Part I - "Prime Movers," The Equipment Driving The Electric Generators

All practical processes in commercial use today for generating electricity have as their final stage the need for mechanical energy to rotate the moveable part of an electric generator - a machine is needed to drive the generating machine. Other than hydroelectric power which uses the mechanical energy of falling water to turn the generator, the "front end" of all commercial generation processes is some type of system converting thermal (heat) energy into the necessary mechanical energy at the generator. The process providing mechanical energy to the generator is known as the "prime mover."

Focusing on systems which convert thermal or heat energy, there are two different pathways, the boiler / steam turbine system and the combustion turbine system. A hybrid system known as combined cycle combustion turbine is included with combustion turbines in this discussion.

Steam Turbine Generating Systems

The boiler / steam turbine system is the older of the two having been invented in the nineteenth century. In the initial part of this process, a heat source is used to increase the thermal energy level of water by converting high pressure water at a lower temperature to steam at a higher temperature. Typical heat sources may be fuel (e.g., natural gas, petroleum products, coal, biomass, etc.) burned in a boiler, a nuclear reactor, or direct heat (geothermal, heat producing industrial processes, etc.).

This high energy (high temperature and pressure) steam is then passed through a (steam) turbine extracting energy and producing lower energy steam (lower pressure and temperature). The resulting expansion and cooling of the high energy steam rotates the turbine converting what was originally thermal energy into the necessary mechanical energy.

The overall energy efficiency (heat rate) of the steam turbine generation (or any other) process is expressed as useful energy output divided by total energy input. For steam turbine generating systems in the U.S., efficiency is measured as British Thermal Units (BTU) of the net electrical energy out divided by BTU of the heat source in. The average heat rate in 1995 for electric utilities in Louisiana for natural gas fired steam turbine generation was 10,828 BTU heat input per KWH electricity output. During the same year, the average heat rate for coal fired steam turbine generation was 11,073 BTU per KWH. One KWH of electricity equals 3413 BTU. Louisiana gas fired steam turbine generation operated at an efficiency of 31.5% in 1995; coal fired steam turbine generation operated at an efficiency of 30.8%.

Capital costs, operating / maintenance (O&M) costs, and emission of pollutants are dependent on the type of heat source used to create steam. Capital costs may vary from $1,000 to over $3,000 per kilowatt (KW) of generating capacity.

Combustion Turbine Generating Systems

Combustion turbine systems are the second basic method for providing mechanical energy to electric generators. These highly efficient systems evolved in the latter half of the twentieth century and were initially based on aircraft jet engines. Energy input into combustion turbines is thermal, typically coming from combustion of a gaseous or liquid fossil fuel (e.g., natural gas, coal gasses, petroleum distillates, etc.). Research has been conducted into the use of pulverized solid fuels (e.g., coal, petroleum coke, etc.) but, to date, has produced few practical results.

In combustion turbine systems, air compressed by an axial compressor (front section ) is mixed with fuel and burned in a combustion chamber (middle section). The resulting hot gasses then expand and cool while passing through a turbine in the rear section. What was initially thermal energy is converted to mechanical energy rotating the turbine. The rotating rear turbine not only runs the axial compressor in the front section but also provides efficient mechanical (rotational) energy which can be directed to the electric generator. The exhaust from a combustion turbine can range in temperature between 600 and 1000 degrees Fahrenheit and contains substantial thermal energy. What is and is not done with this exhaust energy source determines how the combustion turbine system is used. There are two general types of combustion turbine generating systems in commercial use today. These are simple cycle and combined cycle.

A simple cycle combustion turbine system is one in which the exhaust from the gas turbine is vented to the atmosphere and its energy lost. Such a system is not particularly efficient (Louisiana utilities, 1995: 13,449 BTU per KWH or 25.3% efficiency). They are, however, inexpensive to purchase, compact, and simple to operate. Further, simple cycle combustion turbines can be started up and placed in service more rapidly than any system involving a steam turbine. Simple cycle systems are used by the electric utilities as a source of peaking, backup, or emergency power. Conversely, NUGs do not use simple cycle because they are fuel inefficient and produce no steam. NUGs are seldom faced with the problem of peaking power.

