BUSINESS UNKNOWNS SHAPE OIL INDUSTRY RISKS

Richard Pane
Consultant
Tulsa

Strategic thinking about an exploration and production program requires a careful assessment of risk, which can be defined as variability in the components of value creation.

This article surveys, categorizes, and ranks business risks in the upstream petroleum business. It can serve as a checklist for thinking strategically about an E&P program.

While a rigorous definition says that risk is two-sided, most business decisions-and this article-concentrate on the unpleasant side of the proposition.

This explication takes a different tack from other analyses of the business environment. It does not intend to resolve what is known and knowable. Rather, it attempts to define important unknowns and gauge their ordinal potential impact.

A first step in analyzing E&P risks is to recognize that oil and gas-because of their divergent storage, transportation, distribution, and burning characteristics-need to be examined separately.

OIL DEMAND FACTORS

Oil demand is impacted by the quality as well as the size of the economies of various energy using countries. Many analysts anticipate world oil demand growth of about 2%/year in the intermediate to long term.

In the short to intermediate term, the health of the world's oil consuming economies is critical. And the most critical economy of all, of course, is that of the U.S.

The obvious reason for the importance of U.S. economic growth to oil demand is the country's disproportionate direct usage of energy, oil in particular, relative to growth. But the U.S. economy has two major indirect effects on oil demand that are even more important.

One is the oil demand embedded in U.S. imports of raw materials, manufactured goods, and services. A strong U.S. economy represents a strong market for nonoil imports that require oil or gas consumption elsewhere for their production.

The other indirect effect of U.S. economic growth on oil demand is related to the first. It concerns the increasing share of manufactured goods in the total import mix.

Energy-especially oil-that once would have been used in the U.S. to manufacture automobiles or textiles is now being imported in the manufactured goods themselves. The well-documented delinking of the U.S. gross national product (GNP) from energy and oil demand does not take into account the energy and oil consumption embedded in imported goods and services.

Each 1 percentage point of growth in U.S. GNP causes the world to consume roughly 300,000 b/d more of oil. When the 1990-91 recession yields to normal growth in the U.S., the world will require incremental oil production equivalent to the entire Alaskan North Slope.

NEW MARKET ECONOMIES

Another short to intermediate term determinant of oil demand is the transition of formerly Communist countries toward free market economies.

In the short term, the destabilizing effects of the transition are negative for economic growth. At some point and at some unknown pace, however, new economic freedoms and entrepreneurial activity will revive growth and, consequently, oil demand.

This probably will occur before the republics of the Soviet Union and other formerly Communist countries manage to correct the energy use inefficiencies that have plagued their economies for so long.

Renewed economic growth in the Soviet republics alone could account for 1 million b/d of growth each year in worldwide oil demand for the rest of the century.

Growth in the energy mix of nonpetroleum fuels represents some risk to oil and gas demand. In the U.S., the role of nuclear power is shrinking as the oldest plants begin to be retired and as facilities under construction are canceled or converted to use other fuels.

Coal represents a greater competitive threat to oil and gas than nuclear power. The main risk to oil markets is that environmental concerns regarding coal will diminish, perhaps with the acceptance of evidence that coal contributes less than is now generally believed to acid rain.

Another risk to oil and gas is that public utility commissions will agree to hold harmless against financial risk the power companies that commit themselves to construction of large, capital intensive coal plants with long lead times.

Until this unlikely event occurs, utilities and independent power producers will concentrate on small noncoal facilities such as oil or gas combined-cycle or cogeneration units. The more the economy electrifies and the higher oil prices climb relative to coal prices, the more the pressure will be on public utility commissions to allow further market penetration by coal.

Another environmental and regulatory consideration affecting oil demand is a broadening of the mandate for alternatively fueled vehicles from the current requirements set forth in the Clean Air Act Amendments of 1990. This risk seems slight for now.

Methanol and compressed natural gas seem to be the main alternatives to radically reformulated gasoline.

OIL SUPPLY FACTORS

To have a profitable E&P venture, a company must find sufficient quantities of oil at a cost enough lower than the selling price to justify the risk and effort. Furthermore, this margin cannot be so large and certain that it attracts excessive competition for properties.

