To date the greatest degree of demand destruction has occurred within the industrial sector, where the resulting high gas prices have caused a number of firms to declare bankruptcy and other firms to idle capacity. Both of these events have had an adverse effect on the U.S. economy. To date, total demand destruction within the industrial sector equates to approximately 5.5 BCFD, or 26 percent of total industrial sector gas demand. Higher gas prices also have affected the residential sector, as gas supply costs for this sector have increased approximately $17 billion from the five year average for the late 1990s.

This challenge for the U.S. gas supply sector will continue over the intermediate term, as U.S. production levels are projected to continue to decline for some time, primarily because of the limited increase in gas-directed drilling activity despite record gas prices. One of the major reasons for the limited increase in drilling activity is the limitations the industry faces in gaining access to prospective acreage as a result of environmental restrictions and moratoria. The potential reserves that are off limits because of these restrictions, which are increasing rather than decreasing, has been estimated by industry sources at between 200 and 450 TCF. Another significant reason for the limited increase in gas-directed drilling activity is the lack of scale for prospective exploration and development activity. Even though undiscovered reserves exist, many of these reserves are contained in a series of relatively small plays. Majors and large independents need large reserve plays in order to effectively use their staffs, impact their current production levels and effectively allocate capital. Relying on smaller independents to develop these smaller reserve plays has reached a point of diminishing returns because of the downsizing of the U.S. exploration and production industry.

As a result of these and other factors, the industry will be challenged to maintain, let alone increase, production levels from traditional supply areas. Instead, the industry will have to rely on a series of emerging sources of gas supply to fill any gap between supply and demand. However, it will be an extended period of time before these emerging sources of supply are able to make a significant contribution to the U.S. supply sector. As a result, any acceleration in U.S. gas demand requirements only will exacerbate the challenge for the U.S. supply sector and lengthen the period of high gas prices and further demand destruction in other sectors.

With respect to these emerging sources of supply, which include deep reserves below 15,000 feet, the complex subsalt play, reserves offshore Eastern Canada, frontier coalbed methane basins, new LNG terminals and reserves from the Arctic areas of both Canada and the U.S., the challenge and extended time frame for the industry to develop these highly complex and very capital intensive sources of supply can not be emphasized enough. For example, despite a number of industry announcements concerning possible new LNG terminals, the FERC has granted only one certificate for a new terminal and only one other project has applied for a certificate. With respect to the potential for Arctic gas supplies the earliest date for a completion of a pipeline to deliver these supplies is approximately 2009 and these supplies will be from Canada’s MacKenzie Delta. Arctic gas supplies from the Prudhoe Bay will not be available until 2013 at the earliest. To place the potential of these massive supply projects in perspective, the initial combined capacity of these two Arctic pipelines, net of the incremental gas demand requirements for Canada’s heavy oil sands developments, will only be 1.3 BCFD, or 475 BCF per year, greater than the decline in U.S. production over the last six quarters.

One of the significant impacts of the proposed increases in clean air requirements is that it will cause coal-fired generation to be reduced. A significant portion of this decline in coal-fired generation will need to be made up by additional gas-fired generation. This higher level of gas-fired generation will increase natural gas demand requirements within the electric sector, which will further exacerbate the challenge to the U.S. gas supply sector. This increasing dependence of the electric sector on gas-fried generation is most evident in the recent experience of the industry. Since 1996 gas demand within the electric sector has increased approximately 4.7 BCFD, or 45 percent. This is one of the major reasons for the current challenge within the U.S. gas supply sector.

Of particular concern is both the acceleration of the target dates for the proposed changes in clean air requirements and the increases in the levels of emission reductions contained in some proposed initiatives. Accelerating the time line for these changes in clean air requirements will represent a significant challenge for the U.S. gas supply sector, as it is improbable that the time line for the large, complex and expensive emerging sources of gas supply required to meet future demand increases can be accelerated. In fact, the more probable scenario is that there will be delays in the time lines for some of these emerging sources of supply, which has been the case for offshore Eastern Canada.