Typical NUGs in Louisiana operating in industrial electrical generation settings capture the energy content of the hot exhaust gasses of the gas turbine. This exhaust stream is directed through a waste heat boiler to produce steam. The resulting steam may be used in process units for heating, in a steam turbine for generating electricity, or both (see Cogeneration, below).

A combustion turbine driving an electric generator and exhausting to a waste heat boiler / steam turbine electric generator arrangement is known as a "combined cycle combustion turbine" system (usually shortened to combined cycle). Such systems have exceptional energy efficiencies. Some large scale combined cycle generation systems now require only 6500 BTU energy input per KWH of electricity output. This equates to an efficiency of more than 52%. This is double the efficiency of steam turbine electrical generation systems or, in other terms, half the fuel per unit of electricity.

Capital costs, O&M costs, and emissions of pollutants for combined cycle generation of electricity are low relative to the same costs for boiler / steam turbine prime movers. Capital costs are typically less than $1,000 per KW of generating capacity.

Part II - Cogeneration

Cogeneration, by definition, requires the production and use of steam or hot water in addition to the generation of electricity. This system is efficient because the thermal energy of the steam or hot water taken off of the generating system can be used down to lower temperatures than would be possible in the generation process.

Some confusion has developed between the terms "cogeneration" and "combined cycle." The term cogeneration is not specific to either combined cycle combustion turbine generation or steam turbine generation. Either type of prime mover can be used to "cogenerate." Many of the NUGs who were in operation in Louisiana before the 1970's cogenerated using steam turbine generation which also produced process steam.

Combined cycle combustion turbine generation can be thought of as a special case of cogeneration. In this system, the co-production of steam in a waste heat recovery boiler is also used to generate electricity.

Part III - The Current System Under Which Electric Utilities Operate

This part provides information intended for understanding the current system under which electric utilities operate. Such an understanding is essential in resolving an entire spectrum of issues in making the new unregulated, competitive market for electricity work.

The System in Effect for Regulating and Compensating Electric Utilities

Starting in the 1930's during the Great Depression, electric utilities started becoming regulated. Electric utility operations were thought to be "natural monopolies" in both generation and transmission activities by economists of the day. Natural monopoly is a term describing the situation in which consumers are better off being served by one business entity (a monopoly) than by more than one. Having more than one set of power lines and more than one set of generating plants was thought to be redundant and more expensive than having just one. So having electric utilities with only one set of facilities in a service area was believed to allow for lower electricity prices to the consumers.

Such lower prices would occur if, of course, the monopoly owner of the single set of facilities was regulated in such a way that monopoly prices could not be charged. But, this immediately raised the question of what prices should be charged. Since there was no competition, there were no competitive prices against which to judge electricity prices. It was decided that prices charged by regulated utilities should be limited to provide a "fair" return on investments. Further, a fair return was allowed only on those investments which were "used and useful."

Another problem with respect to "fair" pricing also occurred. To promote the highest level of economic development in as many areas as possible in the nation, electric utility regulation from the 1930s until the present either strongly encouraged or required regulated electric utilities to serve virtually all customers in their service area. This requirement held even in many areas where a company operating on a truly competitive basis would have found constructing and operating electric systems not profitable. The "fair return" on investments, again, served to protect regulated electric utilities from financial harm in return for serving such "unprofitable" areas.

Regulatory bodies were created at both the state and federal levels to make decisions under this system regarding utility operations and the pricing of electricity to the consumer. A system by which electricity prices are established was set in place and operates today. Under the currently operative system, electricity prices or electric rates have long been established using the following general procedure:

