uRetrospective

uFigure captions

uOil and gas supply, demand, and price outlook

tOil commentary

tOil benchmarks

tNatural gas commentary

tNatural gas benchmarks

uIndustry trends 

tIndustry trends commentary

tIndustry trends benchmarks

uSummary

Figure Captions

Figure 1. Crude oil price vs. stocks

Figure 2. OPEC quotas and production

Figure 3. World oil demand 

Figure 4. World natural gas demand

Figure 5. US natural gas spot prices

Figures 6 and 7. Alberta normalized gas production profiles and US Lower 48 States vintaged gas production profiles

Figure 8. World regional rig counts (source: Baker-Hughes)

Figure 9. International exploratory well ends

Figure 10. International licensing activity

Figure 11. Global areas of interest

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 Oil and Gas Supply, Demand, and Price Outlook

The objective of this section is to present an outlook for the factors that will shape future industry trends.

Oil Commentary

Oil demand has depended on the strengths of global economies and prices, which, in turn, have depended on OPEC’s ability to control its supplies. Even though OPEC boosted its production quotas by 3.7MMb during 2000, the steep escalation of oil prices was propelled by slow build of oil stocks and realization that excess production capacity had shrunk to the lowest level since the late 1970s. During the first half of 2001, OPEC reduced its quotas as stocks improved and average US crude was $25.30 (WTI  = $28.30), right in the middle of OPEC’s targeted $22-$28 price band. Expecting a global economic rebound and higher oil demand, EIA forecasts WTI will average $28 again in 2002 but expects gradual price reductions in following years due to increasing production capacities. Several factors suggest, however, that production capacities may grow sooner than expected and that OPEC will be challenged to control production and maintain prices within its target range. First is the opening of global E&P opportunities. All but a few producing countries, including major OPEC producers, have (or are considering) programs to stimulate outside investments in their E&P sectors. Investments by majors to develop large OPEC reserves plus a global increase in exploration activity could boost global capacity by as much as 2 MMb/d during 2001 and OPEC plans to add 1 MMb/d or more for each of the next 4 years. Countries that add capacity likely will want to produce it, making it difficult for OPEC to maintain quotas and prices. In fact, OPEC is considering an emergency meeting to lower its September, 2001, quota by 1.0 MMb/d in order to offset resumption of Iraq exports and to boost prices into the middle of its target range. Volatility with downward pressure on prices could result, and we may experience additional roller coaster cycles over the next several years.

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Oil Benchmarks

Crude Oil Price vs. Stocks (Figure 1)

During the first half of the year OPEC succeeded in balancing production and stocks to sustain their basket crude marker price in the targeted $22 to $28 range. Correspondingly, OECD and US crude oil stocks recovered to normal levels (US >310 MMb) and WTI ranged from $26 to $30 during the second quarter. An unexpected drop in gasoline demand and resumption of Iraq’s 2MMb/d exports were cited as key reasons for recent declines in both crude and gasoline prices. 

OPEC is concerned about soft world oil demand and considers dropping its quotas to maintain its price floor. If, however, seasonal demand increases, excess oil stocks could be erased by October, and prices could strengthen into the 4^th quarter. EIA expects WTI to add about $2/bbl by 4^th quarter and to average $28 during 2002. Contrary to EIA projections, IHS data suggest that increased global exploratory drilling should boost production capacities and stocks during 2002. If so, OPEC will be stressed to maintain its price band.

 OPEC Quotas and Production (Figure 2)

OPEC’s decisions to reduce its quota from 26.7 MMb/d at the beginning of the year to 24.2 MMb/d on April 1, 2001, were critical to maintain prices within its target price band. Iraq officially suspended its exports during June, 2001, but was rumored to be moving as much as 400,000b/d through Syria. Iraq resumed exports (about 2.1 MMb/d) during July. In response, OPEC’s basket price tumbled to near $22. 

