data to prove compliance with the CAA. The amendments added in 1977 and 1990 set new attainment goals for ambient air quality and updated the Act to account for issues such as acid rain and ozone. The 1990 amendments established jurisdiction of offshore regions regarding regulation of air quality. The MMS
Energy Information Administration, Office of Oil and Gas, September 2005 9
regulates the OCS in the Western and Central Gulf of Mexico, and the EPA regulates the remaining OCS areas.
Coastal Zone Management Act of 1972
The Coastal Zone Management Act was passed in 1972 based on the perceived need to preserve, protect, develop, and restore or enhance the resources of U.S. coastal zones. This Act encourages coastal States to complete an individual Coastal Zone Management Plan for their coastal areas and requires State review of Federal actions that affect land and water use in these coastal areas. The consistency clause of this Act gives States the power to object to any Federal action that they deem not consistent with their approved Coastal Zone Management Plan. The Department of Commerce is the lead Federal Department responsible for assisting States with their coastal zone management plans, reviewing and approving the plans, and conducting continuous monitoring for compliance. NOAA, within the Department of Commerce, carries out these responsibilities but the Secretary of Commerce must grant final approval to all coastal zone management plans before implementation. NOAA reported 34 of 35 coastal States and U.S. territories were participating in the program in 2003 and that 99 percent of the U.S. shoreline was covered by approved plans.
Endangered Species Act of 1973
The Endangered Species Act (ESA), enacted in 1973, protects and promotes the conservation of all species listed as endangered by restricting Federal actions that are likely to harm, harass, or pursue them. Under the ESA plant and animal species can be listed as facing potential extinction after a detailed legal process. The list includes marine and coastal species that could be affected by natural gas and oil operations in the offshore. In 1995 the Supreme Court ruled that significant habitat modification was a reasonable interpretation of the term “harm.” The ESA can therefore affect natural gas and oil operations in all areas near or where habitat considered critical to listed marine species exists.
Clean Water Act of 1977
The Clean Water Act (CWA) of 1977 is the primary law governing the discharge of pollutants into all U.S. surface waters. Under this law, the EPA requires that a National Pollutant Discharge Elimination System (NPDES) permit be obtained before any pollutant is released. The CWA holds certain industries, including natural gas and oil production, to strict standards regarding direct pollution discharges into waterways. These standards are outlined in the NPDES permits and may be based on the age of a facility. For example, new facilities may be subject to more strict standards than existing facilities. Since the permits are issued on a 5-year basis, natural gas and oil companies must renew their NPDES permits every 5 years or face EPA penalties.
Energy Information Administration, Office of Oil and Gas, September 2005 10
National Fishing Enhancement Act of 1984
The National Fishing Enhancement Act (NFEA) allows States that have obtained permission from the Secretary of Transportation to sink obsolete ships for use as artificial reefs. The practice contributes to marine conservation and enhances fishery resources by creating habitat for many plant and fish species. The passage of the NFEA also opened the opportunity for MMS to enact its rigs-to-reefs policy which allows the conversion of decommissioned natural gas and oil platforms to artificial reefs.
Leasing Moratoria on OCS Lands
For the past 24 years leasing of specific portions of the Federal OCS has been prohibited via the annual Congressional appropriations process, i.e., the funds needed to conduct leasing for the specified OCS areas are not provided to the MMS. Proponents of these so-called leasing moratoria argue that leasing in what they consider to be environmentally sensitive offshore areas might lead to activities that could cause economic or environmental damage despite the host of laws and regulations governing operations in offshore areas.
The first OCS moratorium was enacted as part of the fiscal year 1982 Interior Appropriations Bill. It covered 736,000 acres off the coast of California. From 1982 to 1992, Congress supported annual moratoria on six other areas through the Interior Appropriations Bill. The annual moratoria, which only cover the year in which they are passed, were as follows:
• 35 million acres were withdrawn in 1983 in Central and Northern California and the mid-Atlantic,
• 54 million acres were withdrawn in 1984 in California planning areas, the North Atlantic, and the Eastern Gulf of Mexico,
• 45 million acres were withdrawn in 1985 in California planning areas and the North Atlantic,
• 8 million acres in the North Atlantic were withdrawn from 1986 to 1988,
• 33 million acres were withdrawn in 1989 in Northern California, the North Atlantic, and the Eastern Gulf, and
• 84 million acres were withdrawn in 1990 in California planning areas, the North and Mid-Atlantic, the Eastern Gulf, and all of the North Aleutian Basin.
