Online Journal for E&amp;P Geoscientists

Figure 1. World liquid hydrocarbon recoverable reserve estimates by region. Source: Dr. Ken Chew, IHS Energy, Geneva.

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Figure Captions

Figure 2. OPEC quota and production patterns 1996 through October 2002.

Figure 3. World natural gas resource estimates. Source Dr. Ken Chew, IHS Energy, Geneva.

Figure 4. North American gas production projections without new post-2000 drilling.

Figure 5. Current North America gas market. Regional supply and demand volumes indicated by diameter of the bubbles. Transportation network is diagrammatic.

The petroleum industry is faced with challenging oil demand scenarios. Industry’s ability to meet the challenging demand forecasts is clouded by conflicting and confusing information about oil supplies. According to the U.S. Energy Information Agency’s 2002 outlook, assuming normal economic growth, global oil demand is forecast to hit 118.9 MMb/d in 2020. This represents a 56% increase (43.3 MMb/d) over 2000 demand. U.S. oil demand forecasts are less robust, but still project about 31% growth to 25.8 MMb/d in 2020. In the UK, Dr. Colin Campbell (2002) and his followers predict, on the other hand, that it will not be possible to achieve these targets. They project that global oil production will peak and begin an irreversible decline near the end of this decade. Such predictions draw substantial attention from the press, but analysis indicates their numbers are based on limited data and reflect a conservative bias.

A recent assessment by Dr. Ken Chew, using IHS Energy’s databases (with data on more than 20,000 oil and gas fields) and USGS studies, presents a different world oil supply outlook. The results are shown by region in Figure 1. Starting at the base of the bar charts, the sum of estimated discovered conventional liquids at the end of 2001 was 1,112 billion barrels. The Middle East holds over half of the world’s remaining conventional oil reserves. The next component, reserves growth, a well-documented factor, is expected to add 373 Bbo. The importance of Canadian oil sands and Venezuelan tar sands is indicated by the bright green segments of the bars for North and Latin America. About 560 Bbo are potentially recoverable from these sources. Thus, Western Hemisphere liquid resources, though higher cost to produce, are larger than those in the Middle East. Adding the USGS estimate of 803 Bbo of yet to find undiscovered conventional liquids yields a total world estimated remaining recoverable resource of 2,848 Bbo. This is more than twice the estimate by Campbell (2002) of 1,027 Bbo that is used as the basis for predictions of pending oil supply shortfalls. Consequently, the case is presented that there are sufficient remaining recoverable liquid hydrocarbon resources to meet projected world oil demand through 2020.

Worldwide exploration results over the last twenty years, however, indicate that a substantial change in petroleum industry strategies, investment patterns and activity must be anticipated. International data show that hydrocarbon discovery volumes peaked during the 1960’s and 1970’s but the number of discoveries didn’t peak until the 1980’s. Since 1980, the average discovery field size has been less than half the average field size discovered from 1921 through 1979. Correspondingly, only 385 discoveries were recorded outside of North America during 2001 compared to an average or 550 per year during the 1980’s. Moreover, since 1980, more reserves have been brought on stream than have been discovered. The world’s discovered but non-producing oil resource base is shrinking. Obviously, this trend cannot continue if oil demand forecasts are to be met.

In the U.S., a similar pattern is observed in oil and gas well completions. Since 1985, only 20,400 average annual U.S. oil and gas wells were completed compared with 52,000 per year over the prior six years. Oil well completions dropped precipitously, averaging only 10,400 per year since 1985 compared to 39,000 per year over the prior six years. This trend has direct implications for U.S. oil supply security. U.S. oil production decreased from 7,417 Mb/d during 1991 to 5,848 Mb/d during 2001. Over the same period, petroleum liquids imports increased from 7,627 Mb/d to 11,607 Mb/d. This trend is likely to continue, meaning increasing reliance on risky foreign sources and worsening balance of payments for imports.

Oil market volatility is another concern. Since 1996, the world has suffered two negative economic cycles that were accompanied by depressed oil demand and prices. These cycles substantially impacted petroleum industry investments and stability. OPEC plays a critical role in managing its production quotas to balance oil production with supplies. Their objective is to maintain oil prices in a range ($22 to $28) that meets member countries’ income needs. The price band also has stimulated investments to expand non-OPEC production. This is needed to meet long term demand projections but adds to excess supply problems during periods of economic weakness.

