Power supply situation summary

For at least the last several years, electric utilities in some parts of the U. S. have experienced difficulties in meeting demands for electric power during peak load seasons. Many of these problems have resulted from inabilities to place new facilities in service on schedule. Peak demands for electric power are increasing at a rate bewteen seven and eight percent a year for the contiguous United States as a whole. However, the growth rate in the different regions ranges from six to ten percent. To meet these growing loads, a significant portion of the presently planned new generating capacity is in nuclear units, which in general have experienced technical and regulatory delays well beyond those experienced with fossil plants. As a result of the recent Grand River decision, new steam plants, both fossil and nuclear, face the possibility of still other delays because of inability to obtain cooling water discharge permits.

There are 18 nuclear and 41 fossil steam generating units, 300 megawatts and larger, scheduled for commercial operation in the period January 1972 through January 1973 (Appendices A and B). In the following three years, through December 1975, 136 more large units are scheduled for service. These figures indicate something of the general magnitude of the task of handling the discharge permit application for large power plants alone, and the situation in some ways would appear to be of almost hopeless dimension when all of the other types of commercial and industrial permit applications are added.

Appendix C presents the projected loads and expected generating capacities, as of June 1971, for the summer of 1972 and the winter of 1972-73. It assumed that all new generating units would achieve commercial service as then scheduled and virtually every one of the 69 planned new units would have to meet its scheduled date of availability if area capacity deficiencies were to be avoided since there are no large capacity surpluses anywhere in the country. While the overall reserve margins resulting from the assumption of availability on schedule appear generally satisfactory, it has now become clear that a number of nuclear units cannot achieve commercial status in time to help meet summer 1972 load peaks, and others have doubtful availability to meet the winter 1972-73 peaks. There are likely to be similar delays in some of the new fossil units also. Therefore, it is essential that delays in any units be avoided to the extent feasible.

Adequacy of electric generating capacity in areas with pending nuclear plant operating licenses

Because of the sizes, the large number of units involved, and the many difficuties experienced in meeting planned dates of initial operation, this section of the report discusses in some detail the impacts of nuclear delays in several areas where critical generating capacity deficiencies could develop during the next 12 months.

Because of the uncertainty about ability to issue interim partial power permits occasioned by the recent Quad Cities court decision, no consideration has been given in the following analysis to the availability of power prior to a full license or to the effect of partial power licenses as a means of advancing the date of full commercial power. It has been assumed that full commercial power could not be available sooner than two months after issuance of a full power license. While this is believed to be a realistic interval, it is recognized that longer periods may be involved in some cases and the best information available to the FPC has been used.

As noted, in some instances the listed capacity for peak load periods includes new fossil capacity scheduled for service beyond the May 31 and October 31 cut-off dates normally used by the FPC to identify dependable summer and winter capacity levels. Experience has shown that such capacity often cannot be considered fully dependable during the first few months of operation.

New England power pool

The winter-peaking New England Power Pool has an indicated reserve margin of 21.4 percent during the summer of 1972, with Pilgrim, Vermont Yankee and Maine Yankee units not available for full commercial power. (Commercial dates of 9/72, 11/72, and 3/73 respectively.) However, the ability of the New England Power Pool to assist the summer-peaking New York Pool will be quite limited. For the winter of 1972-73, with Pilgrim and Vermont Yankee commercially available, the reserve margin would be 22.5 percent.

With Consolidated Edison's Indian Point Unit 2 commercial full power availability taken as July 1972, the adequacy of power in the summer of 1972 will be dependent upon the occurrence of heavy demands resulting from very hot weather, upon whether 1,334 MW of new fossil and gas turbine capability scheduled for June and July 1972 will be in service, and upon the rate of unscheduled capacity outages. With both Indian Point 2 and the new fossil units counted as part of the Pool capacity, the reserve margin would be 21.8 percent, a level which has not always been adequate in the past. Without Indian Point 2, the reserve margin would be 17.4 percent and, considering the character of the reserve, difficulties are probable unless supplemental power can be obtained from outside the area. Because of delays in new capacity, which has kept older units in service and required deferment of maintenance, much of the reserve has a below-average reliability.

