ML20063N781
| ML20063N781 | |
| Person / Time | |
|---|---|
| Site: | Skagit |
| Issue date: | 09/16/1982 |
| From: | PUGET SOUND POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML20063N779 | List: |
| References | |
| ENVR-820916, NUDOCS 8210070193 | |
| Download: ML20063N781 (250) | |
Text
{{#Wiki_filter:_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ S/HNP-ASC/ER 9/16/82 File the NRC transmittal letter and the instruction sheets following the NRC tab. File the Energy Facility Site Evaluation Council letter following the EFSEC tab. The following information and check list are furnished as a guide for the insertion of nes sheets for Amendment 7 into the Application for Site Certification / Environmental Report for the Skagit/Hanford Nuclear Project. This material is denoted by use of the amendment date in the upper right-hand corner of the page. New sheets should be inserted as listed below: Discard Old Sheet Insert New Sheet (Front /Back) (Front /Back) CHAPTER 1 1-1/1-11 1-i/1-11 1-iii/1-iv 1.0-1/1.0-2 through 1.1-11/ 1.0-1/1.0-2 through 1.0-11/ blank 1.0-12 Os 1.1-1/1.1-2 through 1.1-23/ 1.1-1/1.1-2 through 1.1-23/ 1.1-24 blank Table 1.1-1/ Table 1.1-2 Table 1.1-1/ Table 1.1-2 through Table 1.1-7 2 of 2/ Table 1.1-6/ Table 1.1-7 blank 1.2-1/ blank 1.2-1/1.2-2 through 1.2-9/1.2-10 Tab 1.2 (blue) Table 1.2-1/ Table 1.2-2 Tab 1.2 (dk blue) Figure 1.2-1 through Figure 1.2-3 1.3-1/ blank 1.3-1/1.3-2 1.4-1/ blank 1.4-1/ blank CHAPTER 2 2.1-3/2.1-4 2.1-3/2.1-4 Figure 2.1-lb Figure 2.1-lb Figure 2.1-2 Figure 2.1-2 Figure 2.1-3 1 of 2 Figure 2.1-3 1 of 2 ( ( Figure Figure 2.1-3 2 of 2 2.1-16 Figure Figure 2.1-3 2 of 2 2.1-16 s_ j l'B210070193 820916 1 Amendment 7
- J~PDR ADOCK 05000522 C PDR .
S/HNP-ASC/ER 9/16/82 Discard Old Sheet Insert New Sheet (Front /Back) (Front /Back) Figure 2.2-2 Figure 2.2-2 Figure 2.2-4 Figure 2.2-4 Figure 2.6-3 Figure 2.6-3 Figure 2.6-4 Figure 2.6-4 Figure 2.6-5 Figure 2.6-5 Figure 2.6-6 Figure 2.6-6 CHAPTER 3 Figure 3.1-1 Figure 3.1-1 Figure 3.1-la Figure 3.1-la CHPUTER 4 4.1-3/4.1-4 4.1-3/4.1-4 4.1-5/4.1-6 4.1-5/4.1-6 4.1-6a/ blank Figure 4.1-1 Figure 4.1-1 Figure 4.2-2 Figure 4.2-2 CHAPTER S Figure 5.6-1 Figure 5.6-1 CHAPTER 6 6.1-15/6.1-16 6.1-15/6.1-16 Table 6.1-8/ Table 6.1-9 table 6.1-8/ Table 6.1-9 Figure 6.1-5 Figure 6.1-5 CHAPTER 7 Table 7.1-3 Sheet 1 of 2/ Table 7.1-3 Sheet 1 of 2/ Table 7.1-3 Sheet 2 of 2 Table 7.1-3 Sheet 2 of 2 Table 7.1-15/ Table 7.1-16 Table 7.1-15/ Table 7.1-16 ; 2 Amendment 7
S/HNP-ASC/ER 9/16/82 O Discard Old Sheet (Front /Back) Insert New Sheet (Front /Back) CHAPTER 8 8-1/8-11 8-i/8-ii 3-lii/8-iv 8-iii/8-iv 8.3-1/8.3-2 through 8.3-1/8.3-2 through 8.3-13/8.3-14 8.3-14a/ blank 8.3-17/8.3-18 8.3-17/8.3-18 8.3-19/8.3-20 8.3-19/8.3-20 8.3-20a/8.3-20b 8.3-20a/8.3-20b 8.3-20k/ blank 8.3-20k/ blank 8.3-21/8.3-22 8.3-21/8.3-22 8.3-23/8.3-24 8.3-23/8.3-24 8.3-27/8.3-28 8.3-27/8.3-28 8.3-29/8.3-30 8.3-29/8.3-30 8.3-35/8.3-36 through 8.3-35/8.3-36 through 8.3-41/ blank 8.3-41/ blank Table 8.3-lb/ Table 8.3-2 Table 8.3-lb/ Table 8.3-2 Sheet 1 of 2 Sheet 1 of 2 Table 8.3-2 Sheet 2 of 2/ Table 8.3-2 Sheet 2 of 2/ blank blank O Table 8.3-3/ Table 8.3-4 Table 8.3-14/ Table 8.3-15 Table 8.3-17/ Table 8.3-18 Table 8.3-3/ Table 8.3-4 Table 8.3-14/ Table 8.3-15 Table 8.3-17/ Table 8.3-18 Figure 8.3-1 Figure 8.3-1 Figure 8.3-5 Figure 8.3-5 Figure 8.3-7 Figure 8.3-7 8.5-1/8.5-2 through 8.5-1/8.5-2 through 8.5-7/ blank 8.5-7/8.5-8 CHAPTER 9 9-1/9-11 9-i/9-il 9.2-1/9.2-2 through 9.2-1/9.2-2 through 9.2-ll/ blank 9.2-31/ blank Tab 9.6 (clear) 9.6-1/ blank APPENDIX A [ Entire Appendix A New Appendix A o 3 Amendment 7
S/HNP-ASC/ER 9/16/82 Discard Old Sheet Insert New Sheet (Front /Back) (Front /Back) QUESTIONS AND RESPONSES N-27/N-28 N-27/N-28 E-9/E-10 E-9/E-10 l 1 1 l l O l l i O 4 Amandment 7
S/HNP-ASC/ER 9/16/82 CHAPTER 1.0 PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION
- CONTENTS l
SECTION TITLE PAGE 1.0 Background 1.0-1 1.0.1 Introduction 1.0-1 1.0.2 The Project 1.0-2 1.0.3 Applicants 1.0-2 1.0.4 Purpose of the Project 1.0-3 1.0.5 The Pacific Northwest Region 1.0-3 1.0.6 Characteristics of the Region 1.0-3 1.0.7 Regional Coordination and Planning 1.0-4 1.0.8 Regional Power Act 1.0-10 1.1 Deterministic Analysis 1.1-1 1.1.1 System Demand and Reliability 1.1-1 1.1.1.1 Load Characteristics 1.1-1 1.1.1.1.1 Load Analysis 1.1-1 1.1.1.1.2 Demand Projections 1.1-2 1.1.1.1.2.1 Puget Sound Power & Light Company 1.1-2 1.1.1.1.2.2 Portland General Electric Company 1.1-4 1.1.1.1.2.3 Pacific Power & Light Company 1.1-9 1.1.1.1.2.4 The Washington Water Power Company 1.1-16 1.1.1.1.2.5 Regional Forecasts 1.1-19 1.1.1.1.3 Power Exchanges 1.1-20 1.1.1.2 System Capacity 1.1-20 1.1.1.3 Reserve Margins 1.1-21 1.1.1.4 External Supporting Studies 1.1-22 1.1.2 Other Objectives 1.1-22 1.2 Nondeterministic Analysis .l.2-1 1.2.1 Introduction 1.2-1 O l-i Amendment 7
S/HNP-ASC/ER 9/16/82 SECTION TITLE PAGE 1.2.2 A Bounding Approach to Regional Need 1.2-1 O 1.2.3 Applicants' Need for S/HNP 1.2-5 1.2.4 Critique of Regional Forecasts 1.2-6 1.2.4.1 PNUCC 1982 Northwest Regional Forecast 1.2-6 1.2.4.2 BPA Forecasts of Electricity Consumption in the Pacific Northwest, April 1982 (draf t) 1.2-7 1.2.4.3 Independent Review of Washington Public Power Supply System Nuclear Plants #4 and #5 (January 1982) 1.2-7 l 1.2.5 The NRDC Forecast 1.2-8 1.3 Consequences of Delay 1.3-1 1.4 Potential for Future Activites at Site 1.4-1 O O l-11 Amendment 7
S/HNP-ASC/ER 9/16/82 CHAPTER 1.0 PURPOSE OF THE PROPOSED FACILITY I AND ASSOCIATED TRANSMISSION TABLES NUMBER TITLE Section 1.1 1.1-1 Puget Sound Power and Light Company l Operating Year (July through June) Load ' Growth Actual and Projected System Loads 1.1-2 Portland General Electric Company Operating Year (July through June) Load Growth Actual and Projected System Loads 1.1-3 Pacific Power and Light Company Operating Year (July through June) Load Growth Actual and Projected System Loads 1.1-4 The Washington Water Power Company Operating Year (July through June) Load Growth Actual and Projected System Loads 1.1-5 West Group of Northwest Power Pool Operating Year (July through June) Load Growth Actual and Projected System Loads 1.1-6 Four Company Loads and Resources Based on 1982 NRF 1.1-7 Northwest Region Loads and Resources West Group Area Only Section 1.2 1.2-1 Northwest Region Existing, Relative Assured, and Potential Resources 1.2-2 rour Company Composite Expected Loads - Existing and Relatively Assured Resources O l-lii Amendment-7 L.. ..... ..
S/HNP-ASC/ER 9/16/82 CHAPTER 1.0 PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION FIGURES NUMBER TITLE Section 1.2 1.2-1 Regional Electricity Forecasts 1.2-2 Northwest Regional Loads and Resources 1.2-3 Four Company Composite Loads and Resources O O l-iv Amendment 7
. . _ ._J
S/HNP-ASC/ER 9/16/82 CHAPTER 1 PURPOSE OF THE PROPOSED FACILITY AND ASSOCIATED TRANSMISSION
1.0 BACKGROUND
1.
0.1 INTRODUCTION
This chapter is presented in four major sections. The first is Section 1.0, BACKGROUND. This section provides an overview of the Project, the Applicants, and the Pacific Northwest Region. The second major section is Section 1.1, DETERMINISTIC ANALYSIS. This section includes the information suggested by Regulatory Guide 4.2 of the Nuclear Regulatory Commission. It presents a traditional deterministic analysis of the need f or the proposed f acility. It is 7 based on f orecasts prepared in 1981 f or inclusion in the 1982 Northwest Regional Forecast (1982 NRF) issued by the Pacific Northwest Utility Conf erence Committee (PNUCC) in May 1982. (Ref 1) These f orecasts present estimated loads as single values (rather than as a range of values). The third major section is Section 1.2, NONDETERMINISTIC ANALYSIS. This section presents a nondeterministic ; analysis of the need f or the proposed f acility. It is based on a recognition of the increasing uncertainties inherent in forecasting electrical loads and planning generating resources in the Pacific Northwest region. Various load forecasts are reviewed and a range of values is presented. The resource presentation includes an array of resource options that can be drawn upon when needed. This approach permits a flexible response to accommodate changing conditions as they evolve. Although this approach is perhaps new in NRC licensing proceedings, it reflects the concepts that are developing in the Pacific Northwest region and are being adopted by the Northwest Power Planning Council in carrying out its responsibilities under the Regional Power Act. (Ref 2) The fourth major section is Section 1.3, CONSEQUENCES OF DELAY. 1.0-1 Amendment 7
- &;; $ l_ ; 1;-:} l1; s 4% % {;[,W,.)L' l:? ?;- k I; 25 & :;-;" G:w . ' Y @ ' > r L*l,n-l (,-
S/HNP-ASC/ER 9/16/82 1.0.2 THE PROJECT The proposed Skagit/Hanford Nuclear Project, Units 1 and 2 (the " Project" or "S/HNP") will consist of two nuclear powered electrical generating units, each with a net electrical output of 1275 megawatts (MW). Tie earliest year for Unit 1 to begin commercial operation is 1991 and for Unit 2 is 1993. 1.0.3 APPLICANTS The Project will be operated by Puget Sound Power & Light Company ("Puget"), the sponsor of the f acility. The Project will be jointly owned by Puget and three other investor-owned utilities (collectively ' Applicants") . The three other owners are Portland General Electric Company (PGE), Pacific Power & Light Company (Pacif ic) and The Washington Water Power Company (WNP). The ownership shares in the Project will be as follows: Puget 40% PGE 30% Pacific 20% 7 WWP 10% Puget is an investor-owned electric utility with its principal offices in Bellevue, Washington. It serves nearly 1.3 million people within a 4,500-square-mile service area that includes eight of the fastest growing counties bordering Puget Sound in Western Washington and Kittitas County in Central Washington. PGE is an investor-owned electric utility with its principal offices in Portland, Oregon. Located in the heart of Oregon's population center, PGE provides service to 54 incorporated cities, of which Portland is the largest, and approximately 40 percent of the State's population in a 3,350-square-mile service area. Pacific is an investor-owned utility with its principal offices in Portland, Oregon. It serves approximately 650,000 electrical customers in more than 240 communities in Oregon, Washington, northern Calif ornia, Idaho, western Monta-a and Wyoming. l WWP is en investor-owned utility with its principal offices in Spokane, Washington. It has a service area of approximately 26,000 square miles and supplies electric service to more than 220,000 customers in 93 communities, ) J.0-2 Amendment 7 {Q & jf_.[ $ $ DN T. Y NN *= . b ?.l I e Y Y$.5 Y Y
S/HNP-ASC/ER 9/16/82 of which Spokane is the largest, in eastern Washington and northern Idaho. 1.0.4 PURPOSE OF THE PROJECT The purpose of the Project is to enable Applicants and the other utilities of the Pacific Northwest Region to meet the increased electrical loads they anticipate during the 1990s and beyond. The Project will be a regional resource. It will be operated as a baseload facility. 1.0.5 THE PACIFIC NORTHWEST REGION For the purposes of this discussion, the terms "Pacif ic Northwest Region" and " region" refer to the planning area defined by the Pacific Northwest Electric Power Planning , and Conservation Act (the " Regional Power Act"). PL ! 96-501; 94 Stat. 2697. The Region as thus defined ' includes the States of Oregon, Washington, and Idaho; j Montana west of the Continental Divide; portions of Nevada, Utah, and Wyoming that lie within the Columbia River drainage basin; and any rural electric cooperative 7 customer not in the geographic area described above, but served by Bonneville Power Administration (BPA) on the effective date of the Regional Act. Essentially, the region encompasses the operating systems of BPA, Portland General Electric Company, Puget Sound Power & Light Company, The Washington Water Power Company, Idaho Power Company, portions of Pacif ic Power & Light Company, Utah Power and Light Company, The Montana Power Company and 113 public electric utilities. 1.0.6 CHARACTERISTICS OF THE REGION l Until the present decade, the Pacific Northwest has relied on hydro-generation for nearly all of its electric energy requirements. Future hydro-developments in the region, l however, will consist largely of the installation of ' peaking generation because nearly all the economically feasible regional hydro sites have been developed. The integration of new thermal generating resources with the hydro resources of the region to maximize reliability has been a goal of the region's power planning for many years. The characterp tics of the region's electrical loads and electrical pwer supply system have developed together and 1.0-3 Amendment 7
S/HNP-ASC/ER 9/16/82 are unique within the United States. Most of the regional power is presently being generated at hydro-electric projects, many of which are owned by the federal government. Much of the power flows to the distributing utilities over BPA transmission lines. Customers in the region, other than industrial direct-service customers of BPA, are served by either investor-owned utilities, public utility districts, municipal systems or cooperative rural electrification systems. Due to the region's vast hydro-electric resources, electrical energy costs in the Pacific Northwest have been quite low, leading to high per capita consumption. Some electrical-energy-intensive industry I has also developed in the region. As previously noted, additional capacity is being installed at existing hydro projects to shape energy to load requirements. The region foresees even greater usage of hydro resources for peaking, with thermal resources, such as the proposed S/HNP, operating as baseload units at high plant f actors, except during periods when suf ficient water supply is available to displace thermal generation. l 1 To properly assess the need for the Project, consideration I must be given to the unique features of the power supply in the Pacific Northwest. Although the hydro capability of the region is large, the firm energy and dependable peaking capacity available from the existing hydro 7 _ resources are limited, not only by the installed machine capacity but also by the usable water storage volume available. 1.0.7 REGIONAL COORDINATION AND PLANNING The electric utilities of the Pacif ic Northwest f orm, in effect, a single regional system. This is made possible by the BPA transmission network that interconnects most of the utilities of the region and makes power from all major generating projects available on a region-wide basis. The operation of the regional system and the planning of new generating facilities are coordinated in a variety of ways through a number of organizations. a. The Northwest Power Pool (NWPPL The Northwest Power Pool (NWPP) is an informal organization of the generating utilities of the Pacific Northwest that coordinates the operation of the hydro and thermal resources of the region to optimize the availability of firm power. 1.0-4 Amendment 7
]
S/HNP-ASC/ER 9/16/82 Coordinated operation also provides a means to resolve problems of interconnected operation and the regional transmission system, to utilize nonfirm power to the greatest advantage and to reduce required reserves to a minimum by pooled use of reserves. Membership in the NWPP includes consumer and investor-owned generating utilities, BPA, the Corps of Engineers, the United States Bureau of Reclamation (USBR) and three Canadian utilities. Member utilities in the United States serve loads in Montana, Idaho, Utah, Wyoming, Washington, Oregon and Northern California. To accomplish the objectives of pooling, the NWPP employs a staff of engineers, known as the Coordinating Group, to make studies and forecasts on a short-term basis necessary to best utilize and pool resources to serve the loads of the region. In doing this, a " critical period" concept is used. Reservoir regulation studies are made on a coordinated system basis and reservoir operating rule curves are established each year for each reservoir, such that with a repeat of the most adverse water conditions of record--the critical period--firm loads of the area can still be carried. 7
- b. Pacific Northwest Utilities Conference Committee (PNUCC)
The Pacific Northwest Utilities Conference Committee (PNUCC) is an informal association of public and private utilities in the Pacific Northwest. An important function of PNUCC is coordination of long-range planning'for the region. As part of this effort, PNUCC issues an annual ll-year forecast of the power loads and resources of the region. Prior to 1981, this forecast covered an area known as the West Group Area (of the NWPP) and the forecast was known as the West Group Forecast. The West Group Forecast's for 1976 and 1977 were received in evidence in this proceeding as Exhibits 72 and 87 during the 1976 and 1977 hearings on need for power. Starting in 1981--to be consistent with the revised planning area established by the Regional Power Act of December 1980--the area covered by 1.0-5 Amendment 7
F-S/HNP-ASC/ER 9/16/82 the PNUCC forecast was changed to the Pacific Northwest Region previously described, an area roughly equivalent to, but somewhat larger than, the West Group Area. Henceforth, the PNUCC forecast will be known as the Northwest Regional Forecast (NRF). The introductory pages and summary section of the 1982 NRF are included in Appendix A to this Application f or Site Certification / Environmental Report (ASC/ER).
- c. Canadian Treaty and Columbia Storage Power e Exchange In 1961, a treaty was entered'into by the United States and Canada providing for the construction and operation by Canada of three dams and storage reservoirs in British Columbia on the Columbia River and its tributaries.
The controlled release of water from these reservoirs increases the dependable capacity and usable energy produced at hydro-electric projects on the Columbia River in the United States. The treaty specifies that the United States and Canada are each entitled to one-half of these 7 increases. Canada offered to sell its share of the treaty benefits to an entity in the United States in order to obtain money to construct the dams. No single entity with the ability to fir.ance such a purchase existed in the Pacific Northwest so the utilities cf the region f ormed a nonprofit corporation, called the Canadian Storage Power Exchange (CSPE), to raise the capital reqcired and purchase the Canadian entitlement to the treaty benefits (Canadian Entitlement). CSPE resold the Canadian Entitlement to 41 investor and consumer-owned utilities in the Pacific Northwest under tri-party exchange agreements between CSPE, BPA and the individual utilities whereby CSPE delivers Canadian Entitlement capacity and energy as received from the Columbia River hydro-electric developments in the United States to the purchasing utility. Each utility, in turn, exchanges such capacity and energy with BPA for federal capacity and energy shaped within limits, as necessary to meet the utilities' load requirements. O 1.0-6 Amendment 7
S/HNP-ASC/ER 9/16/82 1 O Although the Canadian Entitlement was surplus to the needs of the Pacific Northwest at the time of the purchase, forecasts indicated it would be i usable in the area in the early 1970s. The cost , of the Canadian Entitlement was higher than the l power production costs in the Pacific Northwest but was lower than power production costs in California. Consequently, mest of the Canadian ' Entitlement was in turn sold to California utilities on a five-year pull-back provision. A > portion was committed to the State of Californ,ia through the 1982-1983 operating year. All of the Canadian Entitlement sold to California utilities has been withdrawn. ,
- d. Pacific Northwest Coordination Agreement Early in the negotiations pertaining to the i Canadian treaty and CSPE, it became apparent that voluntary coordination could not ensure compliance with all the provisions and operating !
procedures that would be required when Canadian treaty power became available. Negotiations were therefore started to formalize coordination of , generating utilities affected by the Canadian i i treaty. On September 15, 1964, the Pacific i
' \
Northwest Coordination Agreement (" Coordination 7 - Agreement") was signed by the federal entities ! and 14 generating utilities, including the !
- Applicants, having facilities affected by the !
j treaty. A copy of this agreement was received in j evidence in this proceeding as Exhibit 97 during the 1977 hearings on need for power. This ! agreement plays a vital role in maximizing the ! efficiency and reliability of the regional power l system. Among other things, the Coordination Agreement i provides for: ! l (1) Establishing a Critical Period based on }* historical water records. (2) Making Critical Period reservoir ' regulation studies on an integrated ; system basis and establishing reservoir
- operating curves (Energy Content Curves and Critical Rule Curves).
(3) Determining Firm Load Carrying Capability (FLCC) for the Coordinated System and for each System. l
~ !
i l.0-7 Amendment 7 !
S/HNP-ASC/ER 9/16/82 (4) Establishing required forced outage - reserves for the Coordinated System and for each System. (5) Coordinating maintenance outages for the best resource usability by each System and by the Coordinated System. (6) Mandatory interchange of capacity and energy between Systems to assure the ability of each System and the Coordinated System to carry firm load up to the determined FLCC. (7) Conservation of nonfirm energy by coordinated use of available reservoir storage volume. (8) Use of third party transmission, as available for Coordination Agreement requirements. (9) Mandatory release of water from upstream reservoirs, stored above Energy Content Curve, or delivery by upstream reservoir owner of equivalent energy in lieu of water releases. 7 (10) Computation of and payment for upstream and coordination benefits, subject to the FPC approval. (11) Determination of priorities on use of facilities for coordination Agreement requirements. (12) Determination of rates to be paid for Coordination Agreement services. (13) Restoration of FLCC to those Systems whose FLCC is reduced due to the lengthened Critical Period occasioned by the additional storage provided under the Canadian Treaty. Restoration is accomplished by the Systems that I gain FLCC from the increased storage (Columbia River main stream projects) sharing a portion of the gain with the Systems (off stream projects) that lose FLCC. O 1.0-8 Amendment 7
S/HNP-ASC/ER 9/16/82 The Coordination Agreement treats the Coordinated f) v
\' ' System as being a single utility system having a ~
single capacity and energy requirement and with total resources dedicated to serve that requirement. The NWPP Coordinating Group provides the necessary engineering required to assemble and publish load and resource data relating to the immediately upcoming Critical Period, to run reservoir regulating studies for planned reservoir operation, to determine FLCC and reserves and, in general, to guide operations under the Coordination Agreement. Under the Coordination Agreement, each System representative, in joint meeting with other System representatives, is permitted to adjust, within limits, the plan for reservoir operation 4 of its System reservoirs to meet its System's individual requirements. Such adjustments do not permit the reduction of coordinated System firm
. capability without a commensurate reduction in i estimated firm load to be carried.
By coordinating the resources of the Coordination Agreement signatories, both in planning and under operating conditions, additional firm capability C. is made available to the area and nonfirm energy 7 is conserved to a greater extent than would be possible under isolated utility planning and operation. Emergency assistance is provided to each System as required. Coordinated System-wide
- sharing of forced outage reserves reduces the amount of reserves actually required below what would be required under isolated system operation. Additional resources brought on line by a System become a part of the Coordinated System resources unless the System constructing such facilities declares them to be outside the Coordinated System and operates them on an isolated basis.
Signing of the Coordination Agreement did not eliminate the need for the NWPP since some members of the Pool do not have generating f acilities that are aff ected by provisions of the Canadian Treaty and, therefore, are not signatory to the Coordination Agreement. The NWPP l coordinates the resources of its members, l including utilities in British Columbia, which are not in the Coordination Agreement with the resources of the Coordinated System and f urther
} assists the area by analyzing and, to the extent-J 1.0-9 Amendment 7
S/HNP-ASC/ER 9/16/82 possible, solving the operating problems of regional interconnected operation as they arise,
- e. Western Systers Coordinating Council (WSCC)
In 1967 management of the major utilities in 13 western states organized the Western System Coordinating Council (WSCC) in order to improve system reliability through coordinated planning and operation and to assess adequacy of power resources to meet forecasted load and established reliability criteria. Full membership is open to all utilities in the area that have b,ulk power supply resources or major transmission facilities that could affect bulk power deliveries. Associate membership is cvailable to all utilities in the area who do not meet the requirements of full membership. WSCC was the first reliability council to be formed. As other areas of the nation organized councils, WSCC promoted the formation of the National Electric Reliability Council (NERC), to which all regional councils belong. NERC coordinates the activities of all of the regional councils. 7 1.0.8 REGIONAL POWER ACT On December 5, 1980, the Pacific Northwest Electric Power Planning and Conservation Act (the "Act") became law. PL 96-501; 94 Stat. 2697. The Act authorizes the Administrator of BPA, among other things, to purchase electrical power from resources that are consistent with a regional conservation and electric power plan to be developed by the Regional Power Council created by the Act. The Council consists of representatives of the four Northwest states (Washington, Oregon, Idaho and Montana). The first regional energy plan is scheduled to be issued in April 1983. Prerequisites to acquisition under the Act of a major resource, such as the Skagit/Hanford Nuclear Project, by the BPA Administrator include a finding, after notice to the public and a hearing, that purchase of power from the proposed project is consistent with the plan (or certain other criteria in the obligations the Administrator's Act) or is otherwise under theneeded Act. to meet Notwithstanding any acquisition of resources pursuant to section 6 of the Act, the Administrator is directed by the 1 1.0-10 Amendment 7
S/HNP-ASC/ER 9/16/82
\/"]j Act not to reduce his efforts to achieve certain conservation objectives and to acquire certain renewable resources installed by residential or small commercial consumers. The criteria to be considered in connection 1 l
, with .cquisition of a resource include the effect of the l proposed resource on the quality of the environment, the ! compatibility of the resource with the existing regional power system, and the protection and enhancement of fish and wildlif e, including the spawning of anadromous fish. ' t Investor-owned utilities that sell their share of the ! output of a resource will be entitled, if they have a , contract for such purchase, to receive an equivalent l amount of power f rom BPA at a rate reflecting a melded i cost of power from various sources. If a utility does not need its entitlement to power, the power will be offered 7 { to other electric utilities with a priority for utilities in the same class, i.e., investor-owned utilities, public : bodies and cooperatives, f ederal agencies, or direct service industries. ; There are numerous unknowns concerning the effect of the Act. As stated, the first regional energy plan is not . scheduled to be available until April 1983. It will also ! take many months (perhaps years) for BPA to develop the l administrative machinery for processing resource ! acquisitions. Ultimately, however, it is expected that i \m the Act will significantly enhance the ability of the i region's utilities to finance new electrical generating ! projects, such as the proposed Skagit/Hanford Nuclear Project. . l i i 4 i t ] i i [)
\, )
[ 1.0-11 Amendment 7
. . .- _. . _ . _ - _ _ - . . . . _ . _ - . - - . _ . - . = _ -
S/HNP-ASC/ER 9/16/82 References for Section 1.0
- 1. Northwest Regional Forecast of Power Leads and O
Resources July 1982 - June 1983, Pacific Northwest Utilities Conference Committee (May 1982).
- 2. Second Annual Report of the Pacific Northwest Electric Power and Conservation Planning Council (Draft; July 1, 1982).
O O 1.0-12 Amendment 7 A
1 S/HNP-ASC/ER 9/16/82 1.1 DETERMINISTIC ANALYSIS 1.1.1 SYSTEM DEMAND AND RELIABILITY Data are presented in this section both for-Applicants' systems and for the entire Pacific Northwest Region. As has been shown, this region is not only unique by virtue of its heavy dependance on hydro generation, but also highly integrated, for both planning and operation, to such an extent as to constitute, in ef f ect, a single system. The Pacific Northwest Region is thus the appropriate area within the Western Systems Coordinating Council to be considered in evaluating the need for the proposed Project. 1.1.1.1 Load Characteristics 1.1.1.1.1 Load Analysis i The actual peak and energy-loads for each Applicant for i the operating years (July 1 through June 30) 1965-66 7 through 1981-82 are shown in Tables 1.1-1, 1.1-2, 1.1-3, t and 1.1-4. Where available, the temperature adjusted ! energy loads are also shown. ) In addition, these tables include each Applicant's-j projected loads through 1999-2000. These projections were
- prepared by Applicants in late 1981 for inclusion in the i
1982 Northwest Regional Forecast (NRF), the summary j section of which is included in Appendix A to this L j Application for Site Certification / Environmental Report (ASC/ER). I ! As of this writing (September 1982), Applicants are j beginning. preparation of their revised forecasts that will i be included in the 1983 NRF. The 1983 NRF is scheduled to g be issued in the spring of 1983. l l The next table, Table 1.1-5, is for historical reference
- only. It presents actual and projected loads data for the l West Group Area of the Northwest Power Pool f or the
! operating years 1965-66 through.1998-99. The projected I loads ~are from the 1981 NRF and thus are not current; no current load projections are available for the West Group Area. As'previously stated, the West Group Area is roughly equivalent to, but somewhat smaller than, the newly created O ! -1.1-1 Amendment 7
S/HNP-ASC/ER 9/16/82 Pacific Northwest Region. There are no historical data available for the newly created region, as such. 1.1.1.1.2 Demand Projections This section addresses the forecasting methods that were used by Applicants in preparing the load projections set forth in Tables 1.1-1, 1.1-2, 1.1-3, and 1.1-4. Also addressed are Applicants' energy conservation programs and the probable effect of conservation on loads. Finally, the forecasting methods that were used by the PNUCC in preparing and cross-checking the 1982 NRF are addressed. 1.1.1.1.2.1 Puget Sound Power & Licht Company (Puget) Forecasting Methods The Puget load projections set forth ia Table 1.1-1 were based on Puget's 1982 long-term sales forecast. The long-term sales f orecast was developed through the use of four models, two f or the residential sector and one each 7 for the commercial and industrial sectors. One of the residential models is predominantly end-use; the other is a hybrid of econometrics and end-use. Although separate models, they are operated in parallel with inf ormation manually transf erred between them. The end-uce model is used to compute residential energy use and to estimate savings f rom several of Puget's conservation programs. The commercial and industrial models are predominantly econometric. These models have a variety of origins. The residential end-use model is based on computer code supplied by the Oregon Department of Energy. The structure of the residential econometric model stems from a model generated by PNUCC but the computer code was written by Puget's staff. Two of the econometric equations in that model (ranges and clothes dryers) were estimated by PNUCC using l regional data. The others were estimated by Puget's staff using data specific to Puget's service territory. The ! commercial model was also estimated by Puget's staff using Puget specific data. The industrial model was based on the PNUCC model. Additional details concerning Puget's forecasting methods are presented in the Puget document Puget Sound Power & Light's Long Range Forecast 1982. O 1.1-2 Amendment 7
S/HNP-AGC/ER 9/16/82 i [\
\- /
The f orecasting models used to produce Puget's 1t 82 long range forecast incorporate the effects of the f oliowing ,
, f actors on f uture energy growth:
o price of electricity o price of competing f uels (oil and natural gas) o income o population ' o employment o conservation o inflation While these are not all the factors considered by the , forecasting models, they are the major ones. The price of electricity used in the f orecast is determined through an
- iteration process with other Puget models used to determine
' the cost to supply certain amounts of electricity in the future. '
Conservation Puget recognizes that conservation has had a leveling effect on its load growth rates in recent years, although the magnitude of this ef f ect is dif ficult to isolate due to the simultaneous occurrence of other events which have g
\s-also had a moderating influence on load growth. While 7 i Puget will continue to promote the implementation of conservation measures, it cannot impose those measures on ;
its customers. It seems probable, however, that voluntary and regional conservation actions will continue to be implemented in the f uture, and Puget will continue ! to assess the potential impact of these actionc on load growth during the f orecast period. Puget has a well established conservation program aimed at promoting increased energy efficiency in existing residential, commercial and industrial facilities. In the , residential sector, Puget provides free home energy I check-ups to electric space heat custocers and offers 10-year def erred repayment zero-interest loans f or insulation of ceilings, floors and walls, installation of storm windows and insulated glass, and installation of caulking and weatherstripping. This program was expanded l in 1982 to include a cash grant optica f or residential, - commercial and industrial customers, a cash grant f or the installation of solar-assisted domestic water heating, and ! loans f or conversion of electric resistance heating systems to energy-efficient heat pump systems in properly weatherized homes. In addition, Puget provides free water , heater insulation wraps and shower flow restrictors to i
<-~ customers with electric' water heaters. Currently under (c,)
i 1.1-3 Amendment 7
- S/HNP-ASC/ER 9/16/82 development are programs to promote energy-efficient appliances and residential lightirg efficiency.
