Despite increasing refinery power production, oil-fired generation is declining

John Paffenbarger
International Energy Agency Paris

About this report...

Petroleum-based power generation from nonutility producers is increasing. Refineries are a major portion of these producers.

Residual-type feeds are the fastest growing petroleum product segment used for power generation. This trend is driven by refined product demand patterns and the liberalization of electricity markets.

In recent years, gasification has emerged as an effective process for converting heavy refinery feeds to power. Recent projects have proven it to be a flexible and profitable way to produce electricity, hydrogen, and chemicals from feeds ranging from natural gas to tars.

The first article in this report details power-industry trends that affect refiners. A second article, describing a gasification-based utility complex in Texas, illustrates how integrating power, chemicals, and industrial gas production can improve the economics of gasification projects.

Oil-based power production from nonutility sources is increasing. These sources now account for almost 20% of oil-fired power generation.

A major portion of this production comes from refineries.

Another important trend in oil-fired power generation is growth in the use of residual-type feeds. While small in absolute terms, it is the fastest growing segment among petroleum fuels. This trend is driven by changes in oil product demand outside the power generation sector and by the liberalization of electricity markets.

A review of the role of oil products in electricity generation will set the stage for a discussion of these trends, which affect refiners both directly and indirectly.

Background

With few exceptions among Organisation for Economic Cooperation & Development (OECD) countries, the use of petroleum products in power generation has been decreasing since the 1970s. The aging installed base of oil-fired power plants, requirements for environmental protection, and the economics of competition among fuels for electricity generation all point toward continued decreases in oil use for power generation.

Oil, however, plays a key economic role in OECD electricity supply systems by supplying peak-load power, providing operational and planning flexibility, and providing power in isolated or remote electrical grids. These observations are described fully in a new International Energy Agency (IEA) report, "Oil in Power Generation."

Oil's ups and downs

(Fig. 1 [15,927 bytes]) shows total oil-fired power generation in OECD since 1960. From 1960 to 1973, oil use increased continuously and rapidly (19%/year on average), reaching a peak of 26% of total generation. In Japan, Denmark, Italy, Ireland, and Portugal, oil accounted for 60% or more of total electricity generation at the peak.

Fuel oil's competitive economics and relative ease of supply made it the fastest growing of fossil energy sources for electricity generation. Many systems found it the economical choice for base-load power generation.

The oil shocks of 1973 and 1979 put an end to the growth of oil use in power generation. Fuel oil became more expensive, relative to gas and coal. The response to the first shock was not immediate because of a limited ability in the short-term to switch fuels. But from 1980 to 1985, oil-fired power plummeted as rapidly as it had risen in the 1960s. Many coal and nuclear plants ordered after 1973 came on line and contributed to oil's 10% annual rate of decline during this period.

The sharp drop in oil prices in 1986 marked the end of the rapidly decreasing contribution of oil in the power generation fuel mix. Generally, solid economic growth and a slowing of overall plant orders after 1979 stabilized the production from oil-fired, peak-supplying plants. Oil has accounted for 8-10% of total generation during the last 10 years.

Except for the growth of oil use for power in Italy and Mexico, oil-fired power generation has generally declined slowly since 1989. However, large yearly variations in individual countries somewhat obscure this trend.

Installed capacity dropped from a peak of 272 gigawatts (gw) in 1980 to 200 gw in 1994. Oil-fired capacity has dropped more steadily than generation since 1980, with net annual increases occurring on only two occasions. In both instances, capacity increments of less than 3% were seen.

What happened to the 72 gw (net) of oil-fired capacity withdrawn from service? Although precise statistics are not available for the OECD as a whole, it is clear that most of the investment in oil-fired capacity-much of it relatively recent at the time of the first oil shock-was not lost.

Mothballing of oil-fired power plants is often cited as a significant factor in the drop in oil-fired capacity, but less than 20% of oil-fired capacity withdrawn from service since 1974 was mothballed. Rather, many oil-fired plants were converted to burn other fuels, particularly coal.