Iraq is the wild card in the oil supply picture. The chart in Figure 2 shows periodic changes in OPEC and Iraq oil production patterns from 1996 through October 2002. OPEC production quotas are bright green, estimated over-production is dark green and Iraq production, which is exempt from the quotas, is in red. During December 1997, OPEC boosted its quota by 1 MMbo and also over-produced by 1 MMbo. This production entered the market at the same time that Asian economies began to slump with resulting reduction in oil consumption. This precipitated the 1998-1999 oil price collapse, which did not turn around until the end of 1999 when quotas were reduced by 4 MMb/d and over-production was held below 1 MMb/d. OPEC’s task was exacerbated by Iraq, which boosted its production by 1.7 MMb/d to 2.8 MMb/d over this same period. Quotas were raised to 26.7 MMb/d during 2000 but weakening economies coupled with September 11 shocks reduced oil demand and forced OPEC to lower its quotas to 21.7 MMb/d to sustain 2002 prices in the target band. Iraq’s unpredictable and often contrarian politically motivated production policies are reflected in the variations in its periodic monthly production volumes since 1999.

So what are the likely impacts on U.S. oil prices and imports in the event of a war on Iraq? While initial reactions to a war could trigger a jump in oil prices and elevate concerns about oil supplies, these are likely to be short-lived, provided the conflict is brief, does not expand beyond Iraq and is backed by the International Community.

The OPEC 10 have pledged to cover any short falls in Iraqi exports. During 2002, Iraq exports have averaged about 1.5 MMb/d with occasional weekly peaks reaching as much as 2.8 MMb/d. The OPEC 10 has sufficient excess production capacity to cover even Iraq’s maximum production capacity.
Impacts on U.S. oil imports should be minimal. The U.S. already has significantly reduced its oil imports from Iraq* and is strengthening alliances with other oil producing countries, such as those in West Africa, to assure more stable oil supplies.

(* According to EIA data, Iraq imports averaged 778 Mb/d (7% of total) during 2001. YTD through August 2002 Iraq imports decreased to 525 Mb/d (4.6% of total) and during August slumped to 246 Mb/d or 2% of total imports.)

Following a war, it likely will take some time to rebuild Iraq’s production to current levels. After several decades of production and little investment, Iraq possesses a number of large fields that are now in urgent need of rehabilitation. While it will be important to restore Iraq’s economic health, it will be critical to do so without flooding oil markets so to trigger an oil price collapse. Non-Middle East producers like Russia, Caspian countries of Kazakhstan and Azerbaijan, Nigeria, Angola and Algeria have been expanding their productive capacities and also are pressured to increase their exports and revenues. OPEC likely will be challenged to manage its production to balance demand.

U.S. Oil Supply and Policy Issues - Summary

Key issues that are addressed in the foregoing discussion include:

There are adequate oil supplies to meet global oil demand projections through 2020. Consequently, there is time for an orderly market driven shift to alternate energy supplies.
To address oil supply security issues the U.S. must:
1. Consider policies to support a healthy domestic oil exploration and production industry. Policies must improving access to prospective lands; provide investment incentives such as tax credits and royalty relief for developments in frontier areas; and create efficient regulatory processes that do not impede compliant developments on public lands.
2. Diversify its sources for oil imports in order to reduce dependency on high- risk regions like the Middle-East. Perhaps it is time to consider enhancing policies and alliances to champion development of the large unconventional oil resources in our Western Hemisphere neighbors.

Natural Gas Demand and Supplies

Natural gas is the challenge of this decade. Global gas demand growth, driven by pressures for clean energy, is expected to surpass that of oil. According to EIA 2002 estimates, world gas demand will increase by 78% to 162 Tcf/yr in 2002. U.S. gas demand growth, which is forecast to grow 50% to 33.8 Tcf/yr in 2020, also represents a challenge to producers. Even though there is a huge volume, about 800 Tcf, of discovered but non-producing (so called stranded) global gas reserves, the task to develop and deliver this gas to users is more complicated and expensive than for oil.

The chart in Figure 3 shows Dr. Ken Chew’s (IHS Energy) recent estimate of global recoverable natural gas resources. Two regions, the Middle East and the Former Soviet Union (FSU) dominate world natural gas resources. The lowermost orange part of each bar represents the remaining amount of reserves already discovered. The Middle East, with huge amounts of stranded and low cost gas, has the largest gas reserves. The black part of each bar represents estimated reserves growth. This component is large in North America due to conservative methods of reporting reserves. The dark orange part of each bar represents USGS estimates of yet to find gas resources. The FSU and Middle East lead in this category. The uppermost red part of each bar represents cumulative gas production. The plight of North America’s gas situation is registered by the fact that almost half (48.5%) of the estimated ultimate gas resource already has been consumed. Overall global gas resources, though, are substantial, totaling 11,750 Tcf, a 124-year supply at current consumption rates. This bodes well for the potential to meet projected worldwide demand for this clean fuel.