Similarly, increasing the levels of emission reductions will cause an even greater reduction in coal-fired generation and increases in both gas-fired generation and gas demand within the electric sector. This will only heighten the challenge for the gas supply sector. Of particular concern are the carbon dioxide limitations, since the power industry has no viable control options and must rely totally upon switching generation to lower carbon containing fuels, of which the most significant is natural gas. Carbon dioxide limits, because they place an effective cap on fossil fuel generation, significantly increase the challenge for the U.S. gas supply sector.

Of the various Clean Air Act initiatives currently being considered S 366 (Clean Power Act of 2003) and S 843 (Clean Air Planning Act of 2003), with their accelerated time tables for emission reductions and their large emission reduction requirements, particularly their CO2 emission reduction requirements, would represent the greatest challenge for the U.S. gas supply sector. With respect to S 485 (Clear Skies Act of 2003) it would also present a challenge for the U.S. gas supply sector. However, by eliminating the mandatory carbon dioxide limitations and providing for a longer implementation period for the required emission reductions it presents a challenge that may, at least, be manageable.

In summary, the U.S. gas supply sector is challenged to meet existing demand levels. This challenge, which likely will extend over the intermediate term because of limitations associated with traditional supply areas, has resulted in natural gas prices reaching record levels and significant demand destruction within the non-electric sectors for natural gas demand.

The acceleration of the proposed clean air requirement timelines and higher levels of emission reductions will only serve to heighten and extend this challenge to the U.S. gas supply sector, as these changes in clean air requirements will increase gas demand in the electric sector. Furthermore, since the gas supply sector is heavily dependent on a series of complex and capital intensive emerging sources of supply to meet projected increases in natural gas demand, it is doubtful that the timeline for additional gas supplies can be accelerated materially. In particular, the proposed carbon dioxide limits may place the gas industry in a position where it is severely challenged to meet the increases in electric sector gas demand requirements. Empirical evidence to date is that when the U.S. gas supply sector is challenged to this degree the net result is that natural gas prices will be pushed to record levels, with all the attendant cost increases for the other sectors, and demand destruction within the non-electric sectors for natural gas demand.

Current Status U.S. Gas Supply

Over the last two years the U.S. natural gas supply sector has been challenged to meet demand. The primary reason for this phenomenon is that U.S. production has been declining for each of the last six quarters, as illustrated in Exhibit 1.[1] This decline in U.S. production, which equates to approximately 3.5 BCFD, or six percent of total production, has caused natural gas prices to reach record levels[2] and resulted in significant demand destruction[3] in the non-electric sectors for natural gas demand. The latter has impacted adversely the U.S. economy.[4]

Exhibit 1

U.S. Natural Gas Production

This decline in U.S. production is occurring throughout the United States, as five of the seven major supply areas in the U.S. are in decline.[5] The areas in decline include the San Juan basin, the Permian basin, the Mid-Continent area, the onshore Gulf Coast area and the shelf of the Gulf of Mexico. Of these areas the most significant decline has occurred in the shallow water region, or shelf, of the Gulf of Mexico, which historically has been the most prolific producing area in the U.S., as it at one time accounted for 26 percent of U.S. production. The steady decline in production from the shelf of the Gulf of Mexico is summarized in Exhibit 2. Furthermore, the recent development of the deepwater region of the Gulf of Mexico, with its extensive use of modern exploration and production technology, has not been able to offset the decline in production from the shelf, and as a result production for the entire Gulf of Mexico is declining.