Puget is promoting energy efficiency in existing commercial and industrial facilities by providing free electric energy audits to commercial and industrial customers. In addition, 10-year def erred repayment zero-interest loans or cash grants are of f ered f or measures which will result in cost-effective permanent energy savings. These measures include structural modif ications to building envelopes, changes to lighting systems (indoor, outdoor and screet lighting), modifications to heating and ventilating systems, and installation of energy recovery systems. Puget is currently developing conservation programs to reduce load growth by promoting high levels of energy efficiency in new construction, both residential and commercial. These programs could involve technical assistance and direct financial assistance f or high levels of energy ef f iciency. The anticipated ef f ect of Puget's conservation programs is reflected in Puget's load f orecast set f orth in Table 1.1-1. 1.1.1.1.2.2 Portland General Electric Company (PGE) Forecasting Methods The projected loads shown in Table 1.1-2 were developed through the use of PGE's load forecast model. This model, through a series of three submodels, produces a forecast of electric consumption f or PGE's residential, commercial, and industrial customers. A rate impact model was also used to calculate electricity generation costs associated with specific resources and, with the addition of retail mark-ups, arrive at electricity prices. These prices are fed into each of the submodels. l l This rate impact model incorporates the crucial details of l the Regional Power Act regarding the treatment of resource plans and associated costs, the pricing and allocation of BPA power, and the impacts of conservation and cogeneration on rates. The residential submodel utilizes both econometric and end-une methodologies. Residential electricity consumption was initially forecast econometrically by each of seven residential sub-groups. Electricity consumption was 1.1-4 Amendment 7
S/HNP-ASC/ER 9/16/82 , i l r related to electricity price, household income, natural gas ([L,)4 'T price { and heating degree-days. ! ) The econometric results were then " mirrored" through the l use of an end-use module which also relied extensively on ' PGE-specific electricity usage and demographic inf ormation. Over fif teen end-uses are examined f or both single-f amily > i and multi-family dwellings. The final residential forecast i was calculated by subtracting non-price-induced programmatic savings estimates f rom the econometric i* results. i t t The commercial energy consumption was forecasted as a ; product of the number of commercial customers and their ; electricity usage. Whereas th4 number of customers was j projected as a function of the number of residential ; customers, the usage per commercial customer was forecasted as a f unction of electricity price, natural gas price, per i capita income and cooling degree-days. i r The industrial sector, also forecast econometrica11y, was categorized into nine Standard Industrial Classification ! ! (SIC) groups. Electricity consumption for each was forecast as a function of industrial output, wages, [ electricity prices, and the price of fossil fuels. The results of these individual SIC group f orecasts were suramed i to produce the total industrial f orecast. 7 ! This forecast represents a comprehensive effort undertaken i by PGE's Load Planning staf f to provide a basis f or the , Company's planning activities. The myriad of ever-increasing possibilities in a highly uncertain environment ' j were caref ully weighed to prepare an energy picture of what ;
}
is most likely to occur. As such, the forecasting effort is destined to be an ongoing process. l I l Conservation 1 The PGE load forecast shown in Table 1.1-2 was prepared through an analysis of the impact of various load ! management / conservation programs throughout the forecast period. These programs are generally designed to capture i additional conservation opportunities beyond that which is generally considered " price-induced". Since conservation , i can be viewed as a new resource to meet the growth in ~ energy consumption, it is evaluated for cost-effectiveness i as one of several alternatives to meet this growth. This i , analysis utilizes the principle of avoided cost or marginal cost less lost revenue. The difference between { the cost of generation facilities not built and revenue t lost to the Company from energy not consumed because of ['O ) i l 4 : 1.1-5 Amendment 7
. .~ . _ . . _ _ . _ _ _ ..~ _ _ _ . _ , _ _ _ _ _ _ _ _ _ _ . , _ _ _ _ -
S/HNP-ASC/ER 9/16/62 r conservation is the amount that is available as an incentive to sponsor load management programs. If the cost of conservation to the Company exceeds this figure (in terms of average cost per kilowatt hour) it is currently considered uneconomic since nonparticipant ratepayers would be subsidizing those who do participate in the conservation programs. This forecast assumed two types of conservation programs: the continuation of programs currently in existence, and those which, due to their uncertain nature, were discounted and included in the f orecast. The f ollowing briefly describes each program as assumed in the forecast: Programs currently in place These programs, which af f ect primarily the residential sector, have been approved by the Oregon Public Utility Commissioner and are presently operational.
- a. Residential Weatherization Program This program is aimed at decreasing electric space heating requirements for PGE's residential customers, both single- and multiple-family.
Following an energy audit, the owner of an 7 electrically heated dwelling has three options for which to finance the recommended weatherization through the company: 1) a 6-1/2 percent loan for a principle of up to $4,000 to be repaid in equal monthly payments of at least $15 f or a period of not more than ten years, 2) a cash payment equal to 25 percent of the installed cost of the cost-effective energy conservation measures, but in no case shall the amount exceed $350, or 3) a loan to be paid back with no interest in equal monthly payments of at least $15 f or a period of not more than five years,
- b. Water Heater W:.p Program In another program directed at the residential sector, PGE will wrap electric water heaters in an insulation blanket, f ree of charge to the consumer. This reduces standby heat losses that correspond to a maintenance of a given volume of water within a specific temperature range. Part of this program consists of lowering water heater thermostat settings to 1200F or 1400F if a dishwasher is used in the residence. Wide visibility and effectiveness are anticipated as the result of intensive campaigns during the 1.1-0 Amendment 7
S/HNP-ASC/ER 9/16/82
/-
2 l
' summer and f all of 1980 through 1982, in which PGE crews go door-to-door offering to wrap water heaters.
- c. Water Heater Incentive Program ()CiIP)
Another conservation program which af f ects water heating electricity consumption is the PGE Water Heater Incentive Program (WHIP), begun in October 1980. WHIP is a conservation program currently operational whose objective is to encourage a retrofit to heat pump water heaters and solar-assisted water heating systems. PGE offers direct financial incentives to its customers with electric water heaters to encourage this type of conservation. For the heat pump, PGE will pay
$300 toward the purchase of this conservation device. The $300 is a rebate to PGE customers j
and its repayment is not required. For a solar : water heater, the incentive takes either the form . of a $300 rebate or a loan for the tax credits - from the installation of the solar heater which is repayable within the next tax year.
- d. Shower Flow Restrictor Program f This is the least expensive of the conservation 7 programs currently in place. The shower flow restrictor is s small washer-sized device which limits the rate of water flow through
- showerheads, and thus reduces hot water consumption for a given period. These can be I installed by the homeowner himself and were i mailed out to all PGE residential customers during the September 1980 billing cycle. -
- e. Parallel Generation Program 1
Paral'.el generation refers to the generation of ' eler.cric power by a customer f or residential, conmercial, or industrial use. There are currently three categories of parallel ; l generation: small-scale generation of power f rom - ( wind energy, small-scale hydroelectric generation , facilities and industrial cogeneration. Generally, cogeneration is a process whereby ! power is generated as a by-product of some 1 j i existing industrial process. As an example, a : f oundry may use excess heat f rom its smelting ! operations to generate electricity. On the other : hand, small wind and hydro power are assumed to
'~s be more appropriate to residential or commercial -
s s l l 1.1-7 Amendment 7 ! t
n S/HNP-ASC/ER 9/16/82 customers. Under the program, these cogenerators l are compensated at PGE's full avoided cost. Unlike other conservation programs, parallel generation impacts were treated as a resource addition rather than a load reduction,
- f. Commercial Energy Audits Upon request, the Company will prepare an energy audit of a commercial establishment and make recommendations regarding cost-ef f ective conservttion actions. Both O&M and capital improvenents to save energy are identified as are implementation costs and estimated savings based upon engineering estimates and actual historical consumption.
Prospective Programs These conservation programs, aimed primarily at the non-residential and utility sectors, are not operational at this time. However, estimates of savings from these prospective programs were developed. Considerable uncertaint'/ surrounds the exact nature, form and timing of these programs. As such, the potential savings from most of these 7 programs were discounted in this f orecast.
- a. Utility Programs There are two programs included in this category aimed at street light conversions and reducing utility system losses. Street light conversions involve converting mercury vapor lights to a more ef ficient sodium vapor fixture. Reductions in utility system losses are anticipated primarily through reconductoring with larger gauge wires.
The saving estimates for utility programs were not discounted as many elements of these two programs are currently being put into place.
- b. Other Programs In the residential sector, possible programs include heat pump / solar retrofits to existing i electric space heat installations, upgrading the existing. residential building code to require additional insulation, applicance ef ficiency standards aimed at manuf acturer perf ormance standards on all new appliances and other miscellaneous programs.
O 1.1-8 Amendment 7
t-
- S/HNP-ASC/ER 9/16/82 i
2 Non-residential programs include rebates and loans to help capture savings beyond those easy, low front-end cost measures and more stringent building codes for commercial buildings. 1.1.1.1.2.3 Pacific Power & Light Company (Pacif ic) l [ l j Forecasting Methods The f orecasting methods used by Pacific in developing the j
~
_ projected loads set forth in Table 1.1-3 may be summarized
, as f ollows. Pacific prepares an annual electricity sales
- _ f orecast f or the residential, commercial, industrial, street lighting, . irrigation and sales for resale customer classes. This forecast is derived f rom a set of economic, !
demographic and price projections specific to each of the t parts of the six states which are within the Company's
, service territory. These states are Oregon, Washington, Idaho, Montana, Calif ornia and Wyoming. The Load Forecasting and Analysis Department uses two forecasting ;
methods to estimate demand; a combined econometric/end-use analysis of the residential sector, and an econometric I f orecast of non-residential demand. > Residential demand was projected on the basis of eleven 7 . "end-uses". These uses are space heat, water heat, ] electric ranges, dishwashers, electric dryers, ! refrigerators, televisi'6ns, lighting, air conditioning, j freezers and residual uses. In most cases, the percentage j of total households expected to choose a particular heating
- type or appliance in'the future was estimated with an >
! econometric equation containing-such variables as prices, income and housing type. Average consumption for each end- .l use was predicted primarily on the basis of institutional ! factors. Some of these influences are climate, persons
, per household, tastes and expected government actions such as more stringent construction or appliance ef ficiency standards. In addition, the residential sector contains a ,
conservation assessment submodel which analyzes the i i anticipated ef f ect of Company-sponsored and customer-l initiated conservation measures including insulation j retrofits, water heater wraps and solar assisted space t- heat. Within the non-residential sector-the commercial, street , and highway lighting, irrigation, and sales f or resale ! segments-are forecast with single aggregate econometric
- equations. The industrial sector , however, has been subject 'to a significant amount of disaggregation in both !
'the manufacturing and mining components. Future demand is j l-it !
1.1-9 Amendment 7
S/HNP-ASC/ER 9/16/82 f orecast f or the f ood processing, lumber and wood products, paper and allied products, petroleum refining, primary metals and residual categories in manuf acturing. Mining projections are made for the iron ore, uranium, coal, trona and bentonite industries as well as for oil / gas exploration, pumping and pipeline transportation. In addition to the sales f orecasting methodology described above, Pacific also prepares net system input and peak load projections for each state. Net system input in average megawatts is obtained by adding estimates of system losses to the sales f orecast results and then dividing by the number of hours in the year (8,760). The peak forecast is based upon statistical relationships between past system peaks and corresponding temperature levels. Peak is forecast monthly, and annual energy is broken into monthly totals on the basis of historic seasonal patterns. Pacific . subscribes to a national economic f orecasting service marketed by Data Resources, Inc., called the U.S. Macro Model. It has been used by Pacific to build a detailed economic model which " links" each state directly ,i to the national economy through the use of a concept known as " regional export base" theory. This approach allow; the local economy to be disaggregated into two sectors. The 7 first, known as the " basic sector", contains businesses which sell all or most of their output outside the region. Their level of output and employment is directly determined by the magnitude of demand for their products in the national economy as a whole. The remaining sector which is termed "non-basic" markets all, or a predominant share, of its output to consumers or other businesses within the region. Af ter coinpleting the above identification process, it is possible to forecast basic industry employment from the expected level of national demand. In turn the number of non-basic job holders is projected directly from the level of basic employment. Total employment (basic plus non-basic) is the major factor which determines the economic and demographic variables used to derive the energy forecasting equations. Industrial employment along with output per worker determines the level of industrial output. Total employment and national non-f arm labor productivity are the major factors influencing trends in real labor and proprietors income, the largest component of real personal income. Net migration, which is the dominant and most volatile determinant of population growth, is primarily determined by the influence of employment trends on the size of the labor force. 1 O 1.1-10 Amendment 7
-. . _. - ___ - - . . =. . -
S/HNP-ASC/ER 9/16/82 I ' An electricity pricing submodel is an important part of 4 the load forecasting model. It analyzes the capital, fuel, and operations and maintenance components of total cost and f orecasts their impact on f uture electricity prices. The resultant price projections are fed back and f orth through the load f orecasting model until supply and demand are approximately in equilibrium. This process is a major f actor in insuring the internal consistency of the model since electricity prices are related directly to the level of future demand rather than assumed to grow at a certain rate. J i Future f ossil f uel prices are obtained f rom the Data i Resources, Inc., Energy Model. This approach guarantees that the gas and oil price projections used in the load forecast will be used consistently with the other assumptions derived from the Macro Model. Additional i details concerning Pacific's f orecasting methods are set f1982. orth in Pacific document 1981 System Load Forecast, April l Conservation ' Realistic goals for conservation and weatherization
,_s programs have been established based on estimates of the potential reduction in energy consumption by residential, 7 commercial, and industrial customers of Pacific. The j - estimates are divided into projections f or existing customers and new customers. They are based on a history of the Company's experience and documented conservation studies These goals and savings will be monitored on a regular basis and compared with Company projections.
4 Residential Conservation. Conservation measures such as solar heating, insulation and other weatherization retrofits have been applied as percentage reductions to average space heating loads. The solar reductions incorporate both active and passive systems. The potential solar savings for retrofitting an existing home were calculated to be much less than the savings for installing a solar system into a newly constructed home. In a new home, i t is assumed that space heating amounts to i up to 50 percent of the total energy used in a home and that by utilizing passive solar and energy saver home standards approximately 50 percent of the heating energy could be saved. - Pacific has developed several programs to. assist it in obtaining the projected energy savings. Penetration of passive solar into the home market is assumed on the basis of a " Passive Solar Energy Saver Home" program which 1 ! 's - ' l.1-11 Amendment 7
-- , ~~,,..-,,-.----m . --a v ~- - - - - . - , , , - - - - - - - - - - - - , a - .--.-----n--,- -w
S/HNP-ASC/ER 9/16/82 of f ers much inf ormation to builders on the benef its of passive solar residences and how to develop passive designs. It also appears that some conservation gain can be indirectly obtained as the result of builder education on the advantages of using space heat pumps over standard forced air systems. Pacific is looking for interested builders, architects, and homeowners to participate in a passive solar research and development program. The goal of the program is to demonstrate the energy savings achievable by combining passive solar heaters and energy ef ficient design into new housing construction. During 1981 Pacific plans to work with contractors in the building of ten passive solar homes located throughout Pacific's six state operating service territory in representative climatic areas. These homes will be instrumented to determine the energy savings over the first year or two of occupancy. The results will be provided to architect / engineers and builders to assist them in promoting construction of passive solar homes and subsequently to develop efficient designs. To determine the effectiveness of adding passive solar heating, such as a greenhouse (or sunspace) attached to an existing residence, Pacific's Research Department is pursuing several activities. At TERA One, Pacific's experimental conservation laboratory located in Portland, 7 Oregon, tests on heating / cooling systems, insulation, passive solar and miscellaneous items are being conducted. Various heat storage mediums and window insulating shading materials are also being evaluated. In addition, an occupied home in the Portland area is being monitored to determine space heating requirements before and af ter retrofit during the 1979-80 and 1980-81 heating seasons, respectively. As discussed, for passive home design purposes, a major objective is development of an evaluating procedure to assist the customer in evaluating this energy saving option. Water heating conservation potential includes insulation
- or water heater wrap, temperature setbacks, solar and heat I pump water heaters. Each is applied as a reduction to the l water heating load with insulation or wrapping of water i
l heaters estimated at reducing standby water heating losses by approximately 30 percent. It was assumed that all t uninsulated water heaters would be insulated within five ! years. 1 When the thermostat setting of a water heater is set back an average of 300F, the realized energy savings per average household is calculated to be 500 KWH per year. This reduction was applied to 25 percent of the water 1.1-12 Amendment 7
, - _ - - . . - - , _ _ .- - -- ~ - -- - -. . .
i i
- S/HNP-ASC/ER- 9/16/82 t J '
I t
' heaters in the service territory over a five-year period. !
I After that, new homes which require water heat setbacks ! are assumed to approximate the number of older homes which ; are being removed from the housing stock. F i ! To determine the effectiveness and the economics related i to the heat pump water heater, Pacific has an ongoing ! program in five communities: Yakima, Washington;. casper, j Wyoming; Grants Pass, Oregon; Lake Oswego, Oregon; and ! Junction City, Oregon. In each of these localities a home has been selected for the installation of a heat pump [ j water heater. At Grants Pass the same residence is testing the heat pump water heater that earlier tested an } ( active solar hot water heating system. During the tests, the heat pump water heater operates on alternate weeks ! with the conventional immersion heaters. In this manner i 4 Pacific hopes to eliminate variances caused by weather and ! livirg patterns of the families. ' l, 5 The test should provide information with regard to reliability, efficiency, and economics of the heat pump hot water heater as compared to the active solar system and the conventional immersion heater, ; i Home Energy Analysis and Financing Incentives. In order to i i assist Pacific customers in realizing their potential 7 cpace and water heating savings, Pacific is offering them a Home Energy Analysis (HEA). The HEA is provided without charge to all customers in Pacific's six state service area and is the necessary first step in all weatherization { programa offered by Pacific. Since its inception in 1977, the HEA conservation program has proven to be hichly ) popular with customers. [ t F Recognizing the increased volume of HEA requests and the f desire to expand the analyses to include solar and wind ; resources,-Pacific in 1980 implemented a computerized HEA ' procedure. This procedure has simplified the estimates of energy cost savings, installation costs and payback periods. This computer application will eliminate the , need for the energy consultant personally to compute the l j results of each analysis. A computer tie-in via the j 4 customer's telephone processes the data and provides i results within minutes. The Company has completed over 60,000 HEAs and has a goal of 20,000 HEAs in-1982. [ i Home weatherization improvements can be expensive. Pacific.has a number of programs to assist customers in obtaining necessary financing. Qualified electric heat customers may choose from a variety of financing programs f to pay for their weatherization improvements. Pacific ~ ' offers a cash rebate weatherization incentive program as ' (~~s t 1.1-13 Amendment 7 f
,- w.- - ,.. e .-m-g--m- 4-+= e> ..m. ,.e. <y- ,--,.,-im,,,pg., ,,.iy,%e9-ree-e,imm, cy. .-.mmwwm,.-w-g.smy.*=y-*-g--er-au-em- owe e.r n 4ygeme -w
F S/HNF-ASC/ER 9/16/82 well as zero-interest, def erred payment and 6-1/2 percent interest loans. The cash rebate is the newest of Pacific's programs and the one which surveys indicate customers would favor. Eligibility criteria for this program require that the home have electric heat. The following types of individually metered housing may qualify: single-family residence, individually heated multi-family units, individually heated condominiums and mobile homes on permanent f oundations. Introduced in 1978, the zero-interest weatherization program provides no-interest financing to qualified residential electric heat customers f or cost-ef f ective improvements. It is now approved by regulatory commissions and available in the states of Oregon, Washington, Idaho, Calif ornia and Montana. This program provides weatherization loans to homeowners, repayable to the Company at the time the home is sold or any time bef ore. (In Washington, repayment must be made within ten years. In Calif ornia, repayment must begin within ten years.) This financing approach by Pacif ic was a "f irst" nationwide and has been adopted by several utilities in the Northwest. In Oregon, the Company has available weatherization financing at a 6-1/2 percent interest rate to qualified 7 electric space heating customers. The total amount of money loaned to the customer cannot exceed $4,000. Multiple family dwellings are included in the plan with the same per unit limit. Residential electric water heating customers participating in the HEA and recommendations process will receive an installed water heater blanket on electric water heaters. Prior to 1982, approximately 27,000 water heater wraps had been installed in Pacific's Northwest region, with a goal to increase that number to 100,000 by the end of the year. Pacific will continue to work with customers and lending ( agencies to secure other weatherization financing l assistance in addition to the Company sponsored programs. Commercial-Industrial Conservation. Commercial-industrial customers consume about 62 percent of the electricity l provided to all customers by Pacific. A caref ul review of I where energy is used--and adjustments without major I expenditures--may reduce energy consumption as much as 25 percent. Initially, an analysis of the total energy consumed during the past year is made by the energy consultant. This is compared with other known and energy ef ficient 1.1-14 Amendment 7
S/HNP-ASC/ER 9/16/82 (N ( ,) facilities. Next, the physical layout is reviewed, and management and operating personnel of the business are j asked to caref ully review space, f acilities and pattern of energy consumption. The energy consultant, through ', questions and first-hand, on-site evaluations, obtains ! necessary data to calculate and recommend specific energy savings procedures. Estimates of savings, costs and priorities are identified by the energy consultant. , i In 1980, a pilot program designed to computerize the { commercial-industrial analysis was initiated. It is ! anticipated that this program will be expanded during 1981 l and will permit a significant reduction in computation time in this of ten complicated f orm of energy audit. i Also in 1980, a conservation step was initiated that will change the after-dark look of every central business [
}
district served by Pacific by 1987. The f amiliar l blue-green mercury vapor street lights are being replaced with some 45,000 high pressure sodium lights and fixtures. This change-over is expected to cut energy t demand f or street lighting almost in half. 7 i Pacific maintains an ongoing program of contacts with , contractors, developers, architects and designers to discuss energy conservation opportunities. These j opportunities include: o Insulation recommendations to optimize : energy opportunities in new construction. l o Assistance in developing techniques to make ! maximum use of available solar technology to I reduce dependence on conventional energy ! resources. . These contacts insu e that the design community is kept ! up-to-date on new energy conservation techniques. : During 1980-81, Pacific has initiated programs aimed at energy reduction in a f arm or ranch setting. Special emphasis is being placed on irrigation system planning, water management and maintenance. - t i l i (% i ) i x- / , 1.1-15 Amendment 7 1 l l
r , S/HNP-ASC/ER 9/16/82 1.1.1.1.2.4 The Washington Water Power Company (WWP) Forecasting Methods The forecasting methods used by WWP in developing the load projections cet forth in Table 1.1-4 were as follows. WWP's Power Supply Department makes two independent evaluations to perform forecasts for resource planning. The first procedure is referred to as the " traditional" method and the second as the "econometric" method. The econometric forecast. method is used for the official long term Traditional Method. The traditional procedure estimates large industrial loads separately from all other loads and then combines all loads to give the net system load. The large industrial load (composed of the largest 15 to 20 customers) is estimated by examining the customer's response to the Company's Large Industrial Survey, by examining past trends, and by estimating future deviations from these trends. These deviations arise from discussions with the customer, WWP marketing personnel, and observations of industrial activity in the service area. Projected loads (other than large industrial loads) are 7 based on customer usage estimates for direct WWP customer requirements, requirements of small utilities for which WWP supplies generation, and transmission and distribution losses. The amount of electric heat among residential cus-tomers is projected based upon conversion rates of existing customers to, or from, electric heat from other heating methods and penetration rates of electric space heat among new customers to electric space heat. Non-heat residen-tial, commercial, small indtstry, and small utility usage estimates are based upon past trends, historical relation-ships and any foreseeable deviations from historical behavior. Residential electric heat use per customer is estimated for the first year of the forecast. Each year thereafter projected savings to be realized through company i conservation programs and future increases in thermal efficiency standards for new customers are subtracted from the first year's figure to obtain each year's estimate of the residential electric heat use per customer. The end results are obtained by multiplying respective customers by estimated usages and summing the classes, along with a loss j factor system. estimate, to project the total net load for the A crosscheck with the WWP Consumer Services Department is performed by comparing the above-discussed estimates with short-range estimates of kilowett-hour sales 1.1-16 Amendment 7
S/HNP-ASC/ER 9/16/82 [N used in revenue forecasting. Any dif f erences are
\ ,) reconciled using judgment. ,
The f orecasted hourly peak load f or each month is obtained by use of a load factor, a figure derived by dividing the monthly average load by the peak one-hour demand. This factor is obtained for future years by extrapolation. The forecasted peak load is then obtained by dividing the estimated monthly energy load by the peak factor for that month. Econometric Method. In addition to the traditional approach, WWP has developed an econometric load forecasting model. The model is based upon f our primary concepts as discussed below. The first and principal concept of the model is its long-run (long-term) design. Econometric models require identification of specific predictive objectives (such as time frame) in order to provide usef ul output inf ormation. Design of a short-run model requires, for example, far more attention to cyclical behavior patterns, since long-term trends tend to be masked by secondary short-term phenomena. A long-run model is designed to identify basic long-term relationships. The predictive [~,' capabilities of a long-run model are less reliable for the ( first f ew years of the prediction period, but are expected 7
' to have usef ul predictive capabilities in the 10-20 year time f rame.
The second concept of the model is the presumption that national economic activity is a driving force in the region and therefore represents an adequate index of the WWP service territory economic profile. This concept involves use of economic base theory related to manuf acturing employment. The starting point is a national economy f orecast (provided to WWP by Data Resources, Inc.) which is assumed to indicate the dire: tion in which the regional economy will proceed. Next, it is postulated that the region will receive a pro rata share of this manufacturing employment economic activity, as it has in the past. Manufacturing employment is used to derive employment needs related to the non-manuf acturing industries (trade, retail, government, and the like). An estimation of personal income and a population f orecast is then made for the next 20 years through projection of wage rates and demographic relationships. The third concept of the model involves derivatien of the electrical power consumption of residential, commercial,
-s, and industrial customers from the economic activity
, R./
)
1.1-17 Amendment 7
E S/HNP-ASC/ER 9/16/82 projections. The assumption in this step is that past general relationships between variables will continue in the foreseeable future. The derivation is accomplished by separation of the residential electric consumptian into two components. The first component is an estimate of the electricity required for heating dwellings. This combines projections of saturation of electric heating with projections of kilowatt-hour per degree day consumption. Kilowatt-hour per degree day estimates are forecast by relating personal income and electricity prices over the historical time frame. The second component is a projection of non-heat electricity use which specifically relates personal income and electric prices to consumption levels. Numbers of customers are estimated from population forecasts and household size projections. The commercial and small industrial customer electric consumption fore-casts are procedurally similar to the non-heat residential estimate, relating consumption to personal income (as a measure of aggregate economic activity) and electricity prices. Numbers of commercial customers are projected based on the number of residential customers. Large industrial electricity consumption is an exogenous input to the model and is prepared as previously mentioned from marketing surveys and general trends of previous consumption. The fourth main concept of the model involves the relationship of an economic phenomenon known as " price elasticity" with energy conservation. Price elasticity refers to the effect of the price of a commodity, electrical power in this case, on consumption trends. The model is f ormulated on the assumption that, in the long-term, cost-effective conservation programs that are implemented will be included in the price c'.asticity effect. This means that the ef f ect of pric ! on consumption will eventually be reflected in the model results in the long-term, but the model will tend to overstate consumption in the early periods (first f ew years) of a cost-ef f ective conservation program. Conversely, if a conservation program is adopted which is not cost-ef f ective f or the consumer, the model will tend to overstate consumption f or all later periods of the forecast. l Conservation WWP's current conservation programs include programs relating to residential weatherization, water heater jackets, general energy audits, outlet gaskets, shower flow restrictors, and street light efficiency. O 1.1-18 Amendment 7
S/HNP-LSC/ER 9/16/82 Residential Weatherization. In August 1978, the WWP implemented a Weatherization Loan Program f or electrically heated dwellings. The loan is an interest-free loan, ' payable at the end of 10 years or when the home is sold, whichever occurs first. The program has since been expanded and now includes ceiling, wall and floor insulation, storm doors and windows, caulking and weatherscripping and water heater jackets. Water Heater Jackets. In June 1981, the WWP initiated the Water Heater Jacket Program. The WWP will install R-11 insulating jackets on electric water heaters at no cost to 4 the customer. As an additional service, f ree shower flow restrictors and outlet insulating gaskets are distributed l to customers as part of this program. ; Energy Audits. The WWP provides energy auditing services to all its customers even if the customer does not qualif y for the Weatherization Program. Commercial and Industrial audits and conservation services are also available. Outlet Gaskets and Shower Flow Restrictors. The WWP has made available to its customers f ree of charge outlet insulating gaskets and shower flow restrictors. Distribution of these devices is an ongoing projset. Street light Efficiency. The WWP has implemented new I street light and area light rates for high pressure sodium outdoor lighting. In conjunction with this effort, the WWP j has initiated a street light modernization program in Washington. This program will convert mercury vapor street lights to the more ef ficient high pressure sodium light -
- source at no cost to the customer.
The anticipated ef f ect of WWP's ongoing conservation programs is reflected in the Company's load f orecast set forth in Table 1.1-4. ^ l 1.1.1.1.2.5 Regional Forecasts j l The latest regional forecast compiled by the PNUCC is the 1982 NRF. The summary section of the 1982 NRF is included in Appendix A to this ASC/ER. The 1982 NRF Sum of Utilities f orecast indicates that total regional energy loads will increase at an average annual rate of 2.7 percent over the ten year period 1982-83 to 1992-93. The 1982 NRF and two other regional f orecasts are discussed in more detail in Section 1.2. s 1.1-19 Amendment 7 l
r S/HNP-ASC/ER 9/16/82 1.1.1.1.3 Power Exchanges The firm power exchanges (peaking capacity and energy) projected by Applicants through 1999-2000 are shown in Table 1.1-6 (lines entitled " Contracts In" and " Contracts Out"). Those projected by the region are shown in Tables 1-2 and 1-3 of the 1982 NRF. (Appendix A, lines entitled
" Exports" and " Imports".) As can be seen, both Applicants and the region project that firm imports will exceed firm exports by a substantial margin. Of course, when water conditions are better than critical period, nonf irm surplus energy will be available for export from time to time.
1.1.1.2 System Capacity The projected capabilities of Applicants' systems, i.e. their net total resources, both peak and average energy, from 1982-83 through 1999-2000 are shcwn in Table 1.1-6. Applicants' projected loads are also shown as well as the resulting surpluses and deficiencies. 7 The scheduled output of the two proposed S/HNP units is included in the resources listed in Table 1.1-6, coming on line in January 1991 and January 1993, respectively. As can be seen, according to these projections Applicants will need both of these units on line when scheduled. Table 1.1-7 shows the projected loads and resources of the region f rom 1982-83 through 1999-2000. Again, the two S/HNP units are included as resources coming on line in January 1991 and January 1993, respectively. As can be seen, according to these projections the region will need these two units on line when scheduled. Applicants' existing resources are listed in Table 1.1-6. Additional details are presented in Sections III, IV, and VII of the 1982 NRF, which lists all resources available to the region. Applicants' planned resources are also listed in Table 1.1-6, together with the probable on-line date and Applicants' percentage ownership of each resource. All of the planned resources of the region are listed in Section I of the 1982 NRF and additional details are given in Sections III and VI. O 1.1-20 Amendment 7
S/HNP-ASC/ER 9/16/82 N 1.1.1.3 Reserve Margins s_ , l The reserve margin criterion for the Pacific Northwest ! Region is set forth in Section 8(b) of the Pacific [ Northwest Coordination Agreement as follows: , ( The Coordinated System shall maintain reserve r capacity at a level sufficient to protect against ( loss of load to the extent that the probability , of load loss in a Contract Year shall be no greater than the equivalent of one day in twenty years. The determination of such probability l shall be based upon characteristics of Peak Load variability and generating equipment Forced , i Outage rates. ' In planning their reserves to meet this criterion and the other provisions of the Coordination Agreement relating to l reserve requirements, Applicants (other than Pacific) plan i f or peak reserves equal to 5 percent of their small ! thermal, combustion turbine, and hydro capacity and 15 ; percent of their large thermal capacity. For Pacific, j which is a predominately thermal system, to meet the ' criterion and maintain the relative relationship of 7
,-s reserved percentages, reserves are calculated at 6-1/3 (s, percent of Pacific's small thermal, combustion turbines, ,
i and hydro capacity, and 19 percent of its large thermal capacity. ! (Applicants ' peak reserves are shown on the line entitled " Reserves" of Ta ! plan any energy reserves.ble 1.1-6.) Applicants do not [ The reserve margins planned by the Pacific Northwest ! Region as a whole are listed in Tables 1-2 and 1-3 of the l 1982 NRF. Planned regional peak reserves are equal to 12 i percent of the projected peak load f or the first year of the f orecast, increasing 1 percent per year to 20 percent ! and remaining at 20 percent thereafter. The peak reserve requirements are shown on Table 1-2. They are intended to cover, f or planning purposes, all elements of uncertainty not specifically accounted for in determining loads and resources. These include f orced outage reserves, , t unanticipated load growth and project-construction delays. An increasing reserve requ,irement reflects greater
- uncertainty about load levels and of achieving construction schedules in the future.
Planned regional energy reserves are shown in Table 1-3 of the 1982 NRF. They are equal to one-half years' projected load growth for utility type loads. N- - , 1.1-21 Amendment 7 ,
S/HNP-ASC/ER 9/16/82 1.1.1.4 External Supporting Studies The NRF is the most definitive external report relating to the projected loads and resources of the Pacific Northwest Region, including Applicants. The introductory pages and suumary section of the 1982 NRF are included in Appendix A. , The 1982 NRF includes two analyses of the adequacy of the resources of the region to meet anticipated loads. Both are shown in Table 1-1 and described on page 1-10 of the 1982 NRF. The first is a quantification of the anticipated surpluses or deficiencies in peak capacity and energy, assuming critical period water. Deficits of both peaking capacity and energy are anticipated during the 1990s, when the two S/HNP units are scheduled to come on line. (The projected loads and resources for the region beyond the period covered by the 1982 NRF are shown in Table 1.1-7.) The second and most comprehensive analysis of the adequacy of the resources of the region is that obtained through the use of the BPA Energy Reserve Planning Model, which 7 employs a probablistic simulation program. The results are shown at the bottom of Table 1-1 in the 1982 NRF. As i can be seen, there is an 89 percent probability that the region will be unable to meet its firm energy loads during at least one four-month period between now and the end of the 1992-93 operating year. Two other external studies of the projected loads of the Pacific Northwest Region are the forecast prepared by the BPA (Ref 1) and the review of WNP-4 and 5 conducted by Charles River Associates (RA) (Ref 2) . These studies are presented in more detril in Section 1.2. 1.1.2 OTHER OBJECTIVES The primary objective of the S/HNP is to enable Applicants and the other utilities of the Pacific Northwest Region to meet the increased electrical loads they anticipate during the 1990s and beyond. It is also anticipated that from l time to time the output of the Project will be used to l displace more costly generation in the Pacific Northwest l and adjoining regions. l i O 1.1-22 Amendment 7
S/HNP-ASC/ER 9/16/82 References for Section 1.1 1. Bonneville Power Administration Forecasts of Electricity Consumption in the Pacific Northwest, April 1982 (draft).
- 2. Independent Review of Washington Public Power Supply System Nuclear Plants 64 and 45 (January 1982).