President Bush issued a Presidential Directive in 1990 that enacted a blanket moratorium until 2000 on all unleased areas offshore Northern and Central California, Southern California except for 87 tracts, Washington, Oregon, the North Atlantic coast, and the Eastern Gulf of Mexico coast. Separate from the annual moratoria in appropriations legislation, this directive meant that no leasing or pre-leasing activities were allowed to occur in these areas during the entire period. In 1998 President Clinton extended the moratorium through 2012.
Energy Information Administration, Office of Oil and Gas, September 2005 11
The issue of the availability of OCS lease areas has sparked controversy over the years. On one side are those who argue that the United States needs to open restricted areas to natural gas and oil production in order to meet future energy needs or other policy objectives such as reduced dependence on foreign oil. In 2000, the MMS's mean estimate of the undiscovered conventionally recoverable resources resident in the Lower 48 States moratoria areas was 55.5 Tcf of natural gas and 15.7 billion barrels of oil (Figure 3)1. MMS estimated another 6.79 Tcf of natural gas and 0.23 billion barrels of oil in Alaska moratoria areas. On the other side of the conflict are parties with stated goals that include protecting the ocean and coastal environments from further pollution or avoiding potential negative consequences on fishing or tourism. These supporters of the moratoria argue that the negative impacts of exploration and development needed to extract the natural gas and oil likely outweigh the benefits.
Figure 3: Conventionally Recoverable Oil and Natural Gas in Moratoria Areas, Lower 48 States

Source: MMS National Assessment, 2000.
1 MMS revised its estimates in 2003. The volume of Lower 48 undiscovered conventionally recoverable resources in the Federal OCS under moratoria is 72 Tcf of natural gas and 18 billion barrels of oil. These volumes were obtained through communication between the Energy Information Administration and MMS.
Energy Information Administration, Office of Oil and Gas, September 2005 12
Two examples of leasing disputes in recent years are the suspended leased tracts off the coast of California and Lease Sale 181 in the Eastern Gulf of Mexico. Both amply demonstrate how regulatory decisions impact the competing public needs.
In California, debate has ensued over 36 existing offshore leases along the central coast that companies have been unable to develop because of subsequently imposed drilling bans. The leases, which were issued to companies between 1968 and 1984, were set to expire by 1990, but MMS has succeeded in extending the leases since then, through suspensions, to allow more time to prove consistency with State Coastal Zone Management Plans. On August 12, 2005, a Federal judge in California ruled that the MMS could not extend the suspended natural gas and oil leases until an extensive environmental risk assessment is conducted. The decision appears favorable for California officials who feel MMS has failed to show consistency with the State’s Coastal Zone Management Plan. The Federal Government, however, feels that natural gas and oil development in offshore California is important for the nation’s energy security.
Lease sale 181, conducted in 2001, originally included an area of some controversy consisting of 5.9 million acres in the Eastern Gulf of Mexico. Although the area was not under a moratorium, no leasing activity had taken place there since 1988 because there was a concern that it was too close to the Florida shore and that natural gas and oil activity could impact the environment and the coastal communities that rely on tourism for income. The originally proposed leasing area, estimated to contain nearly 8 trillion cubic feet of natural gas and 396 million barrels of oil, was reduced from the original 5.9 million acres to 1.47 million acres. MMS also decided that the blocks excluded from the sale would not be included in the subsequent 2002 to 2007 5-year leasing plan.
Economic Considerations
MMS collects about $6 billion dollars on average in revenue each year from the individuals and companies that lease offshore lands for natural gas and oil development. When awarded a lease through a competitive bidding process, the lease holder pays the bid bonus and then rents the right to develop the resources in that area. In addition, lease holders pay royalties to the MMS based on the value of any natural gas and oil actually produced. MMS, in turn, is responsible for the disbursement of any revenue acquired through the leasing activities to the appropriate Federal or State agencies.
Congress has passed economic legislation to deal with these amounts and the way MMS collects and manages funds derived from the sale and operation of offshore leases. The rules have had a substantial impact on natural gas and oil production in the OCS. They aim to promote production in areas where it may otherwise be prohibitively expensive to drill and to help ensure that the distribution of revenue is fair and equitable.