North American Natural Gas Supply and Demand Issues

North America will continue to be one of the world’s most important gas markets. With 7% of the world’s population, North America consumes 31% of the world’s gas production. Based on EIA 2002 demand estimates, North American gas supplies would add as much as 11.7 Tcf of new gas per year by 2020 when consumption still would equal 21% of the world’s gas production. (EIA’s preliminary 2003 forecast reduces 2020 gas demand by 1.7 Tcf due to projected higher gas prices.) Growth of the North American gas market will impact the global gas business and merits serious long-term policy considerations. Potential Gas Committee (PGC) 2000 gas resource estimates for the U.S. are in line with IHS Energy numbers. PGC mean probable and possible (2P) gas resource estimates equal 610 Tcf. PGC’s total mean U.S. gas resource, including speculative volumes, equals 1,091 Tcf. The Rocky Mountains, with estimated 187 Tcf 2P gas resources, has the largest regional U.S. gas resource and is followed in succession by the Mid-Continent, Onshore Gulf Coast, Alaska North Slope, Offshore Gulf of Mexico and Appalachian/Atlantic Coast regions. Of interest, the U.S. EIA 2002 natural gas forecast targeted these regions, led by the Rocky Mountains plus Canada, to deliver most of the new gas supplies needed by 2020. As part of this review of North American gas supplies it is appropriate to assess key factors that could impact fulfillment of EIA’s outlook.

Tightening North American gas supplies has been exemplified by volatile prices, which culminated during December 2001 when spot gas prices soared to $10 per Mcf. A few key factors explain the tightening supplies. First is a slump in exploration activity. As a result, at no time since 1990 have annual North American gas reserve additions equaled the estimated 32 Tcf of raw wellhead gas production during 2000. North American reserve to production ratios are decreasing. If frontier (mostly arctic) reserves are excluded, the U.S. plus Canada reserve to production ratio barely exceeds 7 years.

In addition, as shown in Figure 4, production decline rates from existing North American gas fields are very high. The chart indicates that if gas drilling were to cease, North American gas production would plunge from about 96 Bcfd to only about 25 Bcfd by 2010. With gas demand possibly hitting 110 Bcfd in 2010 this means that as much as 85 Bcfd or 77% of 2010 gas supplies must come from new wells or other external sources. Clearly, economic incentives and supportive energy policies will be needed to sustain the high levels of industry activity required to deliver the new gas supplies.

Let’s review gas supply parameters for the key sources that are expected to deliver most of the gas production increases to meet 2020 North American demand forecasts.

Onshore Gulf of Mexico, Mid-continent and Appalachian Basins

Canada

Vintaged gas production plots indicate that Western Canadian gas production reached a plateau, with peak capacity of about 21.5Bcfd, in spite of near record gas drilling over the past three years. Gas productivity as measured by average peak production has declined (about 40%) and production decline rates have accelerated (> 160%) since 1990. More than twice as many gas wells must be drilled now just to deliver the same amount of new production. A concern is the fact that August 2002 year to date (YTD) western Canada well completions were 21% less than 2001 YTD numbers. This is expected to reduce near-term gas supplies.

IHS Energy’s Gas Business Model indicates that Western Canadian gas production likely will not increase if the gas price does not exceed $3.00 per Mcf. The model also indicate that $5.00 per Mcf gas would trigger investments to tap the 27 Tcf gas resource in the Arctic McKenzie Delta region and could boost combined Western Canada gas production to more than 30 Bcfd by 2010. Of course, the price to generate sufficient drilling to balance supplies with demand lies somewhere between these extremes. In Eastern Canada, meanwhile, operators already plan to double pipeline capacity to produce and deliver 1 Bcfd from offshore Nova Scotia into the northeastern U.S. states.

