Under the Federal Power Commission's administratively established electric reliability program, docket No. R-362, all utilities (cooperative, investor and public) are requested to report their loads and projected facilities to meet loads on a 10-year forecast. The first complete calendar year of operation under this program was reported to the Commission in April 1971.1 These reports, other data on file with the Commission, and data received from the Rural Electrification Administration in respect to these hearings support the conclusion of the Bureau of Power report (p. 5, appendix A), that cooperatively owned systems do not show a consistent pattern of installing additional generating capacity to supply their own loads. This would appear to reflect a number of factors: economic costs to cooperatives of building their own generation and related transmission; the alternative costs of purchasing power at wholesale from other types of systems, primarily federally owned or investor owned; the policies which any given cooperative may have in respect to regionally sized plants and integrating the operation of its system with noncooperatively owned utilities: and the cost of capital resources to expand bulk power supply facilities, if cooperatively owned. And, there may be others.

But, in all of these, what I see is that cooperatives, as others, will exercise various available options and economic choices. Throughout the United States, electric utilities conduct their bulk power supply transactions through a number of coordinating actions, including 22 formal power pools. That activity is also coordinated with the actions of nine electric reliability councils. The power pools and reliability councils fall into regional patterns, grouped according to load centers. This arrangement reflects several factors, including the natural geographic dispersion of fossil fuel supplies throughout most portions of the Nation, the available technology for locating fossil-fired or nuclear plants throughout various regions of the Nation, and the comparative economic costs and operating factors in building specific transmission lines versus the location of generating units.

We endorse the cooperatives' expanded participation in the regional system planning coordinated through the electric reliability councils. It is the stated policy of the commission to encourage the most widespread and active participation by all types of utilites which may have an interest in bulk power supply plannng and operation; and to project further into the future in respect to loads, generating and transmission facilities, fuels and environmental requirements and procedural and substantive due process requirements to help assure timely construction of needed facilities.

The following map and tabulation identify the councils and pools, and summarize the current utility membership in the electric reliability councils.

1 Appendix E hereto sets forth the Commission's staff initial analysis of these reports. Appendix F sets forth a listing of the member utility systems participating in the R-362 program and the various systems which comprise the Nation's 22 formal power pools.

2 I note the following portion of the 1971 annual report of the National Rural Utilities Cooperative Finance Corp., p. 2:

CFC has ushered in a new era for rural electrification. For 35 years, the Nation's rural electric systems depended entirely upon loan funds from the Rural Electrification Administration (REA) for their growth capital. On February 16, 1971, at the annual meeting of the National Rural Electric Cooperative Association *** in Dallas, Tex., the first two long term, secured REA-CFC concurrent loans were announced. For the first time in the history of the program, outside capital other than that provided by REA would be entering the program. In the words of REA Administrator David Hamil, this meant a 'new ball game under a new set of rules'."

$ 1 cooperative member of SPP is also a member of MAIN.

4 There are 374 members of the ECAR Liaison Committee, but these systems are not member of ECAR itself.
$5 investor-owned members of MAIN are also members of MARCA.
Also a member of SPP.

7 Duplicate membership has been eliminated from numbers in parentheses.

Note: App. F lists cooperative, investors, and public systems which participate in the councils as well as the formal power pools. Staff personnel of the Federal Power Commission and various State public service commissions participate through an observer status role in the work of the councils.

Source: This table has been complied from data in the Apr. 1, 1971, responses of the regional reliability councils to order 383-2.

In addition to participation in regional councils and some power pools, I am happy to note that representatives of cooperatively owned utilities have actively participated in the industry advisory groups which the Federal Power Commission created to assist in its work on the 1971 National Power Survey and on the 1964 National Power Survey.

B. The cost impact portion of your question, as it relates to changing policies and developing techniques, involves variables and assumptions which are almost infinite. Moreover, there are many factual unknowns. To the extent that electric utilities experience continued inflationary spirals in increased costs of capital, material, fuel, taxes, and labor, the bulk power delivered costs of kilowatts and kilowatt hours to cooperative systems (whether self-generated or purchased) will tend to rise from present levels.

Although I believe the precise cost of electric power over the long term is largely unpredictable, I do believe that it is possible to project orders of magnitude subject to rather substantial forecasting error. On balance, it seems clear that the direction of change in power cost will be upward and that the increase over the next 20 years could be double present cost levels unless we are able to largely eliminate inflation or we are able to establish new technologies with currently unpredictable economies over that period of time.

