Minnesota's Energy Future?©

Dell Erickson

Minneapolis, MN
October 20, 2003

Part II-B:  Energy &  Resources

Table of Contents
 

Part II:  Energy &  Resources

 47

       Natural Gas

88

            Natural Gas Demand

89

               Table 9: Natural Gas Use by Economic Sector

89

            Natural Gas Supply

   92

            Locating Natural Gas Reserves

93

               Decline & Depletion: A Sisyphean Race

93

               Figure 14: Depletion Rate – Natural Gas Production by Fields 1990 – 2003

95

               Figure 15: World Natural Gas Decline vs. Demand 2001 – 2030

97

               Figure 16: U.S. Natural Gas Production & Depletion 2001 – 2010

98

               Blackout of August 2003

101

                Storage & the U.S. Winter of 2003 – 2004

103

               Figure 17: Price of Natural Gas & Plant Shutdowns

104

               Table  10: Winter 2002 – 2003 Natural Gas Storage Data

105

               Deepwater Oil & Gas: Gulf of Mexico

107

               Oh! Canada?

107

                  Table  11: Canada Production Decline 2002 – 2003, June

108

                  Figure 18: North America Natural Gas Production & Discovery 1920 – 2020

109

                 Canadian Tar Sands

110

                 Canada & United States Oil Shales

111

               Natural Gas, ANWR & LNG

112

                 LNG

117

              Chevron – Texaco Confirmation

119

 

 

       Pricing Economics

121

            Figure 19: Oil Production vs. Cost of Production

123

            Figure 20: Declining U.S. Oil Production Efficiency

127

            Figure 21: Economics & Net Recoverable Energy

128

 

 

       Coal

130

            Coal Reserves

132

            Productivity

134

            Other Problems of Coal

134

       Nuclear Energy

136

            New Plants & the Morality of Wastes

137

            Efficiency

138

            Pollution

139

            Ore Resources

140

            Fusion

141

            Price-Anderson Act

142

 

Natural Gas

Realizing that the remaining life of oil is now in view, and because natural gas is relatively clean firing, environmentalists and government have promoted its use.  However, it should be considered a temporary energy and environmental fix.  The substantial increases in natural gas use were the consequence of the overly enthusiastic publicity of an earlier period.  The promotion merely maintains the status quo game, replacing the use of one limited resource for another.  Unfortunately, government, industry, and mainstream environmental organizations evidently misunderstood that natural gas is the primary fuel used to warm residential homes in winter and extensively used for food production.  The substitution (economic balancing) of basic energy resources implies comparable pricing.  The suggestion is that peak production and subsequent decline of both oil and natural gas will now occur within close proximity.

Based on the media hype in the 1980s and 1990s one would think that there would be a nearly inexhaustible supply of natural gas —500 to 700 years of consumption at current rates was frequently heard.  If the early stories were accurate it would hardly be a pressing issue today.  Yet, scientists report that U.S. natural gas supply is scheduled to travel down the same road less than 10 years after oil, decades prior to 2030.  Again, the Olduvai theory confirmed!  Speaking at a conference in Germany last summer the preeminent industry scientist, Dr. Cóilín Campbell, said that the outlook for natural gas in the U.S. is in serious doubt and that Europe is not much better off.  Europe, he continued, may have better access than the U.S. to the reserves from Russia, the Mideast, and Africa —if they can afford it.100

This section begins by describing growth in natural gas demand then discusses the supply side.  The conclusion is that due to declining natural gas basins and depletion rates, demand is outstripping resource availability.  The paper then turns to secondary sources of natural gas, first to Canada and its tar sands and Canadian and U.S. oil shale, then to liquefied natural gas (primarily foreign) and the potential for Alaska’s North Slope.  An analysis of a major integrated petroleum and natural gas company, Chevron-Texaco, is performed to determine if the oil and natural gas situation described is reflected in actual company data.  It will be seen that the difficulties involved in discovering and producing additional natural gas are well documented.  This section concludes with a brief mention of pricing economics.  The argument is made that market price signals for oil and natural gas do not properly reflect long-term supply and that physical constraints implies that increasing prices only marginally increases production.

There are two pressing natural gas issues —the near term storage squeeze and the substantial longer term supply relative to increasing demand.  Price increases evident in the previous two years were due to unreliable supply.  Unreliable supply is due to a combination of decreasing natural gas availability and increasing use.  Increasing use is due to a combination of increases in population, industrial usage, large increases in electricity generation, and the ebbing of oil reserves.  Because natural gas is environmentally cleaner than other major energy sources, it may also be a less expensive means to meet pollution regulations required of other energies.

With the unprecedented demand and viselike supply creating rising prices in the previous two years, residential users paid the price and complained while non-residential consumers sought alternatives.  Later the economy slowed, demand decreased and prices moderated.  Yet, ominously, gas reserves failed to rebound.101  Economists and financial allies trusting in higher prices to increase supply were sorely disappointed.  High natural gas prices accomplished little in providing additional natural gas.  The explanation is that there are no known giant or readily accessible large fields remaining to discover and that increasing costs of production cannot compensate for declining reservoirs.102

Similar to oil, the natural gas supply issue involves the simultaneous discovery of additional reserves while overcoming the depletion rates of existing fields.  Providing additional supply involves exploration activities in the U.S. and Canada, increasing foreign imports of liquid natural gas (LNG), and the conversion of domestic coal.  Due to limited supply, natural gas from Mexico cannot be relied upon except temporarily.

Rather than accepting the realities of natural resource availability, government and industry officials promote programs to increase production.  Increasing production hastens resource exhaustion and deprives future generations of crucial energy.


Natural Gas Demand

Nation's Supply of Natural Gas Drying up Fast: Power plants like those in upstate (South Carolina)
will burn increasingly scarce fuel
.
    Brad Foss, 2001.103


Natural gas is the nation’s premier energy source for residential and commercial use.  Comparative consumption data points out that residential and commercial natural gas consumption exceeds residential and commercial use of electricity —approximately 8.5 gigajoules of natural gas and 8.0 gigajoules of electricity.  Similarly, industry uses approximately 10.0 gigajoules of natural gas compared with 3.8 gigajoules of electricity.  Excluding transportation use, natural gas is the largest energy input for industry.

Reflecting large increases in the construction of natural gas plants for industrial use, industrial use increased 43% and non-residential use by 40% in 1998 – 1999 and the first ten months of 2000.  Residential use, primarily home heating, even in this cold winter, increased less than half that of the commercial, 22% and industrial, 20%, use.104

The importance of natural gas in various economic sectors is demonstrated in the following table.

Table 9:  Natural Gas Use by Economic Sector

Item

Percent

Paper

21.8%

Petroleum refining

24.0%

Petroleum & Coal products

25.0%

Manufacturing

37.2%

Plastics

45.0%

Food

53.3%

Mining

56.4%

Chemicals

57.9%

Industrial compounds

61.1%

Oil and gas extraction

74.0%

Nitrogen Fertilizers

93.4%

Industrial Energy Intensiveness and Energy Costs in the Context of Climate Change Policy”, Bernard A., Gelb. November, 21, 1997. Congressional Research Service Reports for the National Council for Science and the Environment. See at < www.cnie.org/nle/clim-11.html >, note Table 3. “Distribution of Energy for Heat and Power by Energy Type, Selected Major Energy-Using Industry Groups and Industries, 1994 (percent of total)”.


Table 9 suggests the potential social and economic scope of reduced natural gas reserves —the energy transition will require patience and life style changes across a broad spectrum of society, residential and commercial users.105

The U.S. used 22.8 Tcf of natural gas in 2000.  According to the Energy Information Agency (EIA) natural gas used as firing fuel for the generation of electricity increased 27% and 31% in the last two years.  EIA data reveals how critically important natural gas is to the Midwest.106  With 23.7% of the nation's households that use natural gas, Midwest households comprise 41.6% of the nation's total residential use.  With enormous numbers of energy immobile consumers using substantial volumes of natural gas, any disruption in availability —even for very short time periods― would be disturbing.  In great part explaining its precarious energy sources and pricing situation, California already generates one-third of its daily and all of its peak electricity using natural gas.  Minnesota is duplicating the California model.  If Murphy's Law were to operate, a natural gas disruption would occur in the Northern Plains states in mid-winter on a day the temperature high grudgingly reached 0ºF (-18C).

As the petroleum situation becomes more pressing, the use of natural gas will accelerate beyond the rapid increases now anticipated.  In 2000, 25,000 MW were added, in 2001, 37,000 MW, and another 300,000 MW is currently under construction or planned before 2004.  Estimates are that before the year 2003 ends, there will be approximately 180,000 MW of additional generating capacity constructed.107  Of that amount, 135,000 MW will utilize natural gas (with 55,000 MW of it peak generating facilities).  The balance of 45,000 MW will likely be coal-fired plants with relatively minor quantities of alternative energies.  The nation's electric utilities plan to add 44.7 gigawatts of capacity in new units from 2001 through 2005.  According to the EIA “ninety-one percent of this total is gas-fired capacity”.107

Adding a safety reserve implies significantly greater demands than forecasted.  Even though the construction of natural gas plants requires one-half to one-third the time of other baseline generating units, the construction demands are a daunting task.  Translated into a construction schedule, nationally approximately 1,200 natural gas generating facilities will be required in less than 48 months, 25 per month.  Suggesting the magnitude of that construction schedule, only 41 additional natural gas fired generating plants were commissioned in 2001, 75 in 2002, and 73 more are scheduled for 2003.  Altogether, 272 additional natural gas facilities are under construction.108

A little appreciated fact is that due to pollution concerns and ease of construction, construction of gas fired generating plants have been the generating plant du jour for more than a decade.  The good news is that some of the new construction has been to replace older gas plants with operating efficiencies up to half those of modern gas generators.  Replacing the older versions reduces gas consumption in regions with concentrations of old natural gas plants —at least attenuating the rapid rate of increasing consumption.

If recent natural gas volume increases are extended outward in time, the volume increases will be in the 6 to 9 Tcf range rather than the 4 to 6 Tcf per year range previously considered.  In that case natural gas plant and infrastructure construction requirements would be multiplied by 150%.  Experts have anticipated that far-reaching increase, and now conclude that within 5 years natural gas use could swell to the 30 Tcf region —primarily due to generation of electricity, and as much as 35 Tcf as some aging oil and coal utilities are replaced.

The net is a minimum forecasted 37% increase in natural gas use in 6 – 8 years, by 2010, and more than a 60% increase to soon follow.

The proposed construction schedule presumes there are adequate pipelines and infrastructure in place or under construction to match the need.  The implication is for the simultaneous addition of several two to four foot diameter pipelines crossing Canada and the U.S. or large volumes of imports.  Although the importation of liquefied natural gas (LNG) theoretically has some potential for filling the gap, to accomplish this task would require several hundred (perhaps thousand) additional LNG tankers, sufficient ports, and the same or more pipelines crossing the U.S.109  Moreover, it suggests that overall natural gas use is geologically capable of increasing by 6 or more Tcf —more than 25% in that brief time frame.

The demand increases apply to propane (and to butane) as well.  Propane demand increases primarily as rural areas are developed.  The large numbers of people moving out of cities into rural areas depending on propane will soon discover rapidly escalating cost and potential supply inconsistency.  Because 70% of propane is manufactured from natural gas with the balance from petroleum, there is little possibility for substitution.110  Adding another level of processing of unconventional fuels such as tar sands implies costs at a multiple of current propane prices.

A few words on pollution are appropriate.  In great measure the passage of the Clean Air Act and 1990s revisions are responsible for the enormous increase in the use of natural gas for electricity generation.  In the face of burgeoning populations California’s and Minnesota’s intention in switching to natural gas was primarily to maintain rigorous air pollution standards at the lowest possible consumer costs.  In addition, the hesitancy to construct traditional baseline coal and nuclear generating facilities is a contributing factor.  The result has been that the grid system was becoming unreliable —reductions in the availability of wheeled energy from other regions and out-state and fossil and nuclear fuel based electricity sources.  Minnesota is following California's lead in energy planning and usage —and the consequences will be no different.

In Minnesota, a fundamental reason for constructing natural gas fueled plants and conversion of several coal plants is to permit existing coal plants to continue to avoid dealing with the state’s obligation to clean air.  According to the state's energy report, 60% of the electricity generated from Minnesota coal plants fails to meet any current air-emissions standards.  Forty percent meet some of the standards; perhaps a single coal generating plant meets current pollution standards.  Since it is the state's responsibility, a fair question to ask is “what is the role of the Minnesota Pollution Control Agency and Minnesota Environmental Quality Board in this matter?  Grandfathering inappropriate clean-air standards is a choice that can be superceded by appropriate state policy.

Minnesota practice avoids its clean-air obligations while continuing current business operations.  Further developments today work in a circular manner to make the situation worse by encouraging current consumption.

The tremendous increases in natural gas consumption are a Faustian bargain agreed to by California, Minnesota, and increasing numbers of corporations.  Endeavoring to maintain a reliable energy source during uncertain, often high demand periods while using the same firing source as baseline and peak generators is a prescription for uncertainty: peaking periods are also the periods most vulnerable to supply disruptions and escalating prices.

California, like Minnesota, imports substantial volumes of natural gas from outside the state, 82% in the case of California and 100% for Minnesota.  While Minnesota has no petroleum reserves, 14% of California’s natural gas is produced from its oil wells.  This places Minnesota in a precarious position and California the potential for circular energy problems.  Because natural gas is used to generate electricity, a limitation on natural gas implies shutting down both oil and natural gas production ―in turn reducing natural gas availability.

According to an EIA/DOE study,111 a brief

2-hour interruption of electricity could result in an approximate 8 percent, or more, reduction in the production from the oil or gas well for that day and … up to 27 percent of the California refining capacity is expected to be forced to shut down completely during a rotating electrical outage should it occur in their block. It takes a refinery 1 to 2 weeks to return to full operating rates following a forced emergency shutdown. If electricity outages were to hit one of these refineries frequently, the refinery might choose to remain down for extended periods of time rather than undergo the high costs of repeated emergency shutdowns and restarts.

Last year’s natural gas prices rose above $11 and industry forecasts are for similar or higher prices during the winter of 2003 – 2004.  Immediate delivery “spot” prices can frequently be more than twice the standard contract price.112  Short-term buyers and sellers come together in the spot market.  These higher prices can be embedded in costs of goods sold and in some instances, passed to consumers.  The suggestion is that pipeline companies and interruptible businesses may enjoy profitably selling contracted natural gas to immobile customers through power plant operators.  On the other hand, firms operating on the margin or unable to pass through higher energy prices may file for bankruptcy. 
 

Natural Gas Supply

Has the supply-side equation for natural gas been examined?  Unless the resource base is considered, construction of new natural gas fired generating facilities will continue until physical reality overwhelms the emotional.  With current consumption and projected increases, the estimated 5 to 10 year reserve life of natural gas resources will be halved.113

The largest U.S. fields were discovered prior to 1971; the largest, the Hugoton Field, was discovered in 1922.  These old gas fields contain approximately 25% of today’s proven U.S. reserves.  Excluding small reserve sites, non-conventional sources such as the tar sands, coal bed methane, and deep water hydrates, the remaining U.S. natural gas reserves of all classes reported by petroleum geologists in the year 2000 are in the 200 – 300 Tcf range.  Using 23 Bcf currently and soon more than 30 Bcf each year, the production life of the easily extracted U.S. natural gas is unmistakably in sight.

The title of Raymond James Energy’s latest report is prophetic: “Fourth Quarter Production Survey Shows 6th Consecutive Decline in U.S. Gas Production: New Projects and Higher Activity Levels Cannot Save Us Now”.  In 1995 the Congressional Research System reported to Congress that “there appears to be about an 18-year supply of producible gas.”  The reserves included 9 years of proven supply with the balance expected from drilling in existing fields and yet to be discovered basins.  The report concludes that finding additional supply is unlikely because the newly discovered fields have been small.  In 1992 for example, despite increased search and drilling efforts only two weeks of additional supply were located and in the year following even with greater discoveries of new fields, the increase in supply was only two and one-half weeks of consumption.114  Domestic peak proved natural gas reserves reached a peak in 1967 and have declined more than 45% to less than 162 Tcf today, a 5 to 7 year supply.


Locating Natural Gas Reserves

In 1997 geologist Joseph Riva wrote about the accuracy of the government estimates stating that the EIA has estimated that about 4 Tcf of 2015 gas production will come from continuous-type (unconventional) deposits.  Since these are mostly known, 4 Tcf x 9 years = 36 Tcf of reserve additions may not be needed.  Nevertheless, some 335 Tcf of proven reserve additions must be accounted for by discovering new fields.115  Yet over the past 10 years a total of only 14.24 Tcf of gas have been added to proven reserves from new field discoveries.  At this rate, it would take 235 years to discover 335 Tcf of gas!  To locate this tremendous volume of natural gas within 15 years (even generously considering the potential growth of new fields) the discovery rate of the past decade would have to be increased by an order of magnitude, clearly a case of the triumph of hope over experience.

Supply estimates assume locating substantial additional volumes of gas reserves that are not known at this time and mining known reserves in now protected areas.  It also assumes that there is, as a matter of fact, a 9 year U.S. supply yet to deliver and that these projections include theoretical reserves in environmentally sensitive areas.  One must accept, moreover, the recent U.S. government report that said there are 200 Bcf to be discovered off the outer continental shelf.  Nevertheless, assuming all the hoped for supply actually exists and dividing that quantity by 30 Tcf a year consumption rate buys the U.S. only a few more days of natural gas use.

Concisely stated, under projected gas consumption increases, there optimistically exists between 5 and 10 years of U.S. natural gas supply.  Moreover, as consumer gas bills demonstrated this past winter, genuine energy supply and pricing problems exist nationwide today.


Decline & Depletion: A Sisyphean Race

In the public's mind oil or natural gas reserves are similar to a bottomless lake —merely install another pipe to increase supply.  The public will want to reconsider their “add another pipe” interpretation.  Geologists report that most geologic structures containing petroleum products are found in structures with three layers —bedrock holding water, oil above the water and natural gas above the oil.  A consequence of this geology is that as the oil is removed, pressure within the structure pushing out the oil or natural gas is also relieved.  The reality is that oil reserves are physically analogous to a sponge; the first squeeze (or pipe) releases relatively large and economical volumes.  As the supply declines increasing effort (energy) is required to squeeze out the oil (or natural gas) even as the gas or liquid dispelled decreases.

The final stage of oil producing fields and rapid transition to natural gas explains why Dr. Cóilín Campbell stated that “in short, technological advances accelerate depletion”.116  Modern technology, sophisticated searches, and drilling of smaller and marginal fields only add a layer of expense to oil or natural gas production without significantly adding supply.  In order to continue pumping, oil and gas field pressures must be maintained.  Pressurizing is generally accomplished by injecting natural gas, hydrogen, nitrogen, or saltwater.  More expensive heating processes or the addition of chemicals to grease the flows —so to speak— can also be utilized.  Because the water injections are most frequently salt water, in many regions severe ground water pollution is a result of pumping oil and natural gas.

