units pressed into service only when the region is threatened with serious power shortages.

The construction of Federal multiple-purpose hydroelectric dams in the Pacific Northwest reached a peak in 1952 when 13 dams were under construction and has steadily declined since then. Presently, Grand Coulee pump generators 9 through 12 and Bonneville Dam Second Powerplant are under construction. Bonneville Second Powerplant will add 182 MW of average annual energy and 558 MW nameplate capacity (including fishwater units). Grand Coulee pump generators 9 through 12 will add additional (200 MW) peaking capability only. Cougar Additions, Strube Dam and generation, and Libby Dam Additions are scheduled for commercial operation from November 1985 to September 1986. McNary Second Powerhouse is authorized but no construction date is set.

However, the outlook for many more large hydropower projects is dim. While half of the power potential remains unharnessed, particularly on tributaries of the Columbia River, almost half of the unharnessed water power lies within wild and scenic rivers, wilderness, and recreation areas. Prospects are better for small hydro projects which make use of existing structures. The Corps of Engineers and the Water and Power Resources Service are conducting studies requested by Congress to assess the total available potential. The Corps of Engineers is in the process of screening this total potential to identify a list of projects which merit further study. The screening process is designed to pick out projects which appear to be economically feasible while meeting environmental tests. Further screening will yield a smaller list of projects which merit a high priority for early development.

The Corps of Engineers' role, with respect to the Federal Columbia River Power System, includes more than just power production. Their projects in the Federal Columbia River Power System were authorized as multipurpose projects of which hydropower is only one function. Other functions include: flood control, navigation, irrigation, recreation, and minimum streamflows. Therefore, the Corps of Engineers must take into consideration purposes other than power generation when scheduling the available water in the river system through their projects. The projects are planned, constructed, and operate in cooperation with the States and other Federal agencies to provide for maximum utilization of the resources. Further, Congress has directed that in those areas lying wholly or in part west of the 98th meridian, any such uses must not conflict with any beneficial consumptive use, present or future. Certainly one of the most common consumptive uses from the Columbia River System is irrigation. Accordingly, in the long-range planning studies, the Corps of Engineers, Bonneville Power Administration, and the Northwest Power Pool all assume this policy will continue.

In addition, a number of thermal powerplants, ranging from relatively small oil-fired combustion turbines to very large coal-fired and nuclear powerplants, with a combined capability of more than 13,000 megawatts, are scheduled for installation in the region within the next decade.

The Federal Columbia River Power System

The Federal Columbia River Power System (FCRPS) is comprised of three principal elements: (1) the hydroelectric generating projects constructed and operated by the U.S. Army Corps of Engineers and the Water and Power Resources Service (WPRS) within the Pacific Northwest region, (2) the electric transmission system constructed and operated by the Bonneville Power Administration, and (3) power acquired by BPA through exchanges and net-billing.

BPA, which became an agency of the new U.S. Department of Energy in October 1977 after being part of the Department of the Interior for its first 40 years, is the marketing agent for the power produced by the Corps and WPRS projects. BPA also acquires some shares of the capacity of thermal generating plants constructed by non-Federal publicly owned entities such as municipal electric utilities and joint operating agencies. BPA melds its acquired power with the Federal hydropower and markets the melded product wholesale to electric utilities, other Federal agencies, and certain (direct-service) industrial customers. BPA also "wheels" (transmits) power over its facilities for others.

BPA has always been obliged to repay the Federal investment in the FCRPS and to pay all FCRPS operating costs from revenues. However, prior to 1975, BPA had received all of its operating and capital investment funds by means of annual appropriations from Congress. BPA is now authorized to sell bonds to the U.S. Treasury to raise capital funds to finance the construction of new transmission facilities. And on behalf of the FCRPS, BPA is obligated by statute to set its power and wheeling charges at "the lowest possible rates to consumers consistent with sound business principles" that will fully repay any bonds it has issued and fully recover all of the costs to the Federal Government of generating, purchasing, transmitting, and marketing electric power, including the amortization of the Government's investment in power facilities, with interest.