Exhibit 2

Production From Shallow Waters (Shelf)

Impact On Demand

The supply and demand imbalance resulting from this decline in U.S. production has caused natural gas prices to rise to record levels, which has caused, in turn, a decline in natural gas demand. This decline in demand has been most pronounced in the industrial sector where firms have had to idle capacity or have gone out of business because they can no longer compete at the current elevated prices for natural gas. This decline in industrial activity, which has impacted adversely the U.S. economy, has been most pronounced in the basic chemicals and primary metals sectors, with the latter being impacted adversely by higher gas-fired electricity prices.[6],[7]

With respect to the chemical industry, which accounts for over 50 percent of industrial sector demand, there has been a fundamental shift in the competitiveness of the U.S. chemical industry versus overseas facilities because of the higher U.S. gas prices. This has occurred because the U.S. chemical sector is heavily based upon natural gas and natural gas liquids, while the European and Asian chemical producers are based heavily on oil (i.e. naphtha). Higher U.S. gas prices have caused the ratio between gas and oil prices to shift from 0.6 in the 1990’s to 1.0 at present, which has provided European and Asian chemical producers with a competitive advantage. One example of the impact of this shift in competitive position between these regions is the recent closure of a Louisiana ethylene and plastics plant in order to move operations to Germany, where gas prices are lower and more stable.

With respect to the net impact of higher prices on industrial sector demand, the best estimate to date is that industrial sector demand has declined approximately 5.5 BCFD, or 26 percent, over the last two years, as illustrated in Exhibit 3.[8],[9]

Impact Of Cost

In addition to causing a reduction in demand within some sectors, the high gas prices resulting from declining production levels have increased substantially the costs of natural gas supply for the other sectors. For example, in the residential sector the supply component for residential gas costs has increased approximately $17 billion from the five year average during the late 1990s.

Exhibit 3

Industrial Demand

Intermediate Term Outlook For U.S. Gas Supply

This challenge for the U.S. gas supply sector likely will continue over the intermediate term, as U.S. production levels are projected by EVA and others to continue to decline,[10] as gas-directed drilling activity has been slow to respond to increases in natural gas prices and decline rates for existing production are high.[11],[12] One of the major reasons for the limited increase in drilling activity during this period of elevated gas prices is the limitations the industry faces in gaining access to prospective acreage, as a result of environmental restrictions and moratoria.[13] While there is tension between the exploration and production industry and other industry observers over the exact amount of the potential reserves that are not accessible because of the various environmental restrictions, the figure has been placed at approximately 200 TCF by the National Petroleum Council study and even higher by a study conducted by Texaco (i.e., 450 TCF). Furthermore, these environmental limitations on access to prospective acreage are increasing rather than decreasing, even though U.S. production is declining. Recent examples include (a) restrictions on drilling under the Great Lakes even though Canada has done such for years, (b) a nearly 75 percent reduction in the offshore acreage that was planned to be offered in the Gulf of Mexico Sale 181 and (c) Pennsylvania’s access restriction of 56 percent of the acreage for the Trenton-Black trend within that state.

Another major reason for the limited increase in gas-directed drilling activity is the lack of scale for prospective exploration and development activity. Even though undiscovered reserves exist, many of these reserves are contained in a series of relatively small plays. Majors and large independents need large reserve plays in order to effectively use their staffs, impact their current production levels and effectively allocate capital. It is this diminishing size and concentration of reserve targets that led the majors away from further development of the shallow waters in the Gulf of Mexico.[14]

Relying on smaller independents to develop these smaller reserve plays has reached a point of diminishing returns because of the downsizing of the U.S. exploration and production (E&P) industry. For example, the tabulation of E&P firms in the U.S. industry by the Oil and Gas Journal has declined from 400 in 1990 to 176 at present, with the smallest firm having assets of only $197,000.[15]

As a result of these and other factors, the industry will be challenged to maintain, let alone increase, production levels from traditional supply areas.[16] Instead, the industry will have to rely on a series of emerging sources of gas supply to fill any gap between supply and demand. However, it will be an extended period of time before these emerging sources of supply are able to make a significant contribution to the U.S. supply sector. As a result, any acceleration in U.S. gas demand requirements only will exacerbate the challenge for the U.S. supply sector and lengthen the period of high gas prices and further demand destruction in other sectors.