It is important to note that an increase in natural gas production implies the approaching exhaustion of the petroleum basis of the field.  Briefly mentioned earlier, declining oil field production explains why natural gas production has increased since 1985.  According to studies by distinguished French petroleum geologist Jean Laherrere world “gas production from oil wells follows oil production from 1950 to 1985, but from 1985, oil declines and gas rises.”  This phenomenon is identical to that described for the Mideast states which are now transitioning from oil to natural gas for domestic energy purposes.  Laherrere states it is “well known” by those in the industry that in the dying days of an oil field “associated gas production rises.”  In researching North American natural gas production Jean Laherrere insightfully notes that “it is striking that associated gas production was in line with oil production from 1950 to 1979 but from 1979, oil declines when gas increases.”117  Confirming the alarming oil reserves data discussed previously, the increase of gas production “from oil wells seems to indicate the near end of most U.S. oilfields”.118  Unfortunately, the production life of natural gas reservoirs is considerably shorter than the reserve life for oil.  Rapidly declining oil and diminishing natural gas production soon follow.

Natural gas development allows for longer periods of oil shipment, by focusing on the more profitable natural gas.  OPEC for example, is using natural gas as a feedstock in developing a chemical industry.  It appears to be a well-founded plan.  Sadly, these same large oil/natural gas producing Muslim nations have calamitous rates of population growth.  They are now undergoing a considered reprioritizing domestic energy interests to temporarily relieve growth induced tensions.

A significant consequence of falling reservoir pressure is that continually higher consumer prices are required to stimulate pumping as reserves decline.  Similar to the sponge analogy —certainly in the U.S., but also in many other nations— depletion rates are now at the point where increasing effort in terms of energy inputs and cost of extraction are required but with relatively less output.  Overcoming depletion requires additional reservoirs must be continuously discovered and additional infrastructure and new wells constructed.

The gas and oil industries are on a treadmill of increasing rates of exploration, drilling, and capital investment only to maintain production and reserves.  Depletion rates are now more important in determining supply than consumption or discovery rates.  In this regard, the math is revealing: a doubling (100% increase) of additional reserves is required to make up a 50% decline in existing reserves.  Additional use due to growth must be layered on top of depletion rates.

The primary reasons are the increasing difficulty in obtaining natural gas from existing wells, newer fields are small, and that the quality of the gas itself is declining.  The large inexpensive gas fields are in significant decline and replacement fields have lower yields.  In the year 2000 the number of wells drilled increased by nearly 45% with negligible changes in the production of natural gas.  Production costs however, are rising in tandem with increasing exploration and drilling activity.119  The fact that very high natural gas prices produced substantial increases in drilling activity but could not result in relatively higher production demonstrates that less productive and marginal fields are being pumped.  One ramification of this development, according to Simmons International, is that “some E&P [exploration and production] companies have been vigorously pursuing acceleration projects over the past year – quick hit, small reserve potential prospects designed to capitalize on high front-end commodity prices and generate maximum returns.”120  The industry’s position is not an enviable one.  Pricing creates incentives, however with expensive production a circular price-production sequence unfolds.

On the other hand, extraction must be maintained or the economy will suffer along with its political and social implications.  Growth and energy demands appear to be stressing natural gas availability years before declines are clearly evident.

The small and expensive “wildcat” wells soon have their inventories piped away.  The high prices California consumers enjoyed were in some measure due to the development of these high cost marginal reservoirs.  More importantly, the drilling of marginal wells suggests a floor for prices, that minimum prices in the $4 to $5 range are required to bring additional and marginal fields into production.  Because of the high depletion rates and costs of new natural gas additions, baseline natural gas costs would be more than $5.00 even in relatively mild demand periods.  Prices will steeply rise in lockstep with demand.  It implies that as this is written (summer 2003) natural gas prices must increase between 25% to 50% or more, to stimulate increased drilling if production is to be maintained.  The revised price floor for natural gas could now be in the $5 – $8 range, a doubling or tripling of normal prices.

The recent yet minor increases in natural gas pumping are not due to success in locating significant new gas reserves but to improvements in seismic technologies and advanced drilling techniques, primarily horizontal drilling.  These modern technologies optimize exploration and temporarily increase yields, yet neither technology can increase reserves a basin contains.  As Dr. Campbell suggests, another way of viewing these technologies is that they increase the rate of exhaustion.  Thus, growth in reserves is more an outcome of changing statistics due to technology than locating unexpected fields.  Production has been maintained by sophisticated engineering resulting in large increases in smaller wells, doubling their numbers since the mid-1970s.

Figure 14 is a colorful chart illustrating the volume of natural gas from wells prior to 1990 and from wells placed into operation each succeeding year.

Figure 14:  Depletion Rate – Natural Gas Production by Fields 1990 – 2003


Courtesy of EOG Resources.
See at < http://www.eogresources.com/investors/stats/us_decline_curve.jpg >.


The U.S. historically averaged a depletion rate of about 0.5%.  Depletion rates have now increased to where depletion currently is a multiple of previous rates.  Figure 14 reveals the successes of additional wells discovered each year from 1990 to 2003 and the steepness of the ensuing decline.  The steepening slopes of the upper portions of each year’s drilling success reflects the increasing rates of depletion.  A surfer might see the similarity of the left to right sequence as the building of a wave.  The steepening slope at the year 2003 is the surfer’s most exciting moment.  The surfer at this point would either continue sideways in the tunnel or break it off by going back up as the wave breaks.  Changing directions is the metaphor’s intended message.  Of interest, the total Bcf trendline (top trendline) shows that U.S. natural gas production peaked in the 1997 – 1998 period.  The chart also vividly demonstrates (lower blue or gray area) that prior to 1990, large reservoirs provided the bulk of natural gas —over 50% as recently as 1990.  Today, the proportion is approximately 15%.

The thinning of the individual trendlines also indicates the rate of annual volume declines.  Clearly, recent wells are small and rapidly depleted.  The 28% depletion rate given in the chart title implies the productive life of class 2003 natural gas discoveries will average approximately 3½ years.  Interestingly, it also suggests the extent of increasing exploration efforts undertaken in order to maintain existing supply and that the industry is running full-blast just to maintain existing supply.

It is difficult to comprehend the effort required merely to replace existing sources when current natural gas fields are depleting at rates of 15% – 40% each year.  The U.S. shortfall is made up from increasing the volume of imports and by interrupting industrial consumers.  The irreversible and disturbing trend of declining domestic reserves with offsetting imports implies ratcheting higher prices and pressure on the U.S. dollar.

In March of 2001, Matthew Simmons, President of Simmons International, testifying before the House Subcommittee on Energy and Mineral Resources commented that the increase in exploration and drilling effort has produced relatively few reserves.  In his testimony he said “natural gas supply is particularly threatened by increasing evidence that the current supply base is now declining at a rate where half of the current supply will be consumed by 2005.”121 (Emphasis added.) This implies that 50% of additional natural gas (about 25 Bcf per day) needs to be discovered to keep pace with depletion (growth is additional).  The level of decline implies an average U.S. depletion rate of at least 15% that newly discovered sources of natural gas have useful lives between 3 and 6 years.

Recent data indicates that despite substantial increases in drilling activity, there remains a squeeze on the natural gas supply.  “Depletion is no longer the forgotten factor in the supply and demand equation” states an insightful study of natural gas drilling and reserves.  This Simmons & Company report shows that beginning at the 2nd quarter of 1998 through the 2nd quarter of 1999, despite increases in drilling activities, production showed a 4.8% decline in reserves.122  Simmons echoed the identical concern earlier at the 1998 Society of Petroleum Engineers Asia-Pacific Oil & Gas Conference.  He noted that depletion rates “in excess of 30%” have been the experience over the last several years and Canada has seen even higher depletion rates.123

“Natural gas inventories are near all-time lows” states Matthew Simmons then asks is a “natural gas train wreck ahead?”  Research from Simmons International concludes that the “U.S., Canada, UK, Indonesia, Netherlands, and Russian gas supply is in decline”.124  In other words, of the world’s total natural gas producing nations, 61% have peaked and are now in production declines.  Depicted in Figure 15 in the following page, the current world shortfall is approximately 8 Tcf or 444 Bcf per day and declining at a rate of 10% annually.125  The report states that year over year, U.S. production declines approximate 1 – 1½% per quarter, or between 5% and 7% annually.126

The worldwide natural gas decline and its unrelenting nature is illustrated in the following graph.  The down-sloping dotted trendline represents the available world’s volume of natural gas while the upward rising solid line represents demand forecasted to grow at 10%.  The difference between the two lines is labeled the “GAP”.  The GAP is the potential natural gas shortfall if growth is not restricted.  It is interesting to note that the GAP assumes a very modest rate of consumption growth, approximately one-third the actual growth in the U.S. over the past decade.

Figure 15:  World Natural Gas Decline vs. Demand 2001 – 2030 


Graph courtesy of Simmons & Company International.124


The limits on natural gas, as indicated in Figure 15, are being felt on other continents as well.  India, for example, is confronting the identical resource impacted fertilizer problems as in the U.S.  India is forecasting serious reductions in di-ammonium phosphate in 2003 – 2004 and 2004 – 2005.  New Delhi reports that the “gap between demand and supply will keep increasing with course of time” and will compel importing large quantities of urea to meet fertilizer and food goals.127  The shortage explains why India is forming a natural gas joint-venture in Iran and the construction of an Iraq-Azerbaijan pipeline.128

Despite the hyperbole, there could be as much as a 20% (approximately 10 Bcf per day) worldwide natural gas shortfall.  The approaching U.S. shortages are likely to be combined with increasing pricing volatility.129

In brief, with current consumption of about 23 Tcf of natural gas each year and with only the existing and plants planned this decade, the U.S. will fully deplete its total proven and estimated U.S. natural gas supply within 5 to 10 years and optimistically (finding large unknown discoveries and inexpensive production) within 10 to 15 years.  Any additional increase in use will reduce even that generous time horizon.  The forecasted 60% increase is unlikely to be realized, and if it is, won't last long.

More generous estimates are more frequently reported in print media.  Yet, the Wall Street Journal in a February 2003 article said that “the U.S. is now facing a shortage of natural gas that could last for years, and the impact is just beginning to ripple through an already ailing economy”.130  In terms of affecting the national economy, repercussions of diminishing natural gas supply were evident last year and this year.  For the first time ever —March 14, 2003— the lower operational limits of propane storage facilities were violated and some natural gas storage reservoirs were depleted beyond their physical recharge ability.  The effect will be to reduce the life and storage ability of certain reservoirs.  If only average, the coming winter 2003 – 2004 promises to be a possible precursor of the future.

There is an unusual (although anecdotal) source of support for an approaching natural gas supply problem: Saudi Arabia.  This oil rich nation has contracted with Chevron and seven other large companies to convert domestic electric utilities from oil to natural gas.  In this way the Saudis will wean domestic use from oil to natural gas.  In this manner they will also be able to sell a little more oil and increase sales of expensive (and profitable) natural gas in liquid form to natural gas craving nations.131

The following chart shows U.S. natural gas production and depletion rates including discoveries of additional reserves, projected to the year 2010.

Figure 16:  U.S. Natural Gas Production & Depletion, 2001 – 2010 

 
Chart courtesy of Karl Davies, Davies & Company
61


Figure 16 is similar to the trendline in Figure 14 (p95) but projects production through the year 2010.  The steepening slopes representing depletion rates illustrated in Figure 14 is evident in Figure 16 by the steadily declining height of the graph bars.  Because of the struggle to discover additional supply and that the discovery estimates are from the EIA, it is possible the additional discoveries (upper, light block) seen in Figure 16 are optimistic.

Joseph P. Riva, Jr., researcher for the Congressional Research Service of the National Council for Science and the Environment states that increases in drilling are doubtful because the resource base is diminishing.  In describing the world natural gas drilling situation, he wrote,132

In 1993, an estimated 12,376 wells were drilled in search of natural gas, compared to between 21,000 and 27,000 wells per year in the late 1970s and early 1980s. Since that time, the domestic fleet of drilling rigs has decreased by 65 percent, and only a fraction are drilling at any one time. In 1992, the active rig count fell below 600 for the first time since record-keeping began in 1940. Also, the fewest number of seismic crews were actively exploring since that count was first recorded, only one-quarter the number active in the mid-1970s. The depressed nature of the petroleum industry is further illustrated by the loss of 450,000 jobs in the past decade. Rising oil and gas prices will encourage drilling, but even at the peak of the past drilling boom, when oil prices exceeded $30 per barrel and/or gas prices $2.65 per thousand cubic feet, less than 27,000 gas wells were drilled. Some of these gas prospects were of marginal quality with unrealistic financial projections and success ratios estimated.

In discussing the economics of additional drilling Riva concludes,133

As large gas accumulations became more difficult to find, the negative results of such programs diminished the appeal of gas exploration as an investment. In an industry that depends upon both borrowed and investment funds, especially as the major companies move overseas, it may be difficult to finance the drilling of large numbers of gas wells.

Natural gas prices in 2003 have held at record high levels during the “low” demand spring period because of “uncertainty in domestic production—now with 929 rigs at work, compared to about 1,100 the last time prices were this high in 2000 and 2001”, states a recent energy industry analysis.134  Another study of the situation in the Gulf, reported that that new prospects are smaller than earlier finds and require 40% deeper drilling, significantly raising costs.  In sharp contrast to the Minnesota position, analysts concluded that drilling activity had tripled in the previous two years but gas production declined nevertheless.  Gas production, the analysis concluded “in the next 5 years may go down big.”135

A recent Simmons & Company report states “U.S. natural gas volumes continue to struggle in spite of sustained record rig counts supports our view that deteriorating well quality is a factor that diminishes the 'yield' of incremental drilling.”136  The diminished quality of the natural gas fields is evident in the depletion rates in the Gulf of Mexico fields.  Those discovered in 1970 declined at the rate of 17% while the newer fields declined at a 49% rate per year.  In the mid-1980s about 6% of oil and 0.8% of natural gas was extracted from deepwater wells.  Reflecting the decline sequence 15 years later, in the year 2000 about 52% of all Gulf oil and about 20% of gas were extracted from deepwater wells.  The more numerous smaller wells are no longer significant producers.137

Industry professionals are not the only ones that have become concerned at rates of depletion.  Consistent with data from David L. Babson and Company, an investment advisor firm, research from the big financial company Morgan Stanley stated that the “decline statistics are striking: production from new gas wells fell more than 40% during the first year alone”.  Answering the Minnesota Energy Planning report, on average, production per gas rig is down 60% since January 1999.”138  Lack of resource opportunity is the essence of Figures 14, p95, and 16, p98.

Mirroring the research by David L. Babson & Company, Brad Foss writes that the U.S. drills 50% more gas wells, but that the rate of decline in existing wells exceeds the rate of drilling.  He continues saying that this pits “industry against nature in a Sisyphean struggle” to maintain natural gas supplies.  Bob Allison, CEO of the big American energy company Anadarko Petroleum, states the U.S. has a “23% annual decline” in natural gas production.  Forgiving his metaphors, Foss says that the U.S. will need “tons and tons of these (wells) to help dig our country out of the mess we're in”.139

Texas is the largest U.S. producer with about one-third of total U.S. production.  Extensive research on gas wells in Texas conducted by Petroleum Engineers Gary S. Swindell & Associates found that “although initial rates have actually improved in recent years, the rates of decline in production have dramatically changed for the worse.”  In wells drilled in the 1970’s and 1980’s first year declines averaged 20% and those drilled in 1998 and 1999 averaged declines of 55%.  The five-year decline rate exceeds 15% per year.  “In the late 1980s the first year decline rate began a sharp increase to the present 56% per year and the five year average decline also increased to 28% by 1994”, states Gary Swindell & Associates.140

Suggesting areas of potential profit opportunity —and cautions regarding future prospects― David L. Babson & Company reports that during the 1990s producers were “extracting reserves profitably in a much shorter period than a generation ago.”  Unlike earlier wells however, due to high depletion rates, today’s wells produce about 40% of their total inventory in the year after drilled “in effect, more efficient straws are sucking on smaller cans of soda pop.”  Despite the increase in drilling, natural gas reserves today are at 1991 levels.141

The industry is beginning to reel from the reserve changes.  Industry exploration and production summary reports released in February 2003 document that American production is “continuing to decline rapidly, with many companies reporting that they were unable to meet Q3 production targets and lowering future targets – both for Q4 and for the next calendar year.”142

Acknowledging that the production of natural gas has been essentially stable since 1995, the Industrial Energy Consumers of America in partnership with 31 other organizations voiced concern to the Administration in January 2003 that since 1998 energy prices were a major reason the manufacturing sector lost two million jobs.  After studying the issues, the IECA urged Congress to support, “clean coal technology, the ultimate solution for power generation”.143

It is now clearer what Matthew Simmons had in mind when he described the looming U.S. energy situation as the “Perfect Energy Storm”.  The 500 hundred-year supply claim is no longer heard!  Indeed, “five more good years” could now be the optimist’s chant.

In an attempt to raise supply expectations for the public, the “Minnesota Energy Planning Report” uncritically reported that “the rig count is a favorable indicator of natural gas supply.”144  The data indicate the opposite viewpoint is correct.

Let’s review the rig count arithmetic to examine the validity of the Minnesota Commerce Energy Department report.  In order to maintain current production rates, 6,100 new wells were necessary in 2001, up from 3,566 in 1999 and 4,580 in 2000.  However, despite substantial increases in drilling, the reserve to production ratio has fallen from nearly 13 years in 1970 to 7.4 years in 1999.  This decline (economists take note) has come at a time of significant gas price incentives.  In terms of gas replaced by new wells, the production rate declines show that since 1990 when about 9% of daily production was from new wells, today it is over 15%.145  The increasing trend demonstrates the deterioration in field opportunities.

In yet another study, Simmons International reports that between U.S. and Canadian data there has been deterioration in average natural gas well productivity and prospectivity (reserve potential to use Simmon’s term) over the last decade.  “Diminishing reserve potential of all fields must be combined and accentuated because of the declining reserves of higher quality producing fields.”  The combination indicates that the decline in reserves and reserve potential exceed the discoveries due to exploration activities.  This is reflected in the number of drilling rigs relative to well success.  Since 1990, drilling rigs increased by about 7% per year with nearly a 70% rate in the last two years.  In contrast, over this time period domestic gas production grew at a meager rate of about 0.6%.  In addition, the large number of drilling rigs currently in operation has not been seen since the 1980s, yet there has been insignificant additional reserves found.146

In response to escalating prices, worldwide gas and oil rigs peaked in 1982.  Suggested by Figure 14 (p95) the number of producing rigs today continues to decline regardless of price.  The largest rig developer, Baker Hughes, indicates that the year ending November 2002, worldwide rigs declined 6.6% and in the U.S. down 7.9%.147  The underlying reason is that profitable drilling opportunities are diminishing and higher prices cannot completely offset the physical realities.

Increases in individual company reported reserves have not come from exploration and discovery but from acquisitions and former oil rigs.  It is also probable significant increases in natural gas drilling are from conversion of oil drilling rigs.  In brief, in recognition of the futility of increasing oil exploration, the number of productive new rigs has remained static or declined for nearly two decades.

Alerting investors to other potential profitable avenues, the purchase or merger of other resource rich firms seems the preferred method to increase an individual firm’s reserves.148  Lack of reserve opportunities underlies the ongoing industry mergers and purchases mania for assets of other resource companies.  Foreshadowing the future, consolidation represents the lack of industry opportunities and the unremarkable securities market for companies involved in drilling.