Energy Information Administration, Office of Oil and Gas, September 2005 13
Outer Continental Shelf Deepwater Royalty Relief Act of 1995
The Deepwater Royalty Relief Act (DWRRA), signed into law by President Clinton in 1995, is intended to encourage natural gas and oil development in the Gulf of Mexico in waters at least 200 meters (656 feet) deep by offering royalty relief on qualifying natural gas and oil lease sales. MMS determines which leases are eligible for the relief based on location (the lease must be in the Gulf of Mexico, west of the Florida/Alabama boundary) and economic viability of the resource field associated with the lease (the field would not be explored or drilled without the relief). Originally, the Act provided guidelines that used water depth to specify the minimum volume of production that is exempt from royalty charges for all eligible leases (see Table 3). After these conditions expired in November 2000, however, the MMS adopted a program which determines royalty relief on a lease-specific basis. Under the revised method, leases located in the same water depth may have different volumes exempt from royalty charges if the economic conditions vary. For example, if one natural gas field is more expensive to access, then it may potentially receive more royalty relief than a field in the same water depth with lower costs to access.
The number of active leases in deepwater areas in the Gulf of Mexico has increased since passage of the Act, but it is unclear whether or not production level increases are associated with the increase in lease sales. Proponents of the DWRRA say that without the royalty incentive, technologies necessary for pursuing deepwater natural gas and oil would be economically unattractive. On the other hand, some argue that technology has advanced enough so that deepwater reserves are economically attractive without the DWRRA incentives. Other factors, notably current and expected natural gas and oil prices, are clearly important to the economics of deepwater resource development.
Table 3: Royalty Suspension Volumes, Expired in November 2000
Depth
Minimum Relief Volume (natural gas equivalent)
Minimum Relief Volume (barrels of oil)
200-400 meters (656-1,312 feet)
98.5 billion cubic feet
17.5 million
400-800 meters (1,312-2,625 feet)
295.6 billion cubic feet
52.5 million
>800 meters (>2,526 feet)
492.6 billion cubic feet
87.5 million
Note: Natural gas equivalence volumes calculated from petroleum volumes based on assumed heat content of 1,030 Btu per cubic foot of natural gas and 5.8 million Btu per barrel of oil.
Source: Energy Information Administration.
Similar royalty relief incentives have been offered since 2001 to encourage production from wells drilled for deep natural gas (greater than 15,000 feet total depth or 4,572 meters total depth) on new leases located in shallow waters (less than 200 meters). Since
Energy Information Administration, Office of Oil and Gas, September 2005 14
most of the shallow water areas have already been developed to depths less than that, the incentives offer an opportunity to extend the reach of existing infrastructure to deeper, albeit more costly, potential producing horizons. More recently, in January 2004, DOI issued a final rule to offer similar incentives for existing leases, and on August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 which includes a provision to increase incentives further on production of deep natural gas in the shallow waters of the Gulf of Mexico. The MMS estimates that upwards of 55 trillion cubic feet of undiscovered conventionally recoverable natural gas resources could exist in these areas.
Distribution of OCS Revenues
In 2000, MMS collected more than $5.2 billion in royalty, rent, and bonus revenues from offshore mineral leases (see Table 4). For revenues derived from natural gas and oil operations located on Federal OCS lands the money is divided among the U.S. Land and Water Conservation Fund, which helps States develop and purchase Federal parks and recreation land, the National Historic Preservation Fund, which provides grants for historic sites, and the U.S. Treasury.
Table 4: Revenues from Federal Offshore Lands, Fiscal Year 2000
Royalties
Natural Gas
$ 2,451,875,964
Oil
1,642,700,114
Other Royalties
141,221,225
$ 4,235,797,303
Rents
$ 207,828,582
Bonuses
$ 441,798,474
Other Revenues
$ 324,238,283
Total
$ 5,209,662,642
Under Section 8(g) of the OCSLA, coastal States are entitled to 27 percent of the revenue from offshore leases in Federal waters that are located within 3 miles of the State's seaward jurisdictional boundary. This decision followed debate over the terms of the original OCSLA in 1978, which provided for a “fair and equitable” share of revenue to go to States that are affected by offshore operations in adjacent Federal waters. The 1985 amendments to the OCSLA determined that the figure of 27 percent was appropriate to
Source: Minerals Management Service, Minerals Revenue.