In fact, some coal-fired plants that had been converted to burn oil during the preshock period, when oil's economics for base-load power generation were favorable, were re-converted back to coal. Other oil-burning boilers were converted to natural gas.

Nonutility, oil-fired plants

One trend worth noting separately is the growth in both absolute oil-fired power production and the share of oil-fired production supplied by "autoproducers" (generators whose primary activity is not public electricity supply). These trends are shown in (Fig. 3 [18,378 bytes]).

Growth has been strongest in the U.S., where it has averaged 38%/year since 1986. The OECD as a whole has seen 7% annual growth in oil-fired autoproduction.

Oil has always provided a greater share of energy input for autoproduction compared to public supply. This is partly because of the ability to use oil in smaller generation plants without the need for costly material-handling systems (coal) or fuel supply infrastructure (gas).

Refineries, in particular, historically have used oil for power generation to meet internal needs. The availability of petroleum fuels and their relationship to refinery material balances has reinforced oil's predominance in refinery power generation.

Oil is also used heavily for power generation in the pulp and paper and metals industries.

Today's situation

Four-fifths of the 200 gw of oil-fired capacity in service today is concentrated in six countries. (Table 1 [14,820 bytes]) Mexico, Italy, and Japan remain reliant on oil for more than 20% of total generation. Portugal and Greece, although they account for only about 1% each of OECD installed oil-fired capacity, also rely on oil for 20% or more of generation.

Utilization rates (capacity factors) of oil-fired plants have decreased since 1980, shifting from base-load and load-following service to peak-load production, on average. Consequently, oil-fired generation has decreased more rapidly than installed capacity (Fig. 2 [17,955 bytes]).

Oil today has four major functions in electricity supply systems:

Meeting peak-load demand

Providing operational and planning flexibility

Providing power in remote or isolated systems

Providing intermediate or base-load supply when more economical alternatives are not available.

Oil's value in providing operational and planning flexibility on a national level is illustrated by the experience in the Netherlands, the U.K., and Ireland in the 1980s (Fig. 4 [24,447 bytes]). Utilization rates of oil-fired power plants increased rapidly in each country over brief periods to accommodate shortfalls in electricity generation from other fuels.

In the Netherlands, a policy decision to limit gas use led to a five-fold increase in utilization rates in 4 years. The U.K. miners' strike of 1984 and a disruption in gas supply to the Irish Electricity Supply Board led to even sharper spikes in plant utilization rates in those countries.

In Portugal, oil-fired power generation can vary substantially from year to year because it makes up for shortfalls in hydroelectricity production, the country's primary source of electricity. Japan uses oil-fired power generation to meet relatively large seasonal swings in electricity demand, resulting in large measure from summer air-conditioning loads.

Oil-fired power plants are used heavily in small, isolated, or remote electricity supply systems. Greece relies on oil-fired power generation for its many island systems. Many other islands throughout the OECD use oil for power supply.

In general, where other fuel options are limited, oil can fill the gap. In Italy, many base-load power plant options have met with strong public opposition. Nuclear plants are prohibited by law, and coal-fired plants have experienced siting difficulties. Thus, Italy is one of only a few OECD countries that have seen consistent growth in oil-fired power generation since the 1970s.

Mexico is another country in which oil-fired power generation has grown. The lowest average fuel oil prices in the OECD (as delivered to power plants) and strong links between oil refining and the power production monopoly through state ownership have been key drivers. Mexico has the highest proportion of electricity production from oil of any OECD country: 55%.

Environment, technology

Residual fuel oil is the predominant petroleum product used for power generation, providing about 80% of total oil energy input. The next largest product is crude oil, at 14%. The remaining 6% of energy input is provided mainly by gas oil, diesel, and kerosine.