Long-Term Outlook For U.S. Gas Supply Sector

Exhibit 4 summarizes the long-term outlook for natural gas demand for several different forecasters. While there are some differences in assumptions for each of these forecasts, they tend to cluster around 30 TCF for 2015.

Exhibit 4

Various Gas Demand Projects For 2015

Source: EIA, Annual Energy Outlook 2002 and EVA.

Reaching this 30 TCF level will be a major challenge for the U.S. supply sector, as empirical evidence to date illustrates that this level of supply can not be attained by further development of traditional sources of supply. Instead, the industry will have to rely on a series of emerging sources of supply, which include the exploration and/or development of: (1) deeper reserves (i.e., >15,000 ft), (2) the highly complex subsalt play in the Gulf of Mexico, (3) reserves offshore Eastern Canada, (4) new coalbed methane reserves in frontier basins, (5) new LNG terminals and (6) reserves in the Arctic areas of both Canada and the U.S.[17] The challenge and extended time frame for the industry to develop these highly complex and very capital intensive sources of supply can not be emphasized enough. For example, it can take up to nine months on a super computer to process the seismic data associated with the subsalt play, which is still in its infancy.[18] Also, drilling a single well for the deep Madden play in Wyoming, which used to take over a year, still takes over 200 days even with the application of significant improvements in drilling technology. Lastly, a string of expensive dry holes (i.e., approximately $440MM to date) over the last two years in exploration for potential reserves offshore Nova Scotia has forced the industry to reevaluate development of the area and delay its time table.[19]

The lengthy timeframe for some of these emerging sources of supply is best illustrated by the time lines for new LNG terminals and the development of a pipeline(s) for Arctic gas supplies. While the nation is reopening and/or expanding each of the existing four LNG terminals, additional LNG supplies beyond the capabilities of the four terminals will be required to meet projected demand levels. At present, despite a number of industry announcements concerning possible new LNG terminals, the FERC has granted only one certificate for a new LNG terminal and only one other project has applied for a certificate. In addition, there has been the announced cancellation of at least two proposed new LNG terminals, as the combination of stiff resistance, primarily on environmental grounds, and the expensive nature of these facilities have forced several potential industry participants to reconsider their involvement in such projects. Also, the U.S. industry has learned that even with new LNG terminals, it will have to compete with the rest of the world for available supplies. This tension with the rest of the world was made very clear this last winter when, despite record U.S. gas prices, LNG imports were limited to just 15 percent above the levels for the winter of 2000/2001, because of high LNG demand from Asian countries.

With respect to the possibility of Arctic gas supplies, the construction of a gas pipeline from the Arctic region to the North American market place will be a massive project that will task severely the existing infrastructure of the region. At present the earliest possible date for the first of the Arctic pipelines, which will be from Canada’s MacKenzie Delta, is the end of 2008 or early 2009. Furthermore, it appears that approximately 75 percent of the initial capacity of this pipeline will be required to meet Canadian gas demand associated with its growing development of heavy oil sands projects.[20] Beyond this there is the possibility of the $19.4 Billion Arctic gas pipeline from Prudhoe Bay, which is projected to be longer than the Great Wall of China. While specifics on the timetable for this massive project are limited, the earliest potential date for a second Arctic gas pipeline appears to be 2013. The possibility of building both Arctic pipelines at the same time is not even being considered by the industry, because of inadequate infrastructure within the region. For example, for the earlier MacKenzie Valley pipeline movements of pipe sections will require one truck haul every five minutes along the Yukon highway system and a doubling of the capacity of the White Pass Railway. Furthermore, the tractor and trailer units for these hauls will have to be twice the typical length of such units in order to move the 82-foot sections of pipe.[21]

To further place the challenge to the U.S. supply in perspective, the initial combined capacity of both of these huge Arctic gas pipeline projects, net of the incremental demand for Canada, will be only 1.3 BCFD, or 475 BCF per year, greater than the decline in current U.S. production over the last six quarters. Further increases in the capacity of these projects likely will not occur until several years after the completion of the Prudhoe Bay pipeline project (i.e., approximately 2015 or thereafter).