4 l 1.1-23 Amendment 7
- ~s [% f
.I \ , s Ns __ / s N 1
TaFle 1.1-1 Puget Sound '*ower and Light Company Operation Year (July through June) foad Growth Actual arul Projected System toads Percent Percent Ener9y Percent Increase Over Energy Actual lacrease tiver Year Peak MW Previous Year Temp. Adjusted increase Over
, Average MW Previous Year Average MW Previous Tear 1965-66 1,073.9 (5.7) 593.2
+ 1966-67 7.6 601.1 9.5 1,139.8 6.1 667.9 12.6 672.0 11.4 1967-68 1,377.6 20.9 746.0 1968-69 11.7 766.1 14.0 1,759.0 27.7 856.2 14.8 851.4 11.1 1969-70 1.582.0 (10.1) 897.6 1970-71 4.8 907.3 6.6 1,723.2 8.9 982.3 1971-72 1,9 34. 9 9.4 972.0 7.1 12.3 1,050.1 6.9 1,043.0 1792-73 2,115.2 9.3 1,132.1 7.3 7.8 1,124.9 7.9 1973-74 2,057.5 (2.7) 1,157.2 LO 2.2 1,163.1 3.4 N , 1974-75 2,052.0 (0.3) 1,210.1 4.6 1,204.3 1.5 4 1975-76 2,247.1 9.5 1,307.5 hh 8.0 1,305.2 8.4 1976-77 2.533.2 12.7 1,345.4 qJ 2.9 1, 3 79 . 7 5.7 1977-78 2,675.8 5.6 1,435.8 8 6.7 1,460.5 5.9 1978-79 3,135.8 17.2 1,625.1 f$ 13.2 1,617.4 10.7 1979-80 3,599.5 14.8 1,659.0 2.1 1,662.7 2.8 () 1980-81 3,254.0 (9.b) 1,646.5 7 % 1981-82 3,557.8 (0.8) 1,679.5 1.0 IO 9.34 1,717.6 4.3 1.716.9 1982-83 Projected 3,160.0 (11.18) 1,774.0 2.2 1983-84 Projected 3,295.0 4.3 3.3 1,831.0 3.2 1984-85 Pro 3ected 3,440.0 4.4 1,910.0 19HI-86 Projected 3,536.0 2.2 1,973.0 4.3 ) 1986-87 Projected 3,588.0 2.0 3.3 2,014.0 2.1 1987-88 t ro tec ted 3,647.0 1.6 2,051.0 1988-89 Projected 3,738,0 2.5 1.8 2,094.0 2.1 1 1989-90 Pro jected 3,823.0 2.3 i 2,344.0 2.4 1990-91 Projected 3,911.0 2.3 2,193.0 1991-92 Projected 3,986.0 1.9 2.3 2,239.0 1992-93 Projected 4,094.0 2.7 2.1 2,291.0 2.3 1993-94 Projected 4,190.0 2.5 2,348.0 8 2.5 1994-95 Pro 3ected 4,306.0 2.6 2,409.0 g 1995-96 Projected 4,400.0 2.6 2.4 2,468.0 i p 1996-97 Projected 4,543.0 3.1 2.4 i 2,515.0 2.7 CL 1997-98 Pro 3ected 4,6 70.0 2.8 ND 4 3 1998-99 Projected 4,805.0 2,6to.O 3.0 %% W 2.9 2,684.0 2.H >' j D ch rt %% Q CD PJ l i 4 4
r 1 l S/HNP-ASC/ER 9/16/82 O Table 1.1-2 Portland General Electric ComFany operating year (July through June) Load Growth Actual and Projected System Loads Percent Percent Actual increase over Energy Actual Increase Over Year Peak ( *8W ) Previous Year Average MW Previous Year 1965-66 1,375 (8.8) 766.5 6.5 1966-67 1,319 (4.1) 819.6 6.9 1967-68 1,561 18.3 886.7 8.2 1968-69 1,907 22.2 1,013.3 14.3 1969-70 1,835 (3.8) 1,066.6 5.3 1970-71 1,900 3.5 1,1 58 .6 8.6 1971-72 2,278 19.9 1,256.1 8.4 1972-73 2,492 9.4 1,329.2 5.8 197*--14 2,321 (6. 9) 1,325.8 (0.3) 1974-75 2,225 (4.1) 1,337.5 0.9 1975-76 2,310 3.8 1,414.3 5.7 1976-77 2,445 5.8 1,433.1 1.3 1977-78 2,519 3.1 1,462.9 2.1 1978-79 2.954 17.3 1.593.5 8.9 1979-80 3,041 2.9 1,592.4 (0.1) 1982-81 2,687 (11.7) 1,580.3 (0.8) 1981-82 7 2,764 2.9 1,595.0 0.9 1982-83 Projected 2,925 5.8 1,708.0 7.1 1983-84 Projected 3.017 3.1 1,752.0 2.6 1984-85 Projected 3,111 3.1 1,801.0 2.8 1985-86 Pro 3ected 3,195 2.7 1,850.0 2.7 1966-87 Projected 3,292 3.0 1,903.0 2.9 1987-88 Projected 3,391 3.0 1,962.0 3.1 1988-89 Projected 3,485 2.8 2,020.0 3.0 1989-90 Projected 3,566 2.3 2,071.0 2.5 1990-91 Projected 3,653 2.4 2,121.0 2.4 1991-92 Projected 3,732 2.2 2,171.0 2.4 1992-93 Projected 3,815 2.2 2,221.0 2.3 1993-94 Projected 3,899 2.2 2,273.0 2.3 1994-95 Projected 3,978 2.0 2,326.0 2.3 1995-96 Projected 4.060 2.1 2,378.0 2.2 1996-97 Projected 4,130 1.7 2,427.0 2.1 1997-98 Projected 4,215 2.1 2,479.0 2.1 1998-99 Pro 3ected 4,281 1.6 2,530.0 2.1 O h Amendment 7 i
( h O w/ Table 1.1-3 Pacific Power and Light Compasq Operating Year (July through June) Load Growth Actual and Projected System loads Peak Average Energy Temp. Adj. Avg. Energy Operating. Incr. Over Incr. Over Incr. Over Year Load Prev. Year Load Prev. Year Load Prev. Year (MW) (%) (Avg. MW) (%) (Avg. MW) (%) 1965-66 1959 -- 1184 7.0 1191 7.4 1966-67 1958 -- 1243 5.0 1253 5.2 i 1967-68 2166 10.6 1305 5.0 1316 5.0 1968-69 2335 7.8 1397 7.0 1384 5.2 1969-70 2378 1.8 1459 4.4 1462 5.6 4 1970-71 2488 , 4.6 1552 6.4 1543 5.5 1971-72 2695 2/' 8.3 1670 7.6 1660 7.6 1972-73 3080}/ 14.3 1800 7.8 1795 8.1 ![
- 1973-74 3013 2/ (2.2) 1828 1.6 1830 1.9 3*
.1974-75 2937 2/ (2.5) 1886 3.2 1884 3.0 k!
1975-76 3243}/ 10.4 2033 7.8 2029 7.7 d, 1976-77 3553 2/ 9.6 2142 5.4 2145 5.7 U3 1977-78 3434 2/ (3.3) 2228 4.0 2243 4.6 k 1978-79 4074 - 18.6 2362 6.0 2354 4.9 y 1979-80 ,4217 3.5 2416 2.3 2420 2.8 7 1980-81 3987 (7.8) 2431 0.6 2478 2.4 1981-82 4147 6.7 2481 2.1 2469 (0.4) 1982-83 Projected 4911 18.4 2688 8.9 1983-84 Projected 5119 4.8 2809 4.5 1984-85 Projected 5414 5.1 2945 4.8 1985-86 Projected 5679 4.9 3088 4.9 1 1986-87 Projected 5914 4.1 3210 4.0 ; 1987-88 Projected 6147 3.9 3323 3.5 1988-89 Projected 6391 4.0 3448 3.8
$f 1989-90 Projected 6625 3.7 3566 3.4 y 1990-91 Projected 6845 3.3 3679 3.2 i g 1991-92 Projected 7040 2.8 3785 2.9 1[
n 1992-93 Projected 7216 2.5 3877 2.4 >>
$ 1993-94 Projected 7403 2.6 3974 25 02 1994-95 Projected 7599 2.6 4078 1995-96 Projected 7818 2.9 2.6 $
4191 2.8 1996-97 Projected 8055 3.0 4323 3.1 4 1997-98 Projected 8310 3.2 4458 3.1 1998-99 Projected 8572 3.2 4602 3.2 4 l
Table 1.1-4 The Washington Water Po+9r Company Operating Year (July through oone) Load Growth Actual and Projected System Loads Percent Percent Energy
- Percent Increase Over Energy Actual Increase Over Temp. Adjusted Increase Over Year Peak MW Previous Year Average MW Previous Year Average MW Previous Year 1965-66 672 (12.0) 444.0 4.3 447.1 5.6 1966-67 684 1.8 463.9 4.5 466.7 4.4 1967-68 750 9.6 489.7 5.6 490.3 5.1 1968-69 917 22.3 528.1 7.E 519.3 5.9 1969-70 858 (6.4) 542.2 2.7 542.2 4.4 1970-71 881 2.7 573.8 5.8 564.4 4.1 1971-72 1,013 15.0 606.3 5.7 600.7 6.4 1972-73 1,076 6.2 628.4 3.6 636.9 6.0 1973-74 1,065 (1.0) 638.8 1.7 637.1 0.0 E0 1974-75 1,047 (1.7) 677.2 6.0 672.7 5.6 $
1975-76 1,189 13.6 723.6 6.9 723.4 7.5 T3 1976-77 1,308 10.0 748.5 3.4 749.5 3.6 $s 1977-78 1,296 (0.9) 759.5 1.5 760.3 1.4 $ 1978-79 1,599 23.4 865.5 14.0 837.0 10.1 p; 1979-80 1,614 0.9 846.1 (2.2) 856.2 2.3 25 1980-81 1,593 (1.3) 852.8 0.8 884.2 3.3 1981-82 7 1,589 (0.3) 842.4 (1.2) 848.9 (4.0) 1982-83 Projected 1,597 0.5 864.0 1.8 1983-84 Projected 1,651 3.4 892.0 3.2 1984-85 Projected 1,710 3.69 918.0 2.9 1984-86 Projected 1,760 2.9 944.0 2.8 1986-87 Projected 1,810 2.8 967.0 2.4 1987-88 Projected 1,860 2.8 991.0 2.5 1988-89 Projected 1,912 2.8 1,016.0 2.5 1989-90 Projected 1,962 2.6 1,040.0 2.4 g 1990-91 Projected 2,012 2.5 1,064.0 2.3 n 1991-92 Projected 2,063 2.5 1,089.0 2.3 1,114.0 $ 1992-93 Projected 2,113 2.4 2.3 2[ 9 1993-94 Projected 2,162 2.3 1,138.0 2.2 [ p 1994-95 Projected 2,210 2.2 1,162.0 2.1 *% " 1995-96 Projected 2,261 2.3 1,187.0 2.2 8 sa 1996-97 Projected 2,314 2.3 1,214.0 2.3 1997-98 Projected 2,367 2.3 1,240.0 2.1 1998-99 Projected 2,419 2.2 1,267.0 2.2
- In ion to temperature adjustments, the figures inc minor adjustments for metering errors.
S/HNP-ASC/ER 12/21/81
\
I TABLE 1.1-5 West Group of Northwest Power Pool h Operating Year (July through June) Load Growth [ Actual and Projected Systes Loads f f Percent Percent Actual Inc.ramat Over Energy Actual Increase Over Year Peak (MW) Previous Year Average NW Previous Year 1965-66 Actual 11,173 7,248 , 1966-67 Actual 11,613 3.9 7.967 9.9 ' 1967-68 Actual 13,309 14.6 8,722 9.5 1968-69 Actual 15,540 16.8 9,628 10.4 1969-70 Actual 15,030 (3.3) 10,101 4.9 1970-71 Actual 15,725 4.6 10,537 4.3 1971-72 Actual 16,876 7.3 10,694 1.5 l 1972-73 Actual 18,259 8.2 11,321 5.9 ( 1973-74 Act ual 18,707 2.5 11,703 3.4 i 1974-75 Actual 18,144 (3.0) 12.088 3.3 ! 1975-76 Actual 19,580 7.9 12.836 6.2 ! 1976-77 Actual 21,497 9.8 13,299 3.6 1977-78 Actual 21,571 0.3 13,660 2.7 1978-79 Actual 25,220 16.9 14,716 7.7 l 1979-80 Actual 26,692 5.8 14,866 1.0 , 1980-81 Actual 24,117 (9.6) 14.830 (0.2) O 1981-82 Projected 27.894 1982-83 Projected 29,032 1983-84 Projected 30,206 15.7 4.1 4.0 17,000 17,658 18,396 14.6 3.9 4.2 4 l l I 1984-85 Projected 31,365 3.8 19,130 4.0 f 1985-86 Projected 32,414 3.3 19,694 2.9 l 1986-87 Projected 33,335 2.8 20,214 2.6 i 1987-88 Projected 36,305 2.9 20,731 2.6 l 1968-89 Projected 35,373 3.1 21,306 2.8 ! 1989-90 Projected 36,474 3.1 21,888 2.7 ! 1990-91 Projected 37,541 2.9 22.463 2.6 i . 1991-92 Projected 38,550 2.7 23.030 2.5 ! 1992-93 Projected 39,560 2.6 23,568 2.3 ! 1993-94 Projected 40,653 2.8 24,143 2.4 ! 1994-95 Projected 41,815 2.9 24,764 2.6 : 1995-96 Projected 43,024 2.9 25,376 2.5 1996-97 Proj e ct ed 44,276 2.9 26,018 2.5 ! 1997-98 Projected 45,578 2.9 26,689 2.6 L 1998-99 Projected 46,920 2.9 27,403 2.7 [ Northwest peak loads are winter temperature sensitive. Thus winters with extrane cold temperatures can result in peaks which anceed several year's load { growth. Negative changes are indicated by parenthesis. O l t i Amendment 4 !
Table 1.1-6 Sheet 1 of 6 FOUR COMPANY LOADS AND RESOURCES BASED ON 1982 NRF i l 1982/83 1983/84 1984/85 1985/86 PK AVG PK AVG PK AVG PK AVG 1 Estimated System Loads 12593 7034 13112 7282 13675 7574 14150 7855 2 Resources 3 System flydro 2680 1073 2679 1072 2679 1072 2680 1072 4 contract Ilydro 3219 IS84 3045 1507 2966 1469 2907 1442 5 Contracts In 3837 1085 3277 973 3148 93!- 3075 899 6 Contracts out -416 -345 -349 -213 -336 -205 -323 -200 7 Small Thermal 1379 420 1673 457 1691 481 1707 475 8 Centralia 1024 716 922 644 922 644 922 644 9 Troj an 756 535 756 535 756 535 756 535 m 10 Wyoming (Existing) 2362 1703 2362 1703 2362 1703 2362 1703 s 11 Boardman No. 1 414 291 424 318 424 318 424 318 5 12 Colstrip No. I 165 124 165 124 165 124 165 124 y 13 Colstrip No. 2 165 124 165 124 165 124 165 124 :p 14 Colstrip No. 3 (1/84; 70%) 0 0 490 153 490 331 490 357 7 $ 15 16 Colstrip No. 4 (7/85; 70%) Creston No. 1 (7/88; 50%) 0 0 0 0 0 0 0 0 0 0 0 0 490 0 304 0 s:o 17 Creston No. 2 (1/90; 50%) 0 0 0 0 0 0 0 0 18 Creston No. 3 (1/93; 50%) 0 0 0 0 0 0 0 0 19 Creston No. 4 (7/94; 50%) 0 0 0 0 0 0 0 0 20 WNP No. 3 (12/86; 30%) 0 0 0 0 0 0 0 0 21 Wyodak No. 2 (12/88; 80%) 0 0 0 0 0 0 0 0 22 Skagit No. 1 (1/91; 100%) 0 0 0 0 0 0 0 0 23 Skagit No. 2 (1/93; 100%) 0 0 0 0 0 0 0 0 24 Total Resources 15585 7310 15609 7397 15432 7535 15820 7797 e 25 Reserves -1239 0 -1230 0 -1304 0 -1378 0
$ 7310 14379 14128 R 9 26 Net Total Resources 14346 7397 7535 14442 7797 U "o " 27 Surplus or (-De f.) 1753 276 1267 115 453 -39 -292 -58 N, w to e O O
{ } Tab d .1-6 Sheet 2 V 6 1986/87 1987/88 1988/89 1989/90 PK AVC PK AVG PK AVG PK AVG 1 Estimated System Loads 14604 8094 15045 8327 15526 8576 15976 8821 2 Resources 3 System flydro 2679 1072 2680 1072 2680 1072 2680 1072 4 Contract Hydro 2898 1431 2878 1422 2857 1410 2839 1398 5 Contracts In 2924 847 2744 781 2579 525 2578 502 6 Contracts out -314 -195 -307 -162 -188 -87 -186 -76 7 Small Thermal 1747 500 1824 532 1869 559 1908 577 8 Centralia 922 644 922 644 922 644 922 644 9 Trojan 756 535 756 535 756 535 756 535 g 10 Wyoming (Existing) 2362 1703 2362 1703 2362 1703 2362 1703 s 11 Boardman No. 1 424 318 424 318 424 318 424 318 $ 12 Colstrip No. I 165 124 165 124 165 124 165 124 }8 13 Colstrip No. 2 165 124 165 124 165 124 165 124 > 14 Colstrip No. 3 (1/84; 70%) 490 357 490 357 490 7 357 490 357 $ 15 16 Colstrip No. 4 (7/85; 70%) Creston No. 1 (7/88; 50%) 490 0 357 0 490 0 357 0 490 357 490 357 j; 254 152 254 190 x: 17 Creston No. 2 (1/90; 50%) 0 0 0 0 0 0 254 76 18 Creston No. 3 (1/93; 50%) 0 0 0 0 0 0 0 0 19 Creston No. 4 (7/94; 50%) 0 0 0 0 0 0 0 0 20 WNP No. 3 (12/86; 30%) 372 138 372 248 372 254 372 257 21 Wyodak No. 2 (12/88; 80%) 0 0 0 0 252 88 252 173 22 Skagit No. 1 (1/91; 100%) 0 0 0 0 0 0 0 0 23 Skagit No. 2 (t/93; 100%) 0 0 0 0 0 0 0 0 24 Total Resources 16080 7955 15965 8055 16449 8135 16725 8331
$ 25 Reserves -1441 0 -199 0 -1508 u 0 -1569 0 u
De g 26 Net Total Resources 14639 7955 15766 8055 14941 8135 15156 8331 1[ p w rr 27 Surplus or (-Def.) 35 -139 721 -272 -585 -441 -820 -490 EE O
Table 1.1-6 Sheet 3 of 6 1990/91 1991/92 1992/93 1993/94 PK AVG PK AVG PK AVG PK AVG 1 Estimated System Loads 16421 9057 16821 9283 17238 9503 17662 9738 2 Resources 3 System Ilydro 2681 1072 2681 1072 2677 1072 2677 1072 4 Contract flydro 2820 1387 2808 1379 2803 1369 2798 1364 5 contracts In 2566 482 1158 477 1088 470 1019 465 6 Contracts out -185 -74 -167 -73 -154 -70 -142 -67 7 Small Thermal 1965 604 1970 609 2037 64) 2044 653 8 Centralia 922 644 922 644 922 644 922 644 9 Trojan 756 535 756 535 756 535 756 535 Ua 10 Wyoming (Existing) 2362 1703 2362 11 Boardman No. 1 424 318 424 1703 2362 1703 2362 1703 $ 12 Colstrip No. I 165 124 165 318 424 318 424 318 y 124 165 124 165 124 e 13 Colstrip No. 2 165 124 165 124 165 14 Colstrip No. 3 (1/84; 70%) 490 357 490 357 124 165 124 7 00 357 490 357 O 15 Colstrip No. 4 (7/85; 70%) 490 357 490 357 490 357 490 m 357 16 Creston No. 1 (7/88; 50%) 254 190 254 190 254 190 254 190 17 Creston No. 2 (1/90; 50%) 254 172 254 190 254 190 254 190 18 Creston No. 3 (1/93; 50%) 0 0 0 0 254 76 254 172 19 Creston No. 4 (7/94; 50%) 0 0 0 0 0 0 0 0 20 WNP No. 3 (12/86; 30%) 372 260 372 260 372 260 372 260 21 Wyodak No. 2 (12/88; 80%) 252 189 252 189 252 189 252 189 22 Skagit No. I (1/91; 100%) 1275 398 1275 845 1275 893 1275 908 23 Skagit Nc,. 2 (1/93; 100%) 0 0 0 0 1275 398 1275 845 24 Total Resources 18028 8842 16631 9300 18161 9844 18106 10403 @ 25 Reserves -1727 0 -1726 0 -1945 0 -1945 0 m 26 Net Total Resources 16301 8842 14905 9300 16216 9844 16161 10403 y 27 Surplus or (-Def.) -120 -215 -1916 17 -1022 341 -1501 665 ( m O O O
i
\
U) \p/ \ ! Table M 1-6 Sheet 4 dr')6 l 1994/95 1995/96 1996/97 1997/98 PK AVG PK AVG PK AVG PK AVG 1 Estimated System Loads 18093 9979 18547 10228 19042 10504 19562 10792 2 Re source s 3 System flydro 2677 1072 2h77 1072 2677 1072 2677 1072 4 Contract flydro 2793 1360 2733 1314 2127 1309 2722 1304 5 Contracts In 945 458 872 451 495 185 481 179 6 Contracts out -127 -64 -81 -43 -69 -43 -66 -40 7 Small Thermal 2061 668 2066 673 2071 678 2076 683 8 Centralia 922 644 922 644 922 644 922 644 9 Troj an 756 535 756 535 756 535 756 535 u3 10 Wyoming (Existing) 2362 1703 2362 1703 2362 1703 2362 1703 gg 11 Boardman No. I 424 318 424 318 424 318 424 318 z 12 Colstrip No. I 165 124 165 124 165 124 165 13 Colstrip No. 2 165 124 124 7 165 124 165 124 165 124 g 14 Colstrip No. 3 (1/84; 70%) 490 357 490 357 490 357 490 357 7 m 15 Colstrip No. 4 (7/85; 70%) 490 357 490 357 490 357 490 357 16 Creston No. 1 (7/87; 50%) 254 190 is 254 190 254 190 254 190 X8 17 Creston No. 2 (1/90; 50%) 254 190 254 190 254 190 254 190 18 Creston No. 3 (1/93; 50%) 254 190 254 190 254 190 254 190 19 Creston No. 4 (7/94; 50%) 254 152 254 190 254 190 254 190 20 WNP No. 3 (12/86; 30%) 372 260 372 260 372 260 372 260 21 Wyodak No. 2 (12/88; 80%) 252 189 252 189 252 189 252 189 22 Skagit No. I (1/91; 100%) 1275 924 1275 924 1275 924 1275 924 23 Skagit No. 2 (I/93; 100%) 1275 893 1275 908 1275 924 1275 924 24 Total Resources 18313 10644 18231 10670 17865 10420 17854 10417 25 Reserves -2006 0 -2003 0 -2004 0 -2004 0
! 26 Net Total Resources 16307 10644 16228 10670 15861 10420 15850 10417 20 i
E Z
" 27 Surplus or (-Def.) -1786 665 -2319 l
%J 442 -3181 -84 -3712 -375 ;;
NJ
. . . , -.- ---- . . _ . , . . , . . - , . ~ . . . . .- ..- , - , - , .,.- . ,. -.. - , - - - . . , . . , . . - , _ - . . . - , . ,. ., . . . . - - . . . . , , . - - _ . . . _ .
Table 1.1-6 Sheet S of 6 1998/99 1999/2000 PK AVG PK AVG I Estimated lystem loads 20077 11088 20609 11383 2 Resource s 3 System Ilydro 2677 1072 2677 1072 4 Contract flydro 2717 1299 2710 1293 5 Contracts In 437 153 270 !!O 6 Contracts Out -57 -34 -28 -25 7 Small Thermal 2081 688 2086 693 8 Centralia 922 644 922 644 9 Trojan 756 535 756 535 m 10 Wyoming (Existing) 2362 1703 2362 1703 $ 11 Boardman No. I 424 318 424 318 y 12 Colstrip No. I 165 124 165 124 e 13 Colstrip No. 2 165 124 165 124 7 $ 14 Colstrip No. 3 (1/84; 70%) 490 357 490 357 Q 15 Colstrip No. 4 (7/85; 70%) 490 357 490 357 M 16 Creston No. 1 (7/88; 50%) 254 190 254 190 17 Creston No. 2 (1/90; 50%) 254 190 254 190 18 Creston No. 3 (1/93; 50%) 254 190 254 190 19 Creston No. 4 (7/94; 50%) 254 190 254 190 20 WNP No. 3 (12/86; 30%) 372 260 372 260 21 Wyodak No. 2 (12/88; 80%) 252 189 252 189 22 Skagit No. 1 (1/91; 100%) 1275 924 1275 924 23 Skagit No. 2 (1/93; 100%) 1275 924 1275 924 24 Total Resources 17819 10397 17679 10362 $ 25 Reserves -2003 0 -2004 0 P' N 26 Net Total Resources 15816 10397 15675 10362 27 Surplus or (-De f.) -4261 -691 -4934 -1021 O co y u O O O
S/HNP-ASC/ER 9/16/82
T TABLE 1.1-6 Sheet 6 of 6
]
- 1) Loads and Resources are those submitted to the PNUCC for the 1982 Northwest Regional Forecast. In the case of PP&L, loads have been adjusted to reflect total Company loads.
- 2) Hydro resources are based on the 1982 NRF 42-1/2 month -
critical period regulation.
- 3) All planned thermal units (peak and energy) are included in estimated amounts as submitted by respective project owners to the PNUCC for the 1982 Northwest Regional Forecast.
7
- 4) Energy capability of existing thermal units is consistent with that assigned for planned units or is l based on historical operation at the discretion of :
each system. Determination of capacity of existing i thermal units is left solely to the discretion of individual sponsoring utilities.
- 5) Reserves are 5% on hydro and small thermal units and s 15% on large thermal units. PP&L assumes 6-1/3% and 19% reserves respectively.
l h h I 5 l Amendment 7 :
Table 1.1.7 LOADS AFD RESOURCES NORTHWEST REGION 82-83 83-84 84-85 85-86 86-87 87-88 88-89 89-90 90-91 91-92 LOAD & RESOURCE COMPARISON January Peak - MW
- 1. Total Load 31,716 32,527 33,547 34,506 35,141 35,440 36,289
- 2. 37,247 38,174 38,993 Net Resources 1/ 32,595 32,455 33,811 35,387 36,305 35,835 36,014 37,155 37,779 37,490
- 3. Surplus (Deficit) 879 (72) 264 881 1,164 395 (275) (92) (395) (1,503)
Energy - Avg. MW
- 4. Total Load 19,240 19,837 20,448 21.010 21,831 22,534 23,030
- 5. 23,552 24,071 24,562 Net Resources 1/ 18,322 18,511 19,261 19,550 20,018 ,20,0R4 20,046 /l,111 21,643 22,097
- 6. Surplus (Deficit) (1,018) (1,326) (1,187) (1,480) (1,813) (2,450) (2,984) (2,441) (2,428) (2,465) 92-93 93-94 94-95 95-96 96-97 97-98 98-99 99-00 00-01 01-02 LOAD & RESOURCE COMPARISON :c January Peak - MW I y
- 1. Total Load 39,856 40,749 41,681 42,599 43,497 44,495 45,506 46,543 47,711 7 mO
- 2. Net Resources 1/ 38,932 38,688 38,938 38,655 48,756 38,340 38,041 Surplus (Deficit) 37,736 37,420 37,076 36,752
$Al
- 3. (924) (2,061) (2,743) (3,934) (5,157) (6,454) (7,770) (9,123) (10,635) (12,004)
Energy - Avg. MW
- 4. Total Load 25,046 25,539 26,056 26,582 27,052 27,603 28,155
- 5. 28,725 29,371 29,975 Net Resources 1/ 22,731 23,344 23,692 23,753 23,616 23,566 23,514 23,468 23,452 23,449
- 6. Surplus (Deficit) (2,315) (2,195) (2,364) (2,829) (3,436) (4,037) (4,641) (5,257) (5,919) (6,526)
Source - Long Range Projections of Po'rer Loads and Resources for Resource Planning, Northwest Region Area, 1982-83 to 2001-02, PNUCC, August 26, 1982. y 1/ Resources include hydro, small fossil-fuel plants, coqeneration, renewables, o, llanford-NPH through June l'f88, Centralia, Trolan, Coletrap fl and 42 (504), 83 and 34 (70s), WNP Bl, 82, 8 J, poordman, Crewton el, 82, SJ, 04, tAayit II B
- y and 82, .ind ns. contractual imports / expos-tu with utilsties outsade the Area.
llanford is not included as a peak resource. Estimated amounts for scheduled )m rt m.stntenance have been deducted. tenorgy only) and for hydro ruolization adjustment (peak only) N 4 Al1 enesting iherma1 unatr$ and future thermal unats (peak pro ject owners. and energy) are ancluded an estimated amounts as submit ted by respect ive $ ' requirements. Duth peak and energy resourcum have been reducud by reserve e 9 9 -
l' l S/HNP-ASC/ER 9/16/82 l
) 1.2 NONDETERMINISTIC ANALYSIS 1.
2.1 INTRODUCTION
Forecasting the growth in demand for electricity in the Pacific Northwest region is increasingly characterized by uncertainties. These uncertainties make forecasting demand difficult, and suggest that the traditional, single point or deterministic approach to forecasting is not suitable in the circumstances that prevail in the region at this time. The fact that others recognize this is illustrated by the recent f orecasts by the Bonneville Power Administration (BPA) (Ref 1), Charles River Associates (CRA) (Ref 2), and the Pacific Northwest Utilities Conf erence Committee (PNUCC) (Ref 3). These forecasts show various high, low, and base values for annual average growth rates that range f'om 0.9% to 2.6%, for periods up to the year 2000. Different models, assumptions and base periods are used by 7 the forecasts. The Applicants believe that a "right" or
" wrong" forecast simply cannot be chosen from those available now. An approach must be developed that recognizes the uncertainties in the region and provides the flexibility to chose f rom among a variety of resources to
{Ny ,) meet power demands as they develop in the future. 1.2.2 A BOUNDING APPROACH TO REGIONAL NEED The challenge f acing both utilities and regional planners is to develop a way to proceed that places reasonable bounds on the uncertainties and provides a base of resource options that will permit a flexible response to changing conditions. The mix of resources to be utilized can then be adjusted in light of the new inf ormation as it develops. The results of the BPA, CRA and PNUCC f orecasts are tabulated below: a 1.2-1 Amendment 7
E S/HNP-ASC/ER 9/16/82 1980-2000 Growth in Electricity Loads Average Annual Compounded Rate Low Most Likely High CRA 1.1 % 1.5 % 2.0 % CRA - adj . (1) 2.0 BPA-draf t 0.8 % 1.7 % 2.5 % BPA-final 0.9 1.6 2.4 BPA-adj.(2) 0.8 2.0-2.2 3.0 PNUCC Econometric 1.4 % 2.1 % 2.6 P, SOU(3) 2.5 (1) The CRA load forecast was adjusted by the PNUCC to correct f or inclusion of cogeneration and other changes. (2) Naticnal Economic Research Associates reviewed the forecast at the request of BPA. They concluded that these rates of growth were more consistent with available data. i (3) SOU - Sum of Utilities Forecast 7 The PNUCC econometric, BPA, and CRA forecasts each predict a low and high annual average growth rate with a base case or mid-range forecast that is characterized above as the "most likely" annual average growth rate. These f orecasts are shown in Figure 1.2-1. The underlying assumptions, data bases and differing forecast methodologies for these three forecasts are not challenged here, and it is recognized that there is no one
" correct" methodology or set of assumptions. Instead, as the first step in this analysis, these f orecasts are viewed collectively for the purpose of selecting plausible high and low cases to define a range of demand broad enough so I that the uncertainties will be bounded and the actual
! demand would likely f all between those bounds. Viewing the f orecasts with this in mind, the "most likely" annual average rate of growth ranges f rom a low of 1.5% f rom the CRA f orecast to a high of 2.5% from the SOU forecast. The BPA and PNUCC econometric models fall in between these two, with rates of 1.6% and 2.1%, respectively. The extreme low values of 1.1% (CRA) and 0.9% (BPA) are less likely, since they f all f ar below the 9 1.2-2 Amendment 7
S/HNP-ASC/ER 9/16/82
- lowest most likely figure. The highest value of 2.6%
(s' (PNUCC) is also unlikely, since it exceeds the highest most likely value of 2.5%. This approach suggests that, as a group, the region's forecasters are more confident that the actual growth rate through the year 2000 will fall between 1.5% and 2.5% than they are that it will fall outside this range of "most likely" rates. The degree of confidence would need to be assessed, but it can be said that this range bounds much of the uncertainty surrounding the growth rate. The next step in this analysis is to identify the generat-ing resources available or potentially available to the region. These are summarized in Table 1.2-1, which is based on the resources shown in the PNUCC forecast (Ref 1). The future resources have been divided into two cate-gories - relatively assured and potential resources. Relatively assured resources are those currently under construction. The total of these plus the existing resources is shown for each year through the year 2000. The final step in this analysis is to compare the existing and relatively assured resources listed in Table 1.2-1 with the regional loads that would result from the previously discussed 1.5% and 2.5% bounding regional load growth rLtes. That is done in Figure 1.2-2. From this comparison 7 ("'s it appears that units the size of S/HNP Units 1 and 2 could be needed as early as 1991 and 1993 if the load growth rate g'] is 2.5%, or as late as 1996 and 1998 if the load growth rate is 1.5%. This conclusion is dependent on the existing and relatively assured resources being available in the magnitude and with the timing reflected in the PNUCC forecast. Unfortunately, however, uncertainty pervades these resource estimates as well. For example, estimates of the amount of hydro energy that will be lost from the regional system by efforts to
" protect, mitigate and enhance the fish and wildlife" of the region's rivers, as required by the Regional Power Act, range from 235 average MW to 4,310 average MW (Ref 4). The draft Fish and Wildlife Program issued September 16, 1982 by the Northwest Power Planning Council recommends flow i
measures that would reduce the region's firm energy load carrying capability by 550 average MW. The final report is to be issued in November, 1982. This loss will reduce the i existing resources listed in Table 1.2-1, and represents a potentially large additional need for new resources. The actual impact of this factor cannot be known until the Northwest Power Planning Council finalizes its program and begins implementation. There is also uncertainty surrounding the extent of cogeneration, renewable resources and additional conservation potential in the region. These a 1.2-3 Amendment 7 l l ._. . _ . _ _
S/HNP-ASC/ER 9/16/82 factors could augment the potential resources listed in Table 1.2-1. The challenge facing the region and the Applicants is to make wise decisions using the potential resources to meet developing load growth with an appropriate and cost effective mix of resources, as new information is developed and uncertainties are resolved. As previously noted, the S/HNP units could be needed as early as 1991 and 1993, depending upon the rate of load growth actually encountered and the resources actually available and chosen to meet the developing need. The precise time of need can only be determined at some point in the future, as the range of uncertainties is narrowed and an improved base for planning develops. For example, should the actual rate of growth be 2.5%, it will likely take all of the potential resources listed on Table 1.2-1 to meet the need by the year 1996. On the other hand, if the rate of growth were 1.5% and all of the other potential resources were chosen ahead of S/HNP, S/HNP might not be needed until after 2000. The critical matter for the Applicants and the region is to 7 ensure that S/HNP is in fact atailable as a potential resource. This can be assured by timely completion of NRC and EFSEC application reviews and issuance of construction permits and site certification. While this need for power approach differs from the typical deterministic method usually seen in NRC applications, it nevertheless demonstrates the requisite need, and does so in a manner that recognizes the uncertainties and realities facing this region. Moreover, there is a distinct and significant benefit to the region from having these units available as a potential resource pending the day when a fully informed decision can be made as to whether they should be constructed. The approach presented here is new; it does, however, reflect the concepts that are developing in the region. See, for example, The Path Along the Ridge: Regional Planning in the Face of Uncertainty, by Dr. Kai N. Lee, March, 1982 and The Design and Evaluation of a Flexible Power Plan, by Steve Aos, et al., Washington State Energy Office, July 4, 1982. These concepts are also being considered by the Northwest Power Planning Council in carrying out its responsibilities under the Regional Power Act (Ref 5). O 1.2-4 Amendment 7
l S/HNP-ASC/ER 9/16/82 1.2.3 APPLICANTS' NEED FOR S/HNP ! The Applicants, the four utilities sponsoring S/HNP, face the same uncertainties as the region. Each of the , Applicants performs its own load forecasting studies, which ' are presented in Section 1.1. The latest projections for i , each Applicant were presented in Tables 1.1-1, 1.1-2, ; 1.1-3, and 1.1-4. The combined projected loads for the four companies were set forth in Table 1.1-6, along with ' l the resources projected by the four companies. Table 1.1-6 i reflects the traditional deterministic approach to demonstrating need for power. It shows that S/HNP Unit 1 and Unit 2 will be needed by the four Applicants during the l 1990s. The nondeterministic or bounding growth rates approach l applied to the region in Section 1.2.2 can also be applied to the four Applicants. This has been done in Table 1.2-2 , and the results are portrayed in Figure 1.2-3. i The first line on Table L.2-2 is the combined projected loads of the ' four Applicants, which are the same as the projected loads shown on the first line of Table 1.1-6. As can be seen, the four companies estimate that their combined average energy load will increase from 7,034 average MW for 1982-83 : to 11,383 average MW for 1999-2000. This represents an average annual compound growth rate of approximatey 2.9%. 7 For the same reasons set forth in the regional discussion, and to accommodate the uncertainties inherent in load forecasting, Applicants have used an upper and lower annual
- average growth rate for the purposes of this presentation. .