Of this remainder, perhaps as much as 2% is provided by Orimulsion, an emulsified bitumen marketed by Bitor S.A., a subsidiary of the Venezuelan state oil company, Petrol?os de Venezuela S.A. The relative shares of the various petroleum products used for power generation have changed slowly since 1980, the main trend being the increase in crude oil's share at the expense of fuel oil.

The increase in crude oil's share from 5% to 10-15% since 1980 has occurred because:

• Japan's use of oil products for power has decreased less rapidly than in most other countries.

• The share of crude oil in Japanese oil-fired generators has risen from 20% to 35-40%.

Economic and environmental factors are responsible for the latter trend.

Crude oil's delivered price to electric utilities has been lower than that of fuel oil. This is a situation unique in the OECD, resulting from import duties and the (former) monopoly fuel oil importation rights of Japanese refiners. The ongoing liberalization of the petroleum sector in Japan is likely to decrease fuel oil's price relative to crude.

Environmentally, crude oil has been attractive because of the availability of 0.1% sulfur crudes from Indonesia and China. Utilities must pay attention to fuel oil sulfur levels throughout the OECD because of restrictions on sulfur dioxide emissions. Except in Japan and a few isolated instances elsewhere, plants firing fuel oil or crude oil (i.e., plants responsible for 94% of oil-fired generation) do not have sulfur-emission control systems. So any sulfur present in the fuel goes directly to the smokestack and atmosphere.

Japan and the U.S., the two top oil users, have been using 0.8-1.0% sulfur oils, on average, for many years. Italy, the third largest oil user, has seen average sulfur levels drop from 1.9% in 1987 to 1.2% in 1994 as a result of a concerted program by the state electricity supplier ENEL SpA. A proposed European Union (EU) regulation would limit power plants to fuel oil with 1% sulfur or less by 2000.

Many existing oil-fired plants have escaped strict limits on emissions of sulfur dioxide, nitrogen oxides (NOx), and particulate matter because they were built before legislation was enacted, beginning in the early 1980s. But newer plants cannot avoid tougher limits, and face added costs for control equipment or advanced combustion technology.

The predominant conversion technology is conventional subcritical steam boilers. Roughly 5% of plants use other technologies, such as gas turbines, diesel engines, or other internal combustion engines that are compatible with clean distillate fuels. Such plants are almost invariably used for small, peak-load supply or in isolated power systems. Some refinery-based plants use fluidized-bed combustors.

New oil-fired plants must consider some form of sulfur control, if not also NOx control. Conventional boiler technology typically calls for scrubbers, but continued advances in both gas turbine and gasification technologies suggest that gasification combined cycle (GCC) plants could be viable in future base-load plants.

Refineries, which may also take advantage of the potential value of hydrogen coproduction from a gasification unit, have demonstrated an interest in petroleum-fired GCC plants. Shell Nederland Raffinaderij B.V.'s refinery at Pernis, the Netherlands; Texaco Inc.'s refinery at El Dorado, Kan.; and three tar-based GCC units in Italy are current examples.1-5

Economics

Oil-fired power generation has become increasingly marginal as it has been economically squeezed out of most base-load and intermediate-load users. Barring an unexpected decrease in fuel oil's price relative to coal or natural gas, this trend will continue in both existing and new power plants.

In existing power plants, short-run marginal costs determine the extent to which these plants are used to meet varying system demand, and oil-fired plants typically have the highest marginal costs in electricity supply systems. This is because fuel costs are the highest for oil-fired plants.

Since 1989, average power plant fuel oil prices consistently have been 10-20% higher than those of natural gas, and fuel oil prices are much higher than coal prices in most markets. Light fuel oil prices, in turn, are roughly double those of conventional fuel oil.

Thus, oil-fired plants are called on when plants lower in the merit order are unable to meet total system demand. On average, throughout the OECD (but with notable exceptions), oil-fired plants have the lowest utilization rates, with the exception of pumped hydroelectric plants.

In new power plants, investment costs must also be considered. But oil-fired plants offer insufficient capital cost savings with respect to coal-fired plants (and none with respect to gas-fired plants) to improve on the disadvantage in marginal cost.