Risks can differ greatly from one area to another.

In the intensely drilled U.S. Lower 48, finding costs have been $8-12/bbl in recent years. A rule of thumb states that a selling price three times the finding cost will yield an acceptable rate of return.

A U.S. producer, therefore, must find oil at $5-7/bbl when prices are $15-21/bbl to be economic. A shrinking rig count and migration of major companies and many independents to prospects abroad testify to a diminishing willingness to undertake the risks that these economic parameters can be met.

Maturity of the accessible U.S. petroleum resource is one reason for these trends. Other factors are availability and cost of human, physical, and financial resources.

There is some risk that professionals and field workers displaced in recent and current oil company cuts will not return to the industry when conditions improve. This probably would not be a serious problem unless there were another drilling boom, which seems very unlikely.

Risks are greater in the area of physical capital. Inventories of good quality used pipe, stacked rigs, and other equipment are being consumed. As excesses disappear, replacement will be at full cost.

After this cost jump, further increments of physical capital should be available without significant further price increases. Absent another drilling boom, and unless the general economy generates greatly increased demand for steel goods outside the oil industry, drilling equipment and supply prices should remain within reasonable limits.

Financing is a problem for marginal prospects. Furthermore, the definition of "marginal" changes. Lenders require more assurances and more robust projects than they did in years past. Where loans are available, however, interest rates are relatively low and seem likely to increase only modestly even in the longer term.

OUTSIDE THE U.S.

In Canada, drilling is below levels of a year ago but not by as much as in the U.S. Finding costs are somewhat lower as well.

Many non-Canadian firms have begun or increased Canadian activity in recent years, many via investments in ailing Canadian companies. A superior and less intensively drilled resource seems to outweigh the risk, seen by many oil company political analysts, that prospective Canadian regulatory and tax policy changes are more likely to hurt than help E&P activities, especially those by foreign firms.

The largest risk relating to oil supply is developments in the Soviet republics. The massive Soviet resource has been badly managed, with policies oriented toward maximum production with little regard for reservoir management. The question is the extent to which the Soviet republics-aided by capital, technology, and organizational skills from abroad -will be able to restore oil production and exports. In the next 5 years, the Soviets could be producing 5 million b/d more or less than they are at present.

Production increases are likely to continue in Africa, South America, and the Far East-which in total have been adding output at the rate of about 1 million b/d/year. Exploration in these areas is brisk. One risk, especially in the Far East, is a tendency toward discovery of natural gas instead of oil.

Political stability and increased business acumen have decreased country risk to manageable levels, although surprise tax or regulatory changes are always possible.

Members of the Organization of Petroleum Exporting Countries are under financial pressure to produce at maximum rates, which this year they have been able to do without wrecking oil prices with Kuwait and Iraq off stream. In fact, current OPEC production rates may not be physically sustainable until members planning to add capacity complete their projects.

In the near term, and as long as Kuwait and Iraq can't produce and export significant volumes, the risk is greater that OPEC output will fall for physical reasons than it is that flow will increase. OPEC available capacity, for now, is fully utilized.

INTERACTING RISKS

Fig. 1 summarizes and ranks the six major risks facing oil markets. These risks encompass more than 90% of the variation likely to be visited on the market.

Because the oil market captures the effects of all forces in the market, variations in it constitute a good proxy for business risk. Historical variations in oil price provide clues to what may occur in the future.

From the late 19th Century, the U.S. average wellhead oil price has coursed through many multiyear cycles. In each cycle, the price varied around an amazingly stable long term average.

From 1890 through 1978, the average was $11/bbl in 1988 dollars. Even the years preceding and following the first OPEC supply disruption in 1973-74 (OPEC I), fit nicely into the prior historical pattern because the price had fallen further and further below the long term average in preceding years (Fig. 2).

OPEC I merely brought the price above the average but left it well within the range of historical variability. OPEC II, in 1979, produced an unprecedented price hike, which quickly reversed the following year.

The big price risk is whether or not history has any relevance to the future or whether fundamental, irreversible market changes have occurred. A way to approach this risk is to examine and estimate the effects of fundamental changes that occurred in history and to compare them with what may occur in the future.