For the upper and lower bounding growth rates, the l Applicants have elected to use rates that are 0.5% higher > and lower, respectively, than the growth rate of 2.9% presented in their deterministic demonstration. These upper and lower bounding rates of 3.4% and 2.4%, [' respectively, have been plotted on Figure 1.2-3. The same 14 spread between the upper and lower bounding growth rates used in the regional analysis is used here because in the , future the Applicants face factors similar to those faced l
- by the region. For the same reasons noted in the regional l l analysis, the Applicants believe that this range is likely to bound much of the uncertainty faced by them on their
- systems (for the Applicants' systems, this 1% spread .
! amounts to about 800 MW in 1990, about 1400 MW in 1995, and !
l about 2100 MW in the year 2000). i f 1 The existing and relatively assured resources of the four Applicants are listed on Table 1.2-2 and plotted on Figure
- 1.2-3. The additional energy that would be added by S/HNP :
Units 1 and 2 has also been plotted on Figure 1.2-3. As '
- can be seen, if the load growth is in the high range, uni'ts i I I
1.2-5 Amendment 7
S/HNP-ASC/ER 9/16/82 the size ofasS/HNP as early Units 1991 and 1 and 2 (and more) could be needed 1993. By 1995, all of the potential resources could be needed. On the other hand, if the load growth is in the low range, all of the potental resources might not be needed until 1999. However, even in the low growth case, a unit the size of the S/HNP units will be needed by 1991 and a second unit of that size will be needed by 1995. As in the case of the region, the above conclusions are also subject to variation resulting from the uncertainties surrounding the amount of hydro energy that may be lost to
" protect, mitigate, and enhance the fish and wildlife" of the region, as well as the uncertainties surrounding the extent of cogeneration, renewable resources, and additional conservation that will actually be realized on the systems of the four Applicants.
1.2.4 CRITIQUE OF REGIONAL FORECASTS The results of the three most reputable load forecasts for the Pacific Northwest Region, the PNUCC 1982 NRF, the BPA Forecast and the Independent Review of WNP-4 and 5 by CRA, were presented in Section 1.2.2. For the reasons 7 previously discussed, the Applicants have not attempted to choose or defend any one of these forecasts as the
" correct" forecast for the region. These forecasts have, however, been critically reviewed by others and, in the interest of completeness, some of these reviews are summarized.
1.2.4.1 PNUCC 1982 Northwest Regional Forecast The PNUCC 1982 NRF, which criticized the Natural Resource Defense Council (NRDC) Model Plan, has in turn been criticized by the NRDC (Ref 6). NRDC's principal criticisms may be summarized as follows:
- 1. PNUCC overstates the penetration rates for conservation measures used by NRDC; 2.
While NRDC recommends several new conservation programs as mandatory, the only ones relied upon by PNUCC are building and appliance efficiency standards; l 3. NRDC uses economic growth rate assumptions which are actually higher than thos used by PNUCC forecasters; and 1.2-6 Amendment 7
S/HNP-ASC/ER 9/16/82
- 4. Avoided cost numbers substantially lower than 100 4
Os mills will validate the NRDC assumptions which are used in the Model Plan. l.2.4.2 BPA Forecasts of Electricity Consumption in the Pacific Northwest, April 1982 (draft) The BPA draft forecast was issued for comment in April 1982. This forecast was reviewed by the PNUCC load forecasting committee. Their comments are set forth in a memorandum dated May 3, 1982 which is included in the 1982 NRF, and appears in Appendix A to this ASC/ER. The extent, if any, to which the PNUCC comments were taken into account in issuing the final BPA forecast is not known as of this writing; although the results of the final forecast have been released and are set forth in Section 1.2.1, the final document is not yet available. The BPA draft forecast was also reviewed by the National L Economic Research Associates, Inc. (NERA) under a contract with BPA (Ref 7). NERA makes the following points:
- 1. Plausible input assumptions were used.
O 2. The forecast is biased toward the low end of the range. A forecast of 2.0 to 2.2% per year is more consistent with the available data than the 1.7% which 7 BPA used.
- 3. BPA forecasts a range from 0.8 to 2.5% per year from 1980-2000. This probably understates the range which should be considered for policy purposes. A range of 0.8 to 3.0% would provide a more defensible guide to policy.
1.2.4.3 Independent Review of Washington Public Power Supply System Nuclear Plants #4 and #5 (January 1982) This review was conducted by CRA for the Office of Applied Energy Studies, University of Washington / Washington State Unversity in conjunction with other studies related to the j decision on whether WPPSS Units 4 and 5 should be terminated. PNUCC submitted comments on the CRA forecast to the Northwest Power Planning Council on May 14, 1982 (Ref 8). PNUCC made the following points: s 1.2-7 Amendment 7
S/HNP-ASC/ER 9/16/82
- 1. The CRA forecast included a 900 average megawatt overforecasting error in 1980, due primarily to a computer code error which caused irrigation sales to be included twice in the base year value.
- 2. Industrial sales are underforecast 1600 average mega-watts in the year 2000 (including a correction for the irrigation overforecasting).
- 3. The net result of these corrections is a revised mid-range twenty year annual growth rate of 2.0 percent rather than the 1.5 percent used in the CRA report.
I 1.2.5 THE NRDC FORECAST i i The NRDC has developed a "Model Electric Power and I Conservation Plan for the Pacific Northwest". NRDC is an intervenor in the S/HNP licensing proceeding and opposes the project essentially on the grounds that conservation and energy renewables eliminate any need for S/HNP. i i While the Applicants have not attempted to criticize the other forecasts discussed, the NRDC model plan assumes a very unrealistic set of circumstances with which the Applicants disagree. It relies heavily on conservation and 7 renewables to develop a future era in which conservation, renewable energy and cogeneration eliminate the need for any new power plants other than those now nearing comple-tion, ie, other than Valmy 2, Colstrip 3 and WPPSS Unit 2. , The PNUCC has analyzed and issued comments on the NRDC plan (Ref 9). The Applicants agree with those comments, which
- are summarized below:
1. General l The NRDC implies that the Northwest Power Planning > l Council's task is to choose between two mutually exclu- ' i sive options (conservation /renewables vs. thermal power plants) , rather than to search for the most cost effective mix of resource alternatives among all of those available.
- 2. Cost Effectiveness NRDC's use of WNP 4/5 as a surrogate for the Region's avoided cost is inappropriate, since their costs played a large part in termination of these units. '
NRDC unjustifiably used different discount rates in performing economic comparisons between 1.2-8 Amendment 7
S/HNP-ASC/ER 9/16/82 e# conservation /renewables and thermal power plants. Extremely low long-term rates of economic growth were used.
- 3. Environmental Costs Risks from thermal plants are quantified, while risks associated with conservation and renewables are essentially ignored. 7
- 4. Conservation NRDC's approach risks significant double counting of programmatic and price induced conservation, penetration rates for conservation measures are highly optimistic, and conservation is unrealistically placed above other social values.
- 5. Cogeneration NRDC uses overly optimistic estimates for cogeneration.
O 1.2-9 Amendment 7
r S/HNP-ASC/ER 9/16/82 Ref erences f or Section 1.2
- 1. Bonneville Power Administration Forecasts of Electricity Consumption in the Pacific Northwest, April 1982 (draf t) .
- 2. Independent Review of Washington Public Power Supply System Nuclear Plants 64 and #5 (January 1982).
- 3. Northwest Regional Forecast of Power Loads and Resources July 1982 - June 1983, Pacific Northwest Utilities Conf erence Committee (May 1982).
- 4. Main Stem Columbia River and Snake River Instream Fish Flow Report, Phase IV, 1985 Level Studies, U.S. Army Corps of Engineers, Interagency Studies (Preliminary; June 1982).
- 5. Second Annual Report of the Pacific Northwest Electric Power and Conservation Planning Council (Draf t; July 1, 1982).
- 6. Comments of the Natural Resources Def ense Council, the National Wildlif e Federation, the Oregon Environmental Council, and the Sierra Club on the Nuclear Regulatory Commission's Draf t Environmental Statement Related to the Construction of the Skagit/Hanf ord Nuclear Project, Units 1 and 2 (June 14, 1982).
- 7. Review of the Bonneville Power Administration, Electricity Load Forecast, NERA (Final Report; April 10, 1982).
- 8. Letter dated May 14, 1982 from PNUCC (Hardy) to Northwest Power Planning Council (Sheets) and enclosed analysis dated May 13, 1982.
- 9. Synopsis of PNUCC Comments on NRDC Draft Model Plan f or the Pacif ic Northwest, Pacific Northwest Utilities Conf erence Committee (May 13, 1982).
O 1.2-10 Amendment 7
xy Table y -1 Q HORillEST REClott i EXISTillC, RELATIVE ASSURED, AllD POTDITI AL RESOURCES AVERACE llW 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88 1988-89 1989-90 1990-91 Existing & Relatively Assured Resources 18,661 18,844 19,584 19,866 20,306 20,393 19,989 20,074 20,012 1991-92 1992-93 1993-94 1994-95 1995-96 1996-97 l'.!97-98 19P3-99 1999-2000 Existing & Helatively Assured Resources 19,977 19,960 19,921 19,878 19,845 19,707 19,657 19,613 19,'90 en 5 _ g Relatively Assured Resources Potential Resources $ (Included Above) Q 7n t Average MW Average 11W Average 11W 1984 Valmy 2 (Northwest Share) 95 S/itP 1 892 Creston 1 381 Colstrip 3 (tlorthwest Share) 357 2 892 2 381 Wi4P 2 770 3 381 1985 Colstrip 4 (Northwest Share) 357 nip 1 875 4 381 1986 WtP 3 (Horthwest Share) 874 Source - Horthwest Regional Forecast of Power Loads and Resources, July 1982 - June 1993, Paci fic florthwest Utilities Conference Committee, thiy, 1982. g 3 c Draf t, Long-range Projections of Power Loads and Re sources for Resource Planning, R
- y. Pacific florthwest Utilities Conference Committee,imly 12, 1982. %
Table 102-2 FOUR C0tlPAtlY C0llPOSITE EXPECTED LOADS - EXISTIllC AtID RELATIVELY ASSURED RESOURCES AVERACE HW 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88, 5988-89 1989-90 1990-91 Expected Loads 7,034 7,282 7,574 7,855 8,094 8,327 8,576 8,821 9,057 Existing & Relatively Assured Resources 7,310 7,397 7,535 7,797 7,955 8,055 L895 7,85c L893 (Deficit) 276 115 (39) (53) (139) (272) (681) (929) (1,164) 1991-92 1992-93 1993-94 1994-95 1995-96 1996-97 1997-98 _ 1998-99 1999-2000 lxpected Loads 9,283 9,503 9,738 9,979 10,228 10,504 10,792 11,088 11,383 Existing & Relatively k Assured Resources 7,886 7,908 7,909 7,916 7,889 7,623 7,620 7,600 7,565 y (Deficit) (1,397) (1,595) (1,829) (2,063) (2,339) (2,881) (3,172) (3,488) (3,818) Relatively Assured Resources Potential Resources (included above) Average NW Ascrage NW Colstrip 3 1/84 360 Skagit/ilanford 1 937 o $' Colstrip 4 7/85 360 Skagit/Hanford 2 937 R WIIP 3 12/86 272 Creston 1, 2, 3, & 4 235 (each) rt a h w Wyodak 2 189 Source: Table 1.1-6 O O O
S/HNP-ASC/ER 9/16/82 30000 PNUCC ECON 2.8% P j NUCC SOU 2.5% 9tA2.4% A - 2E~
// 7 PNUCC ECON 2.1%
G
// ,[ '
# p CnA LO%
a -
/,/ #
, /,/
#A%
M E - /,2 e/ /
. CnA t.sw
' NC ECON 1.4%
G
~
p/ # /, A [ CnA i.i% T _. ./,7'/'u .s-f -
- 9eA o.e%
S 5'g..- ,/
,, - 3/
1980 1985 1990 1995 2000 2005 YEAR I PUGET SOUND POWER & LIGHT COMPANY SKAGIT I HANFORD NUCLEAR PROJECT APPLICATION FOR SITE CERTIFICATIONI ENVIRONMENTAL REPORT O REGIONAL ELECTRICITY FORECASTS FIGURE 1.21 Amendment 7
S/HNP-ASC/ER 9/16/82 O\ LOAD AT 2.5% A YEAR A - V f 25000-A - G E M LOAD AT 13% A YEAR i E - [ *-
,# = PLUS StMNF 2 e """ ~ ~ === PLUS S/HMP 1 T 20000 A % ,,,,,,,,,
I #, _ S -
,,**,# RELATfvELY ASSURED Resources
.*,a 15000 i , , ,
1980 1985 1990 1995 2000 2005 YEAR PUGET SOUND POWER & LIGHT COMPANY SKAGIT / HANFORD NUCLEAR PROJECT APPLICATION FOR SITE CERTIFICATION / ENVIRONMENTAL REPORT
-m NORTHWEST REGION LOADS AND RESOURCES FIGURE 1.2 2 Amendment 7
t S/HNP-ASC/ER 9/16/82 l r [ 14000
}
,14% AARG ,
- 1
,4 i 12000 - ,s' f A ,# 2.9% AARG [
V e ; E ,# i R < !
# 2.4% AARG E /
M 10000-- s'
/ !
r E ^
,/ !
O A
, / / - - . S,-P ,
W - e
/
A e w - I # s ~ % .+S/HNP1 s 8m0- ,-
,# / !
__.______\-*""*'==
== RELATIVELY ASSURED f RESOURCES I i
1 i i i I i 1980 1985 1990 1995 2000 2005 l YEAR i r i ! i f l t ! l PUGET SOUND POWER & LIGHT COMPANY f SKAGIT I HANFORD NUCLEAR PROJECT ) APPLICATION FOR SITE CERTIFICATION / ! ENVIRONMENTAL REPORT l FOUR COMPANY COMPOSITE l LOADS AND RESOURCES l i FIGURE 1.2 3 , l Amendment 7 , i
7 S/HNP-ASC/ER 9/16/82 1.3 CONSEQUENCES OF DELAY The foregoing discussion illustrates that the traditional
" Consequences of Delay" discussion called f or by Regulatory Guide 4.2 does not accommodate the situation in the Pacific Northwest Region. When the uncertainties concerning the future need for power in the region are considered along with the type of planning called f or by the Regional Power Act, it appears that the eff ects of increments of delay of 1, 2 or 3 years as called for in the Regulatory Guide are not meaningful. Under the nondeterministic approach, demand is forecast as falling between a low growth rate and a high growth rate, with the dif f erence between the two calculated to account f or the major uncertainties. Any particular resource could be called upon during the period !
of the forecast, depending upon the circumstances which ! develop in the f uture, resolution of uncertainties, and the ! actual rate of growth in demand. With this approach, the l l analysis of a 1, 2 or 3 year delay is not usef ul. :
' What is important is the addition of the S/HNP to the available resource base. This can be accomplished by issuance of the site certification and construction permits in a timely manner. Receipt of these authorizations in !
i late 1983 or early 1984 would be timely. 7 l ' In the interest of completeness, the f ollowing discussion of consequences of delay (based on a deterministic approach) is included in order to demonstrate compliance
- with Regulatory Guide 4.2. !
The ef f ects of delays of the proposed S/HNP on the reserve margins of Applicants and the Pacific Northwest Region can j be determined from Tables 1.1-6 and 1.1-7 and from Tables : 1-2 and 1-3 in the 1982 Northwest Regional Forecast. l In the case of Applicants, with respect to peak capacity l and reserves, each of the two S/HNP units is included in Table 1.1-6 as a peak resource of 1275 MW for the year when it is scheduled to come on line and for each year thereaf ter. The weighted peak reserve allowance for each unit is 15.8% of 1275 or 201 MW. Thus, a delay in ; the completion of either unit would reduce the peak ! resources f or the year or years af f ected by the delay by l 1275 MW and reduce the peak reserve requirements f or those ; years by 201 MW, f or a reduction in net peak resources of j 1074 MW. The effect of a 1074 MW reduction in net peak ; resources can be seen by subtracting 1074 from the ' projected peak surplus (def iciency) shown on the bottom ! line of Table 1.1-6 f or the year or years af f ected by the , delay. [~'h
\_ / i 1.3-1 Amendment 7 l l
l S/HNP-ASC/ER 9/16/82 l With respect to Applicants' energy resources and reserves, the specific amount included each year in Applicants' energy resources for each S/HNP unit is shown in Table 1.1-6. Since no energy reserves are included in Table 1.1-6, the effect of a delay is to deduct the resource amount from the projected energy surplus (def iciency) shown on the bottom line of Table 1.1-6 for the year or years affected by the delay. With respect to the regional forecast shown on Table 1.1-7 and in the 1982 NRF, a delay of the S/HNP units would have 7 no effect on the values included in the regional forecast for reserves. As previously stated, the regional reserve allowances are a f unction of projected loads - not projected resources, as in the case of Applicants' forecasts. Thus a delay in the completion of either S/HNP unit would simply reduce any surplus or worsen any deficit shown in Table 1.1-7 or Table 1-1 of the 1982 NRF by 1275 MW peak per unit, and for energy by the resource amount included in the forecast, for the year or years affected by , the delay. O [ l O 1.3-2 Amendment 7
]
S/HNP-ASC/ER 12/21/81 l l l l l 1.4 POTENTIAL FOR FUTURE ACTIVITES AT SITE Applicants believe that the site would be physically capable of accommodating two additional nuclear-powered electrical generating units and the proposed Project 4 facilities have been laid-out so as not to foreclose this possibility. However, Applicants do not at present have any plan for proposing any additional units at the site. l l i Y 1 e i I i a t + i i i + i i 1 1 1.4-1 Amendment 4
, S/HNP-ASC/ER 9/16/82 'j l f ( Figure 2.1-2 shows the Site Boundary lines and the Plant exclusion area boundary. The Site Boundary, the Plant 4 I l property lines, and the restricted area-boundary are the ' same. The S/HNP exclusion area boundary encloses an area . within 1 mile (1609 meters) of the line joining the reactor l centers. l7 ( i 2.1.1.3 Boundary for Establishing Effluent Release Limits i The boundary f or establishing ef fluent release limits, in l conf ormance with the restricted area as defined by 10 CFR i 20, coincides with the Site Boundary (refer to Figure j 2.1-2). Table 2.1-1 lists the minimum distances to the j Site Boundary from the effluent release points (center of ; each containment). For purposes of radiation protection ' and general saf ety, the area inside the Site Boundary will be under the control of Puget. 2.1.2 EXCLUSION AREA AUTHORITY AND CONTROL l 2.1.2.1 Authority l f 4 All of the land within the exclusion area is, at present, ) owned by the United States of America and managed by the 4 Department of Energy as part of the Hanford Reservation. l t l Puget is currently negotiating with the Department of i Energy to acquire the legal rights necessary to use the ! Site f or the Project and those necessary to determine all ( activities within the exclusion area, as required by 10 CFR ; 100.3(a). I
- Puget expects to acquire title to 640 acres (the owned land) of the 1200 acre Site and to acquire appropriate !
easements over thr. remaining 560 acres (the easement area) ! of the Site. The owned land, the land being purchased by i Puget, is Section 33 of the Township 12 North, Range 27 l East of the Willamette Meridian. The easement area is the ! remainder of the Site described in Section 2.1.1.2. l i Puget's use of the owned land will be restricted to the ; construction and operation of nuclear electric generating I . facilities. Upon completion of the use of the owned ' land l 1 for these purposes, title to the owned land will revert to : the Government. .The Government will retain all mineral i rights upon or in the owned land, but will agree not to exercise those rights so long as title to the owned land remains vested in Puget.
?
2.1-3 Amendment 7 i'
. _ __ _-_. -. _ _ - - _ , _ . . _ _ . _ . . ~ . - _ . _ _.__ _, __.._.__. _ . _ . _ _ _ ,_,__..,_._ _ _
1 S/HNP-ASC/ER 9/16/82 l Except for the Substation, all S/HNP structures to be located on the Site will be located on the owned land. The ! Substation will be located on the (;asement area. The easements to be acquired by Puget over the easement area will include an easement for an access-control peri-meter fence, thus permitting Puget to fence the Site boundary and control access to the entire Site, as dis-cussed in Section 2.1.1.3. In conjunction with purchase of the owned land, Puget expects to acquire from the Government the authority to determine all activities within the exclusion area consis-tent with the meaning of 10 CFR 100.3(a), including the authority to remove all personnel and property from the area. Puget will agree to exercise this authority in a manner so as not to preclude the Government from under-taking any action or activity within the exclusion area that is permissible under the provisions of 10 CFR 100.3(a). The Government will retain all mineral rights upon or in the exclusion area, but any exercise of these rights will be subject to Puget's above described authority to control all activities within the exclusion area. There are no easements of record within the exclusion area. 2.1.2.2 Control of Activities Unrelated to Plant Operation There are no activities unrelated to S/HNP operation within the exclusion area. [7 2.1.2.3 Arrangements for Traffic Control No public roads, railroads, or waterways traverse the 4 exclusion area. The S/HNP access roads and railroad (Figure 2.1-2) will be located on easements to be granted to Puget by the Government. Puget will have the authority to cor. trol travel on these facilities within the exclusion area. In the event that evacuation or other control of the exclusion area should become necessary, appropriate notice 7 will be given to the DOE-Richland Operations Office for control of non-Puget related activities. l l 2.1-4 Amendment 7
S/ i w .- J h Skagit/Hanford q VICINIT' I BPA 500 kV
~N LINES US GOVERNMENT RAILROAD f To Yakima BPA 230 kV I TRANSMISSION i LINES I
/
l -
~
,i 1 -o, SUBSTATION ,
,/
- .ay 1
ALTERNATE
/ +
SOUTH ACCESS ROAD NORTH ACCESS fo c 6p ROAD PREFERRED f { 0 l fo g SOUTH ACCESS ROAD N ' o ' = SCALE IN MILES
&w
l 2P-ASC/ER 9/16/82 I luclear Project (MAP l PUMPlNG PLANT Q l 4 I 'lNTAKE & i DISCHARGE PIPELINES RAll 40AD ASHE SUBSTATION
-{} WNP-4 O
fo WNP-2 O WNP-1
'>o b
4
-(}
FFTF < PUGET SOUND POWER & UGHT COMPANY I SKAGITlHANFORD NUCLEAR PROJECT APPLICATION FOR SITE CERTIFICATIONI ENVIRONMENTAL REPORT SKAGITlHANFORD NUCLEAR i PROJECT VICINITY MAP l l l FIGURE 2.11b Amendmeni.-+ '
SJ
%~ l .' LL CR C:3 [ 5 O l 70 l lb CENTRAL l LANDFILL 2 l 2 l j
22
) <2s W Q.og* %41g
^f
__q
!/ sTyELL_
.,_.,;__,,______g_
2_ o o c, Cg c30 i T (I W T^^' ' '4, : 7 I d
/L/) _
l S ( \1 0 A M . o )q
#oh S?IAV 2
_L<
=>
#Fo / > .ii%%%A 2.uggsv 3 6 ss sy
+ *
{< * = s= ::= :=,. ,= 5 0 E' ==5 W 28 %
+
e ++ ) $ l 4 %\ D I "( UNIT UNIT ( g<
# ja
- '+
I o k ,g2 g 5e o I p
+.
?p o I In t' s 3 hf" 3o og'%. m 1 , jsee etant g 3
& o l5D'c "h y I. f dDL9?d'~ML L '!L. 2 --
"fffLs o on
@ ,-vc ;W%dL$hk&'
> c pg O
h$.**% + d' O s N*,0 i a# &;;7 s-- 6'; ) LEGEND ,,#+ D f
% x ,,- *%+~ n~ )
Primary Highway O' C'
,# 5
# b y k
Secondary Highway , 5 "
'o p Light - Duty Road .. . :. h .
========== Unimproved Road '
[' % - ES2OI Tj'"O "ay"' **' p,g h *%.,1g
++ Pipeline Rightof way OO %
-t4- -tt -H= Proposed Railroad Q JW
- - -- Proposed Road SCALE Alignment , gd 1
fHNP-ASC/ER 9/16/82 i 2 l C:ln .
/ *;
.f 1 t' l-C ( l [
I
/, -- ,;, 8 g
N .rf l mv i *-
= '
. . ._.J - -e i,
'.'.*/
g LL l 0 ta
.c.,_.. .
, - . 4 .
; s ;
.- m - 26s y 33%.m. i 1
.hh 3 _
i hl . RlQQ Es
. r- _' ,,
>In
_w e
. _h-[fM I
" y ,".. h p . y .
r
*Yj p h '. : r:
r:
. ;.__; , j p- ._ !
# - M ".. d;~.C . f, .I N = l 521 o -
. ---. p , =--s = k ix l t -
'g *
= \q ,_ .
N / \ N [F g g ;;p % w _.....\ / ; m - B^ C " O BARRIC w'AcEEM e = H C ESS > = I"@o?
-:- q's., ENLARGEMENT OF POWERPLANT STRUCTURES
$ C?...
Q,g:: Y QO' M r POWER PLANT STRUCTURE LEGEND [ O' 7 FUEL SUILDING i g 2 DIESEL BUILDING e 3 CONTROL BUILDING 6 f 4 SWITCHGEAR BUILDING j c O s TURBINE BuitDiNG l k 6 AUKlUARY BulLDING e ! 2 7 REACTOR ButLDING f I T S REFUELhG WATER STORAGE TANit j 1 9 CONDENSATE STORAGE TANK p
\Q 10 ULTIMATE HEAT SINE ?
11 RADWASTE SUILDWG i 12 SOUTH GUARD STATION (been service bidg) [
%g g> j ff.
13 SERVICE BUILDING ( Q 14 SMOP AND WAREMOUSE ( 0 15 WAREHOUSE VARD 16 SALLY PORT 8
) 1 17 NORTH GUARD STATION L 18 WATER TRE ATUENT BUILDING t l 19 LOW VOttsME WASTE POND f
'Q f 2o TRAWWG raciuTv iwei PUGET SOUND POWER & LIGHT COMPANY } 0 f[ ;cgga"CJ',j',ous, 2
, eM C SKAGITlHANFORD NUCLEAR PROJECT ,
g a 54 n PAa"ao 'a - ' a' ei APPLICATION FOR SITE CERTIFICATIONI ; pp (/ 24 cOs rot nous' 25 L; NIT NO 1525hv LINE CPTION A ENVIRONMENTAL REPORT i i 28 UNif NO 1525kV LINE OPTION 8 l O g 27 UNIT NO 2 5256v LINE pg, #g 2B SUBST ATsom as PERCOtATiON ,0% ( j i ( Il SEWAGE TREATVENT PLANT SITE AREA MAP / 31 COOLING TOWERS Ep PUVP STRUCTURE i 22 SRioGE o po , tuni 23 R ADWASTE BUILDtNG te u ture if **g.pec ! N - FIGURE 2.12 Amen'dmenE 7
s/ ( ,m-l., < N ,,, l y- ,,, nsese wo l 3 . MfA/d A W N Y _ s is la /3 N l y HY }
~ - s.. %
, . . .. , . , -s:'-u'
, w-
- g. 9:96 6
/'s Ate" w -o e
au w&CN!?" ~~
)s 6 b
, o'$
a j- -- 1
, /
N. '2 lb s/ o i~1 g
- f, -ww/ e' w it'& n
,, -' iew '
^ '.r e a n-- t ,l 13 $g g 16
$ \ r os t) . *
- t '+ ,W Mffg4 C
~-
redu '
- / *, y rM ,loYov7 ass \ '
e or p t' o g TG7 ,/ f* 8 i %'t == 1
pP-ASC/ER 9/16/82 M*."" h 7-9 & r p.w w $# l l1 25 23
- b. g
'N x __
'N
\ ,
[ MEA G -- ~) , ,
~, gg
\ N . )
". ~ * \ 8 s . .ve, %
gmm 1 w ,
'heyr sw / #mW
{&
< ~ 34 35 s e-e, w- t
\ $I,E ww
( - s-w ~~T .. (
>j i 4 1 3 2.
l i 9 !D il s* tt*** _ gev' We m
# ##' 5*W- ** / M*4 * / ** r #
PUGET SOUND POWER & LIGHT COMPANY SKAGli1 HANFORD NUCLEAR PROJECT f*.I~a.<U
- "'t
$"4 #$-
APPLICATION FOR SITE CERTIFICATION / ENVIRONMENTAL REPOHT
! CENTERLINE LOCATIONS OF CORRIDORS FOR RIGHTS OF WAY I
FIGURE 2.1-3 (1 OF 2) Amendment 7 i I
y--:-...., . . . 1 l I l l l
*=amme asemeek Ofd .hene= k
/
r t~v .'
/P)Q* d / S **4 <Ak* e'W l W 9 M'M /b /smet
~ga
*\ 1 a <
i
% en s e.
% e*v /
, ), ,
s.~-; g~- - ' f' kg I f 4"nerws C MeV/ht" Q e- /
' ,i-^'*
W sb'w'W gn%enf nF s
/919 a9 tw9 O mtrere h asp h
? fr9n* f 49 /Po snann/m M&
<em-&m p Ne den, d. war e4,,,,,e ,' w
.mmem* *** M or nee
- 4e ee w
- w. '*en' H H sew __
vm/ m w . . .
-Q m :" h +
+ ir aSb er ama new e . - - - ,
mne meeg _x . _ . - i
,f
)d x fp e f
- -. ._ e, .. ,
\ ..
pr E sirr svestTEC }
,1r '/ ' f. l' r
- - -2+y- - -
.#27 %.
j ,. ; -i
, - ~2 e < = .- -
h J n. n. l
.<,. a / e Q~ :
Q p iI . %w ,'
.. s . ,3
, 33 '1 34
, ( ,,
h*
%.,, 8%E *w
==,_
'u _ _ _ _ _ - - ; 2 3
en
9/16/82 lS/HNP-ASC/ER
- 6 2,3 i
ffff4ff{. ' g} I e, j' 25.u s (Y U 'M " %
- __ E-?*T ran t4 2 h '1 I
, c J/
1 f w +
,g g' , 7l
, 4
=ma
;; ( ",N '
/g
- )\
_.O\ . - i z3 5 Yl
,,x ,/
u\ . b a .- A fp i3 hI p(V I l \
,t-j 23 '
f 24 '
, .r'}f r* , _
26 25 gM i %
~
' s O , m..
36 j "// l PUGET SOUND POWER & LIGHT COMPANY SKAGIT 1 HANFORD NUCLEAR PROJECT 35 - APPLICATION FOR SITE CERTIFICATION / ENVIRONMENTAL REPORT
= ='
i hw' , w- J CENTERLINE LOCATIONS i /~"%fE" OF CORRIDORS FOR 4 fl . afJd. RIGHTS-OF-WAY 1 <. 5- *w ~ '4 FIGURE 2.13 (2 OF 2) Amendment 7
S/ c==
" "^
zo <j " l $NDFILL l l d;: o o o l__n gsTy!1L_ 6'Og- - --~ oo !k 'I \ z. I 2M 0'NMW c30 l T 9) (I .
/L/) _ -
/ tJ \1 I A I C O po ,) EE '
at h
';;,:;~. L == ====. . ... .==== y =~~ == q";* ' '
Xj '*" i l " 1WTK Vl 5 - l UNIT UNIT C 7 % l 3 1 2 q PW l g i c o -
% f a a W
9
# & ln hg "3 o 59 {*% cg I
s # G O' bI I 3f+ p0 - lf s i?.r' sO* G
% s to c
$ W "Y?$~ns=N ----b;p )L-b o U gay g gou 6
D A i,'
#* f
=> O fg Y *% &
.Q o $$ 0 * % ,+#
f.)
=> 69 & sg &;s' N*,
' n & 1
} Vm
.do1h - x ,,+ / *%,% O n~
C
)
O ',#** b *; LEGEND ' p; .. . :. ?cs
~
s *% Primary Heghway ,,5 ch' a %
+k Secondary Highway h % c:p 't, l ught-outy noad CO 1 % 0 1 Milk a .
- =3 a Unimproved Road LES ND CA ED HE $ d
liNP-ASC/ER 9/16/82
/
lo #. o e g{" 1
/43 l r ,.
1 & bo I a w c_.
/_, 8 -s g zo I I
t # 2 6 g (p j FII C21
&z o y a v 7 a Si>% g7 C a 53 gy BARRICADEj
, , d'
- 547 p o'c * * *c o -
xa- ? n I w R gy ; C y r O h 2f O l" Y 00 0 ! 'NO Q$ ' 1 PUGET SOUND POWER & LIGHT COMPANY 0 ? SKAGITlHANFORD NUCLEAR PROJECT 4 a APPLICATION FOR SITE CERTIFICATIONI
- 8 ENVIRONMENTAL REPORT fo s #
osef
# SITE AREA LAND USE MAP 1N jh _ / FIGURE 2.116 Amenciment 7
S/HNP-ASC/ER 9/16/82 I;] 11 1 II Il r ,. ; r- -
.7t
.l. ..
.i. . ,.l... . . .
g.J,. ...
.l.;y.:,
O
, . . c. . ...__4 . , ,
. .t.t.,
.i.i.( m.,.
, .- .i. --
y; L. : . . r.. .... .i .,. .
.4 __ .p._-+
_: -.g.;._-j - -, . ,
.g. m .;. ! .i. .I_,i.i. . .
.j
.j,j j.;.i . !. - .-
.-r;7; i ,
p ,7 , .!.
. } ._._71 . l . l 4
.l.l.,. i- 1-l. .;
..l. .
,a_~.5 -
. +
-. ,t -
- f. . . . . .. .i.,
i
.j. .t .:
,j: . -~: _n_r_ .!.
m __ q .p.g.q l
- ,i / j.i. . .
- p. .i..
r f!
~....,...,.,..,,4
;. ;,i . ,' .~~ [1?ltf..L 4 s ~ ?.TNf ~V.D . n g
f;j- - p, t- , , , , q i n. -
- i. -
.- ,e ,,. s m
-F 7 4 .u g 4 ,, W, s ~ -x'
& ,: :~ R f 7
L
/ ~~ , , , .
& . y Q
- N 2x - l-M' W@ .L._- .K'g '
o$ y
~
' '~ '
f
- g. ,y mg- .b 6
' ~ '
9 @ L,
. ~
"" ~
cm
-=
. ~.
<a
- (l' a
+: ~
g - ge4,[ , 3u7 4,, . -.- ? v* s \
- ) ,. g . .
.,~
' Ag g f'.. .
s ,. 2 k. . . . . f,,
- a
-~ m . .
~
w .
~
g .9. . . . c. k, ,
' M. g>.; '....~. \ . . . ;'
~ *
- LU . d
.; 4 i . h.. .i..
.- r,-- - -1 7 8 *l ..
y
, ,a di
_ _ . . . ,., . . e/ oh
' 'P 4 7-. . p . . . , _ 8 _. .' 4 }q m : .....,.i.
t . _ . - .
..r ..s. ..'.
~~~_ _4, 9.l /<
l MANa0RD son.T sTE..WASHINGTON vets or THE
'* T'1 t y -
, ::..- - _ * . . . PUGET SOUND POWER & UGHT COMPANY
- . Z. _.