New oil-fired boilers incorporating flue gas desulfurization equipment typically have the highest cost of electricity production, across all utilization rates, compared to gas and coal-fired plants. Natural-gas-fired, simple-cycle gas turbines are especially strong competitors to peak-supplying, oil-fired boilers because their capital costs are a quarter to a half as much, and they do not require expensive sulfur-control systems.

This general situation is not uniformly true throughout the OECD, or even in single countries. The fuel and technology choices made by individual power generators depend on local prices for fuels and equipment, which vary considerably.

If natural gas prices are high-for example, if gas must be imported as LNG-oil can be the economic choice for peak-load duty. The high cost of a fuel-supply infrastructure for plants that are used infrequently can favor oil for peak-supplying plants.

Where gas is not available because of a lack of infrastructure or competing uses, oil can be an economical alternative in boilers or distillate-fired turbines. Perhaps most important is that the absence of alternative fuels in local markets can make oil the economical choice for new power plants across all utilization rates.

Electricity market liberalization

Although oil is likely to continue losing share in central-station power generation because of its unfavorable economics, there is one application of oil-fired power generation which has grown in recent years, and which promises sustained growth. This is the use of low-value residual petroleum products, such as petroleum coke, tar, or vacuum resids, in power production.

Two trends are contributing to this growth:

• A lightening of petroleum product demand

• A liberalization of electricity markets throughout the OECD.

The lightening of product demand refers to the sustained shift towards low-sulfur, lighter refined products and decreased demand for heavy products; particularly fuel oil. The shift towards cleaner products is driven by the growth in demand for transportation fuels.

At the same time, heavy fuel oil's economics have discouraged new uses for it in industry or power generation. Industry's share of fuel oil consumption has shrunk from roughly 60% in 1970 to 35% today.

Power's share has remained between 39% and 45%, even as absolute quantities of oil used in power have fallen. Only marine bunkers have shown growth over the last 25 years as a result of expanding world trade.

To meet this lightening demand mix, refiners have made investments in refinery capacity to upgrade or convert heavy residues to light products. The fraction of residues converted varies by market according to the overall demand mix, but as residual oil accounts for less and less of total demand, deep conversion processes become increasingly expensive.

Investment costs for upgrading capacity ultimately determine the price differential between heavy and light products. Facing heavy investment costs to convert residuals to higher-value products, refiners naturally consider selling residual products at a discount.

The growth of petroleum coke for power generation in the U.S. and Japan illustrates this. (Fig. 5 [18,095 bytes]) In the U.S., the average delivered cost of coke for power stations larger than 50 mw was $21/ton in 1994. This is roughly 30% of the cost of fuel oil, on a thermal basis, and 50% of the cost of U.S. coal. Even with a 5% average sulfur content, coke use has increased at a rate of 80,000 tons/year in the U.S. since 1980. (Coke is typically co-fired with coal because of its low reactivity.)

At least two additional economic benefits are available to refiners using residuals for power generation, apart from providing an outlet for heavy refined products. These benefits are:

• The addition of cogeneration capacity to satisfy refinery steam demand

• The coproduction of hydrogen, via gasification, for refinery material balances.

Refiners technically have had the option of producing electricity from residual products for some time. This amounts to adding upgrading capacity to produce electricity rather than lighter products. However, the limited internal electrical requirements of refineries limit the fraction of residual product which can be disposed of in this way.

Without a market for electricity outside the refinery fence, electricity autoproduction is not a strong alternative to residual product price discounting or product upgrading.

Liberalization of electricity markets throughout the OECD is likely to change this. In the post-war period, government-owned or heavily regulated utilities generally have had exclusive rights to generate and sell electricity.

But the desire for more-efficient, less-costly electricity production has led most governments to implement or begin planning some form of electricity market liberalization that permits competition in generation. Refineries could thus enter these new markets and profitably dispose of heavy refining residuals.