The reserve margin in the winter of 1972-73 would be 39.2 percent with Indian Point 2 and 34.5 percent without it, both considered to be generally adequate.

With a highly questionable date of June 1972 as the earliest possible for full power commercial availability of Duke Power Company's Oconee 1 unit and Virginia Electric & Power Company's Surry 1 unit, the adequacy of power in the summer of 1972 for this area may be dependent upon the occurrence of peak power demands resulting from hot weather and the availability of supplemental power from neighboring areas. Counting both nuclear plants as part of the available capacity, and also 1,010 MW of fossil capacity scheduled for June and July 1972, the reserve margin is still a minimal 12.2 percent. Since these fossil units are questionable, the reserve even with the nuclear plants could be as low as 7.3 percent. Without the Surry 1 nuclear plant, but with Oconee 1 and the questionable fossil units, the margin would be 8.2 percent. These margins are substantially below prudent levels and emphasize the importance of the nuclear plant availabilities.

For the winter of 1972-73, the reserve margin with Oconee 1 and Surry 1, but without Oconee 2 or Surry 2 is 23.4 percent.

Florida

Florida, which lacks adequate transmission interconnections within the state and with other areas, is largely dependent upon its own resources and requires more reserve margin than some other interconnected areas. Turkey Point 3, on the basis of present predictions, has an earliest full power commercial availability date of June 1972 and could assist in meeting the 1972 summer peak load if it meets that schedule. Turkey Point 4, with a commercial full power availability date of September 1972, cannot be counted on for the summer 1972 peak load. With Turkey Point 3, the reserve margin in the summer of 1972 would be 17.1 percent. Should Turkey Point 3 not meet the schedule, the situation could become critical.

The reserve margin in the winter of 1972-73, with both Turkey Point 3 and 4 in service, also would be 17.1 percent.

TVA is a member of the Southeastern Electric Reliability Council, which also includes the Virginia-Carolinas sub-region and the Florida sub-region discussed above. Although the TVA system itself experiences a slightly higher lead peak in the winter than in the summer, it has firm power exchange agreements with other power systems which result in summer generation demands greater than those of the preceding winter.

The Browns Ferry Nuclear Plant has three 1,065 MW units under construction, with expected dates of authorization for full power operation of October 1972 (Unit 1), July 1973 (Unit 2), and February 1974 (Unit 3). Although the slippages already experienced by Unit 1 will make it unavailable for the summer of 1972, when the TVA generation reserve margin is only 15.0 percent, it is still needed in time for the winter 1972–73 peak. With Browns Ferry 1 in service, the reserve margin in the winter of 1972-73 will be 19.1 percent, without it the margin will be 13.2 percent.

If the Palisades plant receives a full power license in May of 1972 and is in full power commercial service by late June 1972, the Michigan Pool reserve margin for the summer of 1972 will be 13.7 percent. Without this capability, the reserve margin would be only 8.9 percent and there could be an additional demand on the reserve power available from the East Central Area, which will probably be needed to support prospective shortages in the Northern Illinois area.

Northern Illinois, Wisconsin and Upper Michigan

Recent court decisions and environmental modification requirements make uncertain the availability of power from Quad Cities Units 1 and 2 during the summer of 1972. The Point Beach AEC-estimated date of June 1972 for a full power license indicates that commercial full power status is not probable before August 1972, when the summer load peak may have been already reached. It is clear that without these plants, the adequacy of power in the summer of 1972 will depend critically upon the extent of unscheduled outages and the availability of power from neighboring areas, especially the East Central area.

If the two Quad Cities units and the Point Beach unit were available for the 1972 summer peak, the reserve margin would be 14.7 percent. With none of these three units available, the reserve margin would be only 8.7 percent, which is extremely low.

Because the winter peak is considerably less than the summer peak, the reserves in the winter of 1972-73 appear to be adequate (assuming no shortage of fossil fuel), without the Quad Cities units, the Point Beach unit, the Kewaunee 2 unit or the Zion Unit 1. However, some of these units may be needed in that period to allow performance of urgent maintenance on existing units which is being deferred during the current period of low margins.