Impact Of Proposed Clean Air Requirements

One of the significant impacts of the proposed increases in clean air requirements is that it will cause coal-fired generation to be reduced. A significant portion of this decline in coal-fired generation will have to be made up by additional gas-fired generation, as other forms of generation are limited in their ability to increase significantly.[22] This higher level of gas-fired generation will increase natural gas demand requirements within the electric sector, which will further exacerbate the challenge to the U.S. gas supply sector. This increasing dependence of the electric sector on gas-fired generation is most evident in the recent experience of the industry. Since 1996 gas demand within the electric sector has increased approximately 1.7 TCF (i.e., 4.7 BCFD), or 45 percent. This is one of the major reasons for the current challenge within the U.S. gas supply sector.

Of particular concern is both the acceleration of the target dates for the proposed changes in clean air requirements and the increases in the levels of emission reductions contained in some proposed initiatives. Accelerating the time line for these changes in clean air requirements will represent a significant challenge for the U.S. gas supply sector, as it is improbable that the time line for the large, complex and expensive emerging sources of gas supply that will be required to meet future demand increases can be accelerated. In fact, the more probable scenario is that there will be delays in the time lines for some of these emerging sources of supply, which has been the case for the development of the region offshore Eastern Canada.

Similarly, increasing the levels of emission reductions will cause an even greater reduction in coal-fired generation and increases in both gas-fired generation and gas demand within the electric sector. This will only heighten the challenge for the gas supply sector. Of particular concern are the carbon dioxide limitations since the power industry has no viable control options and must rely totally upon switching generation to lower carbon containing fuels, of which the most significant is natural gas. Carbon dioxide limits, because they place an effective cap on fossil fuel generation, significantly increase the challenge for the U.S. gas supply sector.

If the natural gas supply sector is not capable of meeting the challenge of increased gas demand within the electric sector, as a result either of an accelerated time table for new clean air requirements or the increased emission reduction levels proposed in some initiatives, then the alternative is for an extended period of high gas prices and demand destruction within the other sectors for natural gas demand. Both these latter items will have an adverse impact on the U.S. economy. From one perspective this alternative is a mirror image of what is currently occurring within the U.S. gas industry.

Current Clean Air Act Initiatives

The three Senate proposals have significantly different impacts on the natural gas industry. S 366 (Clean Power Act of 2003) poses by far the largest natural gas supply challenge because (1) its much tighter carbon dioxide and SO2 limitations create the greatest demand shifts towards natural gas; (2) its much shorter compliance period gives the gas supply industry the least time to expand its supply base; (3) its much tighter mercury limit is heavily dependent upon mercury control technology performance that has not been commercially demonstrated yet and may force the shutdown of a large portion of the existing coal power plant fleet; and (4) its new source standards forces the greatest amount of older coal based capacity to be retired.

In comparison to S 366, S 834 (Clean Air Planning Act of 2003) will reduce the challenge to the natural gas supply sector by phasing in slightly higher limitations over a longer period (i.e., four additional years). Its longer scheduled compliance period allows the natural gas industry valuable time to expand its supply base, while reducing natural gas demand pressure by permitting greater coal generation with its alternative emission limitations. Also, mercury technology risk is greatly reduced, as limitations are more in line with current DOE research targets.

Finally, S 485 (Clear Skies Act of 2003) also presents a challenge for the U.S. gas supply sector. However, by eliminating mandatory carbon dioxide limitations and providing for longer periods for implementing the required emission reductions, it presents a challenge that may, at least, be manageable.