Energy Information Administration, Office of Oil and Gas, September 2005 15
compensate States for any damage to, or drainage of, State jurisdiction natural gas and oil resources that operations on adjacent Federal leases might cause. Between 1986 and 2003, coastal States received over $3.1 billion in Section 8(g) revenue (Table 5). They have used this money to support local programs and improvement projects.
Table 5: Federal Offshore Revenue Received by States Under Section 8(g) of the OCSLA, FY 1986-2003
Alabama
$ 198,963,900
Alaska
523,816,155
California
678,204,136
Florida
2,416,063
Louisiana
969,267,130
Mississippi
21,449,651
Texas
751,596,694
Total
$ 3,145,713,709
Current Issues
The Energy Policy Act of 2005
On Monday, August 8, 2005, President Bush signed into law the Energy Policy Act of 2005. This legislation, which is the first comprehensive national energy plan for the United States in 13 years, has several provisions that affect natural gas and oil development in offshore areas. The following bullets are highlights of these provisions and should not be considered comprehensive of the entire law.
• The Act requires the MMS to conduct a comprehensive inventory and analysis of the estimated natural gas and oil resources on the OCS. The inventory includes moratoria areas which are currently closed to natural gas and oil leasing. The Act stipulates that MMS must use any available technology except drilling to conduct the inventory including 3-D seismic surveys and an initial report to Congress will be submitted within 6 months. Since the timeframe for this report is limited, the law authorizes MMS to acquire existing seismic data from industry sources.
• A new coastal impact assistance program will provide $250 million from OCS revenues per year for fiscal years 2007 to 2010 to six energy-producing coastal States: Alabama, Alaska, California, Louisiana, Mississippi, and Texas. The
Source: Minerals Management Service, Minerals Revenue.
Energy Information Administration, Office of Oil and Gas, September 2005 16
allocation to each State will be based on the ratio of OCS revenue generated off a State’s coast to the total OCS revenue in Federal waters. Under this formula, Louisiana is predicted to receive about 54 percent of the assistance money. The money received by the States will be used for coastal restoration, conservation, and other uses.
• The Act contains a clarification of the Federal Energy and Regulatory Commission’s (FERC) exclusive jurisdiction under the Natural Gas Act2 for siting, construction, expansion, and operation of any facility that imports or exports liquefied natural gas (LNG). FERC, however, must consult with affected States’ governments regarding safety issues.
• A provision in the Act establishes a deadline for decisions on appeals of the consistency determination under the Coastal Zone Management Act3. If a State appeals the consistency decision made by the Secretary of Commerce, the Energy Policy Act of 2005 requires the Secretary to close the administrative record for the appeal within 160 days. An extension up to 60 days may be granted under certain conditions. The Act also establishes a 60-day deadline for the Secretary to determine the outcome of the appeal.
• Several provisions in the Act provide increased incentives for natural gas and oil development in offshore areas in order to maintain or stimulate production. The incentives include royalty relief for natural gas production from deep wells in shallow waters of the Gulf of Mexico and for natural gas and oil production in deep waters of the Gulf of Mexico. The Secretary of the Interior has discretion in granting the relief based on the market price of the resource.
• One provision in the new legislation expands the Outer Continental Shelf Lands Act to include the Planning Areas offshore Alaska for royalty suspension at the Secretary of the Interior’s discretion.
• The Energy Policy Act of 2005 grants authority to MMS to manage and oversee alternative-energy related projects on the OCS. Prior to this provision, there was a gap in the law with respect to alternative-energy projects. This provision provides 27 percent sharing of any revenue generated from these types of projects in distances up to 3 miles seaward of State waters.
2 The Natural Gas Act of 1938 was the first Federal law to regulate the natural gas industry. Section 3 of the Act requires Federal approval by the Department of Energy for the import and export of natural gas, including liquefied natural gas (LNG), and approval by FERC for the siting, construction, and operation of onshore LNG import and export facilities.
3 As discussed earlier in this article, the Coastal Zone Management Act of 1972 gives the Secretary of Commerce authority to determine consistency between Federal actions in offshore areas and State coastal management plans.