The various statutes under which BPA operates require that preference and priority be given to public bodies and cooperatives in the sale of FCRPS power. The Bonneville Project Act, Section 4(a), states that: "In order to insure that the facilities for the generation of electric energy at the Bonneville project shall be operated for the benefit of the general public, and particularly of domestic and rural customers, the Administrator shall at all times, in disposing of electric energy generated at said project, give preference and priority to public bodies and cooperatives."

In 1978, BPA marketed power from 30 Federal hydroelectric projects to 147 customers in the Pacific Northwest--116 publicly or cooperatively owned utilities, 8 investor-owned utilities, 6 Federal agencies, and 17 direct-service industrial customers. For 98 of its utility customers, BPA is the sole source of power supply. BPA markets about one-half of the electric energy produced in the Pacific Northwest and provides about four-fifths of the region's electric power bulk transmission capacity.

BPA's transmission system consists of about 12,500 circuit miles of high-voltage transmission lines and 345 substations. The BPA transmission system constitutes America's largest high-voltage transmission network and is the "backbone" grid to which all interconnected utilities in the region are tied for reliability and economic efficiency. BPA also markets and exchanges electric power interregionally over the Pacific Northwest-Pacific Southwest Intertie, and in Canada over interconnections with utilities in British Columbia.

The First Three Decades (1937-68)

BPA's first three decades of operation, from 1937 to the mid-1960's, were by and large a period of abundantly available Federal power. BPA was generally able to meet the net requirements of all of its customers-- preference utilities, investor-owned utilities, and direct-service industries. BPA charged essentially the same rate to all

these customers.

Two major developments occurred during this period of power abundance. First, voters in the State of Washington elected to establish many more publicly and cooperatively owned power agencies than were established in Idaho, Montana, or Oregon. For example, today about 57 percent of Washington State consumers are served by public bodies and cooperatives, while in Oregon, Idaho, and Montana, respectively, 20, 17, and 24 percent are served by public bodies and cooperatives. The choice at the time was based as much, if not more, on political ideology as on power costs since BPA had sufficient power to meet the needs of investor-owned utilities, too. Moreover, larger utilities that built additional generation of their own were often able to do so at relatively low costs that were more or less equivalent to BPA's rate of power.

Second, starting in 1940, direct-service industries--principally aluminum reduction plants--came to the region. By the end of World War II, 5 aluminum plants, 4 of which were established during the war to meet war production goals, were operating in the Northwest. Today there are 10 aluminum reduction plants, the newest of which went into operation in 1971. In addition, major expansions occurred from 1950 through 1968 in existing plants. An important characteristic of the direct-service industries is that they provide a market for interruptible power which in earlier years would have been wasted.

There is a distinction between power planning and actual power operations. The power system is planned so that, ideally, total demand for electricity in the Pacific Northwest is met, even under critical water conditions. The portion of BPA's industrial loads that can be contractually interrupted is included in that total demand. Under actual power system operations, however, the 25 percent interruptible portion of BPA's industrial loads can be and has been curtailed at any time, for any period, and for any reason. In addition, a significant portion of the remaining direct-service industrial load is available as power system reserves.

The Hydro-Thermal Power Program

Until the mid-1960's, virtually all of the electricity generated in the Pacific Northwest was hydropower. Regional planners and engineers had long recognized, however, that there was a limited amount of economically feasible and environmentally acceptable hydro energy potential. As that potential was progressively developed and as the region's population, economy, and demand for electric energy continued to grow, planners and engineers concluded that thermal powerplants would have to be built to supplement dams in supplying electricity to meet growing loads. Additional low-cost peaking power could continue to be obtained by installing additional hydro generator units, primarily at existing dams, and some smaller-scale hydro energy potential could also be developed. But the region's power system would gradually change from virtually all-hydro to mixed hydro-thermal.