Minnesota’s energy reporting is surprising.  Despite modern technology petroleum companies in recent years have not been able to locate significant numbers of large, profitable fields.  Reflecting the lack of discovery and development possibilities the “Wall Street Journal” reports that oil companies are using their substantial accumulated cash to buy their own stock.  Exxon-Mobil, for example, purchased $2.35 billion of stock in 2000 and $1.44 billion in the first quarter of this year.  Shell spent $4 billion in the first quarter.  Perhaps not generally understood by public investors, when a company purchases its securities the company is literally undergoing the process of liquidation ―exchanging investor assets for cash.  Interestingly, the “Wall Street Journal” reports that Stephen Hodge, Shell's finance director, says “the stock buybacks are a 'safety valve' that prevents too much cash from building up.”149  “If the industry had the projects, this cash cache would be spent,” says Larry Andersen, a vice president for Chevron-Texaco, “but there's not a lot of opportunity.”150  Despite intense efforts, U.S. natural gas declined nearly 2.5% in the single year of 2000.151

Summarizing the issues, because demand in growth is at least 10% annually and depletion is in the 15% range and increasing, natural gas reserves must increase at least 25% every year merely to remain even.  It is unlikely this level of discovery can be sustained over any but a limited period of time.  The facts are that discovery is minimal and there is little if any possibility of reversing the trend.

Throughout U.S. history, energy was abundant and reliable due to the original treasure chest of fossil fuels.  However, as natural resource inventories decline and the transition to other energy sources gets underway in earnest, the reliability of the system will decline in concert.  When Minnesota considers balancing the needs against the costs, recall that Minnesota is at the termination of transportation and resource lines.  The wiser approach will be to reduce growth and the growing demand for energy.  Perhaps the silver lining in the precarious natural gas situation is that it should help prepare authorities and the public for the essential economic and social changes due to peaking and decline in oil production.


Blackout of August 2003

The Blackout of 2003 was predictable ―due to the coming together of several very ordinary factors― high demand, deregulation’s emphasis on short term profit, and transporting electricity over long distances.  The New York (actually beginning in Ohio) and eastern blackouts follow those in California, and, at approximately the same time or soon afterwards, overseas in London, Australia, New Zealand, Italy, Finland (Helsinki), Malaysia, the Philippines, and to some extent in France and Sweden.

It’s unimportant if the eastern U.S. incident began from a squirrel chewing a line, a transformer exceeding its capacity, or a poorly timed grid switch, the system was destined to fail.  The system is at capacity and even minor malfunctions imply potential system-wide breakdowns.  The reason the grid collapsed at about 4:00 PM (Eastern Time zone) is that hour is when all time zones in the country were operating ―coast to coast satisfying peak commercial and non-commercial demands.  In the U.S., peak demand is a function of hot weather and air conditioning.  With its low level of air-conditioning, Canada was a spectator drawn into the turmoil.  With the very mild temperatures throughout the 2003 summer, “peak” demands were comparatively low.  Even on the Thursday of the breakdown, nationally the weather was seasonal.  If nationally the summer had been unusually hot, local brownouts and blackouts such as occurred in California in 2001 were probable.

Other than hydropower, once large baseline generators shutdown, they require electricity to re-start.  Nuclear plants require another coal or natural gas generator to begin operating.  Those highly acclaimed eastern windpower projects demonstrated their characteristic unreliability during the blackout —of little help— producing little electricity.

Under government regulation, a generating safety reserve of 15% or more was required and large baseline plants were constructed to ensure system reliability.  The assumption was that the system should be able to manage serious extremes of weather or grid malfunction; today’s de-regulated capacity or transmission safety margin is scarcely adequate.  As in factory production, under deregulation, “just-in-time” delivery is the construction pattern.  Smaller, often natural gas peaking, generating facilities were constructed annually or biannually to pace growth and demand.  The safety reserve was essentially eliminated to improve profitability; safety margins and grid risk were transferred to the consumer.  Matthew Simmons says the safety reserve under deregulation was considered by the industry (and regulators) as a “massive glut” of excess electricity.  In the first five years after deregulation was implemented in the 1990’s Simmons states that capacity increased 4% and in the next five years only 2%.152  Over the same decade demand increased approximately three times the 6% capacity increase.

Proponents argued under deregulation that it was efficient and cheaper to transport large quantities of electricity including electricity from natural gas peaking plants across great distances.  Competition at the wholesale level was assumed sufficient to moderate consumer costs.  In this manner, they allowed, fewer baseline generators would be necessary.  Although fewer baseline generators would be necessary, the same quantity of demand must be met ―only now from smaller facilities.  Reducing transmission needs, the smaller facilities are frequently sited closer to demand.  However, it is the large baseline generators that supply the system grid and under deregulation their generation is increasingly transported great distances.  Transporting electricity is expensive —losing approximately 10% of the electricity delivered.  It also suggests the system is more vulnerable to interruption.  Peak periods are those periods of highest system vulnerability.  There is no surplus electricity and no pragmatic reason to transport electricity long distances.  Continuing growth and the road to the Olduvai Gorge suggest this policy is more than ill-advised.

In testimony before the United States House of Representatives Subcommittee on Energy and Air Quality October 10, 2001, North American Electric Reliability Council’s David N. Cook, General Counsel, said the system is “now being used in ways for which it was not designed”, that utilities that “formerly performed all reliability functions for an area is being disaggregated”, that some companies or organizations “appear to be deriving economic benefit or gaining competitive advantage from bending or violating the reliability rules”, and that construction “has not kept pace with either the growth in demand or the construction of new generating capacity, meaning the existing grid is being used much more aggressively.”  NERC recommended the solution was to continue the voluntary system guidelines enforced by an industry organization but with FERC oversight.  The blackout of 2003 came nearly two years after this testimony was submitted.  Apparently its recommendations were followed.  Under this system electricity is encouraged to be purchased by large users while discouraging additional capacity.

The irony is that all expenses and assets used to provide consumer electricity is allowed in regulatory ratemaking and which an investor rate of return is applied.  Apparently the regulated investor return of 12% – 15% was inadequate; higher investor rates of profitability were evidently anticipated from deregulation.

The entire U.S. electrical system’s demand and supply requirements are being run on high-risk razor thin safety margin made worse by the use of natural gas generators and the system’s grid unreliably connected over great distances.  In addition to human or mechanical error, the system is most at risk when hot or cold weather extremes create maximum load.  The blackout appears to be a textbook example.  Because weather was essentially normal across the country, shortages apparently did not reduce electricity generated by natural gas during the blackout.  The following section discusses natural gas supply and storage during the winter when natural gas demand is highest.


Storage & the U.S. Winter of 2003 – 2004

Due to the natural gas industry’s inability to increase production or infrastructure, reliance on U.S. and Canadian storage during periods of high demand is required.  The high demand periods requires that up to one-third of natural gas consumption come from storage (primarily old natural gas caverns).153  Maximum U.S. storage is approximately 3 Tcf, 13% of annual consumption.  Under normal historical patterns, the industry was able to recharge the reservoirs at a rate between 4.5 and 7 Bcf per day from late spring to fall.  Absent significant demand reductions, the industry is now able to only add to storage 2 – 3 Bcf per day and still provide for normal daily consumption.  Because of the increase in natural gas fired generators, summer peaking plants, and growth, there is insufficient gas to meet high demand —generally winter periods but also in summer— as natural gas peak generating plants are constructed.  The result has been headlined by the Rocky Mountain News: “disastrous fuel shortages forecast”.154  U.S. energy representative Tobin Smith says that due to declining production and high demand that the U.S. will be “2 billion cubic feet of gas per day short” and that natural gas prices will at least double to the $10 to $15 level.  This, Simmons International cautions, “sets up a ‘nightmare’ for natural gas” next winter (2003 – 2004).155  In Minnesota and the U.S., electricity generation using natural gas has now reached the level where —under normal circumstances— it has become impossible to fill storage reservoirs in the 214 days available for recharge.

It would be physically demanding, prohibitively expensive and require additional pipelines to match required storage of more than one-half trillion cubic feet plus annual demand growth.

Natural gas problems during the winter of 2002 – 2003 were a glimpse of the 2003 – 2004 winter to come.  Canada’s official source of energy data, Enerdata, reported the week of February 21, 2003 that gas in storage was down to 18.2% of capacity compared to 64.2% the already weakened previous year; storage in western regions over the same period was down to 31%.  Note that the line dividing the western and eastern Canadian natural gas regions is above the Minnesota – North Dakota border.  Dropping rapidly, the forecast was for supply to fail demand soon.  Early winter 2003 reports that independent electricity generators using natural gas were interrupted and output reduced because of lack of adequate pipeline pressure.  Reuters reported that Ontario authorities had begun to ration supply and urged residential consumers to reduce heating during the day.156

Natural gas restrictions were implemented during the 2002 – 2003 winter when U.S. storage fell to the 700 – 800 Bcf level.  During the second week of March, 2003 the storage low registered just above 600 Bcf of the 3.0 Tcf maximum.  Because delivery is uneven across the nation, restrictions are implemented at squeeze points as storage falls below the 28% ballpark and spreads as it approaches the 20% level.

In a late February 2003 cold-snap — in an otherwise milder than average winter— Duke Energy’s eastern pipeline issued a system-wide alert restricting consumption due to high demand and insufficient supply.157  The consequence of this development was that across the country numerous interruptible consumers were interrupted.  In some instances, plant shut-downs were necessary.  The largest anhydrous-ammonia fertilizer producing state, Louisiana, shut down its fertilizer industry due to a lack of natural gas; Minnesota shut down its anhydrous-ammonia industry the week after Louisiana.  Large numbers of manufacturers in Eastern Canada and adjacent U.S. plants were “timed out” temporarily because of low pipeline pressure.158  In spite of interrupting natural gas users and literally shutting down the fertilizer industry in late February and early March, the winter of 2002 – 2003 left the storage reservoirs at record lows ―approximately 600 Bcf.

High prices and supply interruptions forced closure or reductions in output in several sectors of the economy ―primarily the chemical and manufacturing sectors.  Because the output of the chemical industry affects numerous downstream industries, the effects of last winter will become evident throughout many areas of the economy as the year progresses.  Indeed, due to high natural gas prices at least one U.S. fertilizer plant filed for bankruptcy, ceasing operations in late spring of 2003.159  These shutdowns are consistent with the following chart showing the approximate price of natural gas at which power generating and chemical and fertilizer plants begin to shutdown.

Figure 17: Price of Natural Gas & Plant Shutdowns


Chart courtesy of National Petroleum Council160

 

In addition to milder winters (for several years) last winter’s Natural gas shortages came at a period when the U.S. economy was limping along and Canada’s economy weaker still.  A return to normal weather and economic activity suggests natural gas supply will bump against production limits more frequently and over longer periods of time.  Noted above, natural gas will constrain economic growth.

Embedded in the Table 9 (p89), for example, is the cement and steel industries.  Natural gas is used to heat limestone to 1,800º F in order to produce the basic unit of cement, lime.  It’s an industry highly dependent on abundant natural gas and without which the building of the infrastructure changes to accommodate the energy transition will have difficulty.  Further, the steel industry is a prodigious consumer of electricity generated from natural gas.  Wheeling-Pittsburgh temporarily closed its Ohio plants and Steel Dynamics in Indiana reduced its operations to nighttime production in February 2003 due to high prices and volatility of supply of natural gas.  Setting the stage for increasing offshore competition, selling prices were increased.161  The relatively short-lived price spike this winter quickly raised industry prices.  Research from Goldman Sachs economists found as a result that natural gas intensive sectors declined 0.4% in January 2003 at a time overall industrial output was increasing 0.7%.162  Part V, Tables 18 (p267) and 19 (p268) of this paper suggests that the energy transition increasing coal and coal gasification begin plant construction in earnest.

The probability is that under existing growth programs these restrictions are only the initial installment of sobering natural gas supply variability.  To fill the reservoirs for the winter of 2003 – 2004 will require pumping 2.5 Tcf into storage.  3 Bcf is the normal maximum daily addition unless summer peaking or commercial use is restricted, indicating only 642 Bcf will be added, a winter deficit of 1.8 Tcf.  If additions to storage of 6 Bcf per day on average were accomplished, then 1.3 Tcf would be added to storage; nevertheless, under these circumstances it leaves a national deficit of 1.2 Tcf, 40%.

Table 10 documents the alarming storage and production deficit at late winter 2003.  The degree of drawdown at more than 47% below the 5-year average is overshadowed by the 52% decline from current production.  It is evident that even in this overall mild winter the system had exceeded it resource limits.

Table 10:  Winter 2002 – 2003 Natural Gas Storage Data 

Period

In Storage (Bcf)

Drawdown

March 7, 2003

  721

-117

Year ago

1,728

 

Five year average

1,376

% change -47.6

Stocks from production

Five year average

  439

 

March 7, 2003

  211

% change -51.9

EIA weekly natural gas storage statistics, < http://tonto.eia.doe.gov/oog/info/ngs/ngs.html >.


Canada is in a similar storage situation.  Natural gas storage was 789 Bcf at the end of April, 2003, 52% below the level last year.  The EIA reports that this is “the lowest aggregate inventory level for the end of April recorded by EIA …Eastern and producing regions are at record lows.”163  High spring through late summer 2003 demand for current consumption and recharging of storage facilities implies greater price volatility throughout the period.  It also suggests that the cold Midwest states will suffer very high heating costs, and that natural gas electricity generation in the Western and South Central states could have less reliable natural gas supply combined with very high cost.

Fully aware of the possible repercussions, the natural gas industry used unprecedented efforts this past summer to fully charge every above and below ground storage apparatus across the country.  Indeed, postponing all normally scheduled maintenance, Minnesota energy systems were operating near their maximums all summer.164  Higher natural gas prices this summer (2003) have resulted in (to use EIA’s terminology) “demand destruction” by manufacturing.  It has been the fertilizer, chemical, and aluminum industries that have carried the brunt of high summer prices.  Dow Chemical shuttered its petrochemical plant in Baton Rouge, Louisiana, and transferred its production to its European plants.  Canada’s Potash (Saskatchewan) Corporation nearly eliminated fertilizer production this summer and instead —and sold some its high priced natural gas supply!  The increase in prices and plant shutdowns is the primary reason extraordinary volumes have been pumped into storage vessels this summer and fall.  The above average weekly volume increases pumped into storage closely track the volumes forgone due to “demand destruction”.  The increases are not coming from increased natural gas supply.  The reduction in demand has resulted in the ability to increase volumes pumped into storage facilities at record levels.165

High prices will be carried over to this and following winters from the previous winter and current summer periods.  Simmons & Company state that in combination with the serious rates of decline in new and existing wells, reduced natural gas prices can be maintained for only brief periods due to increasing demands.  In the words of Ryan Zorn, et al, “deliverability constraints will further tighten in a relatively short time frame”.166  These “constraints” will flow through to consumers in two ways.  First, consumer prices will be significantly higher.  Second, there is an elevated probability of reduced natural gas supply during critical mid and late-winter periods.  Because of growth and significant increases in natural gas electric generating plants operating during the summer there is no excess capacity.  Minnesota’s planned conversion of several old coal fired plants to natural gas comes at the most inopportune time.  This “excess capacity” was previously used to charge storage reservoirs over the summer season.  In other words, heading into winter heating season, reservoirs are unlikely to be completely filled and consumer prices on $3 to $4s.  Prices will rise in lockstep fashion as released in February 2003 illustrate the will include high priced gas consumed during high demand periods, including carryover from the previous winter.

Consumers during the 2003 – 2004 winter are likely to experience high carry-over prices embedded in storage plus the full burden of still higher priced high demand winter gas.  Unless electricity boiler resource generating policies are promptly changed, the situation is likely to deteriorate in subsequent years.

Minnesota and the U.S. have reached the point in natural gas supply where they are literally at the mercy of the weather.  The unsettling situation is that even with normal winter and summer 2003 temperatures natural gas could become a national uncertainty during the winter of 2003 – 2004.  A mild summer —a summer with few 90º F days, will reduce summer natural gas consumption and help recharge storage reservoirs; an average summer sets up a serious natural gas production and winter heating dilemma.  Last winter demonstrated that even normal winter weather can create energy supply imbalances.  The situation will worsen over the years if a hot summer follows an average winter.  In that instance, because of extensive use of natural gas in summer peaking electricity plants the natural gas supply system will be unable to recharge storage reservoirs during the summer months and supply will remain at dangerously low inventory levels going into the cold winter months.  If that were to occur then even normal or relatively mild winter temperatures will produce crisis level supply disruptions.  Ironically, companies who purchased natural gas generators believing it will assure a reliable source of electricity or heat during periods of uncertainty will be requested to use another energy source or shut down.

The paper now turns to a discussion of the future sources of natural gas: Gulf of Mexico, Canada, the Canadian tar sands, ANWR, and liquefied natural gas (LNG).  The reality is that supply will be significantly less than equal to demand and short lived.  Optimists believe alternative energy sources are able to replace declining reserves from existing baseline energy sources and provide for growth in coming years —even at substantially higher consumer prices.  It is a position of faith.  Discussed next is an examination of the annual report of Chevron-Texaco.  Industry reports indicate the scope of the industry’s problems are reflected in actual operations.  The final part discusses pricing, economics, and production, examining the contention that increasing prices will increase production sufficiently.  In the contest between economics and geology, geology wins.


Deepwater Oil & Gas: Gulf of Mexico

The remaining sizeable U.S. oil and natural gas fields are found in Alaska and the Gulf of Mexico.  The shallower Gulf fields —less than 1,000 feet in depth— are relatively small, average about 75 million barrels, and have been pumped for many years.  As noted above, the basins are in steep production declines.  Because the shallow larger fields were well known, they were easy and inexpensive to locate and commercialize.  The reason for the delay in developing the remaining deeper basins were high costs and technological —environmentally suspect and difficult to drill safely at the great depths required.  This is the region where federal authorities believe there are 200 Bcf of natural gas to be discovered.  The larger and less pumped deep-water sites are now under development and production.  The gas methane hydrates briefly mentioned earlier frequently lie encapsulated in ice at depths of 15,000 feet.  Mining these deposits will put the sea environment at substantial risk.  In addition to the substantial financial and technological drilling hurdles to overcome, the methane gas is released when the ice is melted by drilling or other means.

The largest discovered Gulf of Mexico field is Crazy Horse in the Boarshead Basin located 125 miles southeast of New Orleans.  It has estimated reserves of one billion barrels at a water depth beginning at 1.25 miles.  While searching for oil and measuring the reservoir, the field has been drilled more than 5 miles deep.  The primary owner is BP with Exxon-Mobil holding 25% ownership.  Sales are to begin with a phased-in plan beginning by 2005, from a floating production facility that produces 250,000 barrels of oil per day.  The plan is to obtain three to four times the initial volume of production.  Although the size of the field appears impressive, its inventory amounts to less than two months of U.S. or twelve days of world oil use.167


Oh! Canada?

The U.S. has a perplexing natural resource attitude toward Canada and Canada toward the U.S.: in the face of looming domestic resource concerns will Canada discover more natural gas and oil in the next decade than discovered in all its exploration successes to date —and export it to the U.S.?

In contrast to the technological hopefuls, Canada is not in a position to provide the U.S. significant long-term natural gas supplies.  Nor, it must be stated, is Mexico with its alarming population problems and considerably fewer remaining energy reserves.  A new research report by Canadian firm C.D. Howe Institute stated that “the era of sending additional oil and gas supplies south is likely ending”.168  Another recent and equally ominous research report from Canadian consultants Purvin & Gertz concluded that “gas production in Alberta, home to 85 per cent of Canada's daily output, has peaked.”169  In the recent natural gas report, the increasing rate of decline in Canada’s natural gas production is evident.  The longer term data show a 4% decline over the prior year while short term production fell 12%, averaging more than -11% in total.  Not illustrated in Table 11 is the most recent data showing a 6% short term decline.  Some of the current consumption decline may be due to restricting consumer and commercial demand to enable winter storage.