Energy Information Administration, Office of Oil and Gas, September 2005 17
States’ Rights
Attention has been given in recent years to the amount of authority States have over their coastal waters. Under the Coastal Zone Management Act a State can review any Federal action off its coastline and require consistency with the approved State plan. Responding to increasing concern over Federal moratoria decisions, the Secretary of the Interior announced in December 2001 that it would be up to the States to request a study of the potential natural gas and oil resources off their shores. In addition, it would be the States’ responsibility to reconsider the leasing moratoria off their shores.
For the first few years after the Secretary’s announcement no State expressed interest in lifting the moratoria. Early in 2005, however, a bill was introduced to give States more control over their coastal zones. The proposed State Enhanced Authority for Coastal and Offshore Resources Act of 2005 (SEACOR) would expand the rights of States to approve or prohibit drilling activity up to 12 nautical miles from shore, as opposed to the 3-nautical mile limit that most coastal States now control. The bill would also allow States to veto oil drilling up to 100 miles offshore and drilling for natural gas up to 40 miles offshore, whereas under current law there is no distinction drawn between offshore oil and natural gas drilling. Some Mid-Atlantic States have expressed interest in the proposal. In late February 2005, Virginia’s General Assembly passed a bill advocating passage of SEACOR, which would potentially open the State’s coastal waters to natural gas and oil exploration and production activities. However, Virginia Governor Mark Warner vetoed the bill on March 29, 2005.
Liquefied Natural Gas
As its energy needs grow, the United States has several options for meeting increased demand for natural gas. One way is to increase imports of LNG. In 2003 LNG supplied only about 2 percent of U.S. natural gas supplies, but by 2010 it may supply upwards of 10 percent. The United States currently has four LNG importing terminals located in coastal ports of the Lower 48 States, plus one terminal located in the Gulf of Mexico offshore.4 There are, in addition, up to three dozen approved or proposed new LNG importing facilities, and several more potential sites have been identified by project sponsors. Congress amended the Federal Deepwater Port Act (DPA) in 2002 to expand the definition of a deepwater port to include facilities used to receive and transport natural gas, usually in the form of LNG. With the change in definition, the DPA authorizes the siting, construction, and operation of LNG terminals on the Federal lands of the OCS subject to strict requirements, guidelines and approval by Federal and coastal State authorities. Under the DPA, the Secretary of Transportation must issue a license for any facility and the Secretary is also required to obtain approval from the governors of each State with coastal waters adjacent to the proposed facility. Of the dozens of planned facilities and potential sites about 10 are located in the offshore. Several of them face controversy at the local, State and Federal levels owing to the concern of nearby
4 An LNG receiving terminal also was constructed in 2001 in Puerto Rico, which is a territory of the United States.
Energy Information Administration, Office of Oil and Gas, September 2005 18
communities about potential impacts on the environment and the homeland security risks posed by LNG terminals.
U.S. Commission on Ocean Policy
The Oceans Act of 2000 established the U.S. Commission on Ocean Policy, a bipartisan panel appointed by the President to examine current U.S. ocean policies and offer findings and recommendations for the future. The commission fulfilled its charge in September 2004 with a comprehensive report that included 212 recommendations addressing all aspects of ocean and coastal policy. Although it is far too early to discern the possible impacts of these recommendations, a few of them could have significant effects on offshore natural gas and oil exploration and production. For example, the recommendations related to offshore natural gas and oil activities include changing the structure of leasing revenue distribution so that coastal States invest in renewable ocean and coastal resources, expanding the environmental studies program operated by the MMS, and studying in more detail the appropriateness and feasibility of gas hydrate exploration and production. Throughout the report the commission emphasizes the importance of habitat protection and restoration, greater use of conservation activities, and the need to reverse trends in biodiversity reduction.
Summary
As technological advances have increasingly allowed the natural gas and oil industry to explore and produce in deeper water and from farther beneath the ocean floor over the past half-century, developments in the management of these submerged lands have aimed to balance the conflicting interests and needs associated with these activities.
The earliest laws and regulations established Federal, State, and international jurisdiction over offshore areas. In 1953, the SLA and the OCSLA defined these regions and maintained that coastal States hold the rights to any natural resources within 3 nautical miles of their coastline. The Federal Government holds jurisdiction outside of this boundary. International boundaries were established in 1983 under Proclamation Number 5030 which set the U.S. EEZ. This claimed rights for the United States to all waters up to 200 nautical miles from the coastline.