; ===;
. ." -Z: C'-
.~ ~ SKAG,IT / HANFORD NUCLEAR PROJECT
" ' ~ ~ ~ ~ ~
APPLICATION FOR SITE CERTIFICATION / ENVIRONMENTAL REPORT SO!L MAP OF THE SITE i l V AND ASSOCIATED AREAS 1 l SOURCE REF. 5 ECiUP.F,2.2 2 l Amendment 7
I S/HNP-ASC/ER 9/16/82 j
'N I ',,
N y
- 7. ".
5-I?{. i l
.. I 3
f PUMPING PMNT _= N f f \_ U S. GOVERNVEN} ' ; 7.. N
%q%3 y,y INTARE AND 0iScHARGE PIPEUNES
'y S
e-I ( [ JUNCTION ' a 3;, f N . . 1!! 4 i l
/: !
C) s- / 's
?.N. g l N (1 ?;t !
SITE BOUNDA p 's g/ ll' _ACCE_SS RAI f E US AREA I N0, _ NORTH ACCESS ROAD - 3; f tx y ( i C ES ROA Nfo A Eh, f ! N [ LEGEND 'Ns g
@ LONG-BILLED CURLEW N i
@ BURROWING OWL \ i
@ LONG-EARED OWL PUGET SOUND POWER & LIGHT COMPANY
@ SWAINSON'S HAWK SKAGIT / HANFORD NUCLEAR PROJECT !
@ REDTAILED HAWK APPLICATION FOR SITE CERTIFICATION / [
@ KESTREL ENVIRONMENTAL REPORT l
N SELECTED NESTING OBSERVATIONS ! o 2 NEAR THE SITE AND !
% ,< l , l ASSOCIATED AREAS DURING MILES JUNE AND JULY,1981 FIGURE 2.2-4 ;
Amendment 7 ,
S/HNP-ASC/ER 9/16/82 l Rt.1 5 O C
+<P+%
o ig:. e il Lu
$1 0 2 l
i s:. gl I . l l
~~-
gl MILES ; I [
$l g ;
. .i . !
l . l Rt.11 A Hanford Town, Site':::/,,.._f :. l !
---1
.U** '. ,.g" l 1_J
. i INTAKE AND d ,
DISCHARGE CORRIDORj: M Hanford :. I ;
- 9 Sand Dunes 'l:l S l !
E 'd:. W l i m i TRANSMISSION : ! 4( CORRIDOR ... r. , l
. - l l
. ;. g5 Ringold
/ Mi
( , E #WA I O X
= - ,
,,l ACCESS RAILROAD SITE BOUNDARYM I.... (**.**
,., j,. }
- 5. w .
.:g.-
$"jjj[ ! .., NORTH ACCESS ROAD L
': l
*,.4..J..t.. **. , **
.* 7,- j !
e
/ ..
a:: i
.* PREFERRED #
,/* SOUTH ACCESS ROAD d
*** ALTERNATE pf f h SOUTH ACCESS ROAD -
1, g ' j a e,# E 6
,2
/o+g d .. 1 n: 'o e
' i.,p)
.,)3 j '
I PUGET SOUND POWER & LIGHT COMPANY
/ AREA SURVEYED DURING F//////J RECONNAISSANCE SKAGIT I HANFORD NUCLEAR PROJECT
{ i APPLICATION FOR SITE CERTIFICATION /
$ FIELD CHECKED DURING RECONNAISSANCE ENVIRONMENTAL REPORT RIVER CORRIDOR - ENTIRE AREA SURVEYED :
g AREA SURVEYED AS PART OF D.O.E. AREAS SURVEYED ! LAND DISPOSAL ACTION : FIGURE 2.6 3 l Amendment 7 i
S/HNP-ASC/ER 9/16/82
$l Rt.1 O
(~'
+,' d+o
% 1I:.
ll w Ell 0 2
/
"I I i i 9 $l MILES j
[N
$I t 0
4M' I {
\, ,
BN 119 Rt.11 A Hanford Town, site , , .:g',::.
/ -
i^
/ h . q~ l f i
. of 1 -l !
o N INTAKE AND DISCHARGE CORRIDOR j; M Hanford
- . I (
l
- 9 Sand Dunes ~2: I t
's:.- F 1
. E l i
- ' l TRANSM!SSION !
4/ CORRIDOR I . - y : T:
~
E . l { I ;
.d. gE Ringold '
E. STOCK CORRAL
\ , / *..****
..** ,f !
f(*(*'. SITE BOUNDARYd
., ,! ;, l l ACCESS RAILROAD +
. f~h ,
~
h -{
,,4.... .,
+., NORTH ACCESS ROAD ;
.' +.
/ .
E
,/ PREFERRED l SOUTH ACCESS ROAD d i Y k E
+/ ALTERNATE $ g '
i SOUTH ACCESS ROAD y - o Oo $:: + [ .%
~ ~
l<:5 . 4+ />: &
- g% 0
.kk f
- w >
PUGET SOUND POWER & LIGHT COMPANY SKAGIT 1 HANFORD NUCLEAR PROJECT i APPLICATION FOR SITE CERTIFICATION /
" U" " ^' O SN 26e IDENTIFIED ARCHEOLOGICAL SITES l FACILITY CORRIDORS ARCHEOLOGICAL AND HISTORIC <
SITES WITHIN THE SITE AND ( ASSOCIATED AREAS FIGURE 2.6-4 Amendment 7
S/HNP-ASC/ER 9/16/82 l N RE. . . - '
'!:1 O :.;:,
MILES l_, 1 1
- HANFORD NCRTH l 1 DISTRICT i Rt.1 6l El
<'g ti:.
%. $1
~
' HANFORD!!
ISLAND SITE llI
, I Rt.11 A Hanford Town, site E ,,7;. l
]' w3. 7, INTAKE AND I j -
11 g DISCHARGE CORRIDORj! -
- 2 ISLAND -,
l $ $$$E " . S / .I o Q y -- lb .... *.... , ,l AD SITE BOUNDARYM /.
** ~
If 7 _f ., NORTH ACCESS ROAD 5. PREFERRED E SOUTH ACCESS ROAD d
,... g
$"H AEESS ROAD WOODED -
o i,g ISLAND :
; T 7 ' DISTRICT -
I8
'*+
l h a PUGET SOUND POWER & LIGHT COMPANY l l NATIONAL REGISTER DISTRICTS SKAGIT l HANFORD NUCLEAR PROJECT APPLICAT NFORS C CATION / h NATIONAL REGISTER SITE FACILITY CORRIDORS NATIONAL REGISTER DISTRICTS AND SITES FIGURE 2.6 5 Amendment 7 l 1
S/HNP-ASC/ER 9/16/82 r' =".^<*4% ' 1n
}J ce
,I
\L !
\
.3 f h WHITE ,1 i
l r- BLUFFS i e--- F r U S Fl H WAHLUKE *1 i
,[~ & WILDUFE SERVICE WILDLIFE l
.-' WHITE i f' BLUFFS RECRE AREA ATION ('
J
, , , , , , l TOWNSITE ,
s g f e f # +, HANFORD TOWNSITE f
* /
j [ GABLE BUTTE GABLE MOUNTAIN / )
. , . . . i
...g ....
K l p s D6sen. age Corridor %( s], I Trennenession '
% * . \s Sh HANFORD }
,e,,, 5AND DUNES Site Boundary ,,4 8,,,,* %(. . . -----e Access namond
{
/m/
- wo,in ace Ro., I ARID LANDS ECOLOGY RESERVE / p,,,,,,,a
[ j
, soutn Access Road j l N 1' . ,n.,e soum acc
/ Ro.a ;
I
* , i
\ RATTLESNAKE i MOUNTAIN j q- ,r I c . ,,- ,
N. N L
!!'? q RICHLAND
..a .
l t h' ! I i L l ' t k INDICATES LOCATIONS OF PUGET SOUND POWER & LIGHT COMPANY NATURAL AND SCENIC RESOURCES SKAGIT / HANFORD NUCLEAR PROJECT
----- FACILITY CORRIDORS APPLICATION FOR SITE CERTIFICATION / .
ENVIRONMENTAL REPORT i l pg NATURAL AND I V) n SCENIC RESOURCES l l> FIGURE 2.6 6 f Amendment 7 , l
S ( l' 28 T 2s 28 27 l ,
\ l o a i i LJ .
F 4!
\
l
,+ \
- - 1 y ,, ,~
m\ j 22 23 . \, t i i
=
14L 12'
- _A.y
" ' [g_-_ .-.
. t!. ja :. [ _ . _- d_ .C if f j/'
E@ f is TR g [ ' a _ _. p _ _ t L 3 41/ f i[v { _ _ 3 "7 UNIT NO.1 l[ Ca 1 4 5 b 1 4
'l g[
?
'J q A JO '3 s sd A
) _
!I u ir 1 *r l-li 1! a m (if lj =d ,
L,.,.! l f ~ l f ll . _ ._ ._ ./.,4 , @
- u__- . .=._:= _
l 23 J D ( _ . _ o o u 31 e i ALTERNATE SOUTH ACCESS ROAD (
/HNP-ASC/ER 9/16/82 f
b I s s c 1 FUEL BUILDING 2 DIESEL BUILDING 3 CONTROL BUILDING L 4 SWITCHGEAR BUILDING [ 5 TURBINE BUILDING 6 AUXILIARY BUILDING F 7 REACTOR BUILDING 8 REFUELING WATER STORAGE TANK
> 9 CONDENSATE STORAGE TANK
, 10 ULTIMATE HEAT SINK
+O 11 RADWASTE BUILDING 12 SOUTH GUARD STATION (below service bldg) 4 ke 13 SERVICE BUILDING 14 SHOP AND WARErlOUSE RAILROAD _AO 15 WAREHOUSE YARD f,
[ V 16 SALLY PORT 17 NOF5TH GUARD STATION r - -- 18 WATER TREATMENT BUILDING ( ! 19 LOW VOLUME WASTE POND L ,( h'j r
,1 20 TRAINING FACILITY (ft.:ure) 21 CONSTRUCTION OFFICE 22 CONSTRUCTION WAREHOUSE I t. . 23 PARKING l b '
24 CONTROL HOUSE 5 25 UNIT NO.1525 KV LINE OPTION A
,..l UNIT NO. 2 26 UNIT NO.1525 KV LINE OPTION B l 27 UNIT NO.2 525 KV LINE J= 28 SUBSTAllON 29 PERCOLATION POND
" 30 SEWAGE TREATMENT PLANT 31 COOLING TOWERS 32 BRIDGE (topowerblock)
"lg *
,__j l 33 RADWASTE BUILDING Ifuture-if required)
"_ 34 DIESEL FUEL STORAGE TAN KS (underground)
; o too rm 400 eocr NORTH l
! 31 t l PUGET SOUND POWER & LIGHT COMPANY SKAGIT / HANFORD NUCLEAR PROJECT T APPLICATION FOR SITE CERTIFICATION / PREFERREDSGUTH ACCESS ROAD ENVIRONMENTAL REPORT PROJECT STRUCTURES AND FACILITIES r SITE PLAN - UNITS 1 AND 2 FIGURE 3.11 Amendment 7
_.___mae S/1 m _ i, h
'* g h[
i s i i.p3t s .- 4
..s
' q. . -t
. .n . -
%N A-s ys g #
g %
' gi
~s i %
=.
.~-j...... ..'.....'l..
8 9=***4 g
%6'x s
We@vesp 'N
.- ' .~N M *% e?.' _ , ,. ! '
,,,,f
- 9. - y-s . .
, m. . . . . . , .
( N ; ' %, [ }., [ ,,' N.
, v-f ., m a s ,i '5e' .-.
,\ xq^ x(s
.' by 500k 3' V " '# ,.
'i,m - <J oS-.,E,ne g..
. - . . ..%...... g, n. . ; n ., 1_;<
- y. %: s.__x*w R
- 'MN w .,m1..
xi a , W 'N.4 x. i -f \ N.. , . .' >l . A .l ceBQHARGE PIPELyGE M'. i t o. , r
'y, s 3.g, Q,m ..
.L %. ,
- .a. cn.o,,
u si,- .o y _ _ _ _ _,_, _
. ,r .____f___.___,_su___-, . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ i.. ___g _ __
._ . . i i m I -,
?. * ..
). l l * , _ k E
y A. ,. 7 u,/ a . *
- 4
. b y ! 11
- , h
/ .
s a r i l N,y
' C ,,,, I .ss y: ~
L ~ ,i :g e T
- . - 's3f.'. ._ ,*.ta_ _ ____'h________.-______-_---_---p,-__ _ - _ _ _ , . _ 1 -
i i - 4,-
,ws .w.. n.g ' 4 . '
i3 33 33 i 37 i ge , , - yesm " - - -- t 4 ._ y 33 ,
,g ,,'-
f s
? ':
f
, ~h
- n. . ,
*s
, .g rf
$ g% <$
c'.t*d..
.t___.,____ .J ~g I ' . M.,.48,lai 4y,,, M--
f3,, --' ---'-. L4___.*'. .. * i
'~
A
% D;Y,p Q3M . 'N;
- .fg i w
* ,, M TER b' Y Q)ke ' stM Y '
- p. 3: ' e ,,
'q j }g
,(*fn ,
to ..& ', ' 1 . za ,a / to
- :ykN -
} {
t - EX AREA '~ l // l PIPEUNES \ *
., J_, .
l
, m __ . .Y__ _ __ _ _ _ _ ' _. _j/ p / - - l__ y_.
_.',__ , . i
, 4_ , ,
A F, l,__ 8( _. .__'_ ____p_ _h0ARYM_ 2 SITE ' es
; k. _-f w ?- -, ao U,g.l j
u m_ w
^
5 g.; ,%-e A - . . .. ,j ga o h. .. 4 j_.p= c ;_n. ; p.9 w< .
. I j
4 AM .i p .4 ,4. f ,A p 4 ;g ,. s 3; , s ; _. g, W ,
\,,
,- .-4, e,lg .,
, ^,,.} __._X. f ',_
't
~
- I
. i AREA g<.
'.., p.,.- s - - - .
><-gw ,,. -Is .' .a4 2.6.A _P-T,' i -;
s h <,'L'" [ > -
-I
'tc." a ; s<. , ,y 4.~
,- r, c) 36 7 \ 36 ;t393 ,J W
_.3} d ' N.J
'a AgCESSMILRogp 4 o w 4g rP , ^,M c, y r, ,
4* 34 * - g e ' 'h g. M,. j . y Qpyg g;3.j . yg n
}. a gg .
,,, g l
, j-. gr,,
D. . _ ' . :
./mt.- .. -
_ [ asa' b n 48 nxn tc y
.../ .-
--+J- i, o
-t
.ey.4 y to %
s. A
,. s 4
,l &r w 1, .a , . ,c.
m.
' .*w< , %e
..; o
,f, c
i
- c. . e-
, s .
.. -;' . ,c-, e' ' A
- . sj ;
.so.uG,#y.s
. gj } . . .k c -
lt'yJ2
$ .en s n .to '# , . 11 ' ^W, 2 .'c-J - **
^
<*"- " Q, y 'j.
J ~ i ,,,,.QA:a/ 4}}f , * 's .
. %, ~, ;
i
, a =y ll'_m. 's. , - - ,x [-s *.Wp gy 6
,^
De . Q, _w.,6 7g _%y; "6
'f' 9
~
'I #
71
4' pa /
j , , y e 6'. Y'e' Q -r # i 4 ~ty,L/
' p% . ,,#qz.-
, w 4o. c[.,/.(9 x.#'.rc,3]: - 19 i, .,- , A, 2
.> $8.g.4 fgg'
~r.,;
a ,y ,- . :
,efM-f'
- y: ,. cyw.s, y *g*9 [f>. vy-d ,
, , -A. , . , o, ,x i
g { :i FFTF, ' u.. < c. , n -; - , 1, .,, ,. Lb_ _ . '._N :- P- . II. ' _-' I-II' O ~T #. ib I b..,_I(' E S . _( . _ f. , t f i i Ub i I l _ __. _ __ _ _. . . - --__._,,._._.______..,__,.,_...._...._..___.___..____m.-.
1 [NP-ASC/ER 9/16/82
~
l- "Q . .Mbs , 2
.1 +
t 1 3 .,' s s s
.- t N 1 ;-
s '% h t '"
. N p>. Ak
(, F - I '
'o .
- 0. 'A x N p34'd fy p i4(A )D;_g
\@ Os g k i S' j h, - a
'-. : g
?",
M^ ~.p " - c; ,$ L'p: 1 @.. RO ']ye& e.
't' .g g 7 ' : * 3 v" f
.; p n;.'
Q ' , f:;.g L~ /J g,y?+.; q ,,,, s y ,,ihs p'Nh'w,3
~
[4 ; ,, y v1
/
f
",~.~ l, p N, M x ';,4 j c ' -
% gt. a# ' -
- i. 2fSi \ a, ps -n ' .p w h, ...a Gn:
Me, $h'%:w;m[i. j- h)- ,T;.['i 6 ' Oi x
.? ..
? ';\ w w.
r.W . k ~' kIM Mak\ '~Jw,q(Nb 'M p
-g* h db ,
e ; WMA I.ao'{f' %, 'k h$$GGQI Qd g,/f 4:e gy &:,t h ~.:- w , w %w$ pyf,.-MjIh,\t -.
'y 4
~ . u.: -
j gg# '%e . -p. J' 9 NMl'n n - mf;S R wpr.f;)/ icy; m. 4 3..),i : % qtsu f f ,., 1,m y ' agk'gg 7. s Y L.; p,f()[j%
. .~~. es Sglp,-m#
L y e 1.- - ,t ; "I y,t ' ag ~k A<QQ. ;
'a-9 ' suesTATION'.
w- iO* ? " j._c_L ) J kl,1
~
i ]p,( (, <gh. j q- _~
+-
) 11 p v Ee N
Q" % 35,'-) ,$ 'cY : gj4d t N -Ji MlQ('h.Mj$,e0ji) f j2 s I) ;, ,N @6.M(ilN)h;,0 . jd MILES $$ N bc1.. -d'5.h't.:rl,4 N i
* ^
Li 5 :- 4 pg+, " ~ S, '.'X. ~y i s ('oP i s'; Ao' i s - jId
'x[ &'
- ; g. ,' lj f.g 4[- ~.
-2 l 7 ,1 5 Q) a
$/
,f .J?.to Mf I
' { M],?M if s.f.O [$ak q j PUGET SOUND POWER & LIGHT COMPANY f / r e
< . '! .N@y,,
jO, , W SKAGITlHANFORD NUCLEAR PROJECT d( ry.p] ..- {, ~2 o c/
} APPL.lCATION FOR SITE CERTIFICATIONI y
"-/;)qc>-., s t, ,
d,Y,-
,[ ENVIRONMENTAL REPORT
' ol)
%/ '
fi t M\ ,;g , b Pr 16 2# 15 14 $.,
- A ph . 'I ,f ll 1 l
Y_ _. - ) k p. l""\'\no* 1),lf,((. N 3 TCOOGRAPHIC FEATURES IN THE g[o. - 5_ ' . ;. VICINITY OF THE SITE AND ASSOCIATED AREAS FIGURE 3.11a Amendment 7
S/HNP-ASC/ER 12/21/81 been constructed at the Hanford Reservation. Presently (~')) x, Washington Public Power Supply System (Supply System) Nuclear Projects No. 1, 2, and 4 are under construction. The principal areas of construction activity on the S/HNP Site are shown in Figures 4.1-1 and 4.1-2. The land area and acreages to be disturbed during construction are listed in Table 4.1-1. An S/HNP construction schedule is shown in Figure 4.1-3. Site preparation for the S/HNP is presently scheduled to begin in 1983, with the first unit complete and operational by 1991. Construction, completion, and operation of the second unit will follow the first by approximately two years. Table 4.1-2 is an estimate of the S/HNP Units 1 and 2 construction work force. Figure 4.1-4 shows total manual manpower requirements by craft during construction for both units. The impact of construction on the sagebrush-bitterbrush ecosystem will be primarily confined to the acres converted from biological productivity uses, eg, buildings, paved parking lots, outdoor storage, roadways, switchyards, etc. This change in land use is expected to result in the displacement or loss of a few birds, mammals, and reptiles, g- and the loss of net aboveground primary productivity of g~ about 1,000 lbs of dry matter per acre per year. None of the lost or displaced animal species is considered to be rare, threatened or endangered by the U.S. Fish and Wildlife Service. The converted acres have no ecological 4 features to suggest that they have unusually significant value as breeding grounds, or unusual significance in migration pathways or production of unusual or significant food items as compared to adjacent acres. Bared soil can be expected to create local areas of dust at any time of the year. Most of the discomfort will be borne by construction workers since the Site is remote from residential populations. Construction traffic is expected to cause some road kills of jackrabbits, reptiles and birds. It is also expected that a few deer will be killed by traffic, particularly night-time traffic. Many years of experience and much data concerning the effects of construction on the environment and the ecology i of the area are available and have been considered in Site l construction planning. l l V 4.1-3 Amendment 4 l i
S/HNP-ASC/ER 9/16/82 4.1.1 LAND USE Much of the area within a 15 mile radius of the S/HNP can be described as sparsely populated, with the exception of Richland which has a population of 28,500 and which is part of an area of urbanization which begins about 10 miles south of the Site. It is estimated that the Tri-Cities area (Kennewick-Pasco-Richland) includes 35 percent of the total population within 50 miles. There is no resident population within 5 miles of the Site. Thus, there will be no significant adverse effect on the general public attri-butable to the construction activities. Existing conditions at the Site have been thoroughly investigated and recorded. Geologic, geophysical and soil investigations have been performed. The construction program is expected to encompass approxi-mately 7 years for each unit. During this period the g problems of dust, noise, and other effects of the high 4 level of activity attendent to any major construction site will be evident. At the conclusion of construction, restoration programs are planned to return those areas not landscaped or utilized for other activities essentially to their natural conditions. Highways, railroads and communications already exist on the Banford Reservation. However, 4 miles of access railroad will be constructed to current Department of Energy stan-dards to move materials and equipment to the Site durina construction and to transport fuel and other materials after the S/HNP is in operation. Maintenance for the rail-road facilities will be provided by the Department of Energy. Rail transportation will consume less fossil fuel than truck transportation, and will reduce truck traffic. Railroad shipments will be delivered to the Hanford Reservation by Burlington Northern Railroad. These ship-ments will be delivered to the S/HNP by DOE-owned railroad equipment. As shown on Figure 2.1-16, two Site access roads, the North Access and the Preferred South Access will be constructed to current Washington State Department of Transportation standards for Primary Highways. The North Access will be constructed from the east side of the Site to Route 10 and the Preferred South Access will be constructed from the 7 southeast corner of the Site to Route 10. In order to avoid impacting traffic density on Route 4, the Preferred South Access and Route 10 will be used for construction workforce access to and from the Site. Maintenance for the two Site access roads will be provided by Puget or the 4.1-4 Amendment 7
S/HNP-ASC/ER 9/16/82 i 1 l Department of Energy. An alternate access road, the : Alternate South Access, from the southwest corner of the ' Site to Route 240 had been considered for construction workforce access. However, DOE advised, in an April 15, 1982 meeting with the Applicant, that it will require use of the Preferred South Access Road instead of the Alternate South Access Road shown in Figures 2.1-lb, 2.1-2 and 2.1-3 , l and that, regardless of whether the Project is built or '
, not, DOE will improve Route 10 by bringing it up to State 7 i l highway standards for a two-lane road. Therefore, the Applicant will be using the Preferred South Access Road. j In ASC/ER amendments subsequent to Amendment 6, Alternative !
j B will be referred to as the alternative containing the - Preferred South Access Road and Alternative A will be referred to as the alternative containing the Alternate South Access Road. Traffic impacts discussed in Section 8.3.10 will not be significantly changed. l l In addition to these Site access roads, Puget is consider- 4 ing improvements to State Route 240 from its intersection i with Route 10 to the Bypass Highway and intersection < j improvements on the Bypass Highway. 7 ! 1 ! ! The road system in the Tri-Cities area has proven capable 4 of handling traffic during the previous large construction projects on the Hanford Reservation and will adequately 4 [ serve the S/HNP. Additional information on transportation is provided in 6 i Section 8.3.10. l Because access to the Site is controlled, recreational l l opportunities do not normally exist at or near the Site. I While the river is open to the general public up to approxi- , mately 8 miles north of the Site, public use of land areas within the perimeters of the S/HNP Site will be nonexis- i tent. On the average, 1,500 to 2,000 people presently visit the Supply System Hanford Generating Plant No. 1 each year. Each visitor is badged and escorted and appointments 4 4 are required. Identification badges will be issued to all l regularly assigned Puget personnel and contractor per- l sonnel. J i Earthwork, involving excavation and fill activities, will i begin after clearing and grubbing. Calculations indicate l that approximately 6,865,000 yd3 of material will be I . excavated during plant construction. Approximately l , 3,355,000 yd3 of this material is unsuitable for reuse as 6 , fill material and excess excavated material will be !
- disposed of in the spoils area located within the Site '
N 4.1-5 Amendment 7 ;
F S/HNP-ASC/ER 9/16/82 Boundary south of the principal Plant structures (see Figure 3.1-la for locations of borrow and spoil areas). 6 The balance of the material, 3,510,000 yd 3 , will be used as fill for structures and other work. Because the soil in the Site a ea is porous, no significant runoff is expected. It is expected that all refuse or debris will be transported to a disposal area and covered with earth backfill; however, if permitted, some construction debris may be burned. Blasting for excavation work is not anticipated at the S/HNP. Should blasting be required it will be in accor- 4 dance with the Guides and Specifications for Military and Civil Works Construction, CE-203. Final yard grading, roads and landscaping to enhance the appearance of the Plant will be completed at the end of the construction period of each unit. A batch type concrete mix plant will be erected on the Site with storage facilities for gravel, sand and cement. The l6 batch plant will be capable of a continuous 24 hour rate of production of 150 cubic yards per hour and will have a peak capability of 200 cubic yards per hour for 8 hours. An appropriately sized-collecting system will be provided to prevent emissions of cement, pozzolan, or dust from any 6 part of the plant to the atmosphere. Emissions from the batch plant will conform to the standards of the Benton. E280.01 Franklin-Walla Walla Counties Air Pollution Control Authority. Appropriate ductwork will direct air from all the producing locations into the dust collecting system. A power driven shaker will be provided to prevent build-up of dust particles on the replaceable filters. Hoppers will be provided to collect the accumulated dust in one location. Provisions will be made to control dust from aggregate during stockpiling or rehandling by a sprinkling system or other methods of control. Approximately 445,000 yds 3 of concrete is required for the S/HNP. Gravel and sand will be obtained from gravel pits located in Sections 22 and 27 of T13N R27E. Existing rail l facilities may be used to transport the sand and gravel to i the S/HNP Site. Stone crushing equipment, conveyors, grad-ers and loaders will be used in the gravel pits. Stock- 4 piles of sand and gravel will be provided for a one-month supply. l l Cement will be delivered to the cite in bulk in water-tight carriers and unloaded by weather-tight conveyors into dry, weather-tight storage bins which are properly vented. O 4.1-6 Amendment 7
] S/HNP-ASC/ER 9/16/82 i i Construction water will be supplied from the Columbia River ) via a temporary intake, and the permanent S/HNP discharge line which will be installed early to serve tnis purpose. 4 l
; Prior to installation of the temporary intake, construction water will be supplied via tank truck. No ground water 4
l i i i f i l i l i i 4.1-6a Amendment 7
- _ ~ .,_...__. -,.- ..,_-.,.. _ ,._ _ - _ - _ ,.. - ,, .. _. . _ . _ _ _ _ . _..__ _ ___.._____.______
S/II
~-
- pm m N___.._
I _ _ _ il _ I. _. i LAYOOWN AREA SUS $f AfiON LAvDO h N
,.-X N pecao ,
, _ _ - ,,,' ( P( AMANf h? R gn '
l E 9 ',A
C, C08sSTRUCT10N RAEJtOAD -._--- . ~ ~
( -,
- ~d M '
Nd l
\~ . , _
ei 2 m us
\,/ \,.
j
.]
Nc^ I" N N 'O 2 4 V, 7 ss (- - l N ,
\/ \ E k' %
1 "NM g /\ ga k U g g,0
/Thesmo E J -'
\
l 1 -
\/ /t 22emm6
\'
$ ;, R: ' \' C g N' - . N 3
% N j'yQ'Se gj 'hP g'M{'s I,g. " .
I'5'; '.5.E w l 3 i e a e 1._
,s . i r' i __,__h.
O. .
," N.
4 y I \ l 'N'
" V l iP ' /
' lLH e
\l l
+ ;;t _ _y m__. J._/_. _
NE ,e PERM ANENT ROAD \ __ Y Mw.3 t yn-l e x s T
,s sg
)Q d' yN' y'%
LAvo0wN w
^
l <
- s -
,, _1 I
l
\ CONSTRUCTION ACCESS ROAD % -
+f~ .
-4 4 + k l i i i l
IP-ASC/ER 9/16/82 1, ,N - n I ,_ __ MEA L80SeO:
/ S 1 N W MEMOUSE JM 2 CONSTPUCTION OFFICE NT . '
\ i A NOtt MANUAL PARKeeG UNITS 1h2. 400 CAAS hO g s \ B CONTRACTORS OFFeCE TRALER AREA C CONTRACTORS NOft MANUAL PARKmG. 3D CARS
\V j ' y/ O CMLWORK AMA N "
# / E MANUAL PAMessG AAtA x\ . '
F SRASS ALLiv$ w G TUROWE GEssERATOR WOM AAEA g ACCESS RAtitOAD M MECMANICAL WORK AntA y J ORYWELL WORE AREA 4 E ELICTRsCAL WORK AAEA
=
[_ j u /
/
%N L esSULATIOes WORE AAiA ti 4 y M CONSTRUCTION FAOUTits 90 FIELO ERECTIO TApeK WOR ( AREA Il I O seSTRUMENTATIOes WORK AREA l <DDDD P tmER PLAft WOma AREA 4
I /. Q CONDENSER ERECTION WORK AAtA lg g f5 5
% g g S $EA T TESTINGLABORATORvWORE ARIA g 2 g g U SITt PREPARATION WORs AREA li y v ACCES$noADPAvwGwOmav6A
- i. $ W RAtROADCONSTRuCToeWoma AncA I 3 6 x LAvDOWNcMANuAL PARuseG FOR unit 2 e LATER OAiS E
i i( g i( I 3 8 ao_> 2.maa. E AaCI*FJ'U T !" ""'" """ ""^*' "* i is'O*"l'E R'E74E'#1^."ETN%ttS""
"*"'^
/
parade l S gc, c PUGET SOUND POWER & LIGHT COMPANY g, SKAGIT / HANFORD NUCLEAR PROJECT t APPLICATION FOR SITE CERTIFICATION / ENVIRONMENTAL REPORT
.e. CONSTRUCTION AND I
.' .e, , ,
-*~ TEMPORARY SITE FACILITIES
~
FIGURE 411
, 1 Amendment 7 !
1 S/HN P-ASC/ER 9/16/82
-s -
6
".'.O , .
4, I
'\
A ' PUMPING PLANT T ;
' " . k.
L _ -. . _ _ . _ __ \ s- .. s -) -.., NU S. GOVERNMENNT ,+<q k0 4 UNCTION'
'\),
gay \ r
. i k
'2-f- 69 KV DISTRIBUTION LINES h
-::N
' (TO FOLLOW INTAKE AND Ti,. g.}
ASHE-TAP TO DOE 'N 8. I
'4
'k
~%,~}Y b NMIDWAYHEWNO h'2,, 230 KV a#'tpo %-
O ,,,
%%to
'h/-
' .; ,fp
%.h
.?;;
y ACCESS R AILROAD N:?, @
':- SUBSTATION l
S/HNP .- PREFERRED SOUTH ACCESS ROAD y 0 g 4
.c i NORTH ACCESS ROAD
' %"?o 2
& [.
\'x lk 1 i
*s s t9[ !