Table 11: Canada Production Decline 2002 2003, June

    Period

  June 2003

  June 2002

% Change

Long term

50,508,368.0

52,650,530.8 

      -4.07%

Short term

226,222,548.7

259,744,410.1

    -12.01%

Total

276,730,916.7

312,394,941.0

    -11.4%

“Detailed Monthly Statistics 2003”, National Energy Board, Canada.
See at < http://www.neb.gc.ca/stats/expgas/index_e.htm#Exports >.Gigajoules.


Canada is the single largest exporter of energy to the U.S.  With 60% of Canada’s oil production exported to the U.S. and over 15% of U.S. natural gas imported from Canada, the U.S. is increasingly dependent on Canada.  Canada currently exports over half of its natural gas production to the U.S.  However, natural gas reserves in Canada are estimated at about 250 Tcf.  Using the consumption factors mentioned above suggests a potential Canada supply of roughly 8 years of U.S. consumption.  Those rates of extraction and export also assume Canadians have little use for their own natural gas!

Gwyn Morgan, CEO of Alberta Energy Company, Canada's largest natural gas company, echoed those comments saying “there is such a tight demand and supply situation for gas, there isn't a lot of gas around… I don't think this is a cycle … this is a new world for natural gas.”170  The maturing reserve basins are reflected in the number of new gas wells.  Identical to the U.S. situation, Canadian producing companies must drill substantial numbers of wells to maintain current production levels.  Reminders of the oil situation, depletion rates of new wells approximating 25% per year are the reason big Canadian Natural will drill nearly four new wells this year for each well drilled the previous year, 600 vs. 160 in 2002.  Helping to explain Canada’s supply and storage shortfall described in the previous section, output is expected to decline 4% this year after falling 3% in 2002.171

Figure 18 in the page following, clearly demonstrates that current natural gas production (upper blue square line, gray squares with open space in black & white) has exceeded discoveries for three decades (solid red or dark gray line) and that the situation is now rapidly deteriorating.  Despite enormous government and industry efforts, discoveries are declining at the astounding rate of approximately 12% every year.  The data document that a serious Canada & U.S. natural gas supply situation is rapidly approaching: the upper “box” production line must come into conformity with the bottom red (black) discovery chartline.

Figure 18:  North America Natural Gas Production & Discovery 1920 – 2020


Chart courtesy of Jean Laherrere, 2001172


Developed at approximately the same time as those in the U.S., depletion rates of the existing large Canadian natural gas fields mirror those seen in the U.S.  Canadian wells drilled in 1990 declined at a 20% rate and the newer (1998) wells by almost 40%.  Reinforcing Canada's precarious natural gas reserve situation mentioned previously, an analysis of Canada's natural gas inventories projects a net ten-fold decline within 25 years.  Despite record drilling (11,350 wells), not only is surplus natural gas not located but 1st Quarter utilization rates of 86% have plummeted to approximately 20% and drilling contractors are now concentrating on easier to locate and drill shallower basins.173

Approximately three years ago Canada opened its large and widely acclaimed Sable natural gas field southeast of Nova Scotia.  With a projected life of about 25 years and estimated recoverable reserves of up to 9.5 Tcf it was heralded as a significant energy source well into the future.  The arithmetic tells a different tale.  At current North American rates of use the arithmetic works out to a supply of 5 to 6 months of use, or about 1% of North American natural gas consumption averaged over time.174

With half its natural gas exported to its southern neighbor, it is likely it won't be long before the Canadian public becomes aware of its own (diminishing) resource situation.  The level of existing exports relative to capacity foreshadows increasing tensions in an otherwise close relationship.  Higher domestic natural gas and electricity rates are likely to leverage tensions.  The possible stresses are succinctly stated in the C.D. Howe Institute report: becoming “more contentious as consumers face higher commodity prices and … sacrifice … direct sharing of the lower costs”.175

“Governments and the energy sector need to move swiftly to head off a possible Canadian consumer backlash against natural gas exports to the United States” stated Ken Vollman, chairman of Canada's National Energy Board.  In referring to the 60% of Canada’s natural gas production exported to the U.S., Chairman Vollman was candid: Canada must contend with shrinking production and higher prices.176  Evident in the U.S. and Canada as well, there is a disconnect with energy and the substantial increases in Canada’s population and energy consumption due to immigration policies.

NAFTA agreements aside, Canadians are likely to become increasingly aware of their looming domestic energy situation.  The U.S. and Minnesota will then be compelled to confront their staggering population to natural gas imbalance.

There is another issue seldom mentioned: Canadian sovereignty.  Canada’s sovereignty is threatened by unrelenting U.S. energy demands and by U.S. companies acquiring Canadian assets.  Today, U.S. companies produce 40% of Canada’s total production and hold an equal percentage of its reserves.  Five U.S. firms are among the top 15 Canadian exploration and drilling concerns.  Large Canadian companies now number six, down from 41 in 1997.  A startling statistic is that of the 35 Canadian companies acquired or merged during this brief time period, 21 were acquired by U.S. companies and in 2001 more than $35 billion of Canadian oil and natural gas assets were acquired by U.S. firms.177  For example, in May 2001 Houston-based Conoco Inc. purchased Gulf Canada Resources Ltd. for $9.8 billion, followed by the $7.2-billion purchase of Anderson Exploration Ltd. by Oklahoma headquartered Devon Energy Corp., the $3.3-billion purchase of Canadian Hunter Exploration Ltd. by Houston's Burlington Resources, and the $13.3 billion Duke Energy  acquisition of Vancouver-based pipeline operator Westcoast Energy.

With the bulk of the assets owned by U.S. companies, foreign corporations now own 48% of all Canadian oil and natural gas assets.  Foreign ownership is discussed in a new book by Mel Hurtig, The Vanishing Country: Is It Too Late to Save Canada?, (McClelland & Stewart Publishers, February 2003).  Mel Hurtig is a well known author, formerly the leader of the National Party of Canada, publisher of The Canadian Encyclopedia, and Chairman of The Council of Canadians.  Regarding acquisition trends in the oil and natural gas industries he states “when you get so much of the industry foreign controlled, your national priorities get ignored.”  Finally, Hurtig makes the frightening statement, “at what point do you abandon your ability to be Canadian?”178

A U.S. led plan to have a continental energy policy would eliminate national sovereignty in energy decisions.  A Canadian group, “Council of Canadians” cautions the program would eliminate national “impediments” to energy decisions.178  Generally, the implication is that energy flows would be one-way to the U.S.

Growing awareness of depletion and future resource supplies suggest that domestic concerns will assume greater priority.  Combining Canada's burdensome debt ($800 billion or more than $26,000 per capita) with increasing Canadian assets transferred to foreigners, one will appreciate the possible level of Canadian anxiety.  It also implies that reevaluating Canadian immigration, tax, and welfare programs will be considered.


Canadian Tar Sands

Alternative energy supporters argue the large Canadian tar sands are a practical enhancement to the current resource base and will provide substantial natural gas and oil energy —in theory, perhaps.  However, because of its low energy yield ―negative energy returns― and long and arduous production process, development of the Canadian tar sands or shale oil is limited, no more than a marginal producer.

The development of the tar sands or oil shale is an example of imagining technology will provide another inexpensive energy source and that as prices rise, the economics become increasingly favorable.  Faith in technology has been discussed and does not require further elaboration here.

The tar sands is a highly inefficient energy source that to be developed requires imposing amounts of oil and natural gas to work, enormous energy to process, is expensive to transport over the long distances necessary for use, results in vast “Grand Canyon-like” pits, requires substantial quantities of fresh water —literally whole lakes holding contaminated water― and is logistically difficult as a large-scale energy source.

The “oil” in the tar sands is a hydrocarbon called bitumen.  The bitumen is composed of a hydrocarbon mixed with water, sand, and clay.  Once separated, the bitumen can be refined as petroleum.  The extraction process involves physics and geology.  There is no comparison between the easily pumped OPEC fields and tar sand or shales lying under a deep layer of the earth’s mantle.  The resource is promoted as a viable substitution because initial production has been from relatively inexpensive, readily available and easily extracted areas.  Already more costly than current energy sources in the best of circumstances, costs ratchet higher as the easy to obtain tar sands or oil shales are quickly exhausted.  As the difficulty of extraction increases, the quantity produced will decline as costs increase.

Processing begins with the removal of deep layers of overburden of—ten several hundred feet— the ores extracted, crushed, centrifuged, caustic soda and hydrogen added, and processed into fuel or natural gas.   An alternate process is to use heat or chemicals to make the bitumen flow like a liquid for pumping.  The tar sands are composed more of water than tar, thus the removal process leaves vast quantities of polluted water —groundwater poisoning if heat or chemicals are used— which must be contained in man-made lakes.  Prolific energy consumers, small local generally stranded natural gas deposits are the processing energy source.  These are temporary sources that when depleted, the true cost of tar sands processing will become evident.

Quite literally, large-scale development of the tar sands requires the construction of a large natural gas pipeline network, or baseline coal, nuclear, or natural gas plant to provide the energy necessary for its production.  The finished energy product must then be transported thousands of miles for use or further processing.  Not surprisingly, the result —at best— is that the net energy available from developing the tar sands only marginally produces more energy than energy used in its mining and processing.  Finally, as the foregoing suggests, the time required from initial extraction to useable fuel is such that it prohibits large-scale development.

New technology, Steam Assisted Gravity Drainage (SAGD) has some potential for reducing the energy requirements of processing.  Nevertheless it requires substantial natural gas and water.179  Thus, the tar sands cannot be considered an economical nor sustainable replacement for existing baseline energies.


Canada & United States Oil Shales

“Shale oil” is physically different from tar sands.  Tar sands contain genuine petroleum whereas “oil shales” are not oil or even a hydrocarbon; shale oil is an organic laden rock called marlstone.  The organic compound is kerogen, an immature “petroleum” resembling wax.  The U.S. has the world's largest deposits, primarily in Wyoming, Utah, and Colorado.180

The energy intensive processes involved in shale oil production equal those of tar sands development.  Because of their location in a dry region of the U.S., water would be a limiting factor in its development.  Vast quantities of water are required to provide the additional hydrogen atom in order to make the substance a hydrocarbon for manufacturing into a petroleum product such as gasoline.  Very expensive gasoline!  Dr. Walter Youngquist makes the point that shale oil development would require “beheading the Colorado River” leaving downstream users with substantially less water.  Because of the water and energy intensive processes, its kerogen processing can be abbreviated at the liquefaction stage (at 9000 F) and used as costly boiler fuel or as a base for plastics.181

In brief, development of tar sands is economically unjustifiable except at remarkably higher energy prices, and environmentally questionable at any level of production.  Because natural gas requires further processing, the economics of tar sands conversion to natural gas is even more discouraging.  The identical situation exists for shale oil.  Even assuming substantial energy price increases, poor economics explains why after huge investments, Canada’s large Suncor Corporation cut their losses and quit the large Stuart shale oil project in March 2001. (For more on tar sands, see the “alternative energies” section.)


Natural Gas, ANWR & LNG

ANWR was mentioned previously in the context of oil.  As is typical of fields with declining oil inventory, natural gas production was substantially increased over the 1988 to 1992 period and again in 1999.

Estimates are that there are between 31 and 35 Tcf of known natural gas reserves in the North Slope region; two-thirds are in the Prudhoe Bay area.  Although these quantities appear to be substantial, the arithmetic indicates it amounts to only about 1½ years of U.S. use.  Some guesstimates are significantly higher with up to 65 Tcf said by some to be in the Beaufort and Chukchi Sea regions.  A January 2003 EPA study found that estimates of ANWR oil reserves reported in the press were frequently three to four times overstated.  The most likely range based on 2000 – 2001 data was between zero and 5.6 Bbls.182  In order to maintain adequate pressure in the Prudhoe Bay basin, more than 9 Bcf per day of natural gas is injected back into the oil reservoirs.  It signifies depletion of the reservoir and rising extraction problems and costs.

However, beyond the environmental concerns, the primary economic difficulty in extracting ANWR natural gas is that there is simply no practical and inexpensive means of delivering it south from Alaska.  The most significant cost of ANWR natural gas is the transportation cost; either liquefied natural gas (LNG) or an expensive pipeline and gas distribution system must be constructed.  In general, North Slope or ANWR natural gas requires natural gas priced at $6 per Mcf at a minimum and more likely in the $10 to $15 range to be economic.  Joseph Mathew, President, Hybrid Energy Advisors outlines the four Alaskan natural gas pipeline proposals.183

I.  The ALCAN Highway Route ―Trans Alaska Pipeline System (TAPS)

Transports between 3 and 6 Bcf/day of natural gas from processing in Prudhoe Bay through a large pipeline to Fairbanks, then eastward following the Alaska-Canada Highway into the Yukon territories of Canada (where it joins another pipeline from the Mackenzie Delta region). Favored by the Alaska government. Requires 2-36" pipelines.

The Mackenzie Valley pipeline (on the east side of the Yukon) connects the Beaufort Sea region with markets in southern Canada and the United States.  It will begin near Inuvik and extend to northwestern Alberta.  Engineers plan to begin shipping 800 – 1,000 million cubic feet per day of the estimated 5.8 Tcf in the reservoir.  The project cost estimate is $4 billion (CDN$).  In June 2003, TransCanada PipeLines paid $80 million to the Aboriginal Pipeline Group (local Indian/Inuit’s) to begin work on the pipeline.

Running between Prudhoe Bay and Valdez, TAPS is the transportation and pipeline system operational since 1977.  The additional TAPS proposal requires 800 miles of new pipelines in the 2,100 mile system of pipelines.  The Prudhoe Bay proposals frequently include an LNG production facility in southern Alaska for sales to Japan and Pacific Rim states.  An LNG plant at Kenai Cook Inlet has been producing product for Yokohama, Japan for more than 30 years ―since 1971― and has contracts to produce and ship LNG to Japan until 2009.  The proposed 800-mile pipeline project requires a new LNG port at Valdez and a parallel tanker fleet.  The cost is in the $15 to $20 billion range.  One Prudhoe Bay – southern Alaska proposal includes constructing an LNG port in western Mexico for pipeline transport to California.

II.  The TAGS Route

Similar to the current Trans Alaska Pipeline System (TAPS) uses a 42”–800 mile long pipeline to deliver between 2 and 4 Bcf/day of natural gas from Prudhoe Bay to Fairbanks and on to Valdez or Nikiski where, unlike #1, the North Slope natural gas would be converted into LNG for shipment to Japan and the Pacific Rim.  By Presidential Decree, originally planned for delivery to Japan, Korea, or other Asian nations.

III.  The Over-the-Top (“OTT”) Route

Delivers between 2 and 4 Bcf/day of natural gas from processing at Prudhoe Bay to northern Canada via a artic sub-sea pipeline to the Mackenzie Delta.  Requires a 52” high pressure pipeline (not produced by U.S. steel mills).  The OTT route is an extension of #1.

The construction costs of these projects are seldom public, but appear to be in the $14 to $20 billion range.  The pipeline would go through the Mackenzie River Valley to the network of Canadian pipelines in Alberta.  It involves a 326 mile offshore pipeline in a trench built into the seafloor under approximately 50’ of water and 874 miles of buried pipelines for delivery of natural gas to the lower 48 states.  The proposal includes a gas-to-liquids (GTL) project on the Kenai Peninsula using the existing TAPS system.  Perhaps the biggest selling feature of this proposal is that it will extend the life of the TAPS pipeline system.  The TAPS system will become inoperational when deliveries fall below approximately 300,000 barrels per day.  Oil remaining in Alaska will then remain in the ground or be converted to GTL or LNG and shipped to the Pacific Rim.  Amoco has constructed a GTL plant at Prudhoe Bay’s Nikiski in the Cook Inlet.  It should be mentioned that the cost of converting natural gas to GTL is approximately 30% of the energy in natural gas.

IV.  The Y-Line Route

The “hybrid” plan; combines the ALCAN Highway route and the TAGS route.  Delivers 3 to 6 Bcf/day Prudhoe Bay to a “fork” at Fairbanks.  Half the volume goes to Valdez or Nikiski for liquefaction into LNG. Much more capital intensive and complex.

Under the assumption of $2.50 Mcf natural gas, pipeline proposals required natural gas prices in the $4 Mcf range to be minimally economic.  Under these assumptions the pipelines are estimated under the best of circumstances to breakeven in the year 2010.  Assuming all regulatory and construction phases were processed smoothly, the earliest natural gas would be transported would be 2008 at the rate of one Bcf/day, approximately 1.5% of U.S. consumption.  Mathew’s research concludes that “there is compelling evidence that any current Alaska pipeline scenario that delivers gas to the United States via a transcontinental pipeline would be marginal at best, from a pure economics perspective” and that, “Alaska gas can be a viable alternative, if there is sufficient government intervention, long-term price views above an economically viable level, or a combination of both.”158

Alaska studied the issues only to find that if the state's obligation was only equal to its percent of royalty in North Slope natural gas (12.5%), the state would not realize a return on its investment for 7 years.  Obviously of interest to potential private investors, at this minimal investment the report concluded that the state will lose approximately $1.75 billion.  Interestingly, Mike Chambers in writing for the Associated Press regarding the study, stated that “results of the report … have not been made pubic, but the industry has tentatively said neither route [Alaskan Highway or Canada] appears economically viable.184

Six major U.S. companies combined with three Canadian counterparts to develop “The Alaska Highway Natural Gas Pipeline Project”, the “ALCAN or TAPS” route, proposal #1.  The objective is to deliver Alaskan gas to Canada and southward to the U.S. by 2008.185  The proposal is a mammoth $20 billion undertaking to construct a 4΄ diameter underground pipeline.  The project has the highly unusual engineering feature of a 2,500 or higher, pounds per square inch pipeline to facilitate gas movement.  The consequences of a seam separation or other incident occurring with a 2,500 to 5,000 pound pressurized Alaska natural gas pipeline would be frightening.  The project is engineered to deliver 4 Bcf per day.  Although the technological hurdles have not all been resolved, it's possible they could be in due course.

Perhaps the greatest physical problems are the shifting nature of the Alaskan and northern Canadian permafrost and the earthquake prone nature of the region.  The likelihood of pipeline cracks is a consideration that must be overcome prior to construction.  The current plan is to construct approximately 25 refrigeration stations along the pipeline to keep the pipeline frozen in place.  On the other hand, the leading scientist with similar experiences in Russia suggests that the number of refrigeration stations could be 10 times that now projected, up to 1 to 2 miles apart rather than the approximately 80 miles apart in the proposal design.  Whether it is 25 or in the hundreds, freezing will substantially add to the costs.  Vladimir Yakushev of Moscow's “Research Institute of Natural Gases and Gas Technologies” also cautions that “[the pipeline] needs to be supplemented by expensive drainage systems to avoid problems with frost heave” and that “to ensure supply while a pipeline is being fixed, two or more parallel pipelines are necessary”.186

A parallel pipeline would nearly double pipeline revenues and costs of construction.  It would also reduce the productive life of the fields, perhaps by half.

If the project were successful in delivering 4 Bcf per day, it would transport 1.46 Tcf per year (365 x 4 = 1.46 Tcf).  At that rate of extraction the known inventory would be fully depleted within 23 years (35 ÷ 1.46) and if delivery were doubled, field exhaustion would arrive early in the 14th year while delivering less than 6% of U.S. natural gas.