The OCSLA also set the base of how to manage these lands for natural gas and oil activities. It recognized the need to balance the potential for damage to the environment and coastal areas with the potential for energy supply. An integral component of the act is the requirement of DOI to lease offshore areas for mineral development and enact regulations to ensure resource conservation, environmental protection, operational safety, and equitable distribution of revenue. In 1982, the Secretary of the Interior created the MMS as part of the Federal Gas and Oil Royalty Management Act to administer and manage all responsibilities related to natural gas and oil production in offshore areas.
Energy Information Administration, Office of Oil and Gas, September 2005 19
Environmental laws and regulations have also had a large impact on the natural gas and oil industry. Concerns over impacts on the environmental and coastal communities led to withdrawals of leasing land in the OCS through Presidential moratoria in effect until 2012, annual moratoria enacted by Congress, and coastal States using their veto power under the Coastal Zone Management Act. Other environmental laws may limit natural gas and oil activities by imposing additional requirements enforced by various Federal departments and agencies. These include: The National Environmental Policy Act, the Clean Air Act, the Endangered Species Act, the Clean Water Act, and the National Fishing Enhancement Act.
Another set of regulations has been established in the past few decades to manage revenue received from individuals and companies who lease offshore lands for natural gas and oil development. Regulations such as the DWRRA offer incentives to pursue natural gas and oil in areas where it may be economically infeasible to drill otherwise. There are also rules that ensure the equitable distribution of the revenue. Depending on the location of the lease area, revenue is divided among affected coastal States, the U.S. Land and Water Conservation Fund, the National Historic Preservation Fund, and the U.S. Treasury.
This article has demonstrated the progression of developments affecting the U.S. offshore regions in the last 50 years including several conflicts and competing priorities. Although many parties have differing opinions on how current and proposed legislation affects the natural gas and oil industry, offshore regions in the United States will continue to be a valuable resource to the United States as the Nation faces new energy challenges.


So here we are at the end of all of the rules and regulations concerning off shore oil, most of which will need to be scrapped or modified to achieve our goal of energy independence and drilling for oil "right" away!! They were well meaning at the time, but the situation is critical, and delay will cause our Nation's demise!!

And here is one more story on how the parties differ on how to proceed in drilling off the coast:

The two political parties have settled on markedly different strategies for improving domestic oil supplies to help lower gasoline prices.

Republicans want to end the 27-year ban on offshore drilling along much of the nation’s coastline, while Democrats want to force companies to speed up exploration in certain offshore areas that they already control. A version of the Democratic plan may come to a vote in the House of Representatives as early as Thursday.
But oil experts say that neither approach will give drivers any relief in the short run from prices that stood Wednesday at nearly $4.07 a gallon, on average. They say the simple reality is that no one knows how much oil is to be found offshore, how difficult producing it would turn out to be or how many years that might take.
And oil companies, amid a global drilling frenzy, are stretched so thin they will be hard-pressed to take on big new projects anytime soon. More than 400 major drilling and production projects are competing for engineers, rigs, seismic equipment and steel to build platforms, and the costs of doing the work have skyrocketed.
“All the partisan ideas that are being offered fall short of producing the huge amount of barrels of oil we need,” said Amy Myers Jaffe, an oil expert at Rice University. “There’s no guarantee to drilling, but it could make a contribution eventually the same way alternative energy and conservation may help.”


Oil companies, while acknowledging the short-run limitations on their industry, say that more drilling capacity will be available eventually and that the time to have the political debate over expanded offshore drilling is now.
Republican legislators have argued in Congress this week that the United States is pleading for more oil from foreign producers while keeping most of its own coastal territory off limits to drilling. Democrats are trying to trump that argument by pointing to existing leases in the Gulf of Mexico that they believe companies have been slow to exploit.
It is far from clear, however, that expanded coastal drilling would produce any drastic change in the American oil situation, even over the long haul.
The biggest problem is that much of the coastal United States, subject to a drilling ban since the early 1980s, has not been thoroughly explored for oil. Neither the industry nor the government has any definitive idea how much could be recovered. In order to hazard a guess for some areas of the Eastern Seaboard, the government has had to inspect geological maps from Morocco, which was connected to North America more than 100 million years ago.