PUGET SOUND POWER & LIGHT COMPANY i SKAGIT / HANFORD NUCLEAR PROJECT ! APPLICATION FOR SITE CERTIFICATION / I ENVIRONMENTAL REPORT l l 1 i t N se xv oisTRisurion tiwes TO PUMPING PLANT f MILES ' FIGURE 4.2 2 i l 6 Amendment 7 l
S/HNP-ASC/ER 9/16/82 i I l 50 dBA l l - l g
, I
-- i ,
l 55dBA
~ ,
x I Q 2d l
,-._a6b .. - --
I l
- 1 L, 2 w
__. x l l r ~ F%@<s
. i l !! I
$ / w# = il. 4_ . . ' ,
I l I 60 dBA L.3.k q 0t i,
..,jij l L Tl59,Ei _BI9 ._l I I l I m --
m -. n, gJ===w, l [ I N i I 000 OD. 1 l Q l b:= " O O ""=:= SITE PLAN - UNITS 1 AND 2 l g I m T , I I 60 92 dBA l l l l I I I I I l l 1 I t_Ss s2U.e_R.2_ _ __ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ l PUGET SOUND POWER & UGHT COMPANY SKAGITIHANFORD NUCLEAR PROJECT APPLICATION FOR SITE CERTIFICATIONI ' ENVIRONMENTAL REPORT I DAYTIMEINIGHTTIME i O OPERATIONAL NOISE SIHNP UNES 1 AND 2 ; f FIGURE 5.61 Amendment 7
S/HNP-ASC/ER 9/16/82 l l l To select representative atmospheric dispersion value at l4 i s the Exclusion Area Boundary and Low Population Zone (LPZ) l5 ' Boundary, X/Q values were determined using direction independent methodology per Regulatory Guide 1.111. This methodology, although sector independent, gives realistic estimates for the Site as a whole. The 2-hour X/Q values were ranked without regard to sector and an overall cumula-tive probability distribution determined. From this distri-bution, the value which was exceeded no more than 50 per-cent of the total time, was selected for the realistic esti-4 mate. Values for longer time periods (ie, 8 and 16 hours, l and 3 and 26 days) were determined by a logarithmic interpo-lation between the overall 50th percentile 2-hour value and the maximum annual average X/Q value over the 16 sectors. Input meteorological data consisted of joint frequency distributions (JFD's) of hourly averages of wind speed and 4 wind direction by stability class. For computer modeling purposes, twelve wind speed groups were used to give good resolution at lower wind speeds (Ref 38). The annual JFD with the standard 7 wind speed groups is shown in Table 6.1-7. The JFD's were based on two years of data collected at WNP-2 as described in Section 6.1.3. Occurrences of calms and variable wind directions were distributed by direction and stability class to the lowest wind speed group of the JFD's. Calms were assigned a speed one-half ( s of the threshold speed of the wind vane. Winds were based on observations at 33 ft and stability class on observa-tions of delta T (245-33 ft) in accordance with Regulatory Guide 1.23 (Ref 39). 6.1.3.2.2 Short-Term Dispersion Estimates The realistic X/Q estimates at the Exclusion Area Boundary and LPZ Boundary for a hypothetical accident are presented 5 in Table 6.1-8. The maximum 0 to 2-hr value at the Exclu-sion Area Boundary is 2.8 x 10-5 sec/m3, and at the LPZ is l7 4.7 x 10-6 sec/m3 l5 The realistic X/Q estimates as a functica of distance are presented in Table 6.1-9. These are sector-dependent 4 values. The higher values are to the SSE of the S/HNP and the lower values are to the W. O d 6.1-15 Amendment 7 i
- , , , - . ,, ., , , . - . . - - . _ - , , - - - - - - . . _ , . , , . , r,- c-- ---,-,,-,a-,.-- - , - - - - .-,~ , ,,
l S/HNP-ASC/ER 12/21/81 l 6.1.3.2.3 Long-Term Atmospheric Dispersion Model This section describes the model for atmospheric dispersion i estimates applicable for long-term dose assessment. Disper-sion factors (X/Q) were determined using the methodology presented in Regulatory Guide 1.111, Rev. 1 (Ref 37) and the NRC computer code XOQDOQ (Ref 40). The calculations were made for the Site boundary and at the standard distances out to 50 miles. All releases were assumed to be at ground level. X/O values were determined by: gyjg) , 2.032 y nij (6.1-4) x ij N12 juij where (X/Q)g = the average effluent concentration,X , normalized by source strength, Q, at a downwind distance, x, for a given direc-4 tien, D (sec/m 3) x = downwind distance (m) nij = length of time in hours of valid data for a given wind direction, D, wind speed class, i, and atmospheric stability, j N = total number of hours of valid data Szj = effective vertical dispersion parameter (m) for stability class j uij = average wind speed (m/s) for wind speed class, i, and stability class, j, for sector D. is calcu-An effective lated to account vertical for building stability wake parameter, effects E23, as follows (Ref 37): 1/2 A zj = a zj + H_2. (6.1-5) _ 27r _ O 6.1-16 Amendment 4
i P S/HNP-ASC/ER 9/16/82 ! I
) TABLE 6.1-8 REALISTIC SHORT-TERM CHI /Qs BY SECTOR FOR S/HNP AT THE EXCLUSION AREA BOUNDARY AND THE LOW POPULATION ZONE f
[ 5 [ Location j Exclusion L Accident Area Low Population Zone [
- Period Boundary (4 miles) 2 hours 2.8E-5 4.7E-6
- 8 hours 2.0E-5 3.0E-6 16 hours 1.7E-5 2.4E-6 7 72 hours 1.2E-5 1.5E-6 I (3 days) 624 hours 7.2E-6 7.8E-7 f (26 days) j Notes- l
- 1. These realistic Chi /Q values (sec/m3) are applicable ;
for a ground-level release to a ground-level receptor, ; based on delta T stability class category and include l plume meander and building wake effects. The values 4 ; are sector-independent 50th percentile Chi /O values. l
- 2. Based on WNP-2 meteorological data f or the period ,
April 1, 1974, to March 31, 1976: 33-f t wind and delta } T (245-33 f t) . I r i l i i f Amendment 7
i S/HNP-ASC/ER 12/21/81 TABLE 6.1-9 Sheet 1 of 10 REALISTIC SHORT-TERM ACCIDENT CHI /Qs BY SECTOR .FOR S/HNP AT STANDARD DISTANCES Distance: 805 meters Receptor Accident Period Direction 8 hours 16 hours 72 hours 624 hours N 7.4E-5 6.5E-5 4.8E-5 3.lE-5 NNE 5.3E-5 4.7E-5 3.6E-5 2.5E-5 NE 4.0E-5 3.5E-5 2.7E-5 1.9E-5 ENE 3.8E-5 3.4E-5 2.6E-5 1.8E-5 E 3.5E-5 3.lE-5 2.4E-5 1.7E-5 ESE 6.2E-5 5.5E-5 4.2E-5 2.9E-5 SE 7.8E-5 6.9E-5 5.3E-5 3.7E-5 SSE 7.8E-5 6.9E-5 5.2E-5 3.6E-5 S 5.8E-5 5.lE-5 4.0E-5 2.8E-5 SSW 3.7E-5 3.4E-5 2.7E-5 2.0E-5 SW l.2E-5 1.2E-5 1.2E-5 1.2E-5 WSW 9.4E-6 9.4E-6 9.4E-6 9.4E-6 W 7.6E-6 7.6E-6 7.6E-6 7.6E-6 WNW 8.7E-6 8.7E-6 8.7E-6 8.7E-6 NW 3.6E-5 3.2E-5 2.5E-5 1.8E-5 NNW 7.lE-5 6.2E-5 4.5E-5 2.9E-5 Notes:
- 1. These realistic Chi /0 values (sec/m3) are for a ground-l level release to a ground-level receptor, based on
! delta T stability class category and include plume l meander and building wake effects. The values are sector-dependent 50th percentile values.
- 2. Based on WNP-2 meteorological data for the period April 1, 1974, to March 31, 1976: 33-ft wind and delta T (245-33 ft).
- 3. Standard distances based on Regulatory Guide 1.111.
Amendment 4
sf n ,-
' @ 20 19' CENTRAL l LANDFILL 2 l
l 1 1 22
- e M 520 f.oer: l
^
!r !.
%j#e __ __,
-{EST WELL
% l . .. .. l c30 T - 3 Ma ~ '
l l l 2 M-
- I -n 1 A 1
~ '
g [SlHNP SITE BOUNDARY N 3 o p0 18 = mm wh um sh,ay a $ [%;9****= 52 3
= c= ==== =
9
,,,s***** **** ==s***
===='
(Mb
+ i 28 I
*% e 17 I -
*+, h l Rh
{" UNIT UNIT E et.. f m US u, 5 b "3 # #
*\s c6 15 g,8' e
- 38 47 9o o $f O*0 I G p 6ce Ao i <
. kkY?&$t'+s=y hk ON AR U
/& & +OA 0 W + /'
1
=> o fg O O
C %y g o b. O % #*
; => 0 # df '
"< (
)
uj -
!b ~ -'
j a
. o ..++** *% _
~s f
,3, , -
g +. s / . 9,c* f % i 8 lg;;. . 3.-' yf <::::) ( %, LEGEND #5 l o S + Primary Highway h % C 4 Secondary Highway o 1 2 0 1 Milt Light - Duty Road
= = = = === == Unimproved Road .
SCALE
INP-ASC/ER 9/lfu'Jg , lo #<::> g Q LEGEND a <g STATION NO. MEDIA g 1 THROUGH 3 PARTICULATES l RADIOIODINE l j DIRECT RADIATION 4.5.7 DIRECT RADIATION ______ e_. 10 THROUGH 15
# PARTICULATES
-520 g l 16 RADIOIODINE I 26 pg DIRECT RADIATION L e i 17 THROUGH 19 DIRECT RADIATION 521
/n o f 9
E E>~% 3 0 O l l t$ WYE' BARRICADEj s,
,s** S47
*m
% o x*4:
V i I h q R
-n 0 0 2 N m. ,
P > BM PUGET SOUND POWER & L4GHT COMPANY i SKAGIT/HANFORD NUC' EAR PROJECT a APPLICATION FOR SITE CERTIFICATIONI l 7O ENVIRONMENTAL REPORT , l O d #
#46 PLANT BOUNDARY
# MONITORING LOCATIONS - REMP N j FIGURE 6.15 (-
l Amendment 7 l
\
\ %/
TABLE 7.1-3 Sheet I of 2
SUMMARY
OF DOSES RESULTING FROM ACCIDt3rTS AT EXCLUSION AREA SOUNDARY (1609 meteral Whole-Sody Beta Skin General Thyroid Gamma Done Dose Assessment of Accident (res) Likelihood Class Descr ipt t on trem) _ tres) I 1.0E-01 1.0E-01 --- certain Natural Background Radiation ( i (Annual) Espected Release Wegligible (Section 5.2) (Section 5.23 certain from Normal Operation (Annual)
-- --- --- occantonal 1.0(a) TRIVIAL ACCIDENTS
--- == -- occasional 2.0(a) SMALL RELEASES OUTSIDE CONTAINMDI7 3.0 RADNASTE SYSTEM FAILURES
--- rare M 3.1 squipment Leakage or 1.0E-02 --
Malfunction Release from Low temperature -- 2.95-04 1.9E-04 rare 3.2 7 g Charcoal Adsorption Tank Supture y tn Release of Liquid Neste 1.25-05 -- -- rare () 3.3 Collector Tank Contents N p3 1
#3 4.0 FISSION PRODUCTS TO PRIMARY SYSTime (BNR)
-- -- -- occasional 4.1(a) Fuel Cladding Defecta Of f-Design Tranalents that 9.35-04 2.15-04 1.23-04 rare 4.2 Induce Fuel Failures Above those tapected 5.0 FIS$10M PRODUCTS TO PRIMARY AND ----- - -
- -----~~- Not Applicable-SBCONDARY SYSTEM (MrR)
> 6.0 REFUELING ACCIDENT U 3.6s-05 3.3E-05 r ar e 6.1 Fuel Dundle Drop 2.3s-05 Q rare seavy Object prop over Fuel 2.05-04 3.35-G4 3.2E-04 h 6.2 in Core 7.0 SPEarr FDEL SAleDLING ACCIDENTS rt u 2.i ei A.a .i, Dr ,in ,.ei 2.3 . , 3...-es 3. ..., ,a,. g g
storage Pool 2.25-05 3.05-05 2.55-35 rare 4 7.2 seavy Object Drop onto Fuel Rock t
t I l l l TAst.F 1.1- 3 Sheet 2 of 2 I I l whole-Body Beta Skin General Accident Thyroid Gamma Dose Dose Assessment of Class Desertptton treen tren) (rem) Lakelshood 7.3 Puel Cash Drop --- 6.0E-06 3.eE-04 rare 3.0 ACCfDENT INITIATIOst EVDITS CONSIDERED IN SAD 0.1 Los s-of -Cool a n t Accidente Small Pipe Break 8.3E-08 3.OE-10 1.OE-10 Entremely rare Large Pipe Break 1.1E-02 5.73-04 3.9E-04 Estremely rare 0.!tal Break in Instrument Line from Pramary system that -- Not Applicable- -- Penetrates the Containment 0.2(a) Rod Ejection Accident (19fp ) -- - -- -- -pot Applicable tn 4.2 Rod Drop Accident (Betal 1.2E-03 2. 6 E- 0 4 1.5E-04 E2tremely rare N l2: 0.3(al Steaaline Steska (PtfD) Not Applicable . - == - - c----- Z M I S.3 Steamline Breaks (Swa) > small Break 1.9E-04 S.9E-06 1.lt-05 Est resely are 5.65-06 6 . 4 E- 06 Entremely eare M Large Break 1. 3 E- 0 4 O N M As tt 3 Os W B % es H 3 O rt N CD 4 tJ O .- .. - O . - - - - O
S/HNP-ASC/ER 9/16/82 O TABLE 7.1-15 CLASS 8.1 ACCIDENTS l DOSES RESULTING FROM LOSS-OF-COOLANT ACCIDENTS AT EXCLUSION AREA BOUNDARY Dose in rem 1 4 1 Time Periods Whole Beta in hours Thyroid Body Skin Class 8.1 Accident Small Pipe Break Total 8.3E-08 3.8E-10 1.8E-10 0 - 2 hrs 6.5E-09 1.4E-10 7.0E-ll 2 - 8 hrs 1.7E-08 1.3E-10 5.2E-ll - 8 - 24 hrs 1.5E-08 7.9E-ll 3.8E-ll 24 - 96 hrs 1.8E-08 1.9E-ll 1.lE-ll 96 - 720 hrs 2.7E-08 1.lE-ll 6.2E-12 7 Large Pipe Break Total 1.lE-02 5.7E-04 3.9E-04 0 - 2 hrs 5.5E-04 1.6E-04 9.2E-05 2 - 8 hrs 1.6E-03 1.6E-04 7.7E-05 8 - 24 hrs 1.6E-03 9.6E-05 7.3E-05 24 - 96 hrs 2.5E-03 6.6E-05 6.3E-05 96 - 720 hrs 4.4E-03 8.4E-05 8.lE-05 O Amendment 7
S/HNP-ASC/ER 12/21/81 TABLE 7.1-16 FISSION PRODUCT INVENTORIES (curies) Gap Radioactivity (3) Isotope Core (l) Gap ( 2) Per Rod I-131 1.19E+08 1.19E+06 2.23E+01 I-132 1.72E+08 1.72E+06 3.22E+01 I-133 1.97E+08 1.97E+06 3.69E+01 I-134 2.54E+08 2.54E+06 4.75E+01 I-135 2.01E+08 2.01E+06 3.76E+01 Kr-83m 1.23E+07 1.23E+05 2.30E+00 Kr-85m 2.67E+07 2.67E+05 5.00E+00 Kr-85 1.23E+06 1.23E+04 2.30E-01 Kr-87 4.92E+07 4.92E+05 9.21E+00 Kr-88 6.97E+07 6.97E+05 1.30E+01 Kr-89 8.20E+07 8.20E+05 1.53E+01 4 Xe-131m 7.38E+05 7.38E+03 1.38E-01 Xe-133m 8.20E+05 8.20E+03 1.53E-01 Xe-133 2.30E+08 2.30E+06 4.31E+01 Xe-135m 6.97E+07 6.97E+05 1.30E+01 Xe-135 4.02E+07 4.02E+05 7.52E+00 Xe-137 1.93E+08 1.93E+06 3.61E+01 Xe-138 1.80E+08 1.80E+06 3.37E+01 (1) Based on operating power of 4100 MWt (2) Equal to 1 percent of the total core inventory (Regulatory Guide 4.2) (3) Based on 848 fuel assemblies in the core and 63 rods per assembly O Amendment 4
S/HNP-ASC/ER 9/16/82
~ 1 g ) CHAPTER 8.0 '
ECONOMIC AND SOCIAL EFFECTS OF PLANT CONSTRUCTION AND OPERATION r CONTENTS SECTION TITLE PAGE , 8.1 Reliability Benefits 8.1-1 i r 8.1.1 Generation of Electricity 8.1-1 I 8.1.2 ( Reliability 8.1-2 l 8.1.3 Economic and Social Benefits of Meeting Load Growth Requirements 8.1-3 8.1.3.1 Survey of Puget Customers Regarding ! the Socioeconomic Costs of l Electric Energy Shortages 8.1-5 l 8.2 Costs 8.2-1 f i 8.2.1 Capital Costs 8.2-1 l 8.2.2 Annual Costs of Operation 8.2-1 8.3 Social and Economic Impacts 8.3-1 ! 8.3.1 Description of the Project in the Context of the Tri-Cities Area 8.3-1 ; 8.3.2 Delineation of Impact Area 8.3-3 I 8.3.3 Alternative Scenarios 8.3-4 I 8.3.4 Uncertainty and the Role of the l r Socio-Economic Monitoring Program 8.3-4a 8.3.5 Tax Revenues Associated with l Construction and Operation 8.3-5 l 8.3.5.1 Tax Revenues 8.3-5 t 8.3.5.2 Projected Conditions Under i Alternative Scenarios 8.3-8 1 8.3.6 Population 8.3-9 i 8.3.6.1 Existing and Developing Conditions 8.3-9 8.3.6.2 Projected Population Conditions Under Alternative Scenarios 8.3-11 \ (])
\~s 8-1 Amendment 7
S/HNP-ASC/ER 9/16/82 SECTION TITLE PAGE 8.3.7 Availability of Qualified Workforce 3.3-13 8.3.8 Economy 8.3-14a 8.3.8.1 Existing and Developing Conditions 8.3-14a 8.3.8.2 Projected Economic Conditions Under Alternative Scenarios 8.3-16 8.3.9 Government and Fiscal 8.3-18 8.3.9.1 Existing and Developing Conditions 8.3-18 8.3.9.2 Projected Fiscal Conditions Under Alternative Scenarios 8.3-19 8.3.10 Transportation 8.3-20 8.3.10.1 Existing Conditions 8.3-20a 8.3.10.1.1 Street Network 8.3-20a 8.3.10.1.2 Traffic Volumes 8.3-20b 8.3.10.1.3 Other Modes of Transportation 8.3-20d 8.3.10.2 Projected Growth in Background Traffic Volumes 8.3-20d 8.3.10.2.1 Population and Employment Growth 8.3-20e 8.3.10.2.2 Traffic Trends 8.3-20f 8.3.10.3 Future Network Improvements 8.3-20f 8.3.10.4 Impacts 8.3-20h 8.3.10.4.1 Construction Impacts 8.3-20h 8.3.10.4.1.1 Peak Hour Conditions 8.3-20h 8.3.10.4.2 Operations Impacts 8.3-20j 8.3.10.4.3 Impacts on Other Modes of Transportation 8.3-20j 8.3.10.5 Mitigating Measures 8.3-20j 8.3.11 Housing 8.3-23 8.3.11.1 Existing and Projected Housing Infrastructure 8.3-23 8.3.11.2 Projected Housing Conditions Under Alternative Scenarios 8.3-24 l 8.3.12 Education 8.3-25 i 8.3.12.1 Existing and Developing Conditions 8.3-25 8.3.12.2 Projected Educational Conditions Under Alternative Scenarios 8.3-26 8.3.13 Utilities 8.3-27 8.3.13.1 Existing and Developing Conditions 8.3-27 8.3.13.2 Projected Utility Service Conditions Under Alternative Scenarios 8.3-29 8-11 Amendment 7
1 l S/HNP-ASC/ER 9/16/82 SECTION TITLE PAGE 8.3.14 Public Safety 8.3-30 8.3.14.1 Existing and Developing Conditions 8.3-30 8.3.14.2 Projected Public Safety Conditions Under Alternative Scenarios 8.3-31 8.3.15 Health Care 8.3-31 8.3.15.1 Existing and Developing Conditions 8.3-31 8.3.15.2 Projected Health Care Conditions Under Alternative Scenarios 8.3-33 8.3.16 Human Services 8.3-33 8.3.16.1 Existing and Developing Conditions 8.3-33 8.3.16.2 Projected Human Service Conditions Under Alternative Scenarios 8.3-34 8.3.17 Private Sector 8.3-35 8.3.17.1 Existing and Developing Conditions 8.3-35 8.3.17.2 Projected Private Sector Conditions Under Alternative Scenarios 8.3-35 8.3.18 Recreation and Leisure 8.3-36 8.3.18.1 Existing and Developing Conditions 8.3-36 8.3.18.2 Projected Conditions Under Alternative Scenarios 8.3-37 8.3.19 Libraries 8.3-38 8.3.19.1 Existing and Developing Conditions 8.3-38 8.3.19.2 Projected Conditions Under Alternative Scenarios 8.3-38 8.4 Impacts on Indian Nations 8.4-1 8.4.1 Existing and Developing Conditions 8.4-1 8.4.2 Projected Conditions Under Alternative Scenarios 8.4-3 8.5 Summary of Social and Economic Benefits and Costs 8.5-1 8.5.1 Benefits 8.5-1 8.5.2 C1 Costs 8.5-5 8.5.2.1 Traffic Costs 8.5-5 8.5.2.2 Fiscal Costs 8.5-6 8-111 Amendment 7
I S/HNP-ASC/ER 8/20/82 CHAPTER 8.0 ECONOMIC AND SOCIAL EFFECTS OF PLANT CONSTRUCTION AND OPERATION TABLES NUMBER TITLE Section 8.1 8.1-1 Estimated Dollar Loss by Consumer Group Section 8.2 8.2-1 Cost Information for Nuclear ($000) 8.2-2 Estimated Costs of Electrical Energy Generation Nuclear Units 1 & 2 8 2-3 Fact Sheet for Power Generation Costs Section 8.3 8.3-1 Construction Pupils for WNP 1/4 and 2, Identified by School District Surveys and Confirmed by Washington Public Power Supply System 8.3-2 Estimated Construction Cost and Potential Property Tax Revenues During Construction (in current dollars) 8.3-3 Tax Base Increases from S/HNP (Assessed Valuation Increases in 1980 Dollars) 8.3-4 Local Population, 1940-1980 8.3-5 Projected Nuclear Related Construction Workforce on the Hanford Reservation by Year 8.3-6 Population Projections by Scenario 8.3-6a Non-Agricultural Wage and Salary Workers, Tri-Cities SMSA by Industry, July 1981 Average Monthly Non-Agricultural Payroll Within Tri-Cities SMSA, First Quarter, 1980 0 8-iv Amendment 6
S/HNP-ASC/ER 8/20/82 1 SOCIAL AND ECONOMIC IMPACTS ( 8.3 8.
3.1 DESCRIPTION
OF THE PROJECT IN THE CONTEXT OF THE TRI-CITIES AREA 4 + The location of the Site in relation to the Tri-Cities and ! surrounding communities and counties is shown in Figure 2.1-1. 16 The early development of Richland, Kennewick and Pasco was tied to the agriculture and transportation industries. Until World War II, for example, Richland (founded in 1910) was a small farming community of several hundred people. At the same time, Pasco and Kennewick developed economies integrally related to the railroad industry. By 1940 the populations of Pasco and Kennewick had grown to 3,913 and 1,918, respectively. The combined population of the three cities in 1940 was 6,078 (Ref 1). 4 In 1942, the town of Richland was taken over by the United States Government through condemnation proceedings as part of a 600 square mile reservation for the Hanford Engineer-ing Works. From 1943-1945 the city of Richland was built to house the personnel and administrative offices asso-ciated with the plutonium production facilities on the Reservation. While the character of Pasco and Kennewick was less dramatically affected during this period, they too, grew and changed due to war-time activities and 4 operation of the Hanford Works (Ref 2). By 1950 the population of the Tri-Cities was over 50,000 and the economy of the area had become closely linked to nuclear technology. By the 1960's corporations such as 5 Westinghouse, Battelle, North American Rockwell, United Nuclear Corporation, Boeing and Exxon located nuclear operations in the Tri-Cities area. The Tri-Cities Nuclear Industrial Council has been an active force in promoting the development of nuclear industries. By the 1970's construction of the Fast Flux Test Facility 4 (USDOE) and WPPSS Nuclear Plants (WNPs) 1, 2, and 4 by Washington Public Power Supply System (Supply System) provided a dramatic stimulus to-the local economy. Over the 1978-1979 period, for example, the Tri-Cities SMSA had the ninth largest increase in personal income of the 273 SMSAs in the United States (Ref 3). , J 8.3-1 Amendment 6
l S/HNP-ASC/ER 9/16/82 l l From 1970-1980 the population of the Tri-Cities Standard Metropolitan Statistical Area (SMSA) grew 54 percent, from 93,356 to 144,469 (Ref 1). Much of this increase in economic and demographic activity was related to nuclear facility construction on the Hanford Reservation. For example, in 1970 there were approximately 4 1,756 construction workers in the Tri-Cities SMSA but by 1979 this figure had grown to 11,110 on an average annual basis, of which 7,630 were employed by the Supply System. By June of 1981, monthly employment in the Tri-Cities SMSA reached 13,880 construction workers. In 1982, major reductions in the nuclear construction program of WPPSS had significant adverse socioeconomic effects upon the Tri-Cities area:
- a. By June 1982 the unemployment rate in the Tri-Cities was 16.8% compared to a national average of 9.8%. In May 1981 the number of claims for unemployment in the Tri-Cities had been 5,250; by May 1982 this figure was 13,290. (Ref 12-13) l b. Outmigration of workers and their families has increased and is continuing. During June 1982 alone, for example, the Washington Department of Employment Security estimated 2,756 workers plus their families left the Tri-Cities. (Ref 12-17)
Outmigration of trained workers has been spurred by advertisements in local newspapers of jobs in such states as Ohio, New Mexico, Colorado, Illinois and Texas. Apartment vacancies and 7 houses for sale have increased dramatically over 1981 levels and by August 1982 over one in every five apartments in the area was vacant.
- c. Schools have experienced declining enrollment due to outmigration and will receive less funding since both state funds and WPPSS impact payments are distributed on a per student basis. As an example, The Richland School District has been forced to respond to declining revenue by cutbacks in custodial positions, laboratory supplies, textbook purchases, counseling programs and virtually all extra-curricular activities. (Ref t
12-15) l In general, the future of the Tri-Cities remains clouded by external decisions which will affect the socioeconomic vitality of the area. An indication of the potential impact of decreases in WPPSS and USDOE related employment can be gleaned from the fact that activity on the Hanford 8.3-2 Amendment 7
S/HNP-ASC/ER 9/16/82 O
. Reservation accounts for approximately 57% of the economic activity in the Tri-Cities. (Ref 12-16) 7 )
8.3.2 DELINEATION OF IMPACT AREA Nuclear related construction over the past generation has changed the socioeconomic character of the Tri-Cities Area. 4 The great bulk of the new activity generated by this construction - from population growth to traffic congestion '
- has occurred in the SMSA and particularly within Richland, Pasco, Kennewick, West Richland and Benton City.
School enrollment data presented in Table 8.3-1 illustrate the localized nature of construction related in-migration. l5 In May of each year school districts in the area conduct a survey to identify " construction pupils," i.e., students whose parents are employed at WNP-2 or 1/4 and whose date of residence in the school district was subsequent to May 1, 1972 (for WNP-2) and May 1975 (for WNP-1/4). Table 8.3-1 depicts the results of the May 1980 survey. As these data demonstrate, construction pupils, both in terms of absolute and relative impact, are concentrated in the s school districts closest to the Site and the core of the SMSA. For example, the Richland, Kennewick and Kiona-Benton districts accounted for approximately 83 percent of all construction pupils identified 'uy the Supply System audit. 4 S.ch data as the school enrollment figures in Table 8.3-1 strongly suggest that the impacts of S/HNP - both positive and adverse - will be centered within Benton and Franklin Counties in general and particularly in the following five communities: (1) Benton City, ( 2) Kennewick, (3) Pasco, (4) Richland, and (5) West Richland. Other communities in Benton and Franklin Counties (e.g., Prosser) will only be modestly affected by S/HNP construction and operation. According to an analysis of the Supply System surveys under-taken between 1975 and 1978, daily commuters residing in 4 Yakima County accounted for 8.5-12.8 percent of the construction work force at WNP-1/4 (Ref 11) . Estimates based on the survey for the 1979-1980 period of daily commuters residing in Yakima County were 10 percent of the construction workforce on WNP-1/4 (compiled from data in Ref 11). This percentage may be lower for the total Supply System construction workers since WNP-2 began construction earlier and could draw more heavily on locally available j labor.
\m 8.3-3 Amendment 7
t S/HNP-ASC/ER 9/16/82 During the 1980 labor-management dispute, it was estimated that about 18 percent of the 6,600 job loss belonged to ! Yakima County. This may over estimate commuters in the l total workforce since the possibility exists that local hires may be protected at the expense of commuters and the fact that commuters become a proportionately larger share of the workforce as the peak year approaches. Therefore, estimates of commuters residing in Yakima County are probably in the range of 10-15 percent of the total con-struction workforce. If this pattern continues through the S/HNP construction period, several hundred residents of 4 such communities as Grandview, Sunnyside and Mabton would obtain jobs on the Project. The economies of the outlying communities can be expected to be enhanced through the S/HNP employment and income effects. The fact that these community work forces have extensive nuclear construction experience suggests that these workers will benefit from the S/HNP job opportunities, although such communities as Grandview, Sunnyside and Mabton generally are not considered part of the Tri-Cities impact area (Refs 11 and 6 26). 8.3.3 ALTERNATIVE SCENARIOS over the past decade the Tri-Cities SMSA has been one of the most dynamic socioeconomic settings in the United States (Ref 4). During the period 1970-1980, for example, the popu3ation increased by 54.8 percent compared to an 11.4 percent rate for the nation. Dependence upon energy related construction, operation and research makes the area vulnerable to marked changes in business conditions and particularly subject to the impacts of external decisions regarding energy development. The range of alternative futures does not appear to be decreasing in the 1980's. For example, the following external decisions will each have a major role in deter-mining the short-term (1982-1990) future of the Tri-Cities area:
- 1. Decisions on the construction of WNP-1 and the 7 eventual fate of WNP-4.
- 2. Decisions permitting construction of S/HNP.
- 3. Decisions of courts on the constitutionality of 4
Initiative 394. This Initiative could have an effect upon WNP 1, 2 and 4, as well as a proposed powerhouse at Priest Rapids Dam. 8.3-4 Amendment 7
4-).) $ $ . D . [ [Ih k... . ). [ 0 [ d '.~ ~.. . . . E y; NO , :. s. 2f: .;k .c. ,.. . O .1. . .h
\
S/HNP-ASC/ER 9/16/82
- 4. Decisions by USDOE to (a) decrease, (b) maintain or (c) increase activities on the Hanford Reser-vation. At the present time approximately 12,000 jobs are accounted for by USDOE and its con-tractors.
1 Given the uncertainty associated with these decisions as well as the magnitude of their potential impact upon the future of the Tri-Cities, a " scenario" approach is appro-priate for the present analysis. Four scenarios are a utilized: Scenario 1 - Construction of WNP-4 resuming as scheduled in 1983 and peaking in 1985 with S/HNP not constructed. 4 Scenario 2 - Construction of WNP-4 resuming in 1983 and peaking in 1985 coupled with construction of S/HNP commencing in 1983 and peaking in 1988. Scenario 3 - Construction of S/HNP commencing in 1983, peaking in 1988 and WNP-4 cancelled. Scenario 4 - No major construction projects after the completion of WNP-1 and WNP-2 for the period 1980-2000. Scenarios 1 and 4 are presented as alternative baseline scenarios to indicate the socioeconomic character of the area without construction of the Project. In this study
" impacts" are conceptualized as the difference between the projected socioeconomic condition of the Tri-Cities without as compared to with S/HNP.
8.3.4 UNCERTAINTY AND THE ROLE OF THE SOCIOECONOMIC MONITORING PROGRAM The wide range of alternative futures which characterize the Tri-Cities area places unusual burdens upon an analysis of the potental socioeconomic impacts of S/HNP. External decisions yet to be made relating to WPPSS and USDOE 7 generate uncertainty for the Tri-Cities. Such uncertainty tends to make a variety of disparate baseline scenarios seem equally plausible. And, as events unfold in the area socioeconomic analyses of an endless iteration of baseines and alternatives might be undertaken with little corresponding increase in the overall understanding of how S/HNP would affect local residents. O 8.3-4a Amendment 7
/
S/HNP-ASC/En 9/16/82 l l Given this situation an approach must be developed which (1) recognizes the uncertain future of the area, (2) delineates probable generic effects, and (3) provides the means through a monitoring program to empirically identify actual impacts of S/HNP construction and operation as such 7 impacts emerge. In cooperation with appropriate local and state agencies, the Applicants will then undertake measures which will mitigate adverse effects while maximizing benefits. O O 8.3-4b Amendment 7
S/HNP-ASC/ER 8/20/82 l . Accordingly, Puget will develop and implement a two-phase program: (1) where adverse socio-economic impacts can be 4 identified on an a priori basis, appropriate mitigation measures will b'e taken; and (2) a socio-economic moni'- toring program will be utilized. The monitoring program will employ standard methodologies, which will identify baseline data, in order to compare socioeconomic conditions "with" S/HNP against conditions "without" S/HNP. Where it is evident that such conditions are worsened by the Project's existence, vis-a-vis its nonexistence (baseline), then it would be Applicant's intention to mitigate the , negative deviation from baseline conditions. The actual nature of mitigating actions can only be addressed on a E231~11 case-by-case basis with reference to specific circum-stances. They could include such possibilities, for example, as direct compensation for costs; upgrading of facilities; expansion of capacities, etc. 8.3.5 TAX REVENUES ASSOCIATED WITH CONSTRUCTION AND OPERATION 8.3.5.1 Tax Revenues Significant tax revenues would be generated by the construction and operation of S/HNP for local jurisdictions O and the State of Washington. Table 8.3-la depicts the tax systems associated with the S/HNP. These revenues would emerge from the following: 4
- 1. Property taxes on the facility. According to Washing-ton Tax Law, private electric utilities are subject to a property tax imposed by the county (Ref 5) . In the case of the S/HNP, Benton County would collect the property tax and disburse part to the State for inclusion in the General Fund for public education.
The remaining portion would accrue to Benton County for disbursement within the County. The exact amount of tax revenues generated depends on the assessments, levies and laws in effect at the time the Project goes on the tax rolls. Table 8.3-lb represents the 1981 levies but the average levy rate will probably decrease because of the Project. The following data, therefore, are presented as examples only and are subject to change. They do, however, place the magnitude of the potential tax revenues in perspective. The estimated value of property to be purchased is '
$450,000 (in 1980 dollars) . This value is based on a 6 1981 appraisal of land value for the specific property E231.02 8.3-5 Amendment 6
r 1 S/HNP-ASC/ER 9/16/82 to be purchased. (This amount differs from that shown l6 in Table 8.2-1, since the value of the project is stated in eithar 1980 dollars or current dollars where an inflaticn or escalation rate is added. Current i I dollars are shown in Section 8.2 where an escalation rate is included. These tables meet the requirements of Reg Guide 4.2, Revision 2, Appendix section 7 l " Tables." For the socioeconomic impacts, 1980 dollars are used unless current dollars are specifically identified. In both cases, the value of the project is the same although the value of the dollar units are different due to the escalation rate used to calculate current dollars.) Table 8.3-2 presents projected costs of construction by year, estimates of cumulative assessed value and estimates of potential property 4 taxes accruing to the State and Benton County during the construction period. Substantial property tax revenues could be paid to both Benton County (total
$89 million in 1980 dollars) and the State (total $68 7 million in 1980 dollars) during the construction period from 1983-1992.
The value of inventories of supplies and materials and l mobile equipment are estimated at $11.2 million for 6 l both units, in 1980 dollars. However, the major increases would come from the assessed value of the E 231. site facilities. Potential property tax revenues dur-ing operation of the facility will be of even greater magnitude and will have dramatic effects upon the tax base of local taxing jurisdictions (Table 8.3-3). These tax base increases could be translated into major revenues for each jurisdiction. In the first 4 year of operation of both units, for example, the following situation would exist if (a) 1981 tax rates , were in effect and (b) the facility was assessed at 80 I percent of its value. Example: Procerty Tax (1980S) Year Assessed State Benton Total 6 Value (1980$) County 1994 $ 2.4 billion $8,250,000 $11,250,000 $19,500,000 5 Over the lifetime of the Plant, therefore, several hundred million dollars in taxes could be paid to Benton County for distribution within the county as well as to the State. To put the impact of the S/HNP 4 in perspective, the total valuation of all property in Benton County in 1981 was just over $2.7 billion and taxes collected for the State, county, roads and schools were $25.9 million. The assessed value of 8.3-6 Amendment 7
1 S/HNP-ASC/ER 9/16/82
<~s -
i t (, S/HNP (in 1980 dollars) alone would be almost double l5 t the valuation of all assessable county property at the current time. If the present tax base remained 4 i constant until 1994, this would mean that the S/HNP ! would account for about 47 percent of the property tax 15 i base when assessed at 80 percent of full value (see
- Table 8.3-3).
- 2. Sales and use taxes of 5.3 percent are collected by 4 !
the State and disbursed as follows: 4.5 percent to > the State, 0.3 percent for the local transit district and 0.5 percent to local jurisdictions. e i Sales and use tax analysis are estimates only and are ! subject to change. These estimates were derived from (a) projections of purchases during construction and 6 operation and (b) review of the document " Taxation of
- l Energy Generation Facilities During Construction and E231.03 Operation," Washington State Department of Revenue (June, 1977). !
The assumption was made that 72 percent of the total construction cost was subject to local sales or use tax. The 72 percent figure is based upon actual 7 ! construction costs and sales tax payments made for WNP-2 through January 1981 (Ref 29). i It was assumed that all fuel purchases would be subject to sales and use taxes by the State of 6 ' Washington, Benton County and the Benton-Franklin E231*03 Transit Authority. It was also assumed that during ' operation, purchase of supplies and materials would be subject to sales or use tax in Benton County. Recent fiscal conditions in the State of Washington have resulted in increased sales taxes at the state level. These increases are temporary, however, and the state sales tax is scheduled to revert to 4.5 l percent on June 30, 1983. ! 7 The sales and use tax effects are applied to an assumed construction cost of about $2.9 billion (in l 1980 dollars). This amount excludes a number of costs, such as the value of the property, the , allowance for funds during construction, transmission l' costs, fuel costs, and various tax payments. The year ' 1987 is displayed to demonstrate an annual year effect ! of these revenues. L l [\
\s /
j ; 8.3-6a Amendment 7
a S/HNP-ASC/ER 9/16/82 O
'~# Annual Sales and Use Tax Revenues (in 1980 dollars)
Total Rev. Average Annual Example Yr. Recipient 1983-1992 Revenues 1987 7 , State 84,553,000 8,455,300 15,487,000 ; Benton County 9,395,000 939,500 1,721,000 ! Benton-Franklin ' Transit District 5,637,000 563,700 1,032,000 l i Total 99,585,000 9,958,500 18,240,000 I i During operation, the sales and use tax is particu- ! larly important because of the cost of nuclear fuel. 4 It is estimated, for example, that the costs of the ; initial cores of the two units will be $292.9 million i in 1980 dollars. Purchase of these cores could ( provide $13,180,000 in revenues to the State; i
$1,464,000 to Benton County and $878,000 to the Benton- !'
Franklin Transit Authority (in 1980 dollars) .
- The following revenues would be generated if annual ;
} fuel costs were $120.4 million in 1980 dollars: i [~' Annual Revenues due 7 to Nuclear Fuel Costs l Entity Only (in 1983 $) ! State $5,418,000 Benton County 602,000 Benton-Franklin Transit District 361,000 Total $6,381,000 i In addition to these fuel costs, the tax on local t purchases will produce revenues each year during the 5 j operation phase. It is estimated-that approximately l
$5,000,000 (in 1980 dollars) in local purchases of l6 j materials and services will be made each year i resulting in increased annual revenues for both Benton 5 i County and the Transit District. .
- 3. Business and occupational taxes are collected by the State during construction. On 2.9 billion dollars of 7 l tax base, taxes would be over $12,500,000 (in 1980 i dollars). j
- 4. Business taxes imposed by local communities will O
\--
generate revenues from the Project. Purchases of local materials, supplies and engineering services, 4 ! i for example, will result in increased business activ-ity during both construction and operation. l 8.3-7 Amendment 7 ! ____.,_______.a
r S/HNP-ASC/ER 9/16/82
- 5. Other revenues will accrue to the local taxing juris-dictions and the State through the business activity 3 generated by expenditures of persons employed at the Project. The relatively high incomes of such 4 employees will mean that they will stimulate more business activity than the average worker and that they will pay more than average taxes. Estimated annual income per worker at S/HNP during construction is $37,289 (1980 dollars). Estimated annual salary per employee during the operations phase is $23,600 (1980 dollars). In 1979, the average annual wages in .
the Tri-Cities SMSA were $15,962. The total annual operations payroll is shown in Table 8.3-20. 8:3.5.2 Projected Conditions Under Alternative Scenarios 4 Under Scenarios 2 and 3, if 1981 levies were in effect, the Project would generate the following estimated revenues during construction: Estimated Revenues During Construction (in 1980 dollars) State $178 million Benton County $100 million Benton-Franklin Transit District S 7 million j S285 million In 1980 dollars, during S/HNP operation Benton County and other local jurisdictions would annually receive $11 million in property taxes and over $600,000 in sales tax. The Benton-Franklin Transit District would receive $370,000 per year from sales taxes. O 8.3-8 Amendment 7
S/HNP-ASC/ER 12/21/81 The magnitude of these additional revenues over those that would be collected under Scenario 1 would allow Benton County to consider such options as significantly improving l services, disbursing funds to local communities and/or lowering tax levies. Under the baseline scenarios, neither these revenues nor these options would exist. 8.3.6 POPULATION 8.3.6.1 Existing and Developing Conditions Table 8.3-4 presents population changes for the area over the period 1940 to 1980. As these data indicate, the SMSA has had significant and sustained growth in recent decades with an increase of 54.8 percent in the 1970-80 period. With regard to age structure, the population of the SMSA is composed of a disproportionately large number of younger persons as projected for 1982 (Ref 4): . Age 1982 (Ref 7) Category N % 4 0-19 50,120 33.7 20-34 41,860 28.1 35-44 17,140 11.5 ( 45-64 28,970 19.5 65+ 10,810 7.2 Total 148,900 100.0% In terms of projections of future population growth, Yandon (Ref 6) has pointed out that population projections for the Tri-Cities have been notoriously inaccurate to the extent that some projections have been out of date even before they were published. Thus, in evaluating projections, the impact of external decisions must be fully recognized. The 1982-1990 population of the Tri-Cities will be influ-enced by the level of construction activity on the Hanford Reservation. Table 8.3-5 presents projected nuclear related construction workforce by year for the Project as well as WNP 1, 2, and 4. As these data indicate, in no case will the workforce between 1982-1990 exceed the 1981 workforce. These data demonstrate a declining construc-tion workforce in the area related to nuclear construction even with S/HNP. This situation may lead to either s 8.3-9 Amendment 4
F l S/HNP-ASC/CR 9/16/82 1 absolute population losses or declines in the expected rate of growth. As Schau (Ref 7) has shown, the bulk of population growth in the Tri-Cities area during the latter 1970's was due to 4 high rates of in-migration. Much of this in-migration was associated with increased USDOE and Supply System employment in the area. From 1975-1980, employment by USDOE and its contractors increased from 9,800 to 12,100. From 1975-1980, Supply System average annual employment 5 increased from 1,585 to 6,549. During the latter half of the decade, these two agencies accounted for 35 percent of all average annual non-agricultural jobs added to the economy during 1975-1980. The combined effect of primary and secondary jobs created by these two agencies was over 63 percent of new jobs created in the Tri-Cities area. The State of Washington population projections for the Tri- 4 Cities SMSA over the next two decades are reflective of , dramatic population increases in the 1970's and project l large increases continuing through the 1982-1992 period. These projections overstate the potential for population growth for four reasons: (1) a decline of Supply System construction employment is underway, (2) there is a high l7 degree of uncertainty relating to the future level of USDOE funding, projected growth rates range from being slightly 4 negative to 1 percent per year, (3) even if WNP-4 and S/HNP are constructed the workforce would not exceed 1981 levels and (4) no other new large construction projects are 7 definite for the area. On the basis of this line of reasoning, it is assumed that actual population growth rates during 1982-1993 will reflect the population growth rates that would have applied 4 during 1970-1981 had the Supply System not existed and DOE employment remained constant at its 1970 level (Kenneth W. ( Bracken, Director-Facilities and Site Services Division 6 DOE, personal communictions, December 18, 1981; James E230.02 l Skubic, Economist, Social Impact Research, Inc., l December 20, 1981). It is assumed that the intrinsic growth rate for population is approximately 1 percent per 4 year, or similar to the national growth rate projections (James Skubic, Economist, Social Impact Research, Inc., 6 December, 1981). However, these intrinsic growth rates E230.02 will not compensate for the fact that population will be lost as nuclear construction is completed and workers and families migrate to other sites. Therefore, population 4 under every scenario is expected to decline at some point during 1981-1993. O 8.3-10 Amendment 7
7 S/HNP-ASC/ER 9/16/82 O\ For Scenarios 1, 2, 3 and 4, it was assumed that when total construction jobs on the Reservation declined, 70 percent 4 of all resident construction workers who lost jobs would leave the area within the year (Ref 22) , that the secondary ; jobs associated with the lost construction jobs (secondary jobs = 0.8 times construction jobs) would also disappear and that 40 percent of the resident secondary workers would leave the area within one year (Ref 22) . For other sectors of the population, it is projected that in-migration rates 7 will equal out-migration rates. It was assumed that 15 percent of the construction work force and secondary jobholders were daily commuters residing outside the SMSA (Ref 4; Dean Schau, Labor Market Economist, personal communication, December 4, 1981). It was assumed that the average family size of construction and secondary workers is 3.2 and 2.5, respectively, (Ref 23), and that there are 6 1.3 jobs per household (Refs 1, 24). In-migration rates for the operations work force are assumed to be 25 percent E230.02 (Frank Clemente, Socioeconomic Analysis, December,1981) . Finally, it is assumed that the population associated with DOE activity increases at one percent per year and that no other major construction projects will occur in the area before 1990. Table 8.3-6 depicts the projected population by the State over the 1982-1993 period as well as the potential popu-O lation based on the four scenarios. Some anomalies in the projections are present in the table. Scenario 4 has the largest population in 1993, which is not what would be expected. The reason for this is two-fold: the fact that the intrinsic growth rates of 1 percent per year operate on a larger base in Scenario 4, as compared to the other scenarios, and that out-migration is assumed to be the same for all scenarios. Scenario 4 actually might be expected 4 to have higher out-migration rates and lower in-migration rates and therefore, even a lower population than that projected here. 8.3.6.2 Projected Population Conditions Under Alternative Scenarios No population growth is projected due to construction of S/HNP. As the following data indicate, loss of construc-tion and secondary workers is projected in all four scenarios:
'o 8.3-11 Amendment 7
i S/HNP-ASC/ER 8/20/82 Number of Persons Leaving SMSA Scenario 2 Scenario 3 Scenario 1 (WNP1,2,4 (WNP1,2 Scenario 4 Year (WNP1,2,4*) and S/HNP) and S/HNP (WNP1,2) 1982 - - 1983 2268 1141 4719 5839 4 1984 928 - 3729 5095 1985 - - - 1236 1986 1306 - - 26 1987 1375 - - - 1988 2349 1706 - - 1989 900 2013 49 - 1990 - 2166 1775 - 1991 - 693 696 - 1992 - 735 739 - 1993 - - - - Total 9126 8454 11,707 12,196 Estimates of WNP-4 construction work force are contained in a letter dated August 27, 1981 from Ms. Alice Lee, 6 Socioeconomic Coordinator of WPPSS, to Dr. F. Clemente. E230.04 In both of the baseline scenarios a decline in population and the rate of growth is projected in the Tri-Cities SMSA. In Scenario 1, for example, it is projected that almost 4,402 construction workers and secondary workers will leave the area over the period 1982-1990. Taking into account other departing family members, Scenario 1 projects a loss of over 9,000 people during the nine year period even with construction of WNP-4. 4 Scenario 4 projects even greater population out-migration with over 12,000 persons leaving the area between 1982-1986. Given the projections of out-migration in the baseline scenarios, construction of S/HNP will not be a stimulant for further population increases. In both Scenarios 1 and 2 out-migration of construction and secondary workers will be reduced in the short-term (1983-1987) but is still projected to occur in the 1988-1992 period. By 1994, it is estimated that slightly more than 600 people will be added to the population under Scenario 2, as a result of operation, amounting to about 0.4 percent of the project *d population of the SMSA. Under Scenario 1, about 400 people will be added to the population by 1994 as a result of operation of nuclear plants. 8.3-12 Amendment 6
n S/HNP-ASC/ER 9/16/82 As was pointed out earlier, the continuing changes with WPPSS Construction Program opens a broad range of plausible scenarios. The recent mothballing of WNP-1 and the termination of WNP-4, for example, would have a significant effect upon the baseline population projections made in this section. Specifically, it can be assumed that such actions by WPPSS may stimulate additional out-migration of construction and secondary workers and, thus, lead to even lower baseline population levels in the Tri-Cities than 7 have been projected in the scenarios presented here. Such a situation would essentially corroberate the findings in this chapter and would make the role of the S/HNP in reducing out-migration even more pertinent. At the present time, however, the problematic status of WNP-1 and WNP-4 suggest a cautious approach to conclusions regarding their demographic impacts on the baseline conditions. 8.3.7 AVAILABILITY OF QUALIFIED WORKFORCE Projections regarding the size of the construction and operations force are presented in Table 8.3-7. Construction As of June 1981, there were 13,800 individuals engaged in contract construction in the SMSA (Ref 8). More than two-thirds of these workers were employed on WNP 1/4 and 2. Tri-Cities is the locus of most major craft unions required for nuclear power station construction including Elec-tricians $112 with 1720 members, Laborers #348 with 2,100 members, ar;d Plumbers and Fitters $498 with 550 members. 4 All craft unions have established apprentice programs and Puget will implement a program to qualify craftspersons as necessary. Despite projected out-migration of construction workers none of the construction scenarios indicates the lack of availability of qualified construction workers. Further, in recent years the Supply System has had minimal diffi-culty in obtaining sufficient craftsmen for nuclear facil-ity construction. Individuals who remain residents of the area but commute to regional construction projects will generally curtail such long distance commuting as employ-ment opportunities become available at S/HNP. Competition for local construction workers could con-ceivably arise from several projects or conditions:
- 1. The variable construction schedules of WNP 1 and 4 could produce conflicts with S/HNP. Even if S/HNP l7 g4 8.3-13 Amendment 7
S/HNP-ASC/ER 9/16/82 l and WNP 4 were to peak simultaneously in 1988, the construction force would be less than that of the WNP units of mid-1981.
- 2. Increases in the USDOE construction program could occur. For example, discussions with USDOE officials revealed potential construction of a Replacement Production Reactor and a Basalt Waste Isolation Facility in the mid-1980's.
- 3. Smaller local construction projects may emerge but most such projects which are known at the present time will have been completed by 1986: I-82 Bridge; Finley Alcohol Plant; Alumax Plant in Umatilla; Kanegafuchi chemical plant in Richland; 4 U& I Potato Processing Plant in Plymouth; and the North Richland Toll Bridge.
- 4. A currently unannounced major project could emerge in the local area. Given the time necessary to plan and finance large projects, however, such an event is unlikely.
l In general, construction projects outside the local area l (e.g., Creston, Satsop and Mt. Tolman) would not be com-petitive with S/HNP because, as research on commuting has demonstrated, workers will tend to minimize commuting distances (Ref 9). Operations S/HNP will require an operations force of approximately 295 individuals plus additional workers periodically required 7 for refueling. The major categories of employment will be operations, maintenance, security and both technical and [ non-technical support. It is estimated that at least 75 l percent of the operations force will be composed of resi-l dents already living in the local area as of 1985. Operations force requirements of 220 persons (75% of 295) l7 from the local labor pool will be available due to the high technology orientation of the area and the fact that several local schools have established programs with Battelle Institute for technical training. Further, the 4 long lead time allows local residents to make individual career planning decisions which will improve their chance of being selected for the operations force. O 8.3-14 Amendment 7
S/HNP-ASC/ER 9/16/82
+
8.3.8 ECONOMY { t t 8.3.8.1 Existing and Developing Conditions ! i In FY 1981, the major non-agricultural employment cate-gories in the Tri-Cities were: Percent of f Non-Agricultural ! Wage and Salary 4 Industry Employment Construction 17.5 Trade 19.3 Services 25.2 Government 16.9 Manufacturing 14.4 Other 6.7 i r 100.0 f i i f t f i f i I L t r i i I
' l 8.3-14a Amendment 7 [
, i
S/HNP-ASC/ER 8/20/82 i Based on potential payroll data, lost income opportunities ( in both baseline scenarios would run into the hundreds of millions of dollars. Construction workers are among the most highly paid employees in the Tri-Cities area and their local expenditures are a significant driving variable in the local economy. As compared to the two potential baseline conditions, the impacts of S/HNP can be delineated: (1) Employment - Construction will provide employment 4 ranging from 563 in 1983 to 4,446 in 1988 to 1386 in 1991. Over the 1983-1991 period S/HNP will provide almost 24,000 person years of employment. Secondary employment will also be maintained during the construction period. Previous research has indicated a multiplier of 1.8 for nuclear construction in the Tri-Cities (Ref 11). After taking commuters , into account, it is projected that construction will support over 16,000 person years of employment in other sectors of the local economy, t Operations will provide employment for 295 individuals over the 40 year technical design life of the facil-ity - 11,800 person years of work. Assuming each oper- l6 [ (_,)h ation job maintains 0.8 secondary jobs, S/HNP will mean employment for approximately 236 persons in other sectors of the economy. 'n addition, 200 workers will be employed during period , refueling operations. None of this employment would take place in either of the baseline scenarios. 4 (2) Income - During construction, it is projected that annual income per worker will average approximately
$37,000 in 1980 dollars for a total of $949 million over the construction period (See Table 8.3-8).
During operation, the total payroll on an annual basis will be $8,141,000 in 1980 dollars or an average of
$23,600 per worker (see Table 8.3-20). 5 These relatively high income levels will stimulate 4 other sectors of the economy and produce expanded i
business activity throughout the SMSA. Table 8.3-8a presents estimates of potential expenditures by the workforce in the local area during the construction 6 I and operations stages. These data lend insight into the role S/HNP might play in the local economy. None of this income would be generated in the baseline scenarios. 4 (Av) 8.3-17 Amendment 6
S/HNP-ASC/ER 9/16/82 (3) Purchase of local materials and services - During construction Puget expects to purchase local supplies and services when they are readily available and competitively priced. Given the extent to which.the 4 local economy has developed in tandem with nuclear power, it is expected that a number of local firms will be available to provide materials and services at a reasonable cost. It is estimated that purchases of
$265 million (1980 dollars) in local materials and services will be made during construction of S/HNP.
During operation, it is assumed that, in addition to 7 fuel purchases, other purchases of materials and ser-vices will be approximately $5 million per year in 1980 dollars. Over the 40 year operating life of the facility, this totals to $200 million spent in the local area. None of these purchases would occur under the baseline scenarios. 8.3.9 GOVERNMENT AND FISCAL 8.3.9.1 Existing and Developing Conditions Both Benton and Franklin Counties have an elected county commission governmental structure, with each county main-taining its own independent planning department. Benton County employs four professional planners and one plan-ner/ draftsman, while Franklin County employs two profes-sional planners. In addition, both counties have such customary departments as county assessor, auditor, clerk, prosecutor, engineer, extension agent, and court facil-ities Coordination and cooperation between the two county structures is facilitated by the Benton-Franklin Govern- 4 mental Conference in Richland. Each of the Tri-Cities municipalities is governed by a council-manager system, with the mayor elected by council in each city. Other municipalities in the counties also maintain city council governments. Municipal planning staffs include 5 positions in Kennewick, 3 in Pasco, 10 in nichland, and 2 in West Richland. Budgetary data for selected municipalities and the two county units in the Tri-Cities SMSA are summarized in Tables 8.3-9 through 8.3-11. Locally-collected taxes combine with intergovernmental revenues transfers to represent the primary sources of operating revenues for both the counties and the impact area municipalities (Tables 8.3-9 and 8.3-10). The two county governments concentrate their operating expenditures on general-governmental services and transportation programs. Munici-pal expenditures as displayed in Table 8.3-11 tend to be concentrated in the areas of (a) general government 8.3-18 Amendment 7
S/HNP-ASC/ER 3/17/82 services, (b) security of persons and property, and ! (c) transportation.
)
As is true of many areas, particularly those which have experienced the added demands of rapid population and economic expansion, governments in the Tri-Cities area have experienced increased expenditure demands and restricted revenues in recent years. These pressures have resulted in proposals for increased local tax rates to provide addi-tional revenues (Refs 12-1, 12-2). Local voters, however, have been hesitant to approve additional or increased taxation, forcing a reduction in some program areas and a general emphasis on fiscal austerity - a trend which is likely to continue into the near-term future. Municipal revenues in 1981 are estimated to have declined in l Richland, Kennewick, and Pasco from 1980. Among the consequences of budget restrictions have been program ; reductions and employee cut-backs. Additional cut-backs , may be expected. For example, the city of Richland has ' i projected a decline in manpower in the fire and emergency ' services department from 39 to 35 persons as a result of anticipated 1982 budget levels. 8.3.9.2 Projected Fiscal Conditions Under Alternative Scenarios 4
+
Scenarios 1 and 4 show that there would be outmigration from the study area as the employment and income from the construction sector declines (Table 8.3-6). This would lead to declines in revenues to local communities. The , additions of employment and income due to S/HNP, as shown in Scenarios 2 and 3, would significantly increase local revenues over what would be the case under Scenario 1 at ! similar points in time without these economic variables. Additional revenues to the State and local areas would come from such sources as property taxes, sales taxes, and B&O taxes, etc. As indicated in Section 8.3.5, construction and operation ! of S/HNP would generate significant tax revenues in Benton
- County, if tax rates are not lowered. It is estimated, for example, that Benton County could potentially receive $150 '
million in revenues from the facility during the con- t struction period alone for use by the County and for disbursement to local jurisdictions. Additional revenues of $30 million would potentially be available during each l5 year of operation, if tax rates remain at 1981 levels. !
\
These revenues would have a sustained and significantly 4 ; positive impact on the fiscal condition of Benton County i 8.3-19 Amendment 5 ,
, , , - ,~,--,--n.. -
..n . , - , . - - , - , , -n.. .._,__-,-,,a, . , . , ,
r S/HNP-ASC/ER 9/16/82 i and, depending upon the manner in which the revenues are disbursed, upon communities within Benton County. It has been suggested by some (Ref 13) that these property tax revenues collected by Benton County should be shared proportionately with cities, school districts and other jurisdictions where the bulk of the S/HNP work force will reside. Potential inequities in revenues and costs could occur if tax revenues generated by the Project in some 6 jurisdictions were insufficient to pay for government E231.10 services necessitated by the Project in those same jurisdictions. Based on past trends of the WPPSS labor force, the areas most likely to be affected would include Richland, West Richland, Kennewick and Benton City. Under the existing tax system those cities would receive property-tax revenues at the discretion of Benton County 4 Commissioners. Neither Franklin County nor the City of Pasco (also within the immediate impact area) would receive any property-tax revenues emanating from the Project under the existing tax system. Recent amendments to the Washington State tax laws (55B 4859) RCW 82.04, 82.08 and 82.12 make it possible for local ( jurisdictions to redistribute sales taxes from large scale energy projects within a local impact area. Such a redistribution would address the questions of equal distribution of population effects and public service 6 demand in the impact area. Since this law has not been used in a specific case as yet, it is not clear how the distribution of revenues might be accomplished. However, it could serve as a means of mitigating negative impacts during construction and equalizing revenue distribution even where there were no demonstrated negative impacts. Under the baseline scenarios none of these revenues would be available to improve the fiscal condition of Benton 4 County and its local jurisdiction. l 8.3.10 TRANSPORTATION This section describes the anticipated transportation i impacts of the S/HNP. Additional information may be l obtained from the Questions and Responses on pages E-52 6 through E-64. The transportation related analyses and conclusions contained in this section were based upon the assumption that access to the S/HNP will be provided by a new access 7 road connecting the southwest corner of the Project Site to SR 240 (Alternate South Access Road). This access 8.3-20 Amendment 7
S/HNP-ASC/ER 9/16/82 i alternative is described in more detail as Alternative A in Section 8.3.10.5. Another access alternative was con-sidered, in which access to the S/HNP would be provided 7 through construction of a new road connecting the southeast corner of the Project Site to SR 10 (Preferred South Access Road). This access alternative is described in more detail as Alternative B in Section 8.3.10.5. The transportation related impacts associated with Alternative B have been
- separately evaluated, and it has been found that these l
impacts are not significantly different from those expected 6 to occur under Alternative A. Therefore, the transpor-tation analysis and conclusions contained within this section are equally applicable to both access alternatives. DOE advised, in an April 15, 1982 meeting with the Applicant, that it will require use of the Preferred South 7 Access Road (Alternative B) instead of the Alternate South Access Road (Alternative A) shown in Figures 2.1-lb, 2.1-2 and 2.1-3 and that, regardless of whether the Project is built or not, DOE will improve Route 10 by bringing it up 6 to State highway standards for a two-lane road. Therefore, the Applicant will be using the Alternative B access road. 8.3.10.1 EXISTING CONDITIONS i 8.3.10.1.1 Street Network i Figure 8.3-1 shows the locations of existing major streets ! and highways serving Hanford Reservation traffic. Regional highway access to and from the area is possible via U.S. ! Route 12, connecting the Tri-Cities to Yakima and the l Seattle area to the west and Lewiston, Idaho, to the east; l U.S. 395 north to Spokane, and SR 14 west to Vancouver, ! t Washington. I 84 connects the area to Salt Lake City and Portland. SR 240 is a key route that passes near the 6 . l proposed _S/HNP, becomes Bypass Highway in Richland, and l crosses the Yakima River on a pair of two-lane bridges !
- popularly called the " Causeway". A key intersection on j Bypass Highway is with Van Giesen Street, which in turn becomes SR 224 west of Bypass Highway. Routes 10 and 4 !
provide access to the Hanford Reservation. Route 4 becomes ! i
' Stevens Drive in Richland, and a branch from Route 4 to the !
southeast connects to Richland's George Washington Way. { Most of the arterials shown in Figure 8.3-1 are two lanes wide. ! Exceptions are Route 4 on the Hanford Reservation, ! i 8.3-20a Amendment 7 i
. ._ _ _ __ __ _ ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ __ _ _.J
S/HNP-ASC/ER 8/20/82 George Washington Way, Stevens Drive, and Bypass Highway. These arterials are four and f?ve lanes wide. 8.3.10.1.2 Traffic Volumes Existing travel patterns and characteristics in the Tri-Cities area are heavily influenced by commuter travel generated on and near the Hanford Reservation. Figure 8.3-2 shows the 1981 traffic volumes on the existing street network that are currently available. The recent history of traffic volumes on streets in the impact area has been one of growth since the mid-1970's, generally in parallel with the pattern of employment on and associated with the Hanford Reservation. Traffic growth on the Causeway, as shown below, mirrors the year-by-year trend of combined occuring in 1980. DOE and WPPSS even to the " notch" 1 Summary of Traffic Counts for State Highway 240 on the Yakima River Bridge (Causeway) 6 May 76 Oct 77 Nov 78 Apr 79 Jun 79 Feb 80 Apr 81 NB 18,690 21,640 24,000 24,290 19,480 na 25,550 SB 18,700 20,310 23,680 24,430 28,410 na 24,990 TOTAL 37,390 41,950 47,680 48,720 47,890 44,120 50,540 Traffic volume Highway trends on Stevens Drive and the Bypass are similar. time peak The volumes in 1981 were at the all-1981). (Washington State Department of Transportation, Traffic along these routes exhibits some unusual and extreme characteristics. Peak hour traffic near the Hanford Reservation forms a much larger portion of daily traffic (15 to 20 percent) than is usually found in urban areas. Peak volumes (3:30 to 4:30 p.m.) on Stevens Drive south of the Reservation represent 15 percent of daily traffic with 95 percent in the heavy direction. On George Washington Way at the same time south of the Reservation, I the peak hour percentage approaches 19 percent with 96 I percent in the predominant direction. At the critical i Causeway across the Yakima River, the peak hour volume on I Highway 75 percent 240inamounts the peaktodirection. 9.6 percent of the daily volume with particularly those near the Reservation,These high percentages, i show the dominance of commuter traffic to and from Hanford. ! I 8.3-20b Amendment 6 1 l l l
S/HNP-ASC/ER 9/16/82 , i
- 2. Implement one of several alternative strategies involving new access road construction, along with upgrading of existing highways and key inter-sections. These alternatives arc similar in ,
nature, but involve two different access corridors ! 6 connecting the S/HNP Site to Highway 240. These l alternatives are: I Alternative A Construct a new Site access road for construction , worker traffic between the southwest corner of the ' Site and Highway 240 (the Alternate South Access 7 Road shown in Figure 8.3-7). This roadway would
- consist of a two-lane reversible operation (
facility during the work 6ay. The road would ! operate as two lanes for single direction travel i only during the morning and afternoon peak periods: cne-way northbound ingress between 6:00 and 8:30 a.m., and one-way southbound egress " between 3:00 and 5:30 p.m. At all other times, this access road would operate as a two-way facility, with one lane in each direction. This I improvement includes two 14-foot wide travel lanes l l with 8-foot shoulders, and appropriate pavement markings, signing, and control flagmen at each end 6 t g-sx to assure safe and efficient operation (a 4 t ) temporary traffic signal may be required at the j , \/ intersection with Highway 240). This improvement ! wculd include developing the intersection of the l Site access road and Highway 240 to provide dual l left-turn lanes from the access road for the ! afternoon peak egress traffic flow. It would also l require the development of matching dual right-turn lanes from Highway 240 for the morning peak ingress traffic flow. Construct a new Site access roadway for non-construction traffic connecting the east side of the S/HNP Site to Route 10 (the North Access Road 7 ; shown in Figure 8.3-7). This roadway would l operate at all times as a two-lane facility, with ; one lane in each direction. This improvement i includes two 14-foot wide travel lanes with 8-foot s shoulders, and appropriate pavement markings and ! 4 signing to assure safe and efficient operations. { Widen Highway 240 between the intersection with 6 )' the new Site access roadway and Bypass Highway to provide two lanes for regular travel, plus two { shoulder lanes for high occupancy vehicle (HOV) ! use during the morning and afternoon peak traffic ; perieds on work days. This improvement is shown ( on Figure 8.3-7. The shoulder HOV lanes would be ' 8.3-20k Amendment 7 { r.- - ,-v ~
i S/HNP-ASC/ER 9/16/82 l l I l used only during the peak periods by high l occupancy vehicles carrying a minimum of two t l persons. The HOV lanes would be used between 6:00 l and 9:00 a.m. by traffic traveling to the Site; i and between 3:30 and 6:00 p.m. by traffic traveling away from the Site. At all other times, the road would operate as a two-lane facility, ! 4 with one lane in each direction. This improvement j includes two 12-foot trave] lanes with 12-foot I shoulders to be used as HOV lanes, modifications of the railroad grade crossing near the Bypass l Highway, widening of intersections, additional j i embankment to accommodate the shoulder lanes, and ; appropriate pavement markings and signing to j 6 assure safe and efficient operation. Temporary ; signals or officer control may be required at the intersection with Grosscup Road and the j intersections serving the Richland industrial j areas west of Bypass Highway. Alternative B This alternative is identical in concept, design, j and operation to Alternative A, but uses a , i different construction worker access route: a new two-lane reversible operaticn Site access road would be constructed for construction-worker i O'~' traffic between the southeast corner of the Site and Route 10 (the Preferred South Access Road 7 [ shown in Figure 8.3-7). This access road would replace the access road connecting the southwest corner of the Site to Highway 240 under ! Alternative A. Route 10 would be improved to state standards for , 4 a 2-lane highway, and would operate as a l reversible facility during both the morning and i afternoon peak hours between the new Site access l road and Higwhay 240. During these peak hours, ' reverse-flow Site-related traffic (outbound during the morning peak hour and inbound during the evening peak hour) would be accommodated via . j Route 4. Throughout the off-peak hours, Route 10 D l would continue to operate as a two-way facility I with one lane in each direction. The section of i Highway 240 between Route 10 and Bypass Highway l would be improved as under Alternative A. j i
- 3. Improve the intersection of Highway 240 and Bypass I Highway to provide a dual right-turn lane for east- I bound to southbound traffic, and a matching dual l left-turn lane for northbound to westbound traffic. Traffic stqnal modifications, including a separate left-tur. phase, would be made as required to assure safe and efficient operation.
8.3-21 Amendment 7
1 1 1 S/HNP-ASC/ER 8/20/82 i i l l
- 4. Improve the intersection of Bypass Highway and Van Giesen to provide a dual left-turn lane for '
northbound to westbound traffic. Both approaches on Van Giesen would be widened to provide for two through travel lanes. Also, two westbound laner would be provided on the west leg across the railroad tracks. Signsi modifications would be made as required to assure safe and efficient operation. Puget Power would also be willing to consider participating in an ongoing rideshare matching, promotion, ard an incentive program with other agencies on the Hantord Reservation. The purpose of this program would be to increase the average vehicle occupancy above current levels. It is expected that this program would include
- special incentives such as preferred parking for carpools and exclusive high-occupancy vehicle (HOV) lanes.
The transportation improvements identified above are in conformance with the following documents recently adopted by the Benton-Franklin Governmental Conference: l 1. Transportation Improvement Program for Calendar l Years 1982, 1983 and 1984. 6
- 2. The Regional Land Use Design Map.
3. The Highway Functional Classification Map. These documents are currently being incorporated into the BFGC's Comprehensive by the first of 1983. Plan, which is expected to be adopted I 1 traffic control measures will be implemented in a ( nner that is consistent with the State Highway mmission's adoption of the 1978 Manual on Uniform Traffic Control Devices (MUTCD), and interpretations thereof. All new roadway facilities will be designed in accordance with j applicable local, county, state, and federal design standards. Maintenance of the new/ improved facilities will be the responsibility of the appropriate jurisdiction. The mitigating measures listed above and the estimated impacts on the V/C ratios of these measures as identified in Figure 8.3-6 are based on a street network including I-82 and I-182 freeways as well as the improvement of Grosscup Road and Twin Bridges. I-182 alters construction worker travel patterns by providing an alternative and shorter pathway to Pasco and Franklin County. The improve-ment of Grosscup Road and Twin Bridges facilitates access to the west Richland area (but is not estimated to attract a significantly increased volume of commuter trips). If, in addition to these improvements, the Horn Rapids Bypass 8.3-22 Amendment 6
S/HNP-ASC/ER 9/16/82 ' is implemented in time to serve S/HNP commuter traffic, it could serve as a viable alternative route (via I-82 and I-182) for traffic desiring to cross the Columbia River on I-182 or the Yakima River on the Causeway. It is estimated that this route could divert as much as half of the S/HNP commuter traffic away from Route 240 and Bypass Highway. From this standpoint, the Horn Rapids Bypass is a viable mitigating measure. However, the estimated cost of the new Bypass Highway would be two to five times that of the miti- 6 gating measures listed above. ' Specific mitigating measures associated with travel by modes other than the automobile have not been listed. It is doubtful that scheduled transit service would be available to the S/HNP Site during construction, but special charter bus operations have proven successful in transporting workers to major employment centers. 8.3.11 HOUSING 4 8.3.11.1 Existing and Projected Housing Infrastructure Population growth in the Tri-Cities has been accompanied by l7 l a corresponding expansion of the housing stock. The total i number of housing units in Benton County rose from 21,826 I in 1970 to 42,651 in 1980, a 95 percent increase. In Franklin County, the number of housing units rose by 58 L percent, from 8,425 in 1970 to 13,316 in 1980 (Ref 1). This trend is evident by referring to the data in Table l 8.3-12. Between 1976 and 1980, the total number of housing l units in the increased by combined Richland-Kennewick-Pasco urban area 39 percent. I Apartments comprise over one-half F of all new units. The greatest increases in housing stock occurred in Kernewick, where total units increased by 52 F l percent in four years. '
)
Vacancy rates for recent years are reported in Table 4 l 8.3-13. As these data indicate, there is a general trend ! l toward an increased number of vacancies. ! Total residential building permits dropped from 1,813 in i 1979 to 553 in 1980. Only 178 residential building permits I were issued during the first quarter of 1981 (Ref 15). If ' that level of activity were maintained throughout the ! remainder of the year, total 1981 building permits would [ amount to about 10 percent of the 1979 total. Given prior i rapid housing construction, the local residential con- l struction industry is presently operating far below l k J 8.3-23 Amendment 7
S/HNP-ASC/ER 9/16/82 capacity, a situation which is unlikely to be reversed while interest rates remain high (Ref 15). ! 8.3.11.2 Projected Housing Conditions Under Alternative Scenarios All four scenarios posit out-migration of construction and secondary workers over the 1982-1991 period. Coupled with decreased growth rates and diminished in-migration, in-creased housing vacancies are projected in each case with the highest vacancies occurring in Scenario 4. For 4 example, it is projected that approximately 4,255 house-holds would leave the area between 1982-1986 under Scenario
- 4. I The scenarios projecting construction of S/HNP suggest that over the next decade a number of individuals who would have otherwise migrated from the area during 1982-1992 will remain and provide support for the housing market. For example, in the case of Scenario 3 as compared to Scenario 4, it is projected that construction of S/HNP will enable approximately 3,000 construction and secondary workers to remain in the Tri-Cities area over the period 1983-1986.