If one makes the reasonable assumption that the technological and economic barriers for an underground high-pressure pipeline cannot be remedied then a standard 32″, 5', or 10' diameter above ground pipeline would be a likely alternative (5΄ and 10΄ pipes are not currently manufactured).

The arithmetic also suggests the standard less technologically demanding and less expensive alternative pipelines are also economically questionable.  Assuming the larger pipelines transport natural gas in the same ratio as a standard 32″ pipeline and generously assuming a 32″ pipeline transports 3 Bcf/day results in a 5' diameter pipeline transporting approximately 10.5 Tcf per year and a 10' pipeline, 15.4 Tcf.  If the pipeline(s) delivers gas at 50 feet per second (a little over 30 miles per hour) over a 2,000-mile pipeline natural gas will reach the lower U.S. in about three days.  (With much higher volumes possible, the significance of the proposal to construct very high-pressure pipelines is evident.)187

In an economy that uses nearly 23 Tcf per year at current consumption rates the supply is significant.  The 5' pipeline would arithmetically deliver about 15% and the 10', an amazing 67% of annual U.S. natural gas requirements.

Constructing the pipeline to the Fargo-Moorhead area for distribution in Minnesota and elsewhere would certainly place Minnesota in a healthier natural gas position.  The good news is that at this volume the Alaska region could supply natural gas to Minnesota —at current rates— for the next 90 years (35 Tcf ÷ 400 Bcf/year).188  One can already hear the hyperbole, proponents saying there is enough natural gas in Alaska to last several generations of Minnesotans!  With Minnesota’s increasing population the percent of natural gas needs will continue to decline; excluding the remainder of the U.S. and sharing the treasure chest with the Dakotas would require careful discussion!

The other news is that the 3 Bcf  pipeline would exhaust the North Slope natural gas reserves within 32 years, the 5’ pipeline within 6 ½ years, and the 10’ pipeline would deliver its bounty for no more than 2 years and three months.  The 5’ and 10’ pipelines will exhaust the North Slope’s natural gas supply in less time than was necessary to construct the pipeline.

Even if the cost of construction of a standard pipeline were 40% less expensive than the cost of the proposed underground pipeline, the revenue generated would be insufficient to cover expenses or earn a return on the investment.  Private investors will be reluctant to invest in such a project.  Thus, funding of this costly project falls to an unsuspecting public through direct taxes or increases in government subsidies.

Under large pipe or high pressure scenarios the investor returns are very attractive.  If it is assumed the wellhead price of natural gas is $1.25 per Mcf the annual revenue of a 10' pipeline would be $19.25 billion ($1.25 x 15.4 Tcf) and for the 5' pipe, $13.8 billion ($1.25 x 10.547 Tcf).  The $1.25 figure is used because it is the floor under proposed legislation.189  Unless production costs rise in tandem, higher natural gas prices imply correspondingly higher returns.  Using the volumes from an unprecedented 10’ pipeline indicates a 160% annual revenue return and a 115% annual revenue return for the 5' pipeline on an estimated $12 billion project (60% of $20 billion).  The period however, for the return and taxes paid into state coffers, and supply of natural gas, as stated above, would be brief.

On the other hand using a standard 32" pipeline transporting a reasonable estimate of 2 Bcf per day indicates that the annual revenue of $912.5 million would not cover the estimated $1.31 billion annual amortization payment or the initial interest expense on the debt used to construct the pipeline, $1.08 billion ($12 billion at 9% and assuming a 20 year life).  A typical 15% before tax return implies $1.8 billion annual revenue return ($12 billion x 15%).  The revenue return implies a wellhead cost double the recent wellhead price, $2.47 per Mcf. ($12b x 15% = $1.8b. $1.8b ÷ 730mMcf = $2.47/Mcf.)190  The higher price, paradoxically, does not produce an increase in natural gas reserves only that larger pipelines be economically constructed and natural gas consumed at a more rapid rate.

Double the above cost figures to include the amortization of design and construction costs plus the annual cost of production, maintenance, administration and finally add a profit margin.  In short, when the wellhead price is $1.25 per Mcf Alaska gas requires more than $5 Mcf. natural gas to be marginally successful.  The federal government option is to sell it to the consumer at below-market rates with taxpayers subsidizing the substantial difference between costs and selling prices.

Not included in the construction costs or consumer price are the substantial costs of de-construction.  De-construction is an expensive and necessary element of developing the region’s natural resources.  Funding the removal and return to the environment approximating the original ecology of the entire impacted region —North Slope, Prudhoe Bay, and Canada southward, must be incorporated in current consumer prices.  Furthermore, salt water or other noxious substances invading the region’s soils or groundwater systems must be prevented.  The Treasure Chest will last a brief time period, yet if the instruments of production are not promptly removed as the resource is depleted, the consequences and infrastructure will last virtually indefinitely: a testimonial to short term practices.

It's understandable why Governor Knowles would be promoting a pipeline.  Because of declining oil revenues, Alaska is heading pell-mell toward serious financial dilemmas.  According to Mike Chambers, the state's budget reserve will be at a deficit by 2004, and the current year's $865 million deficit will increase to $1.1 billion by next year.191  The state appears to have presumed its oil was a treasure rather than a treasure chest that would diminish as consumed.  Although the state appears to have made a number of positive plans, Alaska failed to develop a comprehensive program to prepare the state for sustainability after the oil (and natural gas) treasure chests were depleted.

Albeit the precarious economics, Alaska and federal governments have proposed a number of practices to encourage or subsidize the construction of an Alaskan natural gas pipeline.

Alaska’s study found that there are insufficient gas reserves at any practical natural gas price to justify pipeline construction.  However, in order to overcome the insufficient economics Alaska Governor Tony Knowles proposed a form of welfare: a federal subsidy program to build a pipeline.  The subsidy program required using the Alaska Highway corridor so the federal government would be the primary funding source of the proposed project and also included tax incentives for project developers.192

There are other government-sponsored inducements to constructing an ANWR pipeline.  For example, in the House, H.R. –276 seeks to amend the Internal Revenue Code such that natural gas pipelines are defined as 7-year property for expensing depreciation (January 30, 2001).  The companion Senate bill is S. 593, March 22, 2001.  The legislation would allow pipeline companies to expense the full cost of pipelines normally lasting 50 years over the identical short 7-year period.

Accelerated expensing significantly increases cash flow while reducing reported income for tax purposes.  In the example of the proposed underground pipeline, the implication is that $2.8 billion would be reported as an expense for tax purposes each of the first 7 years.193  Using standard accounting the amount would be one-fifth that amount and taxes paid proportionally higher.  The difference is cash to owners not included in taxable income, a large “subsidy”.  Later when production and associated revenues decline, the reduced depreciation expenses will be charged against reduced revenues, therefore at minimal tax rates.  The function of the unusual IRS depreciation schedule change is to avoid paying taxes when income is greatest and paying reduced or no taxes later when income is reduced due to declining natural gas production.  Reduced taxes flow through to investors.  It is favored legislation because the windfall cash changes are nearly invisible to the public.  Similar hidden subsidies are apparent in the development of alternative energies —notably windpower— discussed later in this paper.

Similar to legislation in Minnesota regarding siting and construction, there is proposed Senate legislation “to Expedite the Approval, Construction, and Initial Operation…” of an Alaska natural gas pipeline.  The legislation is designed to “facilitate” construction by requiring all related items go through a government body designed to fast-track reviews.194  Previous experience has been that “fast tracking” legislation has been used to sidestep environmental and other well established regulatory apparatus.
 

LNG

Transporting liquefied natural gas (LNG) is an alternative to the construction of pipelines.  It is assumed to be an important source of natural gas replacing domestic conventional natural gas.

The section on population and change was introduced with the statement that ―other than ANWR― foreign resources are necessary to sustain our energy driven economy.  The Bangladesh news item was used to alert the reader to our closing natural gas dilemmas.  But are foreign natural gas suppliers readily available and can they be counted on to come to the rescue?  Other than Canada these sources are primarily the states of the Middle East and Russia.

It is clear that the Mideast bloc comprehends the situation.  Al-Attiyah, oil minister for Qatar, states that negotiations are being conducted with Ivanhoe (Canada), Shell, Conoco and with Marathon.  If negotiations are successful, he says Qatar will be “the GTL [gas to liquid] capital of the world” producing 300,000 barrels per day.195

Not surprisingly, the answer is that these sources are less available than preferred because political reasons imply potential supply disruptions and most importantly, foreign natural gas incorporates the cost of its source energy, natural gas, coal, tar sands, etc., yet requires another higher plateau of energy use and costly processing.  Dr. Ali Morteza Samsam Bakhtiari, senior expert in the Corporate Planning Division, National Iranian Oil Company, Tehran, Iran, states that “a gas price as low as $2/MMBtu would induce a price of $20/bbl for GTL products, only taking feed costs into account”.196  Approximately one-third of the energy content of LNG is used to merely transport LNG to market.  The raw material, natural gas, must first be extracted, stored, liquefied in a costly process, stored, transported, and then reprocessed back into natural gas or other related energy using specialized facilities at every step in the process.

Common sense suggests that replacing the gargantuan volume of natural gas now consumed with a manufactured product is unrealistic.  On the other hand, lacking significant increases in imported LNG, the nation’s reliance on natural gas will of necessity be reduced.  In economic terms, the price of LNG is somewhat higher than that of a natural gas pipeline from Alaska but less than coal gasification.  Invariably when discussing LNG, the source is from non-domestic sources.

Unfortunately, there are sound reasons ―high costs and time― ruling out an expansion sufficient to match the need.  The price for each combined LNG unit is more than $5 billion and the nation requires many units, totaling hundreds of tankers and associated ports.197  Each LNG unit is composed of a (foreign) liquefaction plant, several tankers to transport the LNG, and terminals and reconversion facilities at each shipping terminus.

Suggesting the growing unreliability (and probable government and military involvement), increasing LNG shipping and distribution implies greater opportunities for supply disruptions along the extraction, processing and delivery routes ―including susceptibility to hostile actions.  Malaysia International Shipping, for example, has the largest fleet of LNG tankers.  A current illustration will suggest the scope of the potential for disruption.  The world’s largest importer of LNG is Korea Gas.  On August 27, 2003, the Malaysian LNG plant supplying Koreas Gas, burned.  The effect was to create shortages by reducing tanker shipments to Korea Gas by 6 – 8 full tankers.  The fire also forces Korea Gas into the higher priced spot market and in direct competition with LNG shipped to southern Europe.

Shipping LNG also has another serious economic consequence.  High transportation costs suggest that proximity to the fields will be economically advantageous.  In other words, China, Pacific Rim and some European nations will have less expensive and more reliable LNG than the U.S.  These nations will have a measurable economic advantage against the U.S.

Finally, stateside siting of ports and re-gasification facilities and distribution pipelines could also prove to be a serious NIMBY public issue.  The purpose of building LNG port facilities in Mexico is due to NIMBY concerns along the U.S. west coast, to avoid American permitting processes, and to disregard U.S. pollution and labor laws.  Constructing U.S. energy facilities in Mexico will also give Mexico tremendous leverage over U.S. domestic policies, raise questions of U.S. sovereignty, and increase the potential of supply disruptions.

Matthew Simmons & Co. evaluated the importation of LNG.  Simmons concludes that to provide a meaningful percentage of U.S. natural gas will require the doubling or tripling of seaports and associated transportation infrastructure, including large numbers of giant tankers to transport the LNG.  Simmons states that with existing ports supply can only be increased by 3% in the next 5 years.  An 11% increase is possible by 2010 if additional ports and associated facilities are rapidly constructed.198  With the relatively minor volumes now imported, these percentage increases amount to an insignificant volume increase at great economic and environmental cost.  Moreover, despite the costly increases in LNG ships, ports, and necessary facilities, over the next 10 years increases in LNG imports will not match the U.S. demand increase in a single year.  Indeed, the ten-year increase won't match the depletion rate in a single year!

At the present time, the U.S. has two operational LNG port facilities and is in the process of placing one of two others now in standby, into service within one to two years.  The U.S. would require more than 15 LNG ports to manage enough shipping to add only 2-Tcf per year.  Shipping requires more than a month, and more time is necessary to fill and unload the tankers.  Thus a large number of tankers would be required.  The present fleet of LNG tankers is generally owned by non-U.S. entities.  Because there are no surplus tankers, increasing LNG would require building a new fleet of 100s of tankers.

More than expensive, LNG is potentially a dangerous energy product.  “Potentially” is said because the transport and storage of LNG has a superb safety record.  Oil and gasoline can ignite and burn whereas, although highly unlikely, large LNG tankers could take on the characteristics of floating bombs that if exploded near a city would be catastrophic.  In 1944 in Cleveland a much smaller tanker than those in use today exploded with large loss of life.  Its dangers are why the Coast Guard controls the movement of these tankers, an indirect government subsidy.  Storage facilities within cities would pose the same complication.199

Because of these constraints, the practical use of LNG will be significantly less than preferred.

Perhaps a relatively small quantity of LNG could be sold to northern Canada in a quid pro quo tradeoff with Canada shipping a quantity of conventional natural gas to the U.S. in southward flowing pipelines.  LNG sales to Japan and countries in the Pacific Rim area are a likely consideration.  Because of the nearly decade-long lead time required to construct the pipeline, terminals and ancillary production and delivery facilities, ANWR natural gas could only become available when other natural gas inventories are nearly depleted and other fossil fuels increasingly scarce.  Thus, perhaps, ANWR gas could buy time, expensive energy time, to facilitate the transition to a sustainable society.

The following section on Chevron – Texaco describes how ebbing reserve and depletion data are reflected in the financial records of a major integrated oil and natural gas company.


Chevron – Texaco Confirmation

Chevron is now the number five integrated oil company in the world and with its merger with Texaco, the second largest.  Because of its significant position and involvement in both the oil and natural gas industries, an examination of its statistical information should reflect the problems and successes of the industry.  The analysis confirms the foreboding oil, natural gas reserves, and exploration research and developments discussed in this paper.

The Year 2000 Chevron Annual Report contains an 11-year data array showing the production and sales of petroleum and natural gas and related items for U.S. and world operations.  Consistent with the discussed decline in reserves, the data reveals a significant decline in operating wells.200  In 1990 the company had 17,890 operating wells.  Over the course of 11 years the company drilled 5,819 new wells with 623 of them resulting in dry holes (10.7%).  Suggestive of the extent of current and looming industry problems, at year-end 2000 the number of operating wells had declined to 12,415, a 30.6% decline.  Further analysis reveals that the true decline was a staggering 46.2%!  The actual decline was 10,671 wells (17,890 + 5,819 -623 -12,415 = 10,671).

Since 1995 the number of recently drilled wells modestly increased (6-year average of 590 from 455 per year), however it is interesting that the percentage of dry holes fell substantially to the 6% – 8% or less range from the 10% – 12%, and more, range.

The figures demonstrate that the much-ballyhooed new discovery techniques were actually reducing exploration costs and increasing the success rates of drilling programs.  The good news is that drilling is being undertaken with greater efficiency and certainty of outcome!  Unfortunately, it also implies that the industry now knows with greater certainty the volume of total reserves, where they are located, and that there are fewer additional reserves than previously estimated.

It is clear that in spite of committed efforts and use of the most modern and sophisticated discovery techniques available over a period of several years not only by Chevron but worldwide, the industry has failed to discover new fields of substantial magnitude.

Alarmingly consistent with the Olduvai Theory the new technologies validate the conclusion that there is little or no probability that any Super-Giant or other very large petroleum or natural gas fields remains to be discovered.

The reduction in drilling and operating wells is consistent with the declines in the production of both petroleum and natural gas.  Over the 11 year span in the U.S., Chevron's net petroleum production fell 31.9% with natural gas production decreasing 42.2%.  Reflecting the U.S. reserve and import situation, international (non-U.S.) production of petroleum increased 77.6% and natural gas liquids 118.5%.  Suggesting consistency of increasing demands, total net production of oil and gas liquids increased on a nearly straight-line rate of about 2% per year.  On the other hand, reflecting the tenuous natural gas situation, worldwide net production of natural gas declined 19.5% over the period, averaging about 2% per year.

The reserve situation tells a similar story.  One expects that using the most modern exploration techniques, this giant corporation and the industry would have discovered reserves not otherwise known or mathematically estimated.  Yet, despite the most technologically advanced exploration and sophisticated drilling techniques, developed U.S. oil and liquid natural gas reserves declined 4.2% between 1997 and 1998, another 7.8% the following year, and another 2.7% in 2000; this is a 14% decline in only the three years.  Proven reserves, which are slightly higher than developed reserves —by roughly 15%, illustrate the identical trends so discussing them is essentially redundant.

The bottom line is that without the use of sophisticated modern techniques, the reserve situation would have shown an even greater decline.

The worldview confirms the increasing reliance on foreign sourced resources.  Developed world reserves increased 9.7% between 1997 and 1998 and 5% in 1999, but fell 1.7% in 2000.  The 1.7% year 2000 world-wide decline appears to confirm the possibility mentioned earlier that increasing oil production may not be as successful as the government and industry advocates stated.  It also contradicts the economic argument that rising prices will automatically significantly increase supply.  Indeed, consistent with standard economics, prices rose substantially as reserves declined.

The secret of increasing “reserves” by increasing prices is embedded in the cost recovery formula.  The industry compares the estimated cost of extracting the resource to the current price (or near future selling horizon).  If it appears “cost effective” the reserve information is updated to reflect the “additional” reserves.  Note that no new oil or gas has been discovered only that the company or industry assumes it will become economically available.  It may not actually exist; note also that the procedure is subject to manipulation.

Over the 1997 – 2000 period net proven reserves of natural gas tumbled 30% in the U.S. but showed a less worrisome, nevertheless significant, 4.4% decline world wide.  Of some relevance is that there were very large positive reserve revisions during 2000 resulting in a 5.5% total increase in reserves (recall the arithmetic of calculating reserve increases).  If these revisions were of a more typical amount, the actual decline over the period would have been in the 16% range.

Developed U.S. reserves declined 10.8% from 1997 – 1998, another 14.6% in 1999, and 7% in 2000 for a total decline of 29.2% over this short time period.  However, a significant positive statistical revision is seen the last period or the decline would have been greater.

The world-wide developed reserves increased 1.1% in the first period, declined 3% in the next, but increased 6.7% in the last year for an overall increase in the period of 4.6%.  Without the adjustments, 2000 would have shown a 7.7% decline, and over the 1997 – 2000 period instead of a 4.6% increase there would be a 9.5% decrease.

In summary, data from a large integrated petroleum company documents that technology has enhanced exploration activities making it more efficient, reducing exploration costs, and the number of expensive drilling derricks.  The reports also demonstrate that both oil and gas production has or is near peak and that reserves are in decline despite the sophisticated improvements in exploration, discovery, and production.

 

Pricing Economics

The potential significance of the alternative theory of the origin of additional oil and gas potential is self-evident with respect to the issues of the longevity of hydrocarbons’ production prospects and to production costs in the 21st century. Instead of having to consider a stock reserve already accumulated in the finite number of so called oil and gas plays, the possibility emerges of evaluating hydrocarbons as essentially renewable sources in the context of whatever demand developments may emerge.
    Peter Odell, Economist, 2001
.
 