It now looks as though OPEC may have to reduce its quotas to maintain prices even though seasonal 4^th quarter increases in demand eventually may exceed 27.3MMb/d. New and proposed E&P investments could boost OPEC production capacity by more than 1MMb/d during 2001 and again in 2002. At issue is whether OPEC will be capable of managing its price band mechanism through 2002 while faced with increasing production capacities and whatever Iraq attempts to upset oil markets. The outlook is for continued volatility and a bias toward lower prices.

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World Oil Demand (Figure 3)

US and global oil demand have weakened in response to high oil and gasoline prices and slow economic growth. EIA estimates that US and world oil demand will increase 1.6% and 1.7%, respectively, during 2001, and each will add 0.1% to these rates during 2002. The most recent IEA forecast is more pessimistic. Foreseeing the possibility of slower economic recovery, IEA forecasts only a 0.5% world oil demand growth in 2001 and 1.1% in 2002. These modest increases in demand reduce the likelihood of a near-term supply crunch and price spikes. The EIA’s long-term outlook for 117.4 MMb/d (+55%) global oil demand by 2020, though, presents a challenge.

In order to achieve 117 MMb production, OPEC would have to increase its market share to almost equal non-OPEC production at around 58 MMb/d by 2020. Are there sufficient global resources, and can they be produced at an affordable cost to meet this demand? Some believe that global oil production will soon peak, and there is no way to grow production by 55%. Political reactions to reduce dependency on oil and to reduce greenhouse gases, though, could reduce future oil demand growth from the forecast.

Natural Gas Commentary

North America weathered last winter’s gas supply and price crunch, and the market is in the process of sorting out “what next”. Keys to the unexpected rapid recovery were fuel switching that cut winter demand by about 5 Bcfd, reduced industrial demand due to the soft economy, and mild spring weather that allowed record high storage refill rates. Gas storage, which was at record low levels during March, zoomed to above average levels by the first week of July and gas spot prices dropped by $2.00 to average $3.06 during July before declining below $2.40 by the end of August. Despite the rapid market adjustments, the US gas industry did not survive unscathed. Consumer trust and expectations have changed along with a reawakened conservation ethic. Some industrial users are gone, and others improved their fuel switching capabilities. Some planned gas fired power could be delayed, LNG import capacities are expanding, and policy makers are promoting development of frontier gas resources and other options. Prompted by latest indicators that 2001 U.S. gas demand could decline by 300 Bcf, EIA (September 2001) lowered its projected US average wellhead price to $4.20 in 2001 and  $2.65 in 2002. EIA believes that supplies will be adequate to cover predicted 4.6% (1.03 Tcf) growth in demand that would accompany an economic rebound in 2002. 

Recent extrapolations from IHSE databases indicate that even current levels of Canadian and US gas directed drilling could be pressed to cover a 1.03 Tcf increase. If so, US gas supply and demand margins would narrow and increase the likelihood for higher prices by the end of 2002. Projections indicate a 40% increase in gas drilling could boost 2001 US gas production by about 725 Bcf and western Canada could add an additional 200 Bcf. Barring aberrant weather, this should be sufficient to fill storage to capacity, supply new gas fired power plants, and satisfy normal demand during the 2001-2002 winter heating season. Projections indicate, however, that almost 1,000 gas rigs must be sustained to cover a 1.03 Tcf increase in demand. This is due to the rapid decline rates and trend toward lower reserves in recent gas wells. Moreover, it is expected that gas drilling will decrease in the face of wellhead prices below $2.50 /Mcf. According to Baker Hughes, September 7, 2001, US gas directed rig activity dropped below 1,000 rigs for the first time in 15 weeks. Continued declines in gas drilling activity would increase the likelihood of tighter supplies and higher prices if the EIA’s gas demand forecast is realized. It looks like natural gas spot prices could average about $3.90 /Mcf during 2001 and $2.25 - $3.00 (or lower!) during 2002. Supply/demand margins are precarious and subject to multiple variables. Bias toward the lower end of this price range could result through continued high levels of US and Canadian gas drilling, increased conservation, slow economic recovery, and continued moderate weather. Weather and distribution constraints, on the other hand, also could create significant short-term regional price spikes. Thus, the stage is set for possible near-term gas price volatility. 1,000 gas rigs could produce excess supplies, but 900 could produce too little. These factors speak to the need for rigorous economic planning models to guide industry on a smoother path.