This diminished outmigration of 2,308 households would have l7 a significant positive impact upon the housing market. ! One major factor in housing values is the demand, and the increased employment and income effects of the project would increase the demand. The available data on Benton and Franklin Counties real estate sales during the four l year period, 1975 to 1978, show increasing values as the WPPSS construction work force increased. The number of sales increased from 6,967 in 1975 to 9,779 in 1978, a 40 percent increase for the period. The amount of sales increased from $160 million in 1975 to almost $377 million 6 (in current dollars) in 1978, a 136 percent increase during the period. The average value of each sale increased from about $23,000 to over $38,500 (Ref 25, p. 16). Such increases in property values in communities with nuclear power stations have also been documented in the research literature (see, for example, Ref 28) . While the increase in property values can be considerably less in the future, especially in an area with a decline in demand, the added employment and income from the project will support those i values. It is possible that property values under any l scenario will not be any higher than they are now when 7 l measured in 1980 dollars. During operation, it is estimated that less than 100 new 4 families would move into the area and, consequently, the positive impacts on housing and property values due to project related in-migration will be quite small. 6 8.3-24 Amendment 7
i S/HNP-ASC/ER 9/16/82 f l
! I construction of S/HNP, however, differs from the baseline scenarios in that it would: f l
(a) Diminish out-migration of households and students over the 1983-1988 period. For instance, the difference between Scenarios 3 and 4 is approxi- i mately 1,000 students remaining in the area due to i i construction of S/HNP. { i (b) Maintain State funding for these students and i reduce the need for staff reductions in the school ! systems. f t (c) Reduce the need for special levies in the local ! area to finance non-basic educational activities of local school systems. I
! (d) Increase the tax base of the Richland School i District by such a magnitude that the special levy [ ; for residents of Richland would be virtually nil.
Under the baseline scenarios none of these beneficial 4 4 impacts would occur. ( f During operation, it is projected that less than 100 I students would be added to enrollments of schools within ! s the SMSA. i
; 8.3.13 UTILITIES
't 8.3.13.1 Existing and Developing Conditions
{ I' Water Supply Systems Although there are small non-profit and private water systems serving limited numbers of customers in peripheral t ] areas of the counties, the systems supplying Richland, ! Kennewick, Benton City and West Richland serve over 90 [
; percent of the total water system customers in Benton !
County, while the majority of Franklin County water cus- ; tomers are served by the Pasco supply system. ! i I 1 In the City of Richland, the water supply system is cur- 1 rently operating at 84 percent of capacity. In 1980, peak I l' demand was approximately 37,000,000 GPD and pumping l7 capacity was 47,200,000 GPD (Ref 15). In Kennewick, 1980 demand on the water supply system was 94 4 percent of the 22,000,000 GPD pumping capacity (Ref 16). I r 8.3-27 Amendment 7 ; l i
. - - - - . - - - . -._ .--.-.--.-.---.f
S/HNP-ASC/ER 12/21/81 Substantial upgrading of the system capacity is scheduled for completion in 1984-85. The Pasco water system currently has the capacity to pump 18,500,000 GFD, exceeding peak daily demands of about 14,600,000 GPD. A new $650,000 water line project was recently approved to permit major industrial expansion in the southwest section of the municipality. In West Richland, data reported by the Benton County Planning Department in 1980 indicated average daily demand levels of 640,000 GPD, just 32 percent of the 2,000,000 GPD pumping capacity (Ref 17). Similarly, the Benton City water system has substantial excess capacity, with data reported in 1980 indicating that average daily demand levels were 7 percent of pumping capacity. Waste Water Treatment The Kennewick system is operating at 72 percent of the 90,000 population capacity. The Pasco wastewater treatment facility is operating at about 26 percent of capacity. The Richland wastewater system is near capacity, with data reported by the Benton County Planning Department indi- 4 cating that system demands were approaching 90 percent of capacity by 1980 (Ref 17). Both Benton City and West Richland have experienced treatment demands which exceed current system capacities. Improvements are planned in both communities (Ref 17). Solid Waste Solid waste disposal in the area surrounding the Tri-Cities is accomplished by a combination of public/ private systems. Wastes collected in Richland are disposed in a sanitary landfill operated by the city in the Horn Rapids area. Wastes from Kennewick, Benton City, West Richland and Pasco are disposed in the sanitary landfill operated by the city l of Pasco. Although at present solid waste disposal in the area is by conventional landfill procedures, there have been several recent proposals to develop energy extraction facilities which would burn solid waste materials (Refs 12-7, 12-8). l Other Utilities l The Tri-Cities and the surrounding area are provided electrical service by several public utility agencies. In Benton County, about 66 percent of the electric utility customers are served by the Benton City PUD. The cities of 8.3-28 Amendment 4
l S/HNP-ASC/ER 9/16/82 ! Richland and West Richland are provided with electrical
- supplies by Richland Energy Services, which is currently 4 i
operating at about 80 percent of capacity but is being expanded. About 9 percent of the electric utility cus-tomers in outlying areas of Benton County are serviced by l7 the Benton REA. In Franklin County, most localities, including Pasco, are supplied by the Franklin Public Utility District. The primary supplier of telephone services in the Tri-Cities vicinity is the General Telephone Company of the i Northwest, which supplied service to over 90 percent of all Benton County customers, including those in Richland, Kennewick, West Richland and Benton City. The remaining Benton County telephone custotters are served by United Telephone Company of the Northwest. In Franklin County, Pasco is provided tele, hone services by the Pacific Northwest Bell Telephone Company. 8.3.13.2 Projected Utility Service Conditions Under Alternative Scenarios i Under the baseline scenarios, out-migration and decreased 4 growth rates are projected. Further, declines in employ-s_ , ment, income and the local economy are anticipated. This economic slowdown would result in decreased revenues and f rce local jurisdictions to forego planned utility expan-aions and improvements in service. There would be less demand on the current capacities of utility services. Finally, with the lower population in the baseline scenarios, special levy rates may increase. The construction scenarios depict a more dynamic economy with higher tax revenues at present tax rates. Local jurisdictions would be able to improve services when compared to the no-project scenarios. In all cases except Scenario 2, a decline in population is estimated and, therefore, a decline in demand for services. For Scenario e 2, a slight increasing trend (0.6 percent average annual growth rate) is shown to the year 1987, declining there-after. I
- k 8.3-29 Amendment 7
S/HNP-ASC/ER 8/20/82 8.3.14 PUBLIC SAFETY 8.3.14.1 Existing and Developing Conditions 4 Police protection is provided by sheriff's departments in Benton and Franklin Counties, local municipal police departments and the Washington State Patrol division headquartered in Kennewick. Table 8.3-16 provides descrip-tive data on the staff size and number of patrol cars available to each of the counties and the municipal police departments in the immediate Tri-Cities vicinity. Table 6 8.3-17 shows the 1980 crime rates for the area. Jail facilities in the impact area include county jails in soth Benton and Franklin counties, as well as separate city jails in Richland, Kennewick and Pasco. Both property and violent crime rates are below those experienced in other parts of Washington. During 1979, for 4 example, the rate of violent crime per 100,000 residents was 370.2 in the Tri-Cities, compared with 659.5 in Yakima, 395.5 in Spokane, and 434.6 for the state (Ref 18). Table 6 8.3-16a lists crime rates for the Tri-Cities SMSA in 1980. E230.06 Current jail facilities are inadequate and state-mandated
- impr.ovements in Benton County jail facilities have resulted in the recently-initiated construction of a new 109-bed county jail, scheduled to replace the existing 33-bed jail in 1983. The new facility will also house an expanded county justice center comprised of courtrooms and the county sheriff offices. With completion of this facility, prisoner overloads currently experienced at the Benton County, Franklin County, and Richland and Kennewick jails 4 will be eliminated. In addition, a new juvenile detention and court facility operated jointly by Benton and Franklin counties in Kennewick opened in 1980.
Fire protection in the Tri-Cities area is provided by municipal fire departments, and by fire protection units for specific service areas in Benton and Franklin counties. The various departments serving the impact area are listed in Table 8.3-17 along with data on staff size, number of volunteer fire fighters, the service area covered, ano the 6 ISO rating. Only Pasco and Richland maintain exclusively full-time non-volunteer fire departments. These independent departments are engaged in. mutual aid programs 4 to insure cooperation in emergency situations. O 8.3-30 Amendment 6
S/HNP-ASC/ER 8/20/82
- 8.3.17 RIVATE SECTOR
- 4 ,
1 8.3.17.1 Existing and Developing Conditions Many of the employment and income effects of S/HNP have 6 been discussed in Section 8.3.8. The impacts resulting i from these effects can be put in perspective by reference ! to the private sector capacity that has been built up over i the past decade. The Tri-Cities is characterized by a well developed private business sector: ( t k Number of I 4 Type of Business Establishments Building Supplies and Garden Supplies 44 General Merchandise Stores 19 ' Food Stores 88 New and Used Car Dealers 20 ' Gasoline Service Stations 60 i i Apparel and Accessory Stores 68 Eating Places 135 : Drinking Places 36 ' Drug Stores and Proprietary Stores 30 i Banking Establishments ' 24 Real Estate Establishments 137 Business Services 94 i Automobile Repair Shops 46 l Amusement and Recreation Establishments 19 ! , Health Services 181 ( Personal Services 95 ! t i There are over 2,300 hotel and motel rooms in the immediate i 4 Tri-Cities vicinity with an average occupancy rate of G5 l percent (Ref 21). There are over 4,000 service establishments and 32 shopping j centers and malls in the Tri-Cities area. ; 1 ! ! Expansion of the private sector continues to occur, as l l evidenced by a recent proposal to construct a S40 million ! l shopping mall in Richland (Ref 12-10). 8.3.17.2 Projected fr.vate Sector Conditions Under ! Alternativb~$cenarios ' r Under the baseline scenarios a declining economy is pro- f jected. Out-migration of workers, declines in per capita ;
'g income and less business activity would result in lost 8.3-35 Amendment 6 .
S/HNP-ASC/ER 9/16/82 sales, layoffs, business closings and in some cases, e,, bankruptcy. 4 The construction scenarios would result in jobs and income for both construction and secondary workers. This con-tribution to the economy would stimulate local purchases and support business activity. The economic support for the local economy would be a significant addition to the 6 conditions that would be expected to exist without the S/HNP. i l7 Nons of these economic contributions to the private sector would occur under the baseline scenarios. ' 4 During operation, it is anticipated that over SS million per year in purchases from local businesses would be made. The S/HNP would make a continuing contribution to the local economy that would not occur with the baseline scenarios. 6 8.3.18 RECREATION AND LEISURE 8.3.18.1 Existing and Developing Conditions Recreational and leisure facilities and opportunities covering a broad spectrum of participant and spectator activities are available in the Tri-Cities area under the administration of municipalities, county governments, the State of Washington, federal entities, and private firms and organit?.tions. There are 36 city parks located in the Tri-Cities, operated under the supervision of the three municipal Parks and Recreation departments (Ref 16). 4 Benton County Parks and Recreation Department manages Columbia Park, providing a four-mile waterfront area, camping areas, boating facilities, picnic areas, hiking, , swimming, golf, an archery range, and access to swimming, i fishing, and picnicing facilities at Two Rivers, Hover, l Horn Rapids and Plymouth Parks. There are approximately 1,400 acres of developed public park lands and 3,650 undeveloped acres in Benton County (Ref 17). T The State of Washingon maintains facilities for swimming, fishing, boating, picnic areas and other uses at Sacajawea State Park, located near the juncture of the Snake and Columbia rivers in Franklin County. Other state parks, including the 3,710 acre Sun Lakes State Park, are also O. 8.3-36 Amendment 7 l
S/HNP-ASC/ER 8/20/82 accessible from the Tri-Cities. Similar activities and facilities plus overnight camping facilities are locally available in Levy Park and Fishhook Park, both administered 4 by the U.S. Army Corps of Engineers and the Corps maintains recreation and tourist facilities at Ice Harbor Lock and Dam. Table 8.3-20 provides an overview of physical and par- [6 ticipant recreation opportunities for Tri-City residents. Spectator sports and leisure activities available in the area include movie theatres, a full range of television and radio stations, several forms of racing and amateur sports teams. Cultural attractions include the Benton County Historical Museum, several art galleries, and performing arts productions. Expansion of recreational and leisure opportunities include a new city park in Kennewick, a proposal to re-open a swimming park under the management of Benton County, a baseball field developed by the Kennewick American Legion, and a water amusement park to be developed by a private 4 firm in Kennewick. The availability of such activities will expand with the development of a planned multi-use arts and entertainment center in Kennewick (Ref 12-11), and a proposed $16 million arts center in Richland (Ref 12-12). Several innovative park facilities have been proposed, including an off-road vehicle (ORV) park under construction by the city of Richland (Ref 12-13). 8.3.18.2 Projected Conditions Under Alternative Scenarios The baseline scenarios project decreased population levels and thus suggest decreased use of recreational facilities in the area. This lower usage may result in decreased hours of operation and/or the closing of some recreational facilities. I ,
\
Under the construction scenarios, a more dynamic economy l and reduced out-migrativ.. are projected. Both of these ' conditions would provide support for recreational facil-ities in the area. O 8.3-37 Amendment 6
l l S/HNP-ASC/ER 9/16/82 8.3.19 LIBRARIES 8.3.19.1 Existing and Develoi ng Conditions The Tri-Cities area contains several library facilities, 4 the most extensive of which are operated by the Mid-Columbia Library. Richland and Prosser have their own public libraries. The Mid-Columbia Library is centered in Kennewick and maintains branches and services throughou: the SMSA. At the end of 1980, Mid-Columbia had a total of 218,086 volumes, Richland had 120,270 volumes and Prosser had 23,983 volumes. 7 8.3.19.2 Projected Conditions Under Alternative Scenarios The major impact of the Project on the Mid-Columbia Library will be to provide a significant source of new revenue. Mid-Columbia depends upon property tax revenues to develop 4 and maintain its services. For example, in 1980, $386,715 in revenues were obtained via Real and Personal Property Taxes. This figure represented over 43 percent of all revenues for the year. Given the fact that the S/HNP is within the taxing purview of the Library (through Benton County), it can be expected that the proposed facility will generate significant tax revenues and enable the Library to improve and expand services. For example, if the Project were to be valued at $ 2.9 billion (in 1980 dollars) and taxed at 1981 rates, an annual total of $690,000 of additional funds would potentially be received by Mid- 7 Columbia Library. Under the baseline scenarios none of these funds would be 4 availeble to the Library. l
)
9 8.3-38 Amendment 7 J
S/HNP-ASC/ER 12/21/81 3 l i , References for Section 8.3 I
- 1. Census of Population (1980) and Housing, Advance [
Counts, U.S. Bureau of Census, U.S. Government i Printing Office, Washington, D.C. (1981). I
- 2. Population, Tri-Cities Chamber of Commerce, Tri-Cities, Washington (no date). *
, 3. 1979 Personal Income Data for Counties and SMSAs Available, BEA 81-27, U.S. Department of Commerce, jl Bureau of Economic Analysis, Washington, D.C. (May 20, ! 1981). l t
- 4. Annual Planning Report 1981 Richland-Kennewick-Pasco l
SMSA, Washington State Employment Security Department, ! Research and Statistics Branch (July 1981) . !
- 5. Taxation of Energy Generating Facilities During f
- Construction and Operation, Washington State !
Department of Revenue, Research and Information l Division (July 1977) . i g lI j 6. A Review of Hanford Economic Forecasts and Deter- f mination of the Feasibility for a Battelle Update, a O report by Keith E. Yandon to Battelle Pacific North-west Laboratory (November 1978). f
- 7. Badger Mountain Community Plan 1979, prepared by i Richland Physical Planning Commission, Richland, Washington (February 5, 1979).
, i l' 8. Labor Area Summary, prepared by Dean Schau for [
Washington State Employment Security Department, Pasco, Washington (July 1981, August 1981, and July {; 1981). j t
- 9. " Commuting Patterns of Rural Industrial Employees," {'
Frank Clemente and Gene F. Summers, Social Forces, 54:212-19 (1975). !
- 10. 1980 Bureau of Economic Analysis Regional Projections, ,
i U.S. Department of Commerce, Washington, D.C. l 11. Socioeconomic Impact Study WNP 1 & 4, Volume 4: Final s : , Report, prepared by Community Development Services, j l Inc. for Washington 'caol.; ilower Sapply System, , Seattle, Washington (May 1979) . ! l 12. Tri-City Herald, McClatchy Newspapers, Pasco, I l Washington. l i 8.3-39 Amendment 4 i l i _ . . _ . _ _ _ __ _ __ . . - . . _ . . . _ . _ . . _ __ . _ . . _ _ _ . , , . . _ _ . _ . . , _ . _ . . _ . - _l
S/HNP-ASC/ER 9/16/82
- 1) " Doubling of Benton City tax asked," 3/8/81.
- 2) "Richland studies rise in property tax levy,"
3/17/81.
- 3) " Commuter airline plans non-stop Seattle flights,"
8/4/81.
- 4) " Patrol to crack down on Hanford traffic violations," 4/19/81.
- 5) "Hanford traffic jams getting worse, say workers,"
5/17/81.
- 6) "Kennewick enrollment tops 11,000 students,"
9/9/81.
- 7) "Tri-Cities seek way to make garbage pay," 5/7/81.
- 8) " Plant near prosser turns waste into power for PUD," 6/9/81.
- 9) " Cooperation marks trauma center meet," 4/22/81.
- 10) " Shopping mall planned in Shav-Na-Pum gold course site," 5/12/81.
- 11) " Multi-use center accords signing to be asked tonight," 8/4/81.
- 12) "Richland plans $16 million parts center,"
2/15/81.
- 13) "Richland to seek ORU Park," 6/2/81.
- 14) "Tri-City Jobless Rate..." 6/28/82.
- 15) "Richland Cuts School Budget by $1.9 Million,"
8/18/82.
- 16) " Tough Times on Tri-Cities," 8/1/82.
- 17) "Tri-Cities, State Jobless Figures Hold Line,"
8/27/82.
- 13. Neal J. Schulman et. al., Mid-Columbia Construction Impact Group, April 9, 1981.
- 14. Skagit/Hanford Traffic Analysis, Cottingham Transportation Engineering, Seattle, WA 1981.
- 15. Tri-Cities Real Estate Research Report, Volume 4, No.
1, prepared by Tri-Cities Real Estate Research Report Committee in Cooperation with the College of Business and Economics, Washington State University (Spring 1981).
- 16. Greg Easton, Williams Kuehelbeck and Associates, 1981.
- 17. Preliminary Draft Comprehensive Plan - Benton County, Washington, prepared by The Benton County Planning Department, Prosser, Washington (March 1980). ,
- 18. F.B.I. Uniform Crime Reports, Crime in the United States, 1979, Federal Bureau of Investigation, U.S.
I Department of Justice, Washington, D.C. (1979).
- 19. Physician's Reference Manual, Benton-Franklin District l Health Department, Richland, Washington (no date).
8.3-40 Amendment 7
S/HNP-ASC/ER 9/16/82 0' 20. Mid-Columbia Mental Health Center, Mid-Columbia Mental Health Center, Richland, Washington (no date).
- 21. Tri-Cities Hotel-Motel Information for 1981, Tri-Cities visitor & Convention Bureau, Tri-Cities, Washington (no date).
- 22. Construction Worker Profile, Mountain West Research, Inc., December 1975.
- 23. Migration and Residential Location of Workers at Nuclear Power Plant Construction Sites, Volume II:
Profile Analysis of Worker Surveys. Suresh Malhotra and Diane Manninen, Battelle Pacific Northwest Laboratories, September 1980.
- 24. Employment by Type and Broad Industrial Sources, 1976-1979, U.S. Department of Commerce, Bureau of Economic Analysis, April 1981.
- 25. RERC, 1979, Tri-Cities Real Estate Research Report.
Tri-Cities Real Estate Research Committee, Kennewick, WA., Autumn 1979.
- 26. Potential Site Study, Proposed Skagit/Hanford Nuclear Project at the Hanford Reservaton, by URS Engineers for the St&te of Washington Energy Facility Site Evaluation Council, December 15, 1981.
- 27. Draft Environmental Statement related to the Construc-tion of Skagit/Hanford Nuclear Project, Units 1 and 2.
April 1982.
- 28. H. B. Gamble, et al, Ef fects of Nuclear Power Plants on Community Growth and Residential Property Values.
U.S. Nuclear Regulatory Commission, NUREG/CR-0454, Washington, D.C., November 1978.
- 29. Construction Budget, Nuclear Project No. 2.
Washington Public Power Supply System, Richland, Washington. t l 8.3-41 Amendment 7 f ! i
._ . _ . _ . _ ___.. _ _ _ . .. _ _ -..._ - .. ,_ _ ,_ ._ ..,._.,._ - _ _ ,___ ,_I
S/HNP-ASC/ER 9/16/82 \
)
TABLE 8.3-16 1981 LEVIES FOR PROPERTY TAXES IN BENTON COUNTY Taxing 1981 Levy (l) Limit set by Law (1) 6 Distribution
)
State $ 3.5743 $ 3.60 County .9800 1.80 County Road 1.3619 2.25 Rural Library .2955 .50 Port of Benton .3238 N/A School District 400 1.7217 N/A TOTAL $ 8.2572 $ 8.15(2) 7 Regular (3) 6.4886 Special 1.7686 V (1)In dollars per $1,000 of assessed value. Increase in taxes on regular levies limited annually to 6% of previous year tax receipts, exclusive of new construction. (2) Limit f or unincorporated areas is 9.15; may be exceeded by special vote. (3) Includes state, county (0.9331) , county road, Port of Benton, and rural library. Source: Benton County Assessor, 1981. N.
) -
J Amendment 7
TABLE 8.3-2 Sheet 1 of 2 4 ESTIMATED CONSTRUCTION COST AND POTENTIAL PROPERTY TAX REVENUES DURING CONSTRUCTION (1) (in current dollars) Total Cost of Cumu- Potential Revenue to:(3) Construc- lative Benton Trans- tion (2) Cost State County Total Year Planta Fuel mission (S000) ($000) ($000) ($000) ($000) through 1979 $ 231,519 $ -- S S 231,519 $ -- S S -- S -- 1980 24,295 -- -- 24,295 255,814 -- -- -- m 1981 21,550 -- -- 21,550 277,364 -- -- -- g 1982 55,390 -- -- 55,390 332,754 -- -- -- z 1983 178,729 -- -- 178,729 511,483 -- -- -- 7 1984 273,672 -- - - - 273,672 785,155 2,806 3,677 6,483 g 1985 426,993 -- -- 426,993 1,212,148 4,333 S,676 10,009 o 1986 693,550 -- -- 693,550 1,905,698 6,812 8,924 15,736 D 2 1987 877,469 -- -- 877,469 2,783,167 9,948 13,033 22,981 1,119,595 3,902,762 13,950 18,276 32,226 6 1988 912,100 206,275 1,220 1989 580,811 74,255 13,997 669,063 4,571,825 16,341 21,409 37,750 1990 494,684 242,301 3,352 740,301 5,312,126 18,987 24,876 43,8C3 1991 301,756 87,225 7,569 396,550 5,708,676 20,405 26,733 47,138 1992 228,739 -- 886 229,625 5,938,301 21,225 27,808 49,033 Total $5,301,221 $610,056 $27,024 ,$5,938,301 $5,938,301 $114,807 S150,412 $ 265,219 l M l e5 l E
,g aIncludes personal property liability. R D o I
m bm l O . O - O
TABLE 8.3-2 Sheet 2 of 2 l Total 6 Cost of Cumu- Potential Revenue to:(3) - Construc- lative Benton Trans- tion (2) Cost State County Total Year Planta Fuel mission ($000) ($000) ($000) ($000) (S000)
$=
(1)All values for demonstration only are subject to change. The numbers are escalated at 7 g 8 percent per year to account for inflation. : (2)The total value of the Plant includes the cost of construction plus the value of the l4 Q property and allowance f or Funds during Construction (AFDC), Sales Tax and Property M Tax, which total the $8 billion plant valuation (in current dollars). :7 l 5 (3) Based on 1980 levies (1981 taxes): (a) State = $3.5743 per M (b) Benton County: $4.6829 per M (1) County: $.98 per M (2) Library: $.2955 per M 4 (3) Port Benton: $.3238 per M g (4) Road District: $1.3619 per M o (5) Richland School District: g $1.7217 per M , 5 D a R a
O O O TABLE 8.3-3 4 TAX BASE INCREASES FROM S/HNP (ASSESSED VALUATION INCREASES IN 1980 DOLLARS) l6 4 1981 Assessed Total Assessed Increase S/HNP as Taxing Valuation Valuation with in as Percent Jurisdiction (S000) S/HNP Valuation of Total (1980 dollars) 6 Benton County $2,720,630 $5,120,630 88 % 46.9 % m Library 853,018 3,253,018 281 % 73.8 % D i g i Port of Benton 1,303,086 3,703,086 153 % 64.8 % $ o Road District 853,018 3,253,018 281 % 73.8 % 5 D:o Richland School District 1,186,743 3,586,743 202 % 66.9 % NOTE: Data presented as illustrations only and subject to change. The " Increased in Valuation due to S/HNP" column is based on 1981 valuation levels and an assumed plant value in 1980 dollars of 2.4 billion (80 percent of 2.9 billion). l7 8 - a R u km 1
.. . , . .s , - . , ~ . , , _ , . . . . . . . , - - --...,,,-.---,.,,..--.--,.-,,-.--,--.---.-,--,-~.--.<---.,-~,,,-_re. .-___,,--,-----4_,,.-,--,,,,-m--,--._.- - - , - . . - , , _ , - . . _ _ . - . . . - , _ . , _ . . . . . , - , _ . .
1 TABLE 8.3-4 i i LOCAL POPULATION, 1940-1980 1970-1980 1940 1960 1970 1980 Percent Growth Benton County 12,053 62,070 67,540 109,444 62.0 l l Unincorporated Areas 7,529 18,958 20,907 32,655 56.2 ) Incorporated Areas 4,524 43,112 46,633 76,789 64.7 l Benton City 640 1,210 1,070 1,980 85.0 l Kennewick 1,918 14,244 15,212 34,397 126.1 Prosser 1,719 2,763 2,954 3,896 31.9 R Richland 247 23,548 26,290 33,578 27.7 m West Richland -- 1,347 1,107 2,938 165.4 5 t 4 > l Franklin County 6,207 23,342 25,816 35,025 35.7 g N Unincorporated Areas 1,650 7,520 10,153 14,619 44.0 y Incorporated Areas 4,557 15,822 15,663 20,406 30.3 Pasco 3,913 14,522 13,920 17,944 28.9 Tri-Cities SMSA -- -- 93,356 144,469 54.8 Scurces: Bureau of the Census. 1980 Census of Population and Housing, Advance Reports. Final Population and Housing Unit Costs: U.S. Department of Commerce. U.S.
> Government Printing Office: Washington, D.C.
3 Bureau of the Census. 1940, 1960, 1970 Census of Population, Characteristics of C
$ the Population. U.S. Department of Commerce. U.S. Government Printing Office: D
( $ Washington, D.C. ( w l
", n.
O O O
S/HNP-ASC/ER 9/16/82 l l l TABLE 8.3-14 ENROLLMENTS AND CAPACITY OF SCHOOL DISTRICTS School Current Nonutilized District 1979-80 1980-81 Capacity capacity Columbia 885 886 1,129 243 (#400) 4 i Finley 903 902 1,163 261 ' (#503) : Grandview 2,217 2,175 2,783 608 l (#116-200) ' Kennewick 10,767 10,604 11,290 686 (#017) Klona-Benton 1,164 1,163 1,625 462 l7 (#052) Othello 2,413 2,315 2,603 288 (#147-163-55) Pasco 5,490 5,535 7,016 1,481 (#001) , 4 i Prosser 2,012 2,007 2,312 305 (#116) i i Richland 8,559 8,308 10,103 1,795 ; (#400) Sunnyside 3,548 3,412 3,770 358 (#201) l7 ! TOTAL 37,958 37,307 43,794 6,487 l i 4 L Sources: Of fice of Superintendent of Public Instruction, , Olympia, September, 1981. I f t i f l 'N i i l i Amendment 7 l
i TABLE 8.3-15 l ! AVERAGE ANNUAL FTE PUPILS PER TOTAL CERTIFICATED STAFF, 1 AND EXPENDITURES PER PUPIL, 1979-80 Pupils Total Per FTE School certificated Certificated Expenditures District Staff Staff Per Pupil Columbia 51.7 16.5 S2,110.91 Finley 48.5 18.2 2,192.08 m Grandview 119.6 17.7 2,178.28 N! z 4 Kennewick 594.7 17.2 2,069.60 7 Kiona-Benton 55.4 19.8 1,991.85 m Othello 134.1 16.8 2,381.61 31 Pasco 293.2 17.6 2,386.47 Prosser 110.8 17.3 2,125.18 Richland 479.3 17.3 2,221.25 Sunnyside 1P3.8 18.4 2,386.66 State of Washington 42,441.7 17.2 2,344.32
@ Source: Office of Superintendent of Public Institution, Olympia, May, 1981.
3 U g s a N E 2; n ~
/
O - O O
G J v' TABLE 8.3-17 FIRE PROTECTION PERSONNEL WITHIN TRI-CITIES AREA Staff Fire Protection ISO Unit Rating Full-Time Volunteers Total Service Area 6 j Kennewick 5 33 15 48 City l Pasco 5 26 0 26 City Richland 3 42 0 42 City ) BCRFD#1 8/9 1 126 127 Kennewick Area BCRFDf2 8/9 1 17 18 Benton City @ BCRFD#3 8/9 1 11 12 Prosser Area BCRFDf4 8/9 1 17 18 West Richland 5 BCRFDf5 9 1 68 69 Southeast of Prosser FCRFDf3 8/9 3 65 68 Surrounds Jtty of Pasco NOTE: There are " Mutual Aid Agreements" between all fire districts in the area. The "Tri-Cities Mutual Aid Agreement" (September 15, 1980) includts the cities of
> Pasco, Kennewick, Richland, BCRFDs fl, 92, 83, FCRFDf3, Walla Walla County and the 6 rY3 Rockwell Hanford Fire Protection Department. ISO ratings are reported in Public l Protection Classif ication Manual: Washington State (1981).
E , t D a R n
S/HNP-ASC/ER 12/21/81 TABLE 8.3-18 Sheet 1 of 2 EXAMPLES OF HUMAN SERVICES FACILITIES AND ORGANIZATIONS IN THE TRI-CITY SMSA Facility or Organization Descriptive Comments 911 Emergency Dispatch Cntr Provides immediate referral to emergency information and dispatch of ambulance, fire, police, etc., services. Benton-Franklin Association Counseling, recreation, for Retarded Citizens transportation and referral services for learning-disabled individuals. Benton-Franklin Provides services and pro-Developmental Center grams for developmentally disadvantaged children. Catholic Family Services Provides foster care programs, family and indivi-dual counseling programs and 4 adoptive services. Children's Home Society of Residential treatment facili-Washington ties and programs for emotion-ally disturbed children. Benton-Franklin Council Programs to provide meals, on Aging household assistance, health care and information and l transportation services. l Evergreen Legal Services Free legal aid program for ! civil cases involving low-income persons. Good Shepherd Home A residential treatment pro-gram for adolescent girls with behavior problems. Women's Resource Center Broad range of information, education, support and refer-al services for women. O Amendment 4
y a L S/IINP-ASC/ER 9/16/82 i O . i N i HANFORD l l RESERVATION 0 2 3
} ;
SlHNP \ '
/ SITE .: LEGEND 7
/ + FREEWAY -
g ARTERIAL l a i k*# f...i
% .4ii ;
9 t e ; c- ; 9.
*rn n,""* ea. h I
\. (
4* dE"' 3
?
O Twin
- E ;- f Bridges g
- 8 RICHLAND : i 5
WEST :- i RICHLAND v. ,,
's -
BENTON 224 **h) k I ql ... PASCO ' CITY j# sa :: k (i ee*" '*. g N ! I - l The " Causeway' { SOURCE. URS.1981 KENNEWICK l ( I I PUGET SOUND POWER & LIGHT COMPANY j SKAGIT / HANFORD NUCLEAR PROJECT I APPLICATION FOR SITE CERTIFICATION / i ENVIRONMENTAL REPORT l ! l EXISTING MAJOR STREETS ! AND HIGHWAYS SERVING l l HANFORD RESERVATION TRAFFIC FIGURE 8.31 Amendment 7 t
S/HNP-ASC/ER 9/16/82 O ' . a HANFORD 1 RESERVATION 2
? } 9 SlHNP \
/ SITE 4 x! LEGEND 1.8% /
j + FREEWAY a-ARTERIAL 2
%, s:
g ;!!:
.!! i ii '9 i
E 6.5 % i 84
- l
/q$ i e/d$ !.i-(
4.4 % A RICHLAND .i WEST t RICHLAND v., d218[ E] h BENTON 224 PASCO
##
- i.ss2 18.1 %
0.5'/o .-. 0.5% Th.-c.uases-46.4 % KENNEWICK l PUGET SOUND POWER & LIGHT COMPANY SKAGli / H ANFORD NUCLEAR PROJECT APPLICATION FOR SITE CERTIFICATION / ENVIRONMENTAL REPORT ESTIMATED DISTRIBUTION OF
\
S/HNP CONSTRUCTION , s WORKER TRAVEL l FIGURE 8.3 5 Amendment 7 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ - _ _ J
S/HNP-ASC/ER 9/16/82
% i
., noute 11 A L,
\ l ,
t k North Access g<%q Rd. s [ s i 1 4, SKAGIT/HANFORD NUCLEAR PROJECT f . Si n
>}
*::::::::::::: % in Attomate, .
acc., South gg I
- .. Preferred South Access Rd.
r g p 9 {g
.... ARID. LANDS ECOLOGY:.
,' s q . . ..... ................. ..
...... , j ;
=,
\ 6_............................
. 3,
==........................... w
==............ ..... .......
l ... i 5
..... i T... .. .. i ,
....... q Fu = A :::::::: 1 Qllu::. e u u.:.u.- '
% **% no.
_ [
./.. ..
m ,.
- :R.ICH. .LAN.D:j::
- n :: '
. .j, , .
t,'; , l . t,9.*,:. >.I' ,. i
'9 '"t'.
IMPROVE INTERSECTIONS Yakirna River g*p : 0;;;;
' *:4., ,
N ea .:::.. . . MILES NOTE: HOV LANE (S) WILL ONLY BE ADDED TO STATE HIGHWAY 240 BETWEEN THE INTERSECTION OF ROUTE 10 AND THE INTERSECTION OF THE
- ALTERNATE SOUTH ACCESS ROAD IF THE ALTERNATE SOUTH ACCESS ROAD PUGET SOUND POWER & LIGHT COMPANY IS USED. SKAGIT / HANFORD NUCLEAR PROJECT APPLICATION FOR SITE CERTIFICATION /
ENVIRONMENTAL REPORT O POSSIBLE SKAGITIHANFORD ROADWAY IMPROVEMENTS FIGURE 8.3 7 Amendment 7
S/HNP-ASC/ER 12/21/81 8.5
SUMMARY
OF SOCIAL AND ECONOMIC BENEFITS AND COSTS 8.5.1 BENEFITS The primary benefit of the Project will be the employment, income and population effects on the socioeconomic infrastructure of the local area. Each of the four scenarios projects out-migration of construction and secondary workers over the period 1