Offshore Gulf of Mexico

Two years ago, deepwater Gulf of Mexico (GOM) was thought to have sufficient gas resources to supply most of the gas production increases needed to meet U.S. 2020 demand forecasts. The deepwater Gulf, though, has proved to be oil prone. Even though average deepwater monthly production per well has increased markedly, almost 8 times better over the past decade, deepwater gas production growth has not been sufficient to offset decreasing gas production in the more mature GOM shelf. This is due to huge (66% median annual decline) production decline rates and too few deepwater gas wells. It appears that more than 100 active gas rigs will be required to sustain current GOM gas production volumes. The GOM will continue to supply a significant share of U.S. gas but economic incentives likely will be needed to stimulate drilling levels needed to increase overall gas production.

Each of these important gas producing provinces is targeted to add 1.25 Tcf or more of annual gas production in EIA’s 2020 forecast. And according to the PGC’s 2000 report, each of these provinces has substantial gas resources, ranging from 54 Tcf in the Appalachian basin to almost 99 Tcf in the Mid-continent region. (The Mid-continent region covers Oklahoma, Kansas, N. Arkansas, N. and W. Texas and SE. New Mexico.) Most of this resource, though, is believed to be in the deep, less-drilled parts of these provinces. IHS Energy studies in these areas indicate that gas reserves per well increase with depth but that average reserves per well within almost all depth intervals have decreased over the past 30 years. As a result, less than half of the deep gas wells (>12,000 ft.) completed during the last ten years would have generated more than 20% profit even with constant $3.00 gas. Deep wells are more expensive and there a few large operators who can afford to drill them. Smaller, independent operators predominate in these areas. They report that few, if any, shallow, low-risk gas prospects remain to be drilled. This, plus uncertainty about gas prices may explain why 1,500 fewer gas wells (- 24%) were completed through October 2002 compared with October 2001. In these regions, a decrease in gas well drilling quickly translates to a decrease in overall gas production.

Rocky Mountain Region

The Rocky Mountain region is believed to have the largest remaining onshore U.S. gas resource and is targeted by the EIA to add almost 2.7Tcf in annual gas production to meet 2020 demand forecasts. However, Rocky Mountain operators face several challenges that may negate the realization of these forecasts.

First, there are significant environmental and regulatory impediments. Following a decision by the Interior Board of Land Appeals (IBLA) to reopen considerations of Environmental Impact Statements on coalbed methane leases in the Powder River Basin the head of the Wyoming Outdoor Council commented: “Now that the PRB is 98% under lease, all in violation of NEPA, BLM has left us the only option of going after and voiding existing leases and existing drilling.” Similarly, ranchers, orchard owners and water companies in Delta County are suing the Colorado Oil and Gas Conservation Commission (COGCC) over the issuance of drilling permits for a proposed five-well coalbed methane project. These instances characterize the types of resistance that are delaying and even stopping legal rights to develop gas resources on public lands. The EIA has stated that 43% of Rocky Mountain gas resource is "unavailable for drilling due to environmental regulations, lack of pipeline capacity, or other barriers to development." US. Coalbed methane production may peak at around 4 Bcfd and begin to decline after 2006 unless procedures are in place to expand leasing and drilling in the large Rocky Mountain coalbed methane reservoirs.
In addition, the region also suffers pipeline constraints and an overall imbalance of the gas transport network. Pipeline expansions underway will increase capacity to the west coast rather than to larger and less volatile markets to the east and south. Due to this imbalance, pipeline tariffs from the Rockies are higher than those from competing supply regions and spot gas prices during periods of slack demand languish as much as $2.00 Mcf less than prices paid to producers in other regions.
IHS Energy’s North American Gas Business Model indicates the Rocky Mountain price differential may even worsen at higher gas prices because other regions will be able to more readily expand capacity. Thus, the current structure of Rocky Mountain gas transportation must change and price parity be established before it is reasonable to expect that producers will increase investments to exploit the gas resources. North American gas supply and demand nodes and generalized pipeline routes are illustrated in Figure 5. The diameter of the bubbles indicates relative sizes of regional supplies and demand. Even though Rockies gas production is growing, the relative small size of current production is evident. Expansion of the Kern River pipeline, which moves Wyoming gas to southern California may temporarily ease the transportation constraint, but a cure will require expansion of pipelines to move Rockies gas eastward to larger and more stable markets. Paradoxically, the large Rockies gas resource is at risk of being “stranded” at a time when U.S. gas supplies are tightening and LNG imports from outside the continent may win a significant share of the market.