Productivity changes in key producing provinces underlie long-term gas supply concerns. Production decline rates have accelerated over the past decade, the gas resource base has disappointed in some basins, and there is a tendency for average well quality to decline when drilling increases. In the Gulf of Mexico (GOM), the first year decline rate doubled from 27% in 1994 to almost 55% in 1999 and deepwater trends have tended to be oil prone. As a result, increases in deepwater gas well production from 1997 through 1999 added only 1 Tcf in annual production compared to 3 Tcf decline in production from the shelf. And initial year-end data indicate shelf production continued to decline during 2000 in spite of a robust increase (>50%) in gas completions. The annual base decline in offshore GOM gas well production is about 22%. This means that annual gas well drilling must contribute 900 Bcf in new production just to sustain production capacity. The deepwater Gulf may not be able to deliver the volumes required to meet demand forecasts. Similarly, deterioration in Alberta gas well productivity is evident in Figure 6 by significant increases in decline rates and decrease in peak production volume between 1990 and 1999. Correspondingly, the USGS in its World Petroleum Assessment 2000 dropped its estimate of Western Canada gas resources to 19 Tcf. This compares to an estimate of about 170 Tcf by a Canadian source. Gas productivity trends in the US Lower Forty-eight States present a mixed bag, as shown in Figure 7. First year average decline rates increased, but average new well peak production improved from1990 to 1999. However, these characteristics of mature producing provinces will not improve through time, and industry cannot just drill its way out of supply crunches. Thus, in order to meet long-term demand, gas supplies must increase through continued robust drilling in established North American producing basins, and new supplies like arctic gas and LNG imports must be tapped.

It is expected that international gas developments will continue to expand and will capture an increasing share of worldwide capital expenditures. Supplying the growing US LNG market and contributing to expanding liquids demand through GTL technologies could become increasingly important in selected international gas developments.

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Natural Gas Benchmarks

World Natural Gas Demand (Figure 4)

There is a major shift toward natural gas as the fuel of choice. As a result, world gas demand is projected to grow 77% to 161 Tcf/yr in 2020, and US gas demand is expected to grow by 55% to 34.7 Tcf/yr over this same period. EIA (September, 2001) believes that 2001 US gas demand could decrease by 300 Bcf or 1.3%. This is due to substantial fuel switching by energy intensive industries in response to high gas prices last winter, economic slowdown, and expectations that mild weather will continue. Industrial consumers, however, started to reverse the switching process when natural gas prices receded below the cost of oil during late April. Anticipating a pickup in the US economy and continued moderate gas prices, EIA predicts a 4.6% (1.03 Tcf) increase in gas demand during 2002. International gas developments will continue to expand in concert with demand growth.

US Natural Gas Spot Prices (Figure 5)

Several factors – reduced demand due to fuel switching and conservation, increasing supplies from new drilling, and mild weather - have combined to reduce market worries, resulting in a steep decline in spot gas prices since they peaked in December, 2000. Record injection rates restored working gas storage to 2.6 Tcf by the end of August. This is almost 7% above the 6-year average. Less than average injection rates will be adequate to fill storage to the desired 3 Tcf level before the winter heating season. Plots of May 8 and July 19, 2001, Gas Futures indicate the weakening market perception of prices through 2002. Unless there is a marked change in the weather, it looks as though natural gas spot prices could average about $3.90/Mcf during 2001 (down 9% from 2000) and $2.25 - $3.00 (or lower!) during 2002.