Net capability (megawatts).

Peakload (megawatts)..

Reserve (megawatts).

Reserve (percent of peakload).

Summer 1972

121, 122
18,414
2,708

14.7

2 20,018 18,414

1,604 8.7

1 With Quad Cities 1 and 2, at a combined capacity of 809 mw. due to cooling limitations, and Point Beach, 2 Without Quad Cities 1 and 3, or Point Beach. (Note that half the capacity of Quad Cities 1 is committed to the lowa pool.)

Iowa pool

The Iowa Pool, of which Iowa-Illinois Gas and Electric Company is a member, faces the summer of 1972 with a total generating capacity that is 45 megawatts less than predicted peak load if the latter's share of the capacity of Quad Cities Unit 1 is unavailable. With only its existing capacity, and delays of new units on adjacent systems making uncertain the availability of supplemental power, the Iowa systems position is marginal. Projected Iowa Pool conditions for the 1972 summer are presented in the following table.

The Prairie Island, Unit 1. generation facility of the Northern States Power Company (530 MW) is scheduled for commercial service in November 1972. Because in this area the summer peak loads are somewhat greater than the winter peaks, the reserve margin in the winter of 1972-73 appears to be adequate even if the unit is delayed a few months. However, its availability for the summer of 1973 is essential, as indicated in the following table.

Rocky Mountain Area (Public Service Company of Colorado)

The Fort St. Vrain unit, with an estimated full operating license date of July 1972 and a commercial full power availability date of September 1972, cannot be considered as capacity for meeting the peak 1972 summer loads. Without Fort St. Vrain, the company's summer 1972 reserve margin is only 12.1 percent. Because of limited transmission interconnections, little assistance can be provided from neighboring systems.

With Fort St. Vrain available for the winter of 1972-73, the reserve margin would be 22.2 percent, but without it the reserve would be only 3.1 percent. The importance of Fort St. Vrain to an adequate electric power supply is evident.

Major fossil-fueled generating units scheduled for 1972 and early 1973

In the period from January 1972 through January 1973, there are some 41 fossil-fueled generating units of 300 megawatts and larger capacities scheduled for initial operation. More than half of these are located in sections of the country which are also dependent upon large new nuclear units becoming available for commercial service during the same time period if serious deficiencies in capacity to meet expected loads are to be avoided.

These fossil-fueled units are of similar importance to an adequate power supply and are subject to possible delays the same as the nuclear ones except that licensing requirements in most instances are not as complicated.

As mentioned earlier, a list of the fossil-fueled units scheduled between now and the end of 1975 is included as Appendix B of this report.

Interchange power considerations

Virtually all of the major electric utility systems in the U.S. are interconnected, with the exception of a group in Texas which interconnect with each other but not with the remainder of the network which spans the Nation. There are a number of places in which high capacity connections than those in existence would be desirable in order to permit larger power transfers under some normal conditions and in emergency. The attached sketch indicates the approximate transfer capabilities between Electric Reliability Council areas as of 1970.

Possible ramifications of the Rivers and Harbors Act of 1899

The application of provisions of the Rivers and Harbors Act of 1899 has involved permits by the Corps of Engineers for cooling water or other discharges from power plants. Many of the plants scheduled for service in 1972 as men. tioned earlier, both nuclear and fossil-fueled, have applications pending for discharge permits. It is our understanding that approval of the Environmental Protection Agency is required before such permits are issued by the Corps of Engineers.

This area of permit procedure offers a potential threat to the timely availability of new generating plants because of the large volume of permit applications which must be processed and the lengthy procedures involved in some cases. It is our understanding that the total backlog of all applications, both power plants and others, involves some 20,000 permits if it is proven necessary to process all cases that might be subject to review.

The matter of discharge permit procedure is further complicated by the recent court decision in the Grand River Case which challenges the jurisdiction of the Corps of Engineers in the case of non-navigable waters and raises questions about permit authority and environmental review procedures which may require considerable time to resolve.

Fossil fuel problems

We do not have conclusive information at this time about the total fossil fuel picture and the problems which may arise and increase as more restrictive air quality control regulations become effective in the months and years ahead.