Remote Gas Supplies

The Alaska North slope, with estimated 41 Tcf of proven gas reserves, and huge stranded global gas reserves, with estimated 500 Tcf that could be produced at a cost of about $0.50 per Mcf, also likely will contribute to future U.S. gas supplies. Pipelines to tap gas in the Alaska North Slope and Canada’s McKenzie delta are under consideration. Gas price volatility has delayed action and investors may need $4.50/Mcf gas to realize profits. Consequently, pipelines probably will not be in place until after 2010 when 4 to 6 Bcfd of gas could reach the Lower 48 states. Alaska officials champion such developments and the positive economic benefits that would accrue through developing and using domestic energy resources as opposed to imports. Arctic gas resources would provide an important plus to the North American gas supply picture. Nevertheless, the potential deliverable capacity of Arctic gas probably will not be sufficient to solve the supply problem.

IHS Energy’s Gas Business Model, in fact, indicates that imported LNG also must deliver an important part of the new gas supplies that will be needed to meet demand. Current U.S. regassification capacity at four facilities is about 2.8 Bcf/d and planned expansions could boost these to 5 Bcfd by 2005. Trinidad & Tobago, Algeria, Qatar and Australia are the prime current LNG sources. Expansions of these current sources and new LNG supplies from Peru, Bolivia, Venezuela, and Nigeria are under consideration. To handle these additions, new regassification plants are under negotiation for Baja, California, Tampico, Mexico and several locations along the U.S. gulf coast. These new facilities could boost LNG import capacity to 9 Bcfd by 2007. Planned LNG imports are expected to be viable with $3.50 and higher gas prices. A shift toward long-term contracts also would help to attract the capital needed for the LNG facilities supply chain. The diagram in Figure 5 supports the focus of regassification facilities along the gulf coast and possibly raises caution flags about adding too much capacity for the uncertain west coast market.

U.S. Natural Gas Policy Issues

Key issues that are addressed in the foregoing discussion include:

Gas supply issues are more urgent than those for oil.

– Drilling alone in mature producing provinces won’t meet projected demand growth. New wells have smaller reserves and production decline rates have steepened markedly over the past decade.

– Models indicate that gas prices alone, due to volatility, likely will not be adequate to attract the capital needed to assure adequate gas deliverability.

– Furthermore, it will take five or more years to build the infrastructure to tap North American frontier gas and new LNG facilities.

Policy principles to assure security for natural gas supplies are essentially the same as those for oil. Policies must address ways to improve access to prospective lands; to provide investment incentives such as tax credits and royalty relief for developments in frontier areas; and to implement efficient regulatory processes that do not impede critical gas developments on public lands.
To establish long-term gas market stability, balanced energy and environmental policies, gas prices in the $4.00 per Mcf or larger range and, following the melt down of gas marketers, more long-term gas contracts between producers and consumers will be required.

Conclusions

This presentation makes the case that there are adequate global oil and gas supplies to meet projected growth in demand through 2020. Substantial changes, though, in the structure of the global energy and oil and gas businesses likely will be required to deliver the supplies. In the case of oil, during this decade, producers must increase exploration activity to maintain new reserve additions in line with consumption. In addition to diversifying supplies and reducing dependency on high-risk regions like the Middle East, it is time to consider policies to expand development of enormous oil sand and tar sand resources in the western hemisphere. Likewise, the public must be aware that policies like increasing the percentage of ethanol in gasoline do absolutely nothing in regard to assuring there will be adequate gasoline (oil) supplies to do the mixing.

Global natural gas resources are enormous, but developing even low-cost stranded gas resources is complicated and expensive due to the need to build infrastructure to deliver supplies to consumers. The U.S. faces a paradigm shift in regard to natural gas. For the first time, the U.S. will become increasingly dependent on natural gas supplies from outside of North America. Therefore, energy security and a clean environment are increasingly important public policy issues. It was not the objective of this paper to examine issues and arguments posed by conservation and environmental interests. Suffice to note that to serve public interests, balanced policies are needed to assure that adequate secure energy supplies are produced in harmony with environmental concerns. Important global and U.S. energy supply factors and policy matters that should be considered in order to assure adequate energy supplies are outlined in this presentation. One final sobering thought. It is estimated that as much as $3 trillion capital investment will be required to meet projected 2020 oil and gas demand. Energy policies also must be framed to help stabilize markets so that investors can realize a fair return. Otherwise, capital will be a constraint and will add to the problem of delivering energy needed to fuel the global economy and improving life styles.

Reference

Campbell, C.J., 2002, Forecasting global oil supply, Submission to H.M. Government consultation on energy policy.