Gas Production Profiles, Alberta and US Lower 48 States (Figures 6 and 7)

Alberta normalized gas production profiles and US Lower 48 States vintaged gas production profiles characterize changes in Alberta (Western Canadian Sedimentary Basin) and US onshore average annual well gas productivity for wells completed during four calendar (vintage) years - 1990, 1994, 1998, and 1999. Average initial peak well production is indicated by the end of the orange section. Average well production at the end of the first producing year is indicated by the end of the yellow section. Average well production at the end of the second producing year is shown by the end of the green section. In Alberta, production from wells completed during each calendar year was summed as if all wells commenced production on January 1. In the US, production from all completions during a calendar or vintage year was tracked thereafter by reported month through the producing life of each completion. In both cases, annual average well production was calculated by dividing total production at the end of each year by the maximum number of completions in the initial vintage year. In Alberta, average decline rates over the first two years increased from 19% in 1990 to 49% in 1998, and average new well peak production declined from 1,070 Mcfd to 680 Mcfd. In comparison, first year US average decline rates increased from 29% in 1990 to 41% in 1998, but average new well peak production increased from 461 Mcfd in 1990 to 740 Mcfd over this same period. The increase in US peak production is only partly explained by improved completion technologies. The 1990 number was abnormally low due to curtailed production and inclusion of low-volume Section 29 well completions.

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Industry Trends

Industry Trends Commentary

The objective of this section is to highlight likely industry behavior and activities that should prevail in response to continued volatility in oil and gas supplies, demand, and prices. Key factors that are expected to dominate long-term industry strategies and trends include:

§         Long-term demand growth should continue to drive the need to expand oil and gas production capacity.

§         The global shift toward natural gas should continue.

§         Political and market forces should tend to cap long-term inflation-adjusted gas prices in the $3.50 to $4.00 range, and oil prices in the $25.00 to $30.00 range.

§         Increasing pro-environmental public-policy pressures increasingly may moderate hydrocarbon demand growth, curtail environmentally sensitive development, increase costs, and accelerate the shift to alternate energy sources.

§         “Big oil needs big oil”. Majors will focus on areas with large reserves and access to markets – like the Middle East, North Africa, FSU, & deepwater plays.

§         Growing independent operators and even NOCs will fill the voids – like onshore Latin America, US Gulf of Mexico shelf, and UK continental shelf - vacated by majors.

§         Competition among NOCs to attract capital should intensify.

§         Industry consolidations and restructuring will continue in response to changing industry dynamics. The number of global operators will continue to shrink.

§         It is observed that the 1998-99 oil price collapse created much more pain and havoc to the industry than the sum of the dry holes over this period. This may signal an important paradigm shift from the era of managing technological risks to the era of managing commercial and non-commercial risks.

Industry and public policy makers must plan and manage energy development through these challenges. 

Industry Trends Benchmarks

World Regional Rig Counts (Source: Baker-Hughes) (Figure 8)

Regional changes in drilling activity are shown in the chart comparing average rig counts for the first six months of 2001 with the first six months of 2000. The US rig count, responding to higher natural gas prices, increased by 47%; international rigs by 23%; and Canada, which already enjoyed robust drilling activity during the first-half of 2000, by 12%. Latin America activity, led by Brazil and Argentina, increased by 32%. African activity, led by Nigeria and Sudan, increased by 28%. Europe, led by France and the UK, increased by 19%. The Far East, led by India and Malaysia, increased by 16%; and the Middle East recorded the least increase at 10%. 

Review of IHSE well spuds indicates that countries with open, active licensing practices, stable operating environments, and low to moderate risks have tended to record the largest increases in drilling activity. The moderate rate of international drilling expansion since the 1998-1999 oil-price collapse is consistent with patterns over the past decade, but it may reflect other concerns. Continuing excess OPEC producing capacity, major operators’ focus on projects with large reserves and producing capacity, expanding opportunities in the Middle East, and heightened attention to non-commercial risks may contribute to the less robust growth in international drilling.

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International Exploratory Well Ends (Figure 9)

Increases across all international regions tracked by IHSE reveals an important overall 28% gain in international exploratory well ends through YTD April, 2001. This continues last year’s uptrend and represents a welcome break in a long-term downtrend in exploration and appraisal drilling. 