• The electric utilities estimate, for a year period in the future, their electricity sales and their expenses based both on historical data as well as on "known and measurable" factors which are expected to exist in that future year.
• The utility then forecasts a level of capital to be in service during this forward year period based both on existing facilities in service and on new facilities expected to be brought into service.
• The utility then proposes a rate of return on this capital in service which is believed to be fair to both the utility and its customers.
• The dollar amount of forecast capital in service multiplied by the proposed rate of return on capital plus forecast expenses are then added together to determine a total revenue level needed for electric utility operations during that future year. In other words, a specific dollar quantity of required revenue is determined by two forecasts and a proposed rate of return.
• This specific dollar quantity is then divided by the forecast quantity of electricity (KWH) to be delivered to the utility's customers. This establishes an average unit electric rate in cents per KWH which will produce the utility's needed revenue stream in the future year.
• Adjustments are then made for customer classes such as residential, commercial, and industrial.
• These forecast expenses, capital in service, electricity sales and proposed rate of return along with all supporting documentation are then presented to the state regulatory body as part of a "rate case." The rate case is assigned a docket number and the utility submissions along with all analyses, new proposals, proposed revisions, etc. by regulatory body staff, electric customer groups, and other affected parties become part of a legal process presented in hearings held before commissioners of the state regulatory body.
• After these hearings are completed, the commissioners of the state regulatory body decide upon rates which are "fair and equitable" to the utility and its customers. Then, the terms and conditions of these rates are published as "electric tariffs."
• The electricity rates established by this process are in effect until new rates are established in a new rate case before the utility regulatory body. As a result, rates are typically in effect for periods of three or more years.

Effects of the Current Electric Utility Regulatory System on Utility Electricity Rates

This system under which regulated electric utilities operate worked very well from the 1930s through the 1960s. During that period, regional capital costs for possible electric generating technologies did not vary greatly. Steam turbine generation was the only alternative available. Wide swings in operating costs did not occur. Price and availability of all fuels were stable and nearly constant.

After about 1970, however, both the capital cost and operating expense environment changed. There were alternatives in generation technology, steam turbine or combustion turbine, with differing capital and operating costs. At that time, there also began a series of great swings in both the real and perceived prices and availability of fuels. Under such conditions of change, components of the regulatory system have had some very specific consequences affecting the way in which electric utilities operated and on where their focus has been placed. Some of these are:

• The current system forces the utilities to focus on invested capital which is usefully in service. Under the system, such capital is their sole source of income. There are two immediate consequences of this circumstance:

  First, there is a powerful tendency to pursue strategies which are capital intensive. Given that any argument can be made in favor of lower operating costs for a generating technology with higher initial costs, that technology will be preferred over a generating technology which has lower initial costs. Further, should the passing of time show such a capital decision to be poor, more problems arise because of a second consequence.

  For regulated electric utilities, once a capital decision is put in place, it tends to be irrevocable. Once a generating plant is in service, there is no way under the current regulatory system that the utility can replace it with newer, more efficient technology. Invested capital or sunk costs are everything; removing an operative plant from service irreplaceably reduces the sole basis on which the utility earns net income. This is precisely the reverse of the situation facing competitive industry. There, "sunk costs don't count." With revenues based on product cost not on capital invested, competitive industry replaces technologically inefficient plant and equipment on an immediate basis.

• The current system removes focus from operating expenses since their level is irrelevant to net income. The immediate consequence of this is a tendency for such expenses to exceed levels considered normal in competitive industry. Further, once the expenses are "locked in," they are difficult to reduce. The example of SWEPCO shown in the "Sales of Electricity to Utilities by NUGs" part in the body of this report illustrates this situation.
  
  SWEPCO negotiated a natural gas supply contract with a supplier of natural gas prior to 1985. This contract had a significant effect on SWEPCO's weighted average cost of gas (WACOG). Whether or not the initial pricing of natural gas under this contract was "high" is not known The terms of the contract, however, caused SWEPCO's WACOG to be significantly higher than that of other electric utilities in Louisiana from 1985 through 1993. No renegotiation of the contract occurred until regulatory intervention in 1993. Lower gas prices were reached after this process.
• The current system produces electric rates which are not only based on forecasts but are relatively long lasting. Consequences of this circumstance are electricity rates which are slow to react to economic changes. Because of this inability of prices to react to such changes, at any given point in time, electricity rates are likely to be more or less favorable to either consumers or utilities than was intended by regulators.