Geologists look for oil, engineers produce oil, economists sell oil. Beware of economists who tell you how much is there.
     Cóilín J. Campbell, Geologist. 2002201


Prices are impacted by geology and by politics.  Notwithstanding an economist’s mumbo jumbo —and clarity of geologists— making the sustainability transition difficult is that the typical economic signals from reductions in long-term natural gas supply are less transparent and more sudden than for oil.  Because the costs of natural gas are predominately fixed and change less frequently (construction of new pipelines), there are not substantial price differences between the cost of the first and last Ccf of natural gas production.  Thus, current market price is less influenced by long-term demand and supply factors.

The consequence of the economics of natural gas consumption is that diminishing availability will continue unabated until it, as is so wonderfully verbally illustrated, goes “over the cliff”, until shortages impact the economy and personal welfare.

For a nomadic as well as developed society energy is the cornerstone of economy.  The difference lies in the quantity and quality of the energy resource: dung, plants, or nuclear, for example.  How energy is used, priced, and allocated is determined by the economic models used by the society.  That aphorism suggests some economic models place the cart (economy) before the horse (energy source).  The Western economies are energy dependent; energy is not dependent on the economy.

Moreover, traditional economic models indicate that relative scarcity is reflected in price.  That is to say, an expensive item is thought to be scarce.  In general, this relationship seems to reflect common sense.  However, this paper has cited a number of oil and natural gas examples demonstrating that this presumption frequently fails in practice.  The price of diamonds is high not because of scarcity, but because South Africa's De Beers controls the market and those regions, such as the Russian States, with larger quantities are in their self-interested noncompetitive fashion encouraged to play the profit game.  Likewise for oil, the monopoly price is set by OPEC sanction with other factors a secondary consideration.  That pricing power, in turn, influences the price of competitive energies.

It requires a worldwide economic downturn or robust economy for non-political factors to carry the pricing day.  Indeed, the lowering of oil prices is a tremendous economic stimulus to importing nations.  In that regard, the monetary stimulus actually promotes additional sales for exporting nations.  In this generally closed system, when reserves are more than adequate the market price and demand relationship are subject to manipulation.

The bottom line is that physical production is often distinct from pricing and economic price signals.  This suggests that the price signals from approaching capacity constraints are either absent or postponed to a point where the economics of geology overwhelms the politics.  The longer the period of “state” control in the case of oil, the shorter the possible transition period.  OPEC is a good illustration.  An unrealistically low price encourages additional sales of OPEC cartel oil.  It also moves the OPEC cartel's capacity constraints forward in time and indicates that a production downturn will be less anticipated and steeper than it would under another pricing scheme.  This is a theme that will be visited in discussing resource “conservation”.

However, at some rapidly approaching point in time —within this decade— price will not determine production levels because production will be limited by absolute physical resource constraints.  Contrary to statements of some newspaper editors and many conventional and conservative “supply-side economists”, increasing scarcity may increase prices but not significantly increase production.  Increasing production effort suggests that the production trends demonstrated by the oil graphs presented in this paper will possibly display a longer sideways peaking plateau with volatile prices prior to commencing a still sharper decline (see Figures 5 –World Oil (p56) and 8 –U.S. Oil (p61)).  Because looming energy dilemmas are worldwide in scope (excluding the Middle East ―temporarily) all or nearly all exporting nations are likely to soon revise domestic energy resource priorities and reprioritize export levels.

Currently oil, but increasingly natural gas, the primary energy sources of the U.S. will, in the main, be foreign with prices set accordingly.  Although increased natural gas and oil supplies will become available, the U.S. is confronting precarious electricity and transportation resource demand and supply imbalances made worse by relentless growth.

Energy prices will escalate as demand increases beyond resource availability and as more difficult to obtain energy sources are utilized.  The incremental costs flowing through to ratepayers are the rising cost of production due to the deterioration of oil and natural gas reservoirs and high rates of depletion.  The economic repercussions will follow in lockstep with the production efforts.  Thus, the economy will be impacted either by production availability and/or higher prices.  Under either scenario relatively more dollars will flow into energy and away from other economic sectors.  Of some consequence —especially regarding natural gas― it implies that economic restructuring and associated investments must begin when economic price signals for change are understated or minor, and that when signals are evident, it will be politically and economically difficult to undertake.  In other words, markets are not sufficiently far sighted to send the necessary pricing information.

In brief, before the Boomers begin to retire the U.S. will have exhausted its total oil and natural gas inventories.  Although an energy transition should begin soon with appropriate and perceptive pricing policies, an alternative energy to oil and residential natural gas heating must be considered improbable.  The maturing and successful Boomers now constructing large rural homes for retirement may find them expensive to reach by automobile, difficult and costly to heat and cool and the simple afternoon barbecues Americans now frequently enjoy will become an occasional holiday festival as the price of charcoal rapidly rises.

Figures 19, 20, and 21 in the following pages illustrate the pricing and production economics of national resource extraction, primarily of oil and natural gas.  The charts demonstrate that rising prices, at some point, only marginally increases supply, deprives future generations, and can result in net energy losses to society.  The market price or “reference cost” trendline reflects current rather than long-run resource market pricing.

Figure 19:  Oil Production vs. Cost of Production


The 100 periods of Figure 19 represent the 100-years of the Olduvai Theory, 1930 – 2030.  Although an imperfect analogy, “30” would be 1960, “45” –1975, and the current period lies in the area of the “70”.  Assuming the reader is of sufficient age, the reader can think back to these periods and judge if the trendlines are consistent with their memories.  The energy times were good for many years, and then in the early 1970s change was palpable but generally misunderstood.

Although not directly showing actual total reserves or daily or annual production at any point in time (because the graph was calculated to represent the Hubbert Curve), the production trendline represents actual consumption and a generous estimate of remaining reserves —totaling more than three trillion barrels.  There are reports of volumes three or four times that figure.  Unfortunately, these are unconventional sources and extremely difficult to extract and produce —net energy losses— and expensive: society cannot be sustained using them.  Summing the annual volumes under the production trendline will yield the world’s actual total produced (consumed) and estimated reserves.  However, oil produced prior to 1930 would not be included.  Per barrel costs of production have been extrapolated and then overlaid on the graph: the costs are not actual for any period.  The costs are reasonable ballpark numbers up to about the 45th period, but because the “B” plateau area is flatter the actual production trendline shape would be a compromise between the primary trendline and the “with increase” adjustment (upper right of “B”).

The rising production trendline reflects the period of greatest economic prosperity and productivity of oil resources.  The large area labeled “D” (white) is the net energy benefit from oil production.  The result of area “D” are the economies and societies seen today —based on cheap oil.  Area “E” (green or light gray) illustrates the costs of production and should be considered as in constant current dollars.  It begins at a relatively elevated level of $15 per barrel because the discovery and drilling technology were in early stages of development.  With rapid increases in production (and uses) and improvements in technology, costs plummeted –“A”– on the chart, and remained low for decades.

The punch bowl –mixing metaphors, is removed at point “B”, the Olduvai Plateau where resource supply changes become evident.  The shape of the above curve is a textbook-like example; the actual trendline will be somewhat different (note Figures 5 (p56) and 8 (p61)).  “C1” is the point where the ascending cost trendline intersects the now declining production trendline.  It represents the point where a barrel of new oil production approximately costs the energy equivalent of another barrel.  The U.S. is now at point “C1”; a barrel of additional U.S. oil now cost, on average, the energy equivalent of another barrel of oil to produce.  Examining Figure 8 –U.S. oil, one sees this relationship is approximately halfway down the descending side of the curve ―the point on trendline approximately above the year 2000.  Point “C1 or C2” is the point of production where on average there is no net energy benefit from further production.

The identical physical and economic relationships seen in the above chart apply to all energy sources, but the cost curve will be unique to the resource, yet have a similar shape.  The production trendline for natural gas parallels that of the oil graph with the important distinction that once reaching the area of the topping plateau, point “B”, the natural gas production trendline may continue at a relatively high level for a somewhat longer time period, then experience a sharper decline to an exhaustion point at the lower rightside.   The “with increase” oil trendline is a reasonable representation of the natural gas trendline.  The sharp rollover arrives at a period of high natural gas prices.  The trendline indicates the time horizon for the full production period to exhaustion event will be considerably shorter for natural gas than oil and that the yellow flag warnings of the advancing peaking evident for oil are less evident for natural gas.  In other words, regarding natural gas, the rightside trendlines showing depletion and production reductions are much steeper than the initial oil trendline, even as prices rise.  With high consumption momentum, government intervention or escalating prices —or both— may be necessary to reduce demand consistent with supply.  In the language of government and the industry, this is called “demand destruction”.

There are several implications of producing beyond point “C1”.  Most critical is that resource recovery must be less than resource reserve estimates: physical geology takes precedence over economics.  It illustrates that higher per barrel (or Ccf.) price, i.e., price to the consumer, does not invariably lead to more production.  Perhaps the most startling observation is that whether from the USGS, API, or professional petroleum geologists, total reserve estimates greatly overstate the quantity of useful resources.  Because of physical geology only 70% to 80% of the total estimated reserves are economically available.  Oil or natural gas production becomes more difficult as the inventory declines and as basin pressure falls.  In other words, approximately 20% of “reserves” are uneconomic and would be net energy sinks if produced.

To use more energy to obtain energy than the energy produced is a net energy loss to society —at any selling price.  One implication is that living standards cannot be improved without decreasing populations at a rate greater than the rate of decline in resources.  Producing beyond points “C1 or C2” is consuming capital: producing beyond that point makes society less sustainable and economically troubled.

Another important observation regarding the U.S. is that approximately 75% of all known and estimated reserves have been produced, thus producing at the margins is generally the issue.  That is to say, in the U.S. no new inexpensive giant fields are available and those that remain are difficult to locate, drill and to release their oil.  Geologists report and common sense suggests that coaxing oil from these sources in quantity will be increasingly difficult despite the selling price.  In great measure the geological limitation is illustrated by the rolling-over of the production curve, beginning soon after point “B”.  The world trendline in Figure 19 suggests the net energy benefit —like the U.S. before i—t from world oil production is beginning to significantly decline and is on average, likely to become uneconomic in the current decade.

This is precisely what is described by the cost trendline.  The area labeled “F” (light red or darker gray) is the net energy loss from producing beyond point “C1”.  The area “F” also represents the volume of reserves which are uneconomic.  The distance between the lower production trendline and the upper cost trendline at a point in time represents the additional cost of production above the output in oil, the net energy losses.  It may remind some of the humorous refrain that losing money on every sale (production) can be made up by increasing sales (production) volume!

The underlying assumption of point C1 is that costs are equal to net energy.  Although there is a strong correlation in many instances between the price of energy, production costs and net energy benefit, other factors are present.  Generally, a net energy trendline will be the inverse of the production cost trendline.  In Figure 19, the net energy trendline would go negative —go below the bottom scale, at point “C1”.  Determining energy productivity of oil production over the 1915 – 1985 period is illustrated in Figure 20.  In great measure Figure 20 represents area “D” at a point in time of Figure 19 —the difference between the upper production trendline and the lower cost trendline.  Point “C” of Figure 19 would be the date the trendline in Figure 20 pierced the bottom scale —late 1980s.

In the “with increase” scenario the peak is maintained for 10 more years.  However, higher prices induce further production implies shifting the production trendline upward, to C2 for example.  Increasing current production pushes out the time to reach a zero net energy benefit three years, C1 to C2.  Because the point of resource exhaustion (Olduvai Year 100) is fixed (reserves are fixed) and point “C1” is significantly down the production trendline, the implication is that higher prices can change production only insignificantly and temporarily.  The production increase due to higher prices is the difference between the original production trendline and the C2 trendline.  This is illustrated by the dashed vertical lines on either side of point “65”.  In terms of volume, the increase is illustrated by the area (small white) roughly bordered by B, C1, and C2.

The energy and economic loss is represented by the distance between the two dashed lines on either side of period number 65.  The additional cumulative losses are illustrated in the triangle area (light red, darker gray) to the right of C1.  This area represents the increase in capital losses and decline in potential future living standards consumed by uneconomic production increases today.

Society’s net energy losses are also increased by increasing current production.  Because the physical quantity is fixed, the increase in consumption at this time is offset by reduced volume at a later time.  The later reductions are represented by the area (light red or dark triangle) between the “with increase” and production trendlines.  This area lies in the area above the 75 to 95 periods on the bottom scale.  The implication is that increasing production for less than 10 years now takes an equivalent volume over a more than 25-year future period.

Accumulating the annual energy losses of Area F suggests the social and economic restructuring required if production is continued.

A substantial percentage of these situations are avoidable: it is policy not destiny.

Perhaps Figure 19 could be re-titled “Raising Prices, Raising Hope”.  The notion underlying the economic argument that higher prices ipso facto substantially increases supply is based on an incomplete understanding of petroleum geology.  The idea is based more on faith than science and may lull the public into inaction or practices that do not lead to a sustainable society.  Although marginally accurate, raising prices is of minor production benefit while seriously impacting world economies and total energy availability.

As illustrated, there is not a significant nor lasting production benefit from raising prices.  The best that can be hoped for with higher prices is to continue the status quo while moving forward in time the date of physical exhaustion of the resource.  For example, hypothetically shifting the production curve 45º up from point “C1” due to high prices could reverse the production decline and actually increase production.  The downside is that it would be short-lived and reduce by half the time before the resource is exhausted.  It will also reduce the effective horizon for implementing appropriate sustainability programs.  Higher oil and natural gas prices will also have the effect of slowing numerous areas of the economy and therefore the net overall economic effects are negative.  This, ironically perhaps, is the chief benefit of rising domestic oil and natural gas prices ―to slow the economy and natural resources consumed.

Because all assets embody energy, to produce energy using more energy than that produced implies the world’s net energy assets will decline by an equivalent amount.  In other words, the assets built during the least cost high productivity era —generally represented by the distance from “0” to the “B” plateau area on the production trendline, are now being —or soon to be— unwound.  Society is beginning to live off capital accumulated over previous decades.  An analogy would be a corporation that is dissolving, going out of business by using its assets to procure assets that are less productive than existing assets.  Producing energy at a net loss of energy is a means of slowly spreading poverty throughout the world.

The decline in oil production efficiency is demonstrated in the following chart.  Figure 20 covers the period of all Super-Giant fields discovered in the U.S.  The Alaskan contribution is clear in the mid-1970s —the period U.S. production peaked.  Although ending in 1985 the graph covers the period generally known as the glory days of U.S. oil, 1915 – 1985.  This was the period of cheap energy even as its extraction became less efficient.  Economically it created the expansion of the U.S. middle-class (and of Western societies) and determined the idea that the Western-Way was the roadmap to prosperity.

Increases in farm output were derived from incremental improvements in plant genetics and, more importantly, increasing applications of energy.  Figure 20 also indicates that farm output carried a price and that new farm technologies with its emphasis on energy inputs were not sustainable.  It permitted the Green Revolution’s heavy energy dependency and substantial increases in farm output.  OPEC oil’s contributions to the world’s oil economy after 1965 meant the Green Revolution could be exported worldwide.  The consequence was rapidly increasing populations —postponing the Malthusian consequences.  The Green Revolution also meant that marginal lands could be used for crop production.  Once energy inputs are reduced, fields incorporating the high-energy system will require years for natural processes to restore natural soil composition and return fields to a sustainable crop level.  The marginal lands made productive by cheap energy, in a reduced energy agriculture environment are better used to prevent erosion, provide for range livestock, natural and wildlife areas.

Diminishing domestic natural gas reserves can be replaced to some extent by LNG imports in order to continue the Green Revolution.  It however, implies increased food unreliability and much higher crop prices.  Crop reductions also imply call for government intervention and subsides.

The oil shocks of the early 1970s arrived just at the time U.S. oil reservoirs fell into decline and, as the chart illustrates, the net energy benefit of further production began to slide appreciably.  Penciling in a continuation of the downward sloping trendline to the point it crosses the “0” net energy level suggests the approximate time the U.S. food and energy relationship required reevaluation: three decades in the past —the early 1970s.  Shifting the trendline 15 years to the right brings the world’s current oil productivity into focus.

Comparing Figure 8 U.S. oil (p61), with Figure 20 demonstrates the close association with diminishing reserves and costs of extracting the remaining quantities.

Figure 20:  Declining U.S. Oil Production Efficiency


Chart courtesy of John Gever.202


The following graph, Figure 21, was prepared by Dr. Thomas Detwyler, Professor of Environmental Quality at the University of Wisconsin, Stevens Point.  The chart depicts the relationships between resource availability and the economics of resource recovery.  The graph is similar to Figure 19 describing the relationships of oil costs, production, and pricing.  The portion labeled “Net energy” is the critical item ―the actual quantity of energy available to society.  The portion labeled “Energy subsidy” represents society’s increasing struggle to maintain current energy use patterns in the face of diminishing real energies.  The upper trendline labeled “Gross energy delivery rate” can be considered an energy “Hubbert Curve” seen in Figures 5 (p56), 8 (p61), and 19 (p123) for petroleum.  The point labeled “Resource cutoff” is the point in time and energy production where further energy production results in a net loss of available energy, what Professor Detwyler describes as “Unrecoverable resource”.  This is point “C1 or C2” in Figure 19.  As discussed above and at other areas in this paper, resources remain —oil and natural gas primarily— yet the energy effort to extract it is greater than the energy available from its production.  Attempts to extract those “reserves” are unwise: higher prices only marginally increase access to the resource at the cost of diminishing or negative energy returns —regardless of price.

Figure 21:  Economics & Net Recoverable Energy


Chart courtesy of Thomas Detwyler203

 

The above graphs visually explain why Dr. Gever et al., state that there is only a 40 year supply of coal.  Coal mining is expensive —as is mining tar sands or oil shales.  In 40 years or less, the energy cost of extraction will exceed the energy derived from the coal.204  In energy terms, mining uranium ores is likely marginally or uneconomic at this time.  In the U.S. and growing numbers of oil producing nations, the energy cost of extracting oil is beginning to exceed the energy available from the pumped oil —to the right of the resource cutoff in Figure 21.  Referring to Figure 21, Dr. Detwyler describes this as a “subsidy” stating the “energy subsidy that is expended to develop the resource is the difference between the gross energy delivery rate and the net energy delivery rate.”205  The energy costs exceed the energy benefit.  Because of the “cliff effect” of natural gas, the resource cutoff depicted above would be to the right that illustrated.  It is reasonable to assume the cutoff for natural gas is approximately in the area of a vertical line drawn through the “r” in “unrecoverable”.  Adding more pipelines or natural gas infrastructure only increases production cost and moves the resource cutoff point further leftward, closer in time.

Traditional baseline energies —coal and nuclear power— are discussed next, followed by energy alternatives.  Notwithstanding coal and nuclear powers pollution concerns, promoters suggest that coal ranks close to natural gas for its nearly endless quantity of reserves.  The following section will correct both its pollution and reserves reputation.  The conclusion is that the presumed vast quantities are indeed considerable, nevertheless less than required to compensate for the absence of oil and natural gas if the status quo is to be maintained.  The irony is that utilities and industrial concerns having switched to natural gas from oil and coal will either be required to switch back to natural gas derived from coal or very expensive oil from oil substitutes —or to coal.  Historically, coal's unfavorable pollution record is deserved, yet modern coal technologies substantially reduce or eliminate those concerns.  The discussion of nuclear energy follows coal.  The serious nuclear waste problems are well understood, but less known is that the resources nuclear power is dependent on for both plant construction and continued operation are approaching their limits.