Conclusions

Currently the U.S. gas supply sector is challenged to meet existing demand levels. This challenge, which likely will extend over the intermediate term because of limitations associated with traditional supply areas, has resulted in natural gas prices reaching record levels and significant demand destruction within the non-electric sectors for natural gas demand.

The acceleration of the proposed clean air requirement time lines and higher levels of emission reductions will only serve to heighten and extend this challenge to the U.S. gas supply sector, as these changes in clean air requirements will increase gas demand in the electric sector. Furthermore, since the gas supply sector is heavily dependent on a series of complex and capital intensive emerging sources of supply to meet projected increases in natural gas demand, it is doubtful that the timeline for additional gas supplies can be accelerated materially. In particular, the proposed carbon dioxide limits may place the gas industry in a position where it is severely challenged to meet the increases in electric sector gas demand requirements. Empirical evidence to date is that when the U.S. gas supply sector is challenged to this degree that the net result is that natural gas prices will be pushed to record levels, with all the attendant cost increases for the other sectors, and demand destruction within non-electric sector for natural gas demand.

APPENDIX

Exhibit A-1

Henry Hub Natural Gas Price Weekly Data

Exhibit A-2

Production From Selected Regions I

Exhibit A-3

Production From Selected Regions II

Exhibit A-4

RIG COUNT FOR THE GULF OF MEXICO

Stephen L. Thumb

Principal

Energy Ventures Analysis, Inc.

Arlington, VA

Mr. Thumb is responsible for the oil and natural gas practice at Energy Ventures Analysis, Inc. (EVA) and has been involved in a wide variety of projects for each fuel, primarily for industrial and electric utility clients. Examples include preparation of strategic plans, development of bidding programs for natural gas supplies, coordination of market studies, production of price forecasts, as well as being an expert witness. In addition, Mr. Thumb is the author or co-author of over a 25 EPRI and GRI reports on key topics concerning oil and natural gas. Prior to joining EVA, Mr. Thumb had 15 years of experience in the oil and gas industry, including five years as vice president of planning and analysis at Meridian Oil/Burlington Resources. Other positions were at Ashland Oil and Getty Oil. Mr. Thumb received a B.S. in chemical engineering from Northwestern University and an M.B.A. in finance from American University in 1972. He is a certified public accountant in West Virginia.

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[1] There also have been declines in production in Canada’s Western Canadian Sedimentary Basin as documented in “Canada Looks to Other Sources to Offset Steep WCSB Declines,” Natural Gas Week, March 10, 2003, p. 16 and “Analysts Sound the Alarm on U.S., Canadian Gas Production” Natural Gas Week, April 28, 2003, pp 5-6.

[2] See Exhibit A-1 in the Appendix for a summarization of natural gas prices.

[3] The term demand destruction is used often in the natural gas industry to describe the loss of demand as a result of high gas prices. As discussed in subsequent sections of this paper it often involves firms going out of business and plants idling capacity because these entities can not pass through the high gas costs to their customers.

[4] American Chemical Council, Background Paper on Natural Gas Price Shocks and The Economy, February 28, 2003.

[5] See Exhibit A-2 and A-3 in the Appendix.

[6] Bankrupt fertilizer firms include Farmland (Midwest and Louisiana), Vicksburg Chemical (MS), Agrifos (TX), Mulberry Phosphates (FL) and Agway (Syracuse, NY). Mississippi Chemical (Yazoo City, MS) has had a one year credit extension and Terra Industries (Sioux City, IA) has acknowledged limited ability to effectively hedge future gas prices. Mississippi Chemicals has permanently shut down its Donaldsonville, LA plant and Air Products has ceased production at its Pace, FL plant. (Source: Company announcements and trade press.)