Part IV - Divergent Pathways Between Electricity Generators In Regulated vs. Competitive Environments

Until the late 1960s parties wishing to generate electricity had, essentially, one basic technology as a choice - a steam turbine driven generator. The only differentiating choices lay in the thermal sources (i.e., fuels) by which the steam was generated. In fact, the electric utilities, during the latter two decades of this period, actually became more competitive because their larger boiler / steam turbine systems had economy of scale advantages over the smaller systems of potential NUGs.

With the successful development of combustion turbine systems for driving electric generators, however, the generation prime mover pathways of competitive industry and non-competitive electric utilities diverged. Competitive industry took note of the overwhelming fuel efficiencies of combustion turbine based prime movers as well as the low capital cost of such systems. In spite of looming natural gas supply shortages, industrial NUGs chose combustion turbine based generation wherever possible to minimize the cost of electricity imbedded in their product cost. The key here is reliable low cost electricity. Only in low cost electricity could these industrial NUGs remain competitive marketing the products they manufactured. High fuel efficiency and low capital costs were apparent and persuasive arguments in these firms making correct decisions to use combustion turbine technology.

For the electric utilities, however, choices were made according to different criteria. Neither at that time nor even today, do electric utilities make money by producing least expensive electricity. They make money by investing capital. This is a direct consequence of the regulatory system, discussed above, by which these utilities are compensated.

Having higher capital costs, steam turbine driven generation was favored in the system under which electric utilities operated. If there were concerns over the availability of natural gas at reasonable rates, even in regions such as Louisiana which traditionally used natural gas fired boilers, such problems could be circumvented by the use of coal fired boilers or nuclear reactors. As even greater incentive, coal fired boiler / steam turbine systems allowed greater investment in capital than did natural gas based systems and nuclear reactor systems allowed even greater investment opportunities than did coal fired systems. Long before the advent of the legal limitations initiated in 1978 by PURPA and the Powerplant and Industrial Fuel Use Act, industrial NUGs in Louisiana took one generation path and the electric utilities driven by regulatory law and incentives took another.

Adherence to these respective pathways was cemented in place in 1978 by the effects of legislation designed to "fix" the so-called energy crises. The Powerplant and Industrial Fuel Use Act (FUA) of that year forbade use of natural gas as a boiler fuel by 1990. Before 1978, the electric utilities had increasingly pursued the coal or nuclear steam turbine routes to powering generation as a result of powerful regulatory incentives. After 1978, those incentives became legal requirements.

The FUA, together with the Public Utilities Regulatory Policies Act (PURPA) of 1978, also set incentives, based in law, for the cogenerating industrial NUGs in Louisiana to continue the combined cycle route toward generating electricity. Incentives that had existed before 1978 still existed. These NUGs were cogenerators and combined cycle was the most efficient way to cogenerate. These incentives continued to exist because, under the FUA, cogenerators were exempt from the ban on using natural gas. Under PURPA, there were additional incentives in the form of potential sales to electric utilities. PURPA mandated that the electric utilities buy electricity from cogenerators at the utilities avoided cost.

This divergence continued even after the repeal of FUA limitations on use of natural gas by the utilities. In Louisiana, new electric capacity was not needed. Any construction of combined cycle facilities by electric utilities would, therefore, replace existing investment. Under existing utility regulation, the utilities lacked the economic and financial capacity to replace operating investment. So no utility transition to combined cycle generation was possible.

The net result of this divergence of generation methodology by NUGs in a competitive environment and electric utilities in a regulated environment has been the creation of two distinct systems of generation in Louisiana. The one created in a competitive environment by the industrial NUGs is based on combined cycle generation technology. This system can produce electricity at less than 3.97 cents per KWH, the current average industrial electricity rate in Louisiana. The other system created under regulatory constraints by the electric utilities is based on steam turbine technology. This system produces electricity at an average rate of 5.7 cents per KWH.

Go To Appendix B

Return to Technology Assessment Division Reports Menu

Go to Technology Assessment Division Main Menu

Comments or questions to: techasmt@dnr.state.la.us

These web pages were designed under contract to the Department of Natural Resources and are maintained by employees of the Department of Natural Resources.

This page updated June 18, 2008