 

Coal

All truth passes through three stages:
First, it is ridiculed.

Second, it is violently opposed.

Third, it is accepted as being self-evident.
     Arthur Schopenhauer. 1788 – 1860


Because of its long history of providing inexpensive energy and its substantial remaining ore deposits, coal should play an increasingly important role in bridging the Olduvai Gorge.  Its relative abundance and high efficiency will assist in the transition from natural gas and oil.  It must be mentioned at the outset, however, that coal is substantially less available and higher priced than optimists believe.

With 464 plants generating electricity today, for many decades coal fired plants were the primary generators of electricity.  However, because of pollution concerns coal was viewed with growing skepticism and frequently replaced by natural gas generators.  Indeed, most recently constructed generating plants have been designed to utilize natural gas rather than coal and some coal plants convert coal into using gas to propel the turbines.  On the other hand, Christopher Ellinghaus, energy analyst for investment banker Williams Capital Group LP, New York, writes that because of tight natural gas supplies, “only if new coal-fired or nuclear power plants come on line in significant numbers are [electricity] shortages likely to be abated.  Generators would have to build 200,000 MW of capacity fueled by coal or uranium to meet long-term demand.”206  Natural gas plants are recognized for their high efficiencies, followed by oil, nuclear and coal fired plants.  However, in terms of resource availability the sequence is different: coal, nuclear, oil, and finally natural gas.  Alternative energies are excluded because, as will be discussed, they cannot realistically be baseline energy producers.

It is highly probable that energy based contributions to greenhouse emissions are reaching a peak.  This is due to pollution regulations, increases in generating efficiencies, and long term trends in resource availability.  Emissions from oil based electricity generation and various consumer products (paints for example) will soon begin to moderate then decline in relative and absolute terms.  On the other hand, recent natural gas trends are now under reconsideration because the supply of natural gas will not match projected demand.  Data presented in this paper suggests that natural gas plants built in the prior decade will over this decade be retrofitted to burn coal.207

Although producing greater amounts of electricity than any other boiler fuel, the public’s perception of coal is the distant cousin to other energies.  According to the Department of Energy, modern coal generators are clean, filtering out almost all the particulates and removing more than 95% of emissions linked to greenhouse gases.  Indeed, DOE reports that modern coal fired generators are equal to natural gas fired plants in emissions and produce “62 times less nitrogen oxide than a conventional coal plant.“208

Thirty-four modern coal plants are under construction or being planned.209  Wisconsin is adding 1,800 MW of modern coal generators.  Richard Abdoo, Chairman and CEO of Wisconsin Energy, says that southeastern Wisconsin needs at least three new modern coal plants to maintain the reliability of Wisconsin’s electricity.  The last two years of natural gas price and supply volatility is something Wisconsin can no longer afford Abdoo says.  Cautious about the future of natural gas reserves, Abdoo is convinced the U.S. does not have the resources to “support the demand for natural gas over the next 20 years.”210

Approximately 45,000 MW of coal plants nationally under construction or being planned are not the typical pulverized coal fired plants but plants designed to burn gas produced from coal and coal gasification plants.  The intention is to produce competitively priced gas from coal when the price of natural gas (or LNG) rises sufficiently.  This process is less efficient and more costly, but has the benefit when electric generating demands are reduced (low demand periods) of providing natural gas for storage in preparation for the winter heating season or to other users.  A coal conversion plant is operating in Florida at this time.211  It is also likely that coal will be the fuel of choice in the production of hydrogen if hydrogen is produced as an alternative energy.

Coal can be liquefied and processed into a variety of useful hydrocarbons: oil, natural gas, hydrogen and further processed into the myriad items derived from petroleum.  There are three basic methods: the “Bergius Process”, “Fischer-Tropsch”, and the “Karrick” methods.  In 1931, Dr. Friedrich Bergius won the Nobel Prize for his contributions to industrial science.  The Bergius Process converts lignite (low grade “brown coal”) into crude oil.  The process was developed in oil poor Germany during the 1910 – 1925 period in an effort to achieve a level of energy independence.  Germany used the process to include synthetic rubber, fertilizers, and ingredients for explosives.  The process yields one barrel of oil fuel (synthetic fuel) for approximately 7,000 cubic feet of hydrogen.  Although coal can be used as the feedstock for hydrogen, the typical source is natural gas.  (Water, however, can be used as a hydrogen source in an expensive process.)  Because the process involves high pressure and very high temperatures, and both uses and creates hydrogen (hydrogenation), it is heavily energy dependent, creates significant pollution wastes and utilizes large volumes of water.  In brief, the process is expensive and impractical.

A second process is the “Fischer-Tropsch” method developed by Franz Fischer and Hans Tropsch at the Kaiser-Wilhelm Institute for Coal Research, Mannheim, Ruhr, Germany.  Similar to the Bergius Process, it liquefies coal for processing into related feedstocks.  Producing improved energy efficiencies, it requires higher grade coal ores.  A third method is the Karrick process developed by Lewis C. Karrick, of the U.S. Bureau of Mines in the 1920s.  Karrick’s process is known as “Low-Temperature Carbonization”, produces superior energy output and at lower pollution than the Bergius or Fischer-Tropsch methods.  Nevertheless, the fuels and related products derived from the best of these methods are at measurably higher costs. 212

Pollution-free coal plants are also planned to produce hydrogen for generating electricity, fuel cells, and further refined petroleum based products.  “FutureGen” is a $1 billon project sponsored by the Energy Department as a public-private effort.  The design is the first pollution-free, fossil-fuel power plant, a "living prototype" of new carbon sequestration.  Promoted as “emissions free”, no energy process is pollution free.  Although pollution will be eliminated, the additional processing layers —notably for hydrogen— implies significant reductions in generating efficiencies and higher consumer costs.  The pollution is certainly reduced but is transferred, sequestered, rather than eliminated.  Scrubbers remove the sulfur dioxide and nitrogen oxides and convert it to commercially useful items such as fertilizer.  The greenhouse gas carbon dioxide will be sequestered in underground geologic formations.213   A project thought to be the standard for the future is now under development.  The project pipes CO2 from the coal gasification plant in Beulah, North Dakota, to be pumped into Canada’s Weyburn oil field in Saskatchewan province Sequestration in some respects is analogous to the storage of nuclear wastes —with the exception of the lack of radioactivity.  Nevertheless, these modern coal plant designs measurably improve the environmental impact of coal.


Coal Reserves

Energy researchers optimistically estimate there is a 110-year supply of coal at current rates of use.  As in the use of natural gas discussed earlier, any increase in consumption will sharply reduce the useful time horizon of coal reserves to 40 or 50 years.  This time frame should be adequate to manage the transition to a sustainable society.

Coal is a less extreme example of what journalist Brad Foss wrote regarding natural gas —that the U.S. is in a Sisyphean struggle to remain in balance with reserve declines.  The U.S. is trying to perpetually increase output to keep pace with growing demand while ore reserves and quality are declining.

Long term resource availability has not been a major factor in selecting boiler fuels.  Today, the higher efficiency and significantly reduced time and short run constructing costs of natural gas plants appear compelling.  However, given the limited nature of the basic resources (natural gas and uranium), the construction of natural gas (and nuclear) plants implies substantially increased financial and environmental costs in the long run.  Their construction is a temporary fix which in a reasonably short period of time will require replacing.  The replacement plants will be technologically advanced coal fired plants.  Absent prudent policy changes today, over the same time period the construction of additional plants could be necessary.

Dr. John Gever, et al, provides a realistic appraisal of future remaining coal reserves at less than 40 years.  The implication is that in less time than the life of plants built today, by the year 2045 most coal reserves will have been depleted.  As explained in the previous section on pricing economics, because costs of production increase as ores diminish, before the generating lives of these new facilities are ended the use of coal will become another energy sink requiring more energy to produce electricity or gas than the energy obtained from the coal.214

In addition to the issue of declining reserves is the declining quality (Btu input) of reserves and increasing cost to extract the ores.  The large reserve estimates are based on total coal deposits, ignoring the declining quality of the ores.  Lower quality ores contain significantly less energy.  The difference is analogous to burning lower Btu pine rather than high Btu oak in a wood stove.  The implication is that considerably larger volumes of ore are required to produce an equivalent amount of energy.  Increasing volumes also imply increasing environmental consequences.

Dr. Gever's research determined that the average energy content of U.S. coal declined 14% between 1955 and 1982.  Considering the energy used to extract, transport, and process the ores, the result would be that energy quality declines rapidly after 1967.  The available energy output continues to decline.  Moreover, as noted above because the higher grade and easy to mine ores will soon be depleted, mining will be increasingly difficult, expensive, and require effective and costly anti-pollution measures.  Because of generally higher quality ores previously available, the irony is that the net result of years of funding and research producing the improved efficiencies of modern plants has only returned overall generating efficiencies back to the levels achieved 30 years ago.

The good news is that coal reserves are in politically safer geographic locations (frequently Western nations), in substantially greater quantity than oil, natural gas or uranium, and generally produce less expensive electricity.  The other good news is that today's coal firing technology results in generating plants over 30% more efficient than earlier era models  —approaching 50% total efficiency.

However, the less good news is that coal mining requires large quantities of water, diesel fuel (petroleum), and often natural gas in mining and transporting the ores —via trains, barges, and trucks.  Coal mining requires large volumes of scarce water and has the potential of creating hazardous water pollution in the process.  Moreover, the better quality and abundant ores are generally found in water deficient areas in the western states.  Exacerbating the situation, oil provides about half of the fuel in coal mining and transport.  With diminishing natural gas and oil resources, coal’s price will increase.  The net is that there will be substantially less energy available from coal than first considered, yet significantly greater quantities over a longer time period than oil, natural gas, or nuclear power.

Because of coal's substantial role in generating electricity today and its likely future, the government is funding greater numbers of coal initiatives than any other energy source, more than $250 million in 2001 and about $320 million in 2002.  Increasing efficiency and decreasing emissions, new IGCC coal technology funded by DOE and scheduled to be operational by 2010 is engineered to produce electricity at overall efficiencies of 55% while reducing emissions of SO2, NOX and particulates to less than one-tenth of NSPS requirements.  The consumer cost of electricity produced is designed to be 10% to 20% lower than consumer prices of other new conventional models of coal fired plants.  Because of large reserves and despite higher cost than historically experienced, coal will play a significant energy role leading to a sustainable energy policy.  Coal gasification plants in particular, will facilitate the transition from natural gas allowing the number of natural gas plants to be reduced to sustainable levels and to meet its residential heating mandate.

The sharp price increases in natural gas and progressive increases of oil suggest the increasingly favorable economics of coal.  For example, summing the changes in the price of coal, in May 2002 the EIA/DOE stated,216

In response to the tight supply market during the year, the delivered price of coal reversed the downward trend that started more than a decade ago.  On an annual basis, the average utility price per ton of coal delivered to utilities rose by 2% percent in 2001, the price of coking coal increased by 4 percent, and the price of other industrial steam grew by 3 percent.  Reflecting further recovery in world coal export prices from the lows reached in late 1999 and early 2000 and the limited availability of coking coal in the international market, the average price of U.S. coal exports—measured in free alongside ship (f.a.s.) value— increased by 6 percent, while the price of coal imports rose by almost 13 percent.

If the construction scenario suggested earlier becomes reality, then mining costs would be substantially increased and the currently projected 40 year coal inventory would be reduced.  Although short term construction cost could be reduced, if coal (or similar energy bearing ore) were converted by liquefaction plants (GTL) to use oil for existing plants the efficiencies would be further reduced

An interesting sidebar to coal reserves is that the primary reason coal remains in quantity today is that oil and (to a lesser degree) natural gas displaced coal as the primary energy source.  If the rate of coal consumption had been maintained, then the U.S. coal supply would effectively have been depleted by today.  Dr. Albert Bartlett addressing this issue says that at the historic growth of coal use, 6.69% per year, U.S. coal would have been consumed before 1967 at the low reserve estimate.  Even under the optimistic estimate he reminds us that by 1990 the U.S. would have depleted its coal deposits.  He concludes by saying “the use of coal as an energy source … is possible only because the growth in the annual production of coal was zero from 1910 to about 1972.”217  When considering remaining oil, natural gas, and nuclear energy resources, the identical usage pattern applies.


Productivity

Efficiency is exceedingly important from a number of perspectives.  Higher efficiencies imply lower overall cost and fewer plants needed to produce the same energy.  The higher the efficiency the less the firing resources required, land, and environmental consequences.  If a generating plant is considered having an efficiency of 33% it implies that the energy equivalent output of two of every three of that class of plants will not be available to the end user.  It also suggests that the associated siting problems, construction, operating, and much of the additional infrastructure costs of three generating plants apply.

Efficiency also impacts the cost of remodeling or replacing old plants and the quantity of additional facilities constructed.  Oil plants are roughly 40% efficient.  The efficiency of coal generators is less than natural gas or nuclear plants.  With efficiencies higher than oil or coal it is self-evident why natural gas fired plants are built: they can be constructed quicker, require significantly reduced financial outlays, and because of higher efficiencies fewer plants are required to produce equivalent electric output.  However, this source of electricity is severely limited by natural resources.

Because the efficiency of modern coal generators approaches 50%, to replace old oil or coal plants with modern coal burning technologies suggests fewer total generators than previously.  The construction and retrofitting of old plants with modern plants implies that perhaps one of six or seven old technology plants could be scrapped with no loss of electrical generation.  The environment would be measurably improved.

One method proposed to overcome coal's lack of efficiency relative to oil or natural gas is to convert coal to natural gas ―coal gasification.  With current technology coal gasification is about 40% efficient, at best maybe 5% better than traditional coal plants.  In addition, with construction costs around $1.5 million per megawatt of capacity, gasification plants are approximately 2½ times as expensive as natural gas and approximately 25% higher than traditional coal plants.218  Thus, coal is not the hoped for perpetual motion machine.  It will, however, play a significant role in the trend to sustainability.


Other Problems of Coal

There is additional coal mining capacity for another approximately 10% increase in coal deliveries.  However if it is to be realized, the number of coal unit trains will need to increase.219  Nearly at capacity for the rails and number of coal cars, there are approximately 82-100 unit trains leaving Wyoming/Dakota every day.  The capacity hurdle can be overcome with additional funding, however, in the not distant future physical constraints will limit mining or substantially increase its costs.  The reserves will be available but increasingly difficult and expensive to obtain.  In other words, coal is a transition mechanism that growth can overwhelm.

Without retrofitting coal plants constructed in the 1950 to 1980 period with modern anti-pollution technology, coal's considerable contributions to global warming and its remediation costs will only be considered indirectly.  Grandfathered by pollution legislation years or decades after construction, anachronistic regulations are a leading contributor to greenhouse gases.  With relatively modest per kWh cost increases, the old plants’ environmentally unacceptable emissions can be brought into compliance with modern clean air standards.

Replacing outdated and uneconomic existing plants with modern high efficient coal plants will remedy many of the environmental problems of older models.  Because the older plants are fully depreciated for expense purposes, the electricity generated is among the lowest priced in the nation.  It suggests that the reduction in the number of generating plants and higher efficiencies are unlikely to overcome the higher costs of new construction.  The net price increase for modern plants is a consumer manageable 0.5¢ to 1¢ per kWh but with significant environmental benefits.

Mercury and CO2 emissions are primary concerns of coal fired plants.  However, these pollution concerns can be remedied with current technology.  Current scrubbing technology can reduce to safer levels or eliminate this form of pollution.  Worldwide, coal fired plants currently produce approximately one-third of the total atmospheric mercury emissions.  Accordingly to a report by Matt Little, policy analyst at the Northeast-Midwest Institute in Washington, D.C., “there is sound evidence that mercury emissions can be cut dramatically and cost-efficiently.”220

The EPA has established Maximum Achievable Control Technology (MACT) standards for municipal and medical waste incinerators to reduce mercury emissions by not less than 90%.  The EPA has estimated that up to 90% mercury reductions in coal plants may be required under the MACT standard.  98% of mercury emission reductions have already been achieved by some existing plants.  However, in February 2002 the Bush administration’s “Clear Skies Initiative” proposed mercury reductions of 46% in 2010 and 69% in 2018.  The increase is less than it appears.  Coal plants already eliminate 35% of the mercury as a result of using anti-pollution measures used to remove other pollutants.  Regulations for removing additional NOx, SO2, and particulates indicates that 46% of mercury —a minor improvement— will already be reduced by 2010. Costs of installing mercury controls have been estimated by the EPA range from 0.31 to 1.92 mills/kWh.  This cost is comparable to facilities to reduce NOx —burners (0.21 – 0.83) and selective catalytic reduction (1.85 – 3.62).222

The additional cost for reducing mercury at Xcel’s’ (NSP’s) 1968 Allen S. King Plant (on the St. Croix River in Oak Park Heights, MN), burning Powder River Basin lower quality sub-bituminous coal, by ADA Environmental Solutions in Colorado is 0.5 mills/kWh with 90% reductions.  Capitol costs are estimated to be in the $2.50 – $3 per kW range, or between $1 and $1.8 million.  Of interest, a coal plant under construction in Council Bluffs, Iowa is required to reduce mercury emissions by 83%.223

An all-inclusive solution to eliminating CO2 emissions is carbon sequestration.  Sequestration is a costly process capturing CO2 at the plant site.  Phil Amick, vice president of Global Energy is clear about the possibilities for sequestration.  He said that it “eliminates all CO2 emissions, but it increases the cost of electricity to consumers by 66 percent”. Because sequestration is an inexperienced technology, the consumer costs are uncertain, but a doubling of the approximately 1¢ per kWh estimated for pollution retrofitting would seem in the ballpark.  These costs must be included if pollution is to be at acceptable levels and energy efficiently allocated among competing economic groups.  With technological advances in sequestration and especially in coal burning efficiencies, only then will coal’s potential be fully realized.

 

Finally, coal plants leave the legacy of a radioactive core requiring careful disposal.  It explains why decommissioning nuclear and coal generating plants is a complicated and expensive development.

 

One wonders if the petroleum fired trains now used to transport coal great distances will devolve into the coal fired engines characteristic of an earlier era?  Economics and oil reserves support turning back the clock: operating costs of diesel or electric trains are more than double the cost of coal/steam trains.  Visions of those once mighty steam powered behemoths symbolizing freedom and national expansion still exert a romantic pull to some.

 

Nuclear Energy

With 109 nuclear power plants, the U.S. is the world’s major user of nuclear power —nearly one-quarter of the world’s total.  Initially promoted by the military and power industry as being “too cheap to meter”, nuclear power has failed to match its original billing.  On the other hand, in conjunction with coal, nuclear power will provide baseline energy to span the transition to a sustainable society.

Potentially increasing its relative electrical energy contribution, the current administration’s national energy plan appears to rely on nuclear power and hydrogen.  The Department of Energy states that the first objective is to “focus on the limitless potential of hydrogen to power our economy with virtually no adverse environmental effects” and the second is to “tackle a major hurdle on the long, tentative path aimed at ultimately releasing the potential of fusion to produce electricity—and hydrogen—in a safe, economical, and environmentally benign manner.”  The energy program also asserts that “these programs have the potential to substantially reduce, if not eliminate, our dependence on imported oil.”225  The Administration’s use of terms such as “limitless energy”, “environmentally benign”, and “eliminate oil dependence” suggests that science based writers played a minor role in writing the report.