The Republican argument is based on the assumption that drilling in areas that are now under moratorium — the Atlantic coast, almost all of the Pacific coast and Gulf of Mexico waters adjacent to the Florida coastline — could prove to be as productive as in offshore areas where leasing and drilling have been going on for decades.
Only about 20 percent of the continental shelf is open for drilling, providing about 27 percent of domestic oil production and 14 percent of natural gas production. Republicans say that modern seismic work and drilling in deep waters in the central Gulf of Mexico have meant a sixfold increase in estimates of the oil there, and they believe that would happen again if exploration were expanded.
Representative John E. Peterson, Republican of Pennsylvania, is leading the House forces in favor of offshore drilling. He said opening more areas would cut down on fear and speculation in the oil markets.
Most oil companies support the Republican position and are particularly eager for access to the eastern gulf, noting that the water in some parts of it is shallow and drilling would be easy.
“These areas have potential, and we really need to find out what is out there,” said Stephen J. Hadden, senior vice president for exploration and production at Devon Energy, a major gulf producer. “We’re encouraged the dialogue is now occurring, and people are asking the hard questions as to why this is off limits.”


Supporters of the Republican position put estimates for potential oil production from new areas at 1 million barrels a day or more. That would be a notable improvement in domestic production, of about 5 million barrels a day. The United States consumes more than 20 million barrels of oil a day, importing most of it.
Democrats call the Republican estimates inflated, and some independent analysts agree.
David Kirsch, an oil analyst at PFC Energy, a consulting firm, said that if the most promising areas off Florida and California were opened for drilling, their peak production in a decade could be as little as 250,000 barrels a day — less than a quarter of what the gulf produces now.
“It’s almost a desperate attempt to take advantage of the political climate brought on by high energy prices to steamroll through legislation that won’t fundamentally address those high energy prices,” Mr. Kirsch said.
Whatever the offshore potential, Democrats argue that the country cannot drill itself out of its energy bind. At hearings this week, they blamed oil speculation rather than lack of supplies for the recent run-up of energy prices, though little hard evidence has emerged to support that position.
Democrats also argue that only 10.5 million acres of the 44 million acres leased offshore are producing oil or gas. Why, they ask, give the oil companies any more territory?
The House is scheduled on Thursday to consider a Democratic proposal that would rescind federal leases if companies are not actively using them. The Democrats say the companies are saving up leases both onshore and offshore while demanding access to more federal territory.
“Big Oil is stockpiling these leases, as they enjoy record profits, while Americans feel the pain at the pump,” charges Representative Nick Rahall, Democrat of West Virginia and chairman of the House Natural Resources Committee.
But oil company executives say the roughly 34 million offshore acres the Democrats are talking about are hardly idle. They note that it can take several years of work after a lease is signed before companies decide to invest $100 million in a deep-water well to determine how much oil or gas is below.
Once drilling starts, a dry hole in one field may make a company reconsider drilling in adjacent waters with a rig that could be used more profitably elsewhere. Typically, companies give up their leases after either five years or 10 years if the area does not produce anything.
Those who favor an end to the offshore ban argue that opening more shoreline would give the companies more options.
“With more targets available, there would be more drilling opportunities that meet the economic hurdles,” said Jerry Jeram, a managing director and head of petroleum engineering at CIT Energy, a firm that finances energy projects.
Estimates of oil offshore are largely the work of the Minerals Management Service, a government agency that oversees production on federal lands.
In areas where drilling is banned, mostly off California, it lists proven reserves that are quite modest, 1.5 billion barrels of oil and 1.56 trillion cubic feet of natural gas.
If thorough exploration were undertaken, the agency estimates that areas now subject to the drilling ban could turn out to contain 17.8 billion barrels of oil and 76.5 trillion cubic feet of natural gas. Areas of the continental shelf already open to drilling are estimated to contain five times as much oil and natural gas.
Chris C. Oynes, a senior administrator at the Minerals Management Service, cited a “distinct possibility” that when modern seismic work and drilling are done, the estimates will go up.
But he added, “I want to be cautious because there have been a lot of people who have explored for oil over the years and bought leases and then drilled 10 straight dry holes.”


That pretty much sums up where our country is at this time!!

Thanks, and Part II will be tomorrow!!