[7] Currently idled aluminum plants include Alcan’s West Virginia plant, the Mead, Tacoma and Trentwood, WA plants for bankrupt Kaiser, Alcoa’s Troutdale, OR and Rockdale, TX plants, the bankrupt Longview, WA plant and the Goldendale plant. These eight plants may never reopen. At present in the Pacific Northwest, which is the heart of the U.S. aluminum industry, only two plants are operating (i.e., Glencore’s Columbia Falls in Kalispell, MT at 20% capacity and Alcoa’s Ferndale plant in Bellingham, WA). (Source: Company announcements and trade press.)

[8] “As Gas Prices Increase To New Norm, Chemical Sector Could Be Hit Hard,” Inside FERC’s Gas Market Report, February 28, 2003, pp 9-10; and “Chemical Analysts Grow Bearish As U.S. Sector’s ‘Golden Era’ Closes,” Natural Gas Week, February 24, 2003, p. 5.

[9] “Record U.S. natgas prices punish manufacturers” Reuters, February 25, 2003.

[10] “Analysts See Bullish Gas Market Rebalanced by Pricing Factors,” Natural Gas Week, December 30, 2002, p. 3; and “Analysts Sound The Alarm on U.S., Canadian Gas production,” Natural Gas Week, April 28, 2003, pp 5-6; and “CERA Warns of Fragile Balance In Supply/Demand Outlook for 2003,” Inside FERC’s Gas Market Report, February 14, 2003, p. 1.

[11] See Exhibit A-4 in the Appendix.

[12] The annual rate of decline in production from new U.S. wells accelerated to 27 percent in 2002 from 17 percent in 1990. See “EIA’s Rosy Gas Supply Projections in Doubt,” Natural Gas Week, March 10, 2003, p. 9.

[13] “Witnesses Urge Greater Access As Check for Rising Gas Prices,” Natural Gas Week, March 3, 2003, p. 7; and “Producers Concerns Unheeded In New Rockies Reserves Study,” Natural Gas Week, January 20, 2003, p. 3-4 and “AGA Calls For Access to Closed Areas: Court Upholds Forest Land Closings,” Inside FERC’s Gas Market Report, December 20, 2002, p. 16.

[14] “Drilling Boom Deemed Unlikely Despite Natural Gas Price Surge,” Natural Gas Week, March 3, 2003, p. 1.

[15] “Special Report OGJ 200/100” Oil and Gas Journal, September 9, 2002, pp 70-90.

[16] This challenge will continue to exist even during potential periods of downward gas price volatility, which for example might occur do to unforeseen weather events, such as very warm winter weather.

[17] EPRI, Gas Supply Outlook-Gauging Wellhead Deliverability Now and in the Future (1004588), February 2002.

[18] For other non-subsalt exploration plays it typically takes less than a month to process the associated seismic data and that is accomplished on a basic computer.

[19] “East Coast Canada Loses Luster As Petro-Canada Abandons Well,” Natural Gas Week, May 5, 2003, p. 16.

[20] “Canadian Energy Exports to U.S. May Slow As Capacity Tightens,” Natural Gas Week, April 14, 2003, p. 1.

[21] “Report Says Southern Pipe Route The More Feasible Alternative” Natural Gas Week, February 3, 2003, p. 4 and “The Aboriginal Pipeline Group” Oil & Gas Journal, March 3, 2003, p. 8.

[22] Dependence upon natural gas generation is directly attributable to other power sources having only a very limited ability to offset coal generation losses. Hydro power expansion is limited by the lack of appropriate sites and growing permitting opposition. Nuclear power is hindered by its very high production costs and continuing waste disposal problems. Nor are other renewables able to displace large coal losses because of resource limitations and high costs. For example, areas offering Class 5-7 wind resources are very limited and distant from load centers. Lower class wind resources are far too expensive to develop and transmit. In addition, because wind power units only operate at best 25 to 33 percent of the time, additional gas-fired generation is required to supplement wind power units in order to replace the lost base load coal-fired generation.