Thirteen years ago (1988), international exploratory drilling represented 42% of total wells but declined to only 25% of total wells by 1999. YTD 2001 exploratory drilling has rebounded to comprise 31% of total wells. This uptick might prove to be only a temporal response to cover exploration projects that were suspended during the 1998-1999 oil price collapse. YTD 2001 international seismic activity, a traditional indicator for new exploration, is up only 7% from 2000. Regardless, increased exploratory drilling should yield important new discoveries and reserves that would generate future increases in development well drilling and production. Kashagan, a super-giant 2000 discovery in the north part of the Caspian Sea, is a case in point. Reports credit Kashagan with 3,000 meters of pay and possible reserves that could range from 20 to 60 Bbo! This discovery could forge significant shifts in future oil supplies. A long-term concern, though, is the fact that international discoveries over the past decade (including Kashagan at 20 Bbo) have yielded only about 14 Bbo per year in oil reserves compared to current 27.8 Bbo annual demand. Including reserve growth factors and adding US and Canadian reserves still do not cover current demand. This does not portend calamity but speaks to the importance of sustaining a healthy level of global exploratory drilling.  

YTD 2001 development well ends are about flat with 2000. Gains in Africa, Australasia and Europe offset deficits in the Far East, Latin America, and Middle East.

International Licensing Activity (Figure 10)

Improved health of the international sector also is indicated by the turnaround in licensing activity with a YTD 15% gain in awards and a 44% decrease in relinquishments. YTD 2001 awards more than doubled in Africa and Europe. The 2001 African awards, which are spread across 15 countries compared with 9 in 2000, reflect expanding industry interests. Australasia and Latin America, with continued activity in Colombia, have recorded modest gains in awards, while awards have lagged so far in both the Middle East and Far East. 

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Global Areas of Interest (Figure 11)

§         Major strategic issues with policy or long-term implications focus on:

-  Washington D.C. for the evolution of US energy policies that would influence global supply and demand considerations;

-  The Middle East for OPEC policies, changing investment policies and opportunities, resulting expansion of productive capacity, and Iraqi actions that might disrupt oil markets;

-  The FSU for improving political and legal stability and energy policies that would impact production and exports and on the development and access to large new Caspian area reserves; 

      -  Asia for its economic health and on China as the largest energy growth market – particularly for gas and possible opportunities for suppliers.

§         Areas with a positive outlook include: 

-         Alaska North Slope, Canadian Maritimes and US GOM for expanding E&P activity;

-         Brazil for deepwater developments and new license rounds but with caution in regard to fiscal and environmental policies;

-         The west coast of Africa for expanding E&P activity and deepwater developments;

-         North Africa for E&P activity and access to prospects;

-         China’s expanding Bohai Bay and onshore gas developments.

§         Areas of interest for gas developments include:

-         Alaska North Slope and McKenzie Delta for access to arctic gas reserves to serve the US;

-         Bolivia and southern cone infrastructure expansion;

-         Venezuela and Trinidad & Tobago for possible new regional gas infrastructure development and exports to the US;

-         Algeria for expanded supplies into Europe;

-         FSU for expanding supplies to Europe and Asia;

-         Persian Gulf gas infrastructure and LNG exports that could set a price cap for other regions;

-         SE Asia and NW Shelf for Australia for LNG developments to serve Asia and the US West Coast.

 Summary

 While the outlook for long-term growth in oil and gas demand is positive, continued volatility in shorter-term supplies, demand, and prices will present challenges to the petroleum industry. Increasing pressures from environmental interests and concerns in managing commercial and non-commercial risks – those fiscal, legal, and political variables that impact portfolio security and profitability – present additional challenges. Evolving paradigms, on the other hand, like the global shift toward natural gas and expanding investments in the Middle East, also create opportunities. Independent operators fill the voids left by majors in mature producing provinces. Increasing competition for investments by NOC’s should lead to enhanced license terms. There also are increasing opportunities to transfer natural gas technologies and business skills into the international arena. Those operators who can parlay technology or management skills to exploit low-cost, low-risk situations should improve their chances to prevail in the continued volatile scenarios that are likely to arise.

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