Dell Erickson

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

“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 2^nd quarter of 1998 through the 2^nd 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 & Company⁶¹

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 

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

“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), no