Oil supply has been impacted by giant finds, leaps in seismic and drilling technology, worldwide exploration efforts, and theoretical geological and geophysical concepts.

Oil demand has been impacted by world wars, the Great Depression, the automobile, and the interstate highway system.

The future is unlikely to bring changes more momentous than these. With a great deal more oil remaining to be found and developed, and with competing fuels a developing factor, oil prices probably will remain within the historical range.

The message for managements, financiers, and investors is that prudence requires oil price assumptions far lower than the current price.

GAS FACTORS

Many of the factors operating in oil markets are the same in gas markets. There are three main differences. Gas is harder and more costly than oil to store and ship, more geographically dispersed and plentiful, and-in the U.S.-more burdened by a history of market-shaping regulation.

Because of the nature of the fuel, gas markets are more insulated geographically than those for oil, and gas demand is driven more than oil demand is by winter space heating needs.

In the U.S., demand for gas is expected to grow significantly only in the electric generation sector. This may be encouraged by environmental regulation.

In the intermediate to long term, there is a risk that "shortages" will develop for at least short periods, again frightening customers away from commitments to gas use. This risk is reduced by diversification in the North American pipeline network, increased and more-efficient use of underground storage, and contract innovations.

The short term risk is that industrial fuel switching toward gas in the last couple of years of low gas prices will reverse, dropping U.S. gas consumption by 1-2 tcf/year. This would serve to keep oil and gas markets in North America delinked.

A large risk in North America's gas market in the near term is supply. A return to normal winter weather in the U.S. could in just a few weeks erase what seems to have become a permanent deliverability overhang and fundamentally change the psychology of the market.

If shortages develop, replacement-cost thinking might drive contract trends and, thus, drilling for years to come. LNG would be little more than a safety valve that would provide a small increment of gas for the market at the margin.

North America is likely to provide essentially all the gas it needs with wellhead prices of $2-3/Mcf for the indefinite future. Gas producers will have to work hard and smart to accomplish this. They probably will continue to squeeze each other's costs down in their attempts to win markets. The past summer's brutal competition has scared off many producers and furthered the trend toward industry consolidation.

MARKET PROSPECTS

Japan, the most coveted market for LNG, has signed contracts for all it expects to need into the next century. Any more gas found in the Far East will have to make a market, including transportation infrastructure. The risk is substantial and will remain for some time that more gas will be discovered than can be used.

Europe has potential to build much more demand for gas as more infrastructure is built to handle North Sea production and long line deliveries from the Soviet republics. Europe is relatively rich but has low penetration of gas in the energy market. It is doubtful that gas-rich areas of Africa and the Pacific Rim will be able to send much expensive LNG to Europe.

Because of marketability problems for gas through most of the world, oil is the predominant exploration target. North America offers the best prospect for finding, selling, and delivering gas on a commercial basis.

With a North American free trade agreement taking shape, the risk is that gas abundance and producers' aggressive optimism will repeatedly bring too much gas onto the market.

In the near term, another risk in North America is that regulatory overhaul will be destabilizing. The process, however, should tend to open markets and create competitive efficiencies over time.

Nevertheless, public utility commissions may continue to resist efforts toward greater competition, creating a risk that efficient gas delivery is still years away.

Fig. 3 ranks the major gas market risks worldwide and in North America.

SUMMARY

Profitability of any effort in the oil and gas business is dictated by the relationship between costs and the schedule of market prices over time. In the oil market, cost is related to where the oil is found, and market price is determined by whoever tips the balance between supply and demand.

For the rest of the decade, the largest single impact on the oil market is likely to come from the Soviet republics' efforts to rebuild their economies and energy industries.

In the gas market, cost is also related to where the gas is found. But market price is determined by regional factors when price is low relative to other fuels and substitute fuels when regional gas markets firm up.

The risks and rewards of participation in the oil business are more symmetrical than those of the gas business.

Gas prices and demand can be capped in any region by oil much more than world market oil prices, and demand can be capped by regional gas gluts.

In both oil and gas, risk is lowest for those whose costs are relatively low. In both oil and gas, risk can be managed by signing contracts for future deliveries under terms than produce a known margin.

In neither market, however, is profitability a sure thing.