Nuclear power is limited by uranium ores and other scarce natural resources used in plant manufacturing; its nuclear wastes problems are well known, but pollution is also evident in heating water and in ore extraction and enrichment.

The first four goals of the Department of Energy’s plan is to provide “Nuclear Weapons Stewardship” and nuclear energy and goal #7 states the Yucca Mountain depository will begin to accept nuclear wastes by 2010.  It also indicates a second nuclear waste depository (other than Yucca Mountain) is also contemplated.

The Senate legislation provides $35.5 billion for energy research and development.  It includes $1.7 billion for nuclear energy, $2 billion coal and $1.8 billion for hydrogen fuel-cell development.  Less known, it authorizes a new Alaska natural-gas pipeline and facilitates permitting for oil and gas exploration.  More than $15.5 billion in subsidies for energy efficiency and renewable energy are included.226

However, the Bush Administration's proposed energy policy will require a more comprehensive viewpoint if the nation is to adequately meet its looming energy dilemmas.

Worldwide, approximately 20 nuclear power plants are currently underway.  Reactors under construction as of December 31, 2002 are as follows:227

China

4

Finland

*

France

0

India

7

Japan

3

Russia

3

South Korea

2

Taiwan

1

U.S.

0

* one is planned for 2009

Other than Finland, the list doesn’t indicate the 11 nuclear power plants also planned in that time frame.  Japan’s goal is to have nuclear power provide 40.7% of the nation’s electricity by 2010.228  Both India and Japan have similar reasons ―lack of adequate domestic fossil fuels.

Nuclear energy should be seen as temporary and a last resort to resolving energy dilemmas for a number of reasons.  Although the impending energy needs are large, the economics and morality of nuclear power make a compelling case against further development.229

Uranium mining carries many of the same negative consequences as coal but add the seldom-mentioned additional difficulty of safe disposal of hundreds of thousands of tons of radioactive tailings from mining and ore processing.  Of more practical significance is that the resources necessary to construct and operate nuclear power plants are unable to match the need.  Finally, from the political arena, nuclear power would never have been as successful, had not the government stepped in to limit liability from possible accidents ―the Price-Anderson Act.  Continuing this theme, the Minnesota Legislature passed “Eminent Domain” legislation as a means of circumventing local interests when siting new nuclear and other energy developments.

That the public considers living near a nuclear power plant undesirable is a telling example of its safety concerns and lack of public support.  It's a classic example of NIMBY.  The radioactive components are hidden behind thick-walled concrete bunkers while waste heat is dissipated using huge cooling stacks or hidden underground in pipes emptying into local rivers, lakes, or oceans.


New Plants & the Morality of Wastes

The implications of a build-up of nuclear plants are consumer price increases, re-allocation of existing energies, and intergenerational waste conflicts.  Because nuclear power facilities require enormous quantities of energy to construct the facility and to fabricate nuclear fuel, the energy costs to construct and operate large numbers of nuclear plants in the near term would require siphoning scarce energy from other economic areas.  Even more efficient and operationally safer pebble bed reactors entail serious waste disposal issues, and increased opportunities for terrorism.  The flow of funds to nuclear power will also reduce potential funding of yet more expensive alternative energies, pushing alternative energies down the priority ladder.  Because economic price signals would be at odds with trends, government pricing policies would be necessary.  Having said the preceding, it is also important to state that in less than a decade the benefits of existing nuclear power plants will become increasingly apparent to consumer pocketbooks and energy system reliability.

The Bush Administration will want to reconsider its energy policy.  In comparison to the building of all the pyramids of Egypt and The Great Wall of China, the construction of nuclear power plants to provide new and replace old non-nuclear generators makes these structures a minor-league task.  To replace existing non nuclear produced energy (typically fossil) with nuclear energy would require a mind boggling number of nuclear plants, a minimum of 1,200 and possibly up to 1,900.  The numbers indicate that even with conservation, a compete nuclear power system would be required to be constructed every week for the next 20 or more years.

If half of the additional U.S. electric generating plants now planned within the decade were nuclear, as some propose, then 150 of the conservatively estimated 300 (possibly more than 400) or more generating facilities would be nuclear.  That level would imply the construction of a complete nuclear plant and associated infrastructure every three to four weeks for over 10 years.

Because the life of a nuclear facility is 30 to 35 years, it implies that more than two additional nuclear generating plants will be necessary to provide electricity for a baby born today.  The dollar cost of these developments is literally beyond imagining.  In addition, the siting problems would be staggering, construction a logistical nightmare, and the required staffing and skill levels impossible to fulfill.  Each plant will require dismantling its highly radioactive sections and shielding it from the environment in perpetuity.  It also implies that land now used for growing food or other development is destined to become a nuclear energy facility.

The identical land situation is applicable to all other proposed forms of baseline energies and incomparably worse for windpower.

Nuclear power advocates rarely consider the costs and risk associated with routinely transporting highly radioactive wastes crosscountry and storing it in depositories.230  The Yucca Mountain depository is a political solution using gerrymandered science.  With already subscribed (stored) nuclear wastes, the site will be filled within 30 years of its opening.  The planned expansion up to its maximum capacity will be fully subscribed by additional wastes accumulated within the 15 years prior to its opening.  The potential for destroying an underground aquifer must be considered a serious hazard.  Earthquakes even in what are considered stable regions such as Yucca Flats, are a disturbing probability over the required storage period.  The probabilities of only a single waste canister or salt dome leaking its contents into a ground water or river system becomes a certainty over many generations.  Because the material will be readily accessible —and near bomb-grade— Yucca Mountain can also thought as a storage for nuclear weapons material.  Los Alamos is not far from Yucca Mountain.

Moreover, the probability of a nuclear reactor catastrophe or terrorist act becomes a certainty with increasing numbers or time.  Once done, the devastation is permanent, widespread, and there is no turning back time.  Offshore nuclear developments suggests that sensitive materials will become increasingly available for radical groups.231

Benefiting current electricity users in a moment of geologic time, the production and storage of nuclear wastes will burden hundreds or likely thousands of generations to follow with the maintenance of the longest lived deadly waste substance known.  Placing those unparalleled Biblical requirements in perspective, note that humans have been significant in the world scene for merely two or three hundred generations, the “modern era” only six, and the nuclear period less than two generations.

If there is a return to lower living standards as projected, will society have the financial wherewithal and will to maintain the indispensable protections in perpetuity?  Do present electric users and governments have the moral right to obligate future generations in this manner?  Does the single generation that benefits have the right to saddle all future generations with its wastes?  Won't current children then grandchildren and their descendents wonder why today's societies’ chose to ignore a progressively deteriorating population/resource imbalance?


Efficiency

Dr. Gene Tyner, Director of the Oklahoma Institute for a Viable Future, researched the energy flows of nuclear power and concluded under optimistic assumptions that approximately two decades are required for nuclear power to have a positive net energy contribution.  Under more typical assumptions, the breakeven point is half-again that for the optimistic scenario.  When traditional fossil energy forms yield more that 40 : 1 energy return, the 3.8 return on nuclear energy over the life of a plant implies a staggering cost change.  Demonstrating its ability to generate electricity, in a 100 year growth scenario, 4.67 quads of net positive energy, electricity, were generated each year.232  The price of electricity was determined to be approximately 7¢ per kWh in today’s dollar.  Explaining the relatively low net energy is that in the early years high fuel production costs and substantial energy requirements were evident while in later years decommissioning and waste considerations became the deciding condition.  On the other hand, in a windcommerce study, discussed later, the net energy produced was found to be negative and more expensive.  Tyner concludes, “any expectation that nuclear power will be a viable substitute for fossil fuels is, at best, questionable.  Such an undertaking appears to be nothing more than a roundabout way of consuming fossil fuels —perhaps, an investment in the storage of a small amount of fossil fuel in a relatively dangerous form.”232

The research by Dr. Tyner refutes claims that operating cost for nuclear production is favorable —they frequently overlook the full cost involved.  The subsidies include research, design and construction of plant and transmission facilities, fuel production, water or air subsidies (free use of the commons), accounting strategies for waste and storage, or decommissioning.  The subsidies are discussed in the concluding section on nuclear power regarding the Price-Anderson Act.  Most would agree that subsidies are generally appropriate to early development stage energies.


Pollution

A frequently heard selling point for nuclear power is that it is pollution free.  Yet, nuclear plants use freely the commons of air and water.  Because they require vast quantities of water for cooling they are sited near large water sources.   Water pollution in the form of heating is a serious matter and the possibility of contamination always present.  The same holds true for air as the massive cooling stacks vividly demonstrate.  In colder climates, the exhaust plume rises thousands of feet and disappears into the horizon, very much a cloud produced by nuclear power.

The argument is made that nuclear generators do not produce greenhouse emissions and thus do not contribute to global warming.   Speaking for the Administration, Vice President Cheney was clear about this when he said on CNN that nuclear power “doesn't emit any carbon dioxide at all.”233

While it is accurate to say nuclear plants do not directly emit greenhouse gases, nuclear energy is a multiple step process with each process, notably enrichment, emitting significant quantities of greenhouse gases.  The entire cycle may contribute four to five times as much CO2 as renewable energy sources.

As Dr. Tyner suggests, the process is exceedingly energy intensive relying on electricity generated from fossil fuel plants.  The fact is, states Mark Cohen, that the “enrichment process is so electricity-intensive that when nuclear power plants were being built in this country in the 1950s, new coal-burning plants were also constructed for the sole purpose of powering the nuclear enrichment stations.”234  The environmental consequences of coal generating plants are therefore embedded —yet generally hidden in the costs of nuclear power.  Legislation passed over the years regarding these old energy intensive and polluting coal plants generally have grandfathered exemptions from clean-air standards.  Thus, nuclear power carries a legacy of the foulest of all air pollution and its pollution redirected to the coal fired electric industry.

Because of energy intensive processing, the economics of nuclear power will be increasingly in dispute as cheap oil and coal are replaced by higher cost alternative energies.  In a circular fashion, those replacement alternative energies are themselves dependent on inexpensive energy for their development.  With cheap oil arriving at an inflection point, the economics of relative energy costs using net energy analysis will become paramount.


Ore Resources

Nuclear development is limited by the basic resources used in the construction of the plant and fuel ores used to “fire” the boiler to generate the electricity.  Despite the position of nuclear energy proponents that there is a nearly boundless supply of nuclear resources, nuclear energy requires a very scarce and expensive resource, uranium (U-238 =>U-235), chrome used in the manufacture of, and helium to operate the generating plants.  The resource requirements of the proposed new plants mentioned earlier greatly exceed the availability of necessary resources.

The rare earth metal, chrome, for example, is required to produce stainless steel throughout the nuclear facility.  Even without the construction of numerous nuclear power plants, chrome will be exhausted early in the next decade.

Perhaps the primary reason nuclear power has been successful has been the 1996 “Megatons to Megawatts” program between the former Russia and the U.S.  In that program high grade “ores” from scrapped warheads were shipped to the U.S. for its nuclear power industry.  That source generated approximately 10% of nuclear power in the U.S.  Uranium is a relatively scarce ore, about three to four parts per million in the typical ore deposit.  If the ore is 0.3% fissionable U-235, then approximately three pounds are extracted from refining one thousand pounds of ore.  After mining, the ore must undergo extensive processing in order to fuel a power plant.

A miniscule fraction of uranium ores are high grade (2%) and the U.S. has only 3% of total recoverable ores (not only high grade).  Canada has 14%, Australia 28%, South Africa 10%, and Russian States 25% of total uranium ores.  The most optimistic of assumptions may have been made by the source in preparing this information, the Uranium Information Centre (an Australian trade association for Australia’s uranium mining industry).235  Considering all sources, as of 1999 there were approximately 3.1 million recoverable tons of uranium ore.  Excluding military stockpiling and use, nuclear reactors use more than 65,000 tons each year.  Thus, excluding the military and assuming no increase in nuclear reactors, at best there remains less than 47 years before ores are exhausted.

The world has slightly more than 400 operating nuclear power plants at this time.  On average each facility requires 163 tons of ore per year (65,000 ÷ 400).  If only 100 additional nuclear facilities were constructed, they would require 16,300 tons of ore each year and over a 30-year life, 488,000 tons.  In other words, the construction of only 100 nuclear power plants will move forward in time by seven years the exhaustion of uranium ores —to 40 years (before 2040).  The addition of 200 plants implies the exhaustion of the world’s uranium ores in approximately 32 years (before 2032).

In the heyday of nuclear power development, the life of the basic fuel was estimated to be roughly 30 years at then current use rates.  With that 30 year supply, the U.S. was thought to have among the largest deposit of ores in the world.  Obviously, the 30 year period has been significantly reduced in the intervening decades.  It was reported in the EIA’s 2002 uranium report, that U.S. uranium declined every year of the last six years.  The EIA said that U.S. uranium production was 2.3 million pounds in 2002, “11 percent below the 2001 level and 63 percent less than in 1996.”236

One suspects that with the proliferation of nuclear use by the military and other uses, the available ores has also been materially reduced.  Any proposed increase in nuclear generating plants will substantially reduce even the limited time horizon now clearly coming into view.

The high quality ores are nearly depleted at this time.  Lower quality ores imply greater quantities of ore materials extracted, increasingly difficult and higher costs of extraction, and higher energy consumption, and costs of processing rise in tandem.  The lack of quality ores supports that nuclear energy costs and energy output comparisons based on earlier models will be increasingly misleading.  Of consequence, much of the remaining ore supply is located on the “other side of the world” and its use would either require transporting enormous volumes of ore or local processing and shipping the concentrated radioactive material around the globe.  Local processing entails the construction and staffing of the large-scale energy facilities used to produce the energy consumed in uranium processing for export and sound environmental policies for the enormous volumes of waste material.

Thus, any consideration for constructing new nuclear power plants should include very high costs of initial construction, and operating costs rising as ores are diminished until becoming prohibitively expensive, in turn compelling shortened operating lives.


Fusion

It is not hyperbole to state that if status quo living standards are to be maintained then the energy transition hinges on the rapid discovery and development of fusion or the fast breeder reactor.  Literally, planet Earth has been fuelled by fusion since inception: nuclear fusion energy from the Sun photosynthesized by plants and converted into other energy forms.  Because of the limited resources supporting nuclear energy, if it is to be an energy partner in another decade or two and possibly sustainable, then fusion or the fast breeder reactor is necessary.

Absent that longed-for scientific breakthrough and its rapid development, however, changes in life styles will be required to conform to the new energy realities.

The technological optimist's answer is fusion, the wished for perpetual motion machine.  Fusion is another technological pipe-dream being developed with a $4 billion government plan to produce a vitamin pill size reaction.  Although nuclear energy proponents have continually maintained fusion's inevitability is just around the corner every year 20 years away, the technological complexities are such that if it ever succeeds, it will require another two decades to develop.  In that time frame all existing baseline energies will be at or approaching exhaustion.  With research funding second only to coal, the government feels the expensive effort is worth it, $250 million of funding in 2001 and 2002.

Yet, after investing billions of dollars over decades in the vain attempt to find the technological key to the fast breeder reactor, the effort has been a technological flop the U.S., France, Germany, England, and Russia have seen the light that its time cannot come —have begun to give up.

Even if successful, there is one potential drawback of these plants that cannot be avoided: they produce plutonium.  Plutonium is the terrorist's #1 choice for bombs and worse, has the potential for massive-scale nuclear-poisoning.  If breeder reactors became common, there could be large numbers of generating plants making bomb materials, some of which would be in unfriendly regions.

Pebble Bed reactors mirror all the concerns of the typical nuclear generating plant and add unique problems.  The positive aspect of Pebble Bed reactors is that they are one-fifth or less the scale of a typical nuclear facility.  Thus, a reactor can be sited in a smaller area or several can be connected in a series on the same site.  The fuel itself is encased in two to three inch balls and refueling doesn’t require the shutdown of the plant.  Similar to lack of chrome for nuclear plant construction, proposed Pebble Bed reactors require helium, a gas, for heat exchange.  In less than 15 years at current use, U.S. reserves will be depleted.237  As stated previously, any increase in use will significantly shorten the life of the available helium.  The greatest and ultimate distinction is that the breeder reactor could use the “wastes” from current nuclear reactors and would turn relatively abundant U-238 into fissionable Pu239.

Much of the foregoing is hypothetical.  Generating electricity on earth on a sufficient scale by controlling the same nuclear reactions as at the center of the Sun has been found to be a significant technological challenge.

The public may wonder what a core meltdown would look like.

 

Price-Anderson Act

Were it not for government subsidies, there wouldn't

be one nuclear power plant in this country.
      Mark Cohen, 2001.239

Nuclear power would not exist were it not for the Price-Anderson Act limiting the accident liability of nuclear plants.  The Price-Anderson Act shifts the liabilities of a nuclear power accident from the utility and the government to the local survivors of a mishap.  The current Act expired in August 2002.

Today's reincarnation of the old Price-Anderson Act (Atomic Energy Act of 1954) is the interestingly titled “Electricity Supply Assurance Act of 2001”, H.R.1679 (Senate version, S 1360 IS).  The Act is being carried by Rep. Barton (Texas), Chair House Energy Subcommittee who intends to use a “fast-track” approach to move it through Congress.

The Act provides a number of benefits to the nuclear industry.  Similar to that seen in the recent Minnesota energy legislation, Sec. 13-B provides that the Nuclear Regulatory Commission “must streamline processes wherever possible” in order to provide rapid responses to issues placed before the agency.  In addition, the Act pays all user, application, and approval fees increasing capacity, provides $15 billion per year for capital improvements, pays for college education related to nuclear power, and $60 million per year to market nuclear power plus another $15 million per year industry for “optimization efforts”.  The nuclear industry certainly has a large government funded public relations program!

Nevertheless, the heart of the legislation is its assumption of liability for accidents.  The Act sets maximum company liability at $20 million, indemnifies every party up to $10 billion, and eliminates civil penalties for those in involved in the industry.239

It is clear that nuclear power is limited by scarce resources, inordinately expensive, and comes laden with unrelenting epochal safety concerns.  Perhaps the best nuclear energy policy is to channel funds from the nuclear power industry into more cost efficient coal and other technologies which meet safety requirements, are environmentally forgiving, and sustainable.

Part I discussed energy growth and population concluding that growth must be arrested.  Part II discussed reliance on baseline energy resources and contributions to a sustainable society.  The conclusions were that natural gas supply is at a critical juncture, oil production is peaking, and nuclear power has resource limits and unmanageable wastes.  Although more expensive than in the past, coal will play a substantial role in the transition to a sustainable society.  Part III discusses possible solutions to energy problems discussed in Part II.  A discussion of conservation and various proposed energy alternatives is made; and energy, food, the California situation and its Minnesota similarities, and related real-life examples follow in Part IV.  A determination of Minnesota's (and by implication, the nation’s) future energy needs and costs is done in Part V.  Conservation has a proper role in resolving energy dilemmas but rather than the panacea thought by some, if not implemented wisely, leaves society in a more precarious position than if conservation were not practiced.  Similarly, the alternatives of tar sands, oil shales, and hydrogen are unlikely to significantly replace existing mainstream energies.  Windpower has potential to be a contributor, but only with substantial environmental tradeoffs and only as a minor, costly and unreliable energy player.  The conservation and alternative energies section closes with a discussion of agricultural biomass and energy —primarily ethanol, methanol, biodiesel, and wood.  An evaluation of these technologies concludes that the manufacture of energy using farm biomass is unwise energy and farm policy.
_____
Used with permission of Dell Erickson
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