The move towards electricity market liberalization is a worldwide phenomenon. Nearly all OECD governments have begun the process of electricity market reform. The Public Utilities Regulatory Policy Act of 1978 began the process in the U.S., and the pace quickened in 1992 with the Energy Policy Act, and again last year with the Federal Energy Regulatory Commission Order 888.

The U.K., New Zealand, the Australian states of New South Wales and Victoria, and the Nordic countries all have introduced "pool" systems as a means of introducing competition in generation. EU countries agreed in 1996 to progressively open their electricity supply systems to competition. And Japan has allowed independent power producers to bid for new capacity.

The strong growth in oil-based autoproduction of electricity is partly a response to new opportunities for sale of electricity by oil refineries. There are now more than 80 refinery-based power generation projects in the U.S., many of which use fluidized-bed combustion of residual products. In Japan, the 1996 solicitation of capacity bids by independent power producers resulted in 800 mw of refinery power production using residuals, out of a total of 3,000 mw awarded.

National policies

An important concern of OECD governments in past years was that the use of oil in power generation exposed both electricity sectors and national economies to damage in the event of a disruption in oil supply. A primary objective of OECD countries, most of which do not have large indigenous reserves of oil, has been to reduce dependence on imported oil.

As one means of moving toward this objective, most governments enacted regulations in the 1970s which restricted or discouraged the use of oil in power. EU Directive 75/405/EEC of 1975 and the U.S. Power Plant and Industrial Fuel Use Act of 1978 are notable examples.

Import oil dependence and energy security remain fundamental concerns today. However, the evolution in oil markets and prices since the oil shocks of the 1970s, combined with a general political movement towards market orientation in the energy sector, have led most governments to drop formal restrictions on fuel choice for power generation. The U.S. Fuel Use Act was repealed in 1987, and the EU directive was repealed in late 1996.

The report supporting the latter stated that repeal of the directive "would offer electricity generators and refiners greater flexibility, facilitate the possible return to operation of certain multiple-fuel units (coal/oil, oil/gas or combinations with wood/peat), and help make refineries more profitable, by creating markets for surplus heavy fuel oil."

In effect, this affirms the role of the energy market in utility fuel choices, including oil products. The quantity of oil used in power generation in the OECD as a whole is such that the likely severity of a disruption in fuel oil supplies resulting from a general oil supply disruption appears low. This is because of the inelastic demand for light oil products and the fact that there are relatively few other uses for residual fuel oil.

In fact, the use of oil in power can be seen as providing an important source of energy security in relation to potential disruptions in other fuels, none of which are completely without risk of disruption.

Outlook

While the potential for growth in refinery oil-fired power generation is evident, it is not likely to reverse the continuing downward trend in oil-fired power generation in most countries, where 80% of electricity is still produced by public central stations. Apart from the use of low-value residuals, the relatively high marginal cost of oil-based power generation will increasingly confine oil's use to peak loads.

Only a portion of the aging stock of oil-fired plants will be replaced as they reach retirement age over the next 10-15 years. Regardless of the long-term level of oil-fired power generation eventually reached, there is no doubt that oil will continue to play an important economic role in OECD power generation.

References

1. Rhodes, Anne K., "Dutch refinery nears completion of major renovation," OGJ, Mar. 17, 1997, p. 60.

2. Rhodes, Anne K., "Kansas refinery starts up coke gasification unit," OGJ, Aug. 5, 1996, p. 31.

3. Aalund, L.R., "Gasification, polygeneration capture interest of refiners," OGJ, Dec. 9, 1996, p. 40.

4. Del Bravo, Robert, Starace, Francesco, Chellini, Igino M., and Chiantore, Paolo V., "Italian IGCC project sets pace for new refining era," OGJ, Dec. 9, 1996, p. 43.

5. Aalund, L.R., "Italian refinery gasification project to make electricity, steam, and H2 from tar," OGJ, Oct. 21, 1996, p. 33.

The Author