An industry booster looks at the forecasts for price and technology and sees some big "ifs" for modular, on-site and distributed applications.

I'm a believer from way back in using natural gas for modular, on-site and distributed generation. But I worry that we might be overselling it.

Certainly, the idea of a natural gas fuel cell in every home basement needs careful examination. Add to that the notion that we can replace much of our commercial power demand with gas-fired systems such as fuel cells and microturbines.

I've followed closely the industry projections for gas supply and demand, including the much-vaunted 30-Tcf market. These projections take account of steadily advancing technology and signs that the electric and gas markets are converging. One cannot deny the shifting economies of scale and rising environmental concerns that tend to appear to favor natural gas. Yet the industry projections for gas and electricity prices - and their effect on U.S. natural gas supply and demand - remain open to question. The situation is very elastic. It is difficult to predict how environmental pressures might impact coal-fired and nuclear capacity, or what a substantial reduction in existing coal or nuclear capacity would do to natural gas and power prices.

What's more, there are major implications for the very future of the local distribution companies (LDCs). How long can residential and commercial markets for direct gas use hold out against electric competition? Many factors could limit the development of self-generation or microturbines.

My view is hopeful, but tempered. This large-scale conversion to gas-fired applications may eventually take place, but very likely over a much longer timeframe than what is envisioned in some of the more optimistic projections.

Early Work: A New Vision for Gas

The applications I'm talking about are gas-fired generation applications requiring capacities ranging from 5 kilowatts to 50 megawatts, and the associated applications involving combined heat and power, or cogeneration.[Fn.1]

Because it is much cheaper to transport energy in the form of natural gas than as electricity (even after allowing for typical conversion efficiencies of 30 percent to 60 percent on an LHV basis, defined as lower heating value), and because natural gas can be stored at moderate cost (unlike electricity), there are obvious economies that can be found by the overlapping electric and natural gas grids. Beginning in the 1950s at the Institute of Gas Technology (IGT), and continuing at the Gas Research Institute (GRI), I advocated R&D to create technology for using such economies. The goal was to minimize the cost of energy services for all classes of consumers at the highest possible efficiency and lowest environmental impact.[Fn.2] As now is widely recognized, such benefits can be achieved not only by on-site distributed generation (DG), but also by gas-fueled modular generation. Gas-fueled modular generation often is more cost-effective in increasing the capacity of the electric grid than transmission and distribution investments.

At IGT, I started the molten carbonate fuel cell program in the United States, and rallied industry support for IGT's TARGET program (Team to Advance Research in Gas Energy Technologies). TARGET led to the development of the International Fuel Cells Corp./ONSI PC-25 200-kW natural gas-fired, phosphoric acid electrolyte fuel cell cogeneration system. I also championed the "total energy" concept as part of the industry GATE initiative (Group to Advance Total Energy), the forerunner of today's cogeneration industry. In addition, I was an early proponent of development and commercialization of gas-fired, combined-cycle turbines, which now clearly are destined to capture the majority of new modular generation in the United States and much of the rest of the world.[Fn.3]

To validate this option and all the other distributed and modular generation technologies that depend on ample, low-priced supplies of natural gas (and liquefied natural gas, LNG, in areas without indigenous supplies), IGT worked to develop the global LNG industry and GRI pioneered so-called "unconventional sources" of natural gas. My role in the policy area primarily was to rebuild confidence in the huge, economically recoverable North American natural gas resource base, which pretty much had been written off during the Carter Administration.[Fn.4] Somehow energy policymakers had forgotten the power of price and technology elasticity of supply and demand.

Gas Supply:

The Current Outlook

The pessimism of the 1970s gave way eventually to the "gas bubble" of the 1980s. We now may be going a little overboard with confident predictions of a U.S. natural gas market as large as 30 trillion cubic feet (Tcf) by 2010. The recent major forecasts don't see this occurring until nearer to 2015.[Fn.5, 6] In fact, the drilling slump between 1998 to 1999 caused by low oil and gas prices has created some concern that gas deliverability in the lower 48 states might drop below projected demand by 2000.

Fortunately, the stunning reversal in this price decline triggered by OPEC and other oil producer output cuts beginning in April 1999 at least has restored the active U.S. gas rig count to an adequate level. This problem, therefore, should prove temporary - as have similar previous occurrences.