The concept of blending hydro and thermal resources together in an optimum fashion was not new. Its genesis dated back many decades. The idea fulfilled the predictions of regional planners and engineers in the Pacific Northwest and elsewhere who, since the early 1920's, recognized the advantages of integrating hydro peaking capacity with thermal energy. In 1955, the United States Senate Public Works Committee directed the Corps of Engineers to review its "308 Report" by restudying the Northwest's hydropower potentials "as part of a combined hydrothermal system." Complying with that congressional directive, the Corps published a comprehensive revision of the "308 Report" in 1958 which spelled out the concepts of joint operation of hydro projects with thermal projects. These concepts were developed into an action program by the Joint Power Planning Council in 1968 called the Hydro-Thermal Power Program (HTPP).

While some of the details of the Hydro-Thermal Power Program are complicated, the essential features are quite simple. Basically, it was designed to fulfill two key objectives. First, it should permit development of an adequate and reliable supply of power to meet future Northwest electricity demand at the lowest practicable cost. Second, the long-range plan should achieve optimum combination of the region's generating and transmission resources--hydro and thermal, Federal and non-Federal, public and private, existing and planned. Even before the program was approved, it was also assumed that an optimal future power system, which would be able to meet electric energy demand with (1) substantial flexibility as far as plant siting is concerned, and (2) the most efficient and least use of generation and transmission resources, could be structured to pay maximum effective attention to protection of the environment.

To meet these twin objectives, the region's utilities and the Federal Government would plan, build, and operate the region's entire electric system as though it were under a single ownership--the "one-utility" concept. Thermal power would be integrated with hydropower. Markets would be assured for the output of the largest and most economical thermal plants. Bulk transmission, peaking capacity, forced outage

reserves, reserves for unanticipated load growth, and, when available, surplus hydro energy for thermal fuel displacement would be primarily Federal responsibilities. Building the most economical thermal powerplants timed, sized, and located to meet regional needs (instead of just the needs of the owners), and providing essential low-voltage transmission and distribution would be the key responsibilities borne by non-Federal utilities. An unprecedented high level of interutility cooperation would be the goal.

Phase 1 of the HTPP (1968-73)

The plan was conceived by the Joint Power Planning Council, which was organized in 1966 and consisted of 108 participating Pacific Northwest utilities and BPA. The plan was unveiled on October 22, 1968, and a year later, on October 27, 1969, was approved by the national administration. Implementation of the program was initiated by Congress in the Public Works Appropriations Act of 1970. The Act approved net-billing, the principle whereby BPA would acquire some of the publicly financed shares of the output of non-Federal thermal powerplants (an arrangement which is explained below). Authority to implement the remainder of the program through 1981 (Phase 1) was provided in the Appropriations Act of 1971. Thus, the Hydro-Thermal Power Program was launched. A list of the plants included in the HTPP are listed on page IV-31.

Perhaps the most important feature of Phase 1 of the HTPP is that BPA acquires some of the output of some of the proposed thermal powerplants through "netbilling.' Under this arrangement, preference utilities (public bodies and cooperatives) have built and are building portions or all of certain thermal powerplants to meet their future power requirements. They furnish the output to BPA. BPA in turn bears the preference customers' shares of the costs of those powerplants, acquires the power output, and blends it with Federal hydropower. BPA then sells the blended product to its various customers, including the participating preference utilities. It "pays" those utilities for their shares of the powerplants' costs by reducing their annual bills for power purchases and other services from BPA. Three goals are accomplished: (1) financing costs for preference utilities to build powerplants are reduced (through lower interest rates) because of commitments by BPA to acquire output and pay costs, (2) BPA's power supply is augmented, and (3) costs are distributed to all consumers of BPA power.

Two unexpected events occurred to limit use of this approach to meet regional power demands. First, unanticipated skyrocketing costs for construction of new thermal powerplants began to exhaust BPA's netbilling capability earlier than anticipated. This occurred because thermal powerplant costs have beed increasing much more rapidly than BPA wholesale power rates, which are based on blended hydro-thermal costs. If more thermal powerplants were to be built in addition to the four which are already covered under net-billing, the sums that BPA would be obligated to credit against preference customers' billings (reflecting