Moreover, if the prediction of electric power cost in the future, on an overall industry basis, is difficult, it is even more difficult to predict with any assurance the power cost of the cooperative sector of the electric power industry since it is subject to variable governmental policies as well as growth of rural service areas.

The cost of REA-financed G. & T. power may increase at an even greater rate than wholesale rates for the balance of the electric utility industry. In the past, these cooperatives have been financed with 2percent debt money. In recent years, the Rural Electrification Administration has financed less and less of a project with Government loans. Borrowers have financed more with money secured at higher rates of interest. Any significant jump in financing costs, plus all the other problems common to the utility industry-higher fuel costs, higher facility costs, added environmental, or other costs, necessarily will show up in the rates charged by the G. & T.'s.

In summary form, the following variable factors will govern future costs: (1) environmental standards and costs; (2) control of inflation; (3) fuel costs; (4) the success of the current nuclear generation program for bringing the fast breeder reactor into significant commercial operation during the eighties; (5) the extent to which utilities are able to utilize available economies of scale (particularly in generation and transmission) that are presently technologically feasible or will be during the next few decades; (6) the extent to which the ownership structure of the industry changes, including combinations and consolidations, as well as changes in the shares of the business of the industry served by investor owned, publicly owned, and cooperatively owned sectors; (7) the extent to which the antitrust laws will be employed to stimulate or discourage changes in the structure of the industry and in the joint use of bulk power supply facilities: (8) national energy import policies (with particular reference to oil and LNG) and import policies relating to equipment and sup

plies utilized by the power industry, as well as international monetary policies; (9) Federal, State, and local tax policies; and (10) the extent of the research and development effort by the electric power industry and governmental agencies, and the success of these efforts in further improving economies of scale, improving environmental control equipment and procedures, and in other ways improving the quality and reducing the cost of electric service.

Obviously, among the listed factors, there are some which are likely to have the effect of decreasing electric power costs. For example, I would cite the possible cost reduction effects of a successful nuclear program, greater economies of scale, and new means of conversion, which may be found through research and development.1

Second question-You also ask for my views "on the potential electrical interconnection of various regions of the country, anticipated research and development efforts related to bulk power supply and the impact of environmental concerns on the entire power industry.

Appendix C outlines the current status of electric power transmission in the contiguous United States. There are trouble spots in our electric utility systems network, both short range and long term. Some transmission ties are in need of strengthening. In some geographic areas, more installed capacity is needed for reserve purposes, and there is need for improved planning and operation of all systems of the three ownership sectors of our pluralistic utility industry on a fully coordinated basis. Presently, individual utility systems face problems which include (a) the operation of existing facilities refiably and with maximum economies; (b) the planning of generation and transmission facilities to meet loads in future years with regard to the needs of all neighboring systems upon regional bases and maximizing the advantages available from economies of scale, new technologies and new equipment; (c) the operation of public utility service within the framework of a proliferating array of State and Federal regulations and laws, and (d) the acquisition of the necessary capital resources to meet an industrywide growth rate that is doubling approximately every decade. Gross electric utility plant investment (undepreciated) of all sectors (cooperative, investor and public electric. systems) totaled $95.1 billion in 1968.

By 1990, we estimate that this figure will increase to approximately $484.4 billion, in 1968 equivalent dollars.

1 In this respect I would note that the incremental costs of installing the big "shiny new units" on a unit cost/kilowatt basis is tending to rise for many systems over embedded historical plant and associated costs for older units due to higher material, land, and labor costs, thereby increasing average capital costs of individual systems. While there are numerous economies of operation and fuel, there are also cost increases.

2 A comprehensive analysis of electrical interconnection conditions was presented to the House Subcommittee on Communications and Power on May 6, 1971, hearing pp. 433-438 and appendixes F and G thereto.

Our estimate of total investment is set forth in the National Power Survey to be published this year. The following table shows the actual breakdown of investment by ownership sectors for 1968. It also shows the breakdown of the estimated total 1990 investment on the assumption that the shares of toal investment by ownership sectors remains the same as in 1968.

GROSS INVESTMENT IN ELECTRIC PLANTS