Reserve replacement for 1998 should be near 100 percent since the active gas rig count in 1998 averaged 560, only 4 below the 1997 level when total additions were 104 percent of gas production.[Fn.7, 8] Moreover, the number of gas well completions in 1998 was 12,106, the highest since 1985 and substantially higher than the 11,327 completions in 1997.[Fn.9] Average total additions of 1.9 billion cubic feet per well from 1990 through 1997, and 1.8 billion cubic feet per well in 1997,[Fn.10] suggest total 1998 additions of 22 to 23 Tcf. That amount exceeds considerably dry gas production of about 19 Tcf. In other words, the drilling slump apparently hit U.S. gas exploration and development relatively late in 1998 and, as noted above, already had abated by September 1999.

Nagging Worries:

Limits on Market Penetration

Despite a very bright promise, several factors appear to place limits on residential and commercial market penetration of microturbines and fuel cells.

Cheap Grid Power. It seems highly unlikely that most electric power users, especially residential and commercial users, will want to sever their connection with the electric grid. They generally could not afford to invest in enough spare on-site capacity to ensure service reliability. Even large commercial and industrial users would not wish to pass up relatively cheap off-peak power, typically priced in the 1.5 cent to 3.5 cents per kilowatt-hour range at the various trading hubs. Thus, the electric grid is here to stay. As regional transmission organizations take over its management, the grid likely will become ever more cost-effective for delivery of relatively cheap power - from both existing resources and the new merchant plants.

High Fuel Costs. Another factor that will limit self-generation is the price of the natural gas fuel itself, and what that means given the projected relationship between delivered gas and electricity prices.

LHV efficiencies of proton exchange membrane (PEM) and phosphoric acid electrolyte natural gas-fired fuel cells - the fuel cell technologies best suited for residential and commercial markets - are roughly 40 percent (including energy losses in the conversion of natural gas to hydrogen, which is the actual fuel). Microturbine generators have an LHV efficiency of about 30 percent. Therefore, without credits for productive use of the waste heat, the cost of gas alone can equal or exceed the cost of purchased power.

Table 1 shows some recent projections of delivered natural gas and electricity prices in key markets in 2015 and 2020. For example, at current microturbine-generator heat rates of about 12,500 Btu per kilowatt-hour (higher heating value, or HHV, basis), it is obvious that the projected cost of gas at commercial rates would exceed the projected price of electricity in the commercial market. Of course, the energy service companies and utilities marketing microturbines in the 30- to 75-kW capacity range now offer promotional gas rates - typically $3.50 per million Btu. That rate seems a little low for annual consumption levels at, say, 80 percent load factor of 2.6 to 6.6 thousand cubic feet (MCF).

Then there are non-fuel operating and maintenance costs on the order of 0.5 cent to 1 cent per kilowatt-hour and capital charges on the order of 1.3 cents per kilowatt-hour on installed costs that today still are in the $600 per kilowatt range. These costs bring the total into the 7 cents per kilowatt-hour range, even at promotional gas rates. That rate is barely below today's average commercial electricity prices.

On the positive side, however, it is true that microturbine generators are cogeneration capable (albeit at higher investment costs). Thus, by 2015 to 2020, installed costs in 1997 dollars probably will have dropped to the projected value of $350 per kilowatt. Also, the low efficiency of 30 percent (LHV basis) should have improved by then.

Interconnection Costs. There also appear to be inherent limitations on the market penetration of microturbines other than for peakshaving, standby, premium power supply and remote locations. Widespread use in supermarkets, fast-food chains, etc., as primary sources of power, especially with the uncertainty of the tariff for connected load charges by the local utility, seems unlikely. In addition, there are the market entry barriers of complex and widely varying interconnection rules.

Yet, even with these constraints, a substantial global market for microturbine generators still should develop in the 25- to 500-kilowatt range, especially the design that is based on established aerospace technology and large-volume automotive production for turbocharger applications. It has high reliability and minimal service requirements, thanks to a single moving part supported by air bearings and thereby requiring no lubrication. This design also is relatively light and compact, generates little noise and emits low concentrations of nitrogen oxides. Moreover, although natural gas is the preferred fuel, microturbine generators can operate with other premium hydrocarbon fuels.

Fuel Cell Uncertainties. Compared with microturbine generators for DG applications, the prospects for fuel cells in the single-digit-kilowatt to single-digit-megawatt capacity range are even more poorly defined. As noted before, the only commercial product is the 200-kW PC-25 of International Fuel Cells Corp./ONSI, a joint venture of United Technologies Corp. and Toshiba Corp. Over 200 units have been sold and the operating experience has been satisfactory.

Typical economics, again based on a promotional gas rate of $3.50 per million Btu, are shown in Table 2. Even with the hot water credit, power costs exceed average commercial electricity prices. However, for high load factor operation in areas where commercial electricity rates are high and gas is relatively cheap, where there is a premium on reliable power supply, in remote locations, or where the cost of bringing in additional grid power is high, these systems obviously are finding a niche. With large-volume production, equipment costs also could be reduced substantially.

Clearly, however, the marketing experience with this excellent system illustrates the limitations of the inherently high first-cost fuel cell technologies as distributed power sources. The efficiency advantage over other DG options of fuel cell technologies that operate at much higher temperatures than PEM and phosphoric acid fuel cells - notably molten carbonate electrolyte and solid oxide systems - cannot at present compensate for these high costs.

Success Stories: Where Gas

Gensets Work Best

Table 3 summarizes my estimates of the performance characteristics and costs of available gas-fired distributed and modular generation options, based on various literature sources. The most widely used systems for emergency and back-up power systems are proven reciprocating-engine-driven gensets of up to 5- to 6-MW capacity. The performance of these units, which generally have the lowest first cost, continues to improve. However, they require a great deal of maintenance to ensure reliable operation and have not been used extensively for DG or cogeneration in areas with access to reliable grid supplies.

Turbine-driven gensets are popular for on-site large commercial and industrial cogeneration applications. In fact, gas-fired cogeneration's market penetration has grown in recent years. In 1997 there were 34 gigawatts (GW) of such capacity in the United States, compared with 745 GW of conventional power generation capacity. However, this market is projected to grow only to 39 GW by 2020.[Fn.11]

The biggest market for combustion turbines is in various forms of grid power supply. Simple-cycle combustion turbines, because of their low first cost and low non-fuel O&M costs, traditionally have been the preferred option for meeting peaking needs of electric utilities, although the new, high-efficiency aeroderivative turbines also can be economical sources of intermediate and even baseload power. But the advanced combined-cycle turbine systems, with their high efficiencies and relatively low first cost and their low pollutant and carbon dioxide emissions, now dominate the new generation market.

Combined-cycle turbines increasingly are built as merchant plants by independent power producers (i.e., without long-term contracts for energy and capacity) because of their ability to generate baseload power profitably at about 3 cents per kilowatt-hour from $2.50 per million Btu natural gas.[Fn.12] They emit one-third as much carbon dioxide per unit of power production as coal-fired steam-electric plants, cost roughly one-third as much as new coal-fired plants, and emit negligible amounts of sulfur oxides. Their nitrogen oxide emissions can be controlled to meet the most stringent regulations of the Environmental Protection Agency. In contrast with the relatively static cogeneration outlook, the Energy Information Administration (EIA) projects that combined-cycle capacity will increase from 15.4 GW in 1996 to 211.5 GW in 2020, and combustion turbine/diesel capacity from 70.1 GW to 186.7 GW.[Fn.13]

Coal, Nuclear and Kyoto: What Impacts?

There is no question that advances in gas-fired distributed and modular generation technologies have moved the economic null-point between the pipe and the wire closer to the power user. However, as noted before, shifting economies of scale to ever-smaller generation capacities do have limits set by rising costs of fuel supplies and of equipment, installation and electric grid connection costs per unit of output. Total market penetration of gas-fired distributed and modular generation also will be limited by how much natural gas will be available for power production at costs competitive with other sources. This situation is elastic since it is hard to predict how environmental pressures will impact existing coal-fired capacity and conceivably could stabilize and even increase nuclear capacity.

Emissions Reductions. For example, of total U.S. emissions of 1,480 million metric tons of carbon (MtC) in the form of carbon dioxide (CO2) in 1997, 471 MtC, or 32 percent, came from coal-fired power plants.[Fn.14] Any credible effort to comply with the Kyoto Protocol requirements for the United States to lower its 2008 to 2012 greenhouse gas emissions 7 percent below 1990 levels would have to include a major shutdown of coal-fired plants. Such plants, whose present variable generation cost is only 1.5 cent to 2.5 cents per kilowatt-hour, would need to be replaced with natural gas-fired, combined-cycle turbines.

Repowering is another option. Such compliance also would be facilitated by keeping in operation most of the zero-carbon-emission nuclear fleet, whose variable generation cost also is just 1.5 cent to 2.5 cents per kilowatt-hour. Nevertheless, EIA projects a decline in U.S. nuclear capacity from 100.7 GW in 1996, to 56.4 GW in 2015 and 48.9 GW in 2020.[Fn.15] What a substantial reduction in existing coal-fired and nuclear capacity would do to natural gas and power prices is difficult to predict.

The Gas Response. As shown in Table 4, even without considering Kyoto Protocol compliance, EIA projects an increase in natural gas use for power generation, excluding cogeneration, of 5.3 Tcf between 1996 and 2015, and 6.1 Tcf between 1996 and 2020.[Fn.16] This projection includes generation by independent power producers (IPPs) and exempt wholesale generators (EWGs). GRI projects a corresponding increase of 4.3 quadrillion Btu (quads), or about 4.2 Tcf, excluding industrial and commercial cogeneration (see Table 5).[Fn.17]

My independent assessment of increased gas consumption between 1996 and 2015 for all power generation uses based on EIA data for capacity changes, shown in Table 6,[Fn.18] projects 7.2 quads, or about 7.0 Tcf. Thus, it already appears that the consensus projection of 31 Tcf natural gas demand in 2015 is too low. Obviously, any significant replacement of the 305 GW of existing coal-fired capacity with natural gas-fired, combined-cycle plants would increase this amount substantially. This possibility has generated all the talk about a 30-Tcf gas market by 2010 and a potential 40-Tcf market by 2020. The Lower-48 resource base (including proved reserves) of more than 2000 Tcf, plus the growing Canadian import potential, are quite capable of supporting such goals, but it is yet to be seen if they can be achieved at prices projected by EIA and GRI (see Table 7).

Based on the rapid ongoing advances in exploration and production technologies, my view is that they can, although obviously there will be continuing price volatility. In this context, it is important to note that the break-even price of natural gas for power generated in combined-cycle baseload plants with power generated in advanced clean coal technology plants, such as the integrated coal gasification-combined cycle technology now being commercialized, is over $5 per million Btu.[Fn.19]

To quantify the potential demand for natural gas, let us assume we want to replace all of the 304.7 GW of 1997 U.S. coal-fired capacity that operated at 67.3 percent load factor and a heat rate (HHV) of 10,300 Btu per kilowatt-hour[Fn.20, 21] with combined-cycle plants operating at the same load factor and at a heat rate of 6,300 Btu per kilowatt-hour. This replacement would require an additional 11 Tcf of natural gas per year and would reduce annual carbon emissions in the form of CO2 from 471 MtC to 162 MtC, or by 309 MtC. Such a reduction represents 57 percent of the required 538 MtC cut in emissions below the projected 1,790 MtC level in 2010 required under the Kyoto Protocol.[Fn.22]

To do that by 2010 obviously is virtually impossible. Aside from the huge increase in gas demand and the associated increases in pipeline capacity, it would require a capital investment of roughly $140 billion in combined-cycle capacity. It is quite clear, however, that a substantial portion of this conversion likely will take place as projected by EIA and at least hypothesized by GRI, but over a longer timeframe. Certainly, just about all new capacity for intermediate and baseload power supply will be gas-fired, combined-cycle systems and new peaking capacity will be gas-fired, simple-cycle turbines. However, EIA still sees coal-fired, steam-electric capacity increasing from 305 GW to 333 GW from 1996 to 2020, but without any allowance for possible impacts of the Kyoto Protocol.[Fn.23]

Gas LDCs: Still a Role?

The commercialization of DG technologies has major implications for the future of the gas LDCs. The assumption that they and the pipeline transmission companies will become merely suppliers of gas for power generation - a relatively low-margin business - is unfounded for the same reasons noted as limitations on DG market penetration. However, the still-profitable residential and commercial direct gas use markets will require major end-use technology advances to protect them against electric competition and incursions by energy service companies that will attempt to market DG and cogeneration technologies packaged with gas supplies at attractive rates. Not only are real prices of electricity supplied to these markets projected to drop more rapidly than gas prices,[Fn.24, 25] electric end-use technologies continue to improve, thanks to major R&D investments by the large electric appliance and equipment manufacturers.

The only relatively safe gas market may be space heating where, due to technology advances, gas has made a dramatic comeback. Gas also is gaining a foothold in commercial cooling and refrigeration, again on the basis of ongoing technology advances spearheaded by GRI. The prospects for a gas-fired residential heat pump developed by GRI to capture some of the year-around electric heating and cooling market are, however, uncertain because of its high first cost and limited life between overhauls.

In any event, it is interesting to see how the more than $40 billion per year of value added at the burner tip over the acquisition cost of gas is divided. Figure 1 and Table 8 show the natural gas value chain for 1997. Both primarily are based on data from EIA's "Annual Energy Outlook 1999," except for some assumptions concerning what portion of the electric generation, industrial and commercial loads is served directly by pipelines. The city gate price for gas reported in a recent EIA "Monthly Energy Review" seems high ($3.61 per Mcf in 1997) compared with the gas wellhead and import border costs reported in EIA's "Annual Energy Outlook 1999" and unduly inflates the value added by transport to the city gate.

It is apparent that supplying the industrial and large power generation markets is not very profitable. Moreover, as noted before, growing retail competition also may lower the profitability of residential and commercial markets where transportation costs inherently are high and where temperature-sensitive loads require large storage investments.

Crystal Ball Gazing:

Some Unanswered Questions

The preceding discussion raises a number of conflicting questions.

* Profit Margin. How much of the more than $40 billion of value added at the burner tip beyond the acquisition cost of gas still captured largely by gas transmission and distribution companies will be captured by energy marketers and energy service companies?

* Electrification. Will electrification and retail competition erode the value of natural gas in the residential and commercial markets?

* Fuel vs. Product. Will gas become merely a source of power for distributed and modular generation, plus what remains of central generation? On the other hand, are expectations for large market penetrations of DG technologies in the residential and commercial markets unrealistic because of economic, technical and operational barriers?

* Technology Options. Will straight gas LDCs be able to keep residential and commercial customers without advanced technologies that keep direct gas use competitive with electric options or allow LDCs to provide complete on-site, gas-fueled energy services in competition with grid power?

* LDC as a Business. Or will the issue of the future of straight gas LDCs become irrelevant, as convergence of the electric power and gas supply businesses each proceeds unabatedly, with usual dominance of the electric side in the merged entities?

* Price Stability. Can a 5 Tcf to 10 Tcf per year increase in U.S. gas consumption over the consensus projection of 31 Tcf by year 2015 for various forms of power generation be accommodated without a substantial increase in gas prices?

* Turbine Turnout. Can the equipment manufacturers satisfy in a timely fashion and at relatively stable prices what promises to be a global explosion in demand for combined-cycle and simple combustion turbine systems, or will that prove a major growth limitation in DG and modular generation capacity?

Henry R. Linden is the Max McGraw Professor of Energy and Power Engineering and Management and director of the Energy + Power Center at Illinois Institute of Technology in Chicago. He is the retired founding president of the Gas Research Institute and a past president of the Institute of Gas Technology. In addition, Linden has served on the boards of such companies as the AES Corp., Sonat Inc. and UGI Corp., and has published extensively. He may be reached at hlinden@alpha1.ais.iit.edu.

1 Linden, Henry R., "Drivers of the Electric-Gas Convergence," The Electricity Journal, Vol. 10, No. 4, May 1997, pp. 14-25 (Linden, "Drivers of Electric-Gas Convergence").

2 Linden, Henry R., "A New Look at the Future of Gas," Public Utilities Fortnightly, Vol. 83, No. 12, June 5, 1969, pp. 13-20.

3 Linden, Henry R., "The Case for Increasing Use of Natural Gas in Generation," Public Utilities Fortnightly, Vol. 121, No. 4, Feb. 18, 1988, pp. 25-29.

4 Linden, Henry R., "Energy Policy and the Gas Option," The Bridge, Vol. 9, No. 4, Winter 1979-1980, pp. 25-29.

5 "Annual Energy Outlook 1999," Energy Information Administration, Document No. DOE/EIA 0383(99), December 1998 ("Annual Energy Outlook 1999," EIA).

6 "GRI Baseline Projection of U.S. Energy Supply and Demand, 1999 Edition," Gas Research Institute, Baseline/Gas Resource Analytical Center, August 1998 ("GRI Baseline Projection of U.S. Energy Supply and Demand," GRI).

7 "Monthly Energy Review," Energy Information Administration, Document No. DOE/EIA 0035(99/09), September 1999 ("Monthly Energy Review," EIA).

8 "U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1997 Annual Report," Energy Information Administration, Office of Oil and Gas, Document No. DOE/EIA-0216(97), December 1998 ("U.S. Crude Oil," EIA).

9 "Monthly Energy Review," EIA.

10 "U.S. Crude Oil," EIA.

11 "Annual Energy Outlook 1999," EIA.

12 Linden, "Drivers of Electric-Gas Convergence."

13 "Annual Energy Outlook 1999," EIA.

14 Ibid.

15 Ibid.

16 Ibid.

17 "GRI Baseline Projection of U.S. Energy Supply and Demand," GRI.

18 "Annual Energy Outlook 1999," EIA.

19 Linden, "Drivers of Electric-Gas Convergence."

20 "Annual Energy Outlook 1999," EIA.

21 "Monthly Energy Review," EIA.

22 "International Energy Outlook 1999 with Projections to 2020," Energy Information Administration, Document No. DOE/EIA-0484(99), March 1999.

23 "Annual Energy Outlook 1999," EIA.

24 Ibid.

25 "GRI Baseline Projection of U.S. Energy Supply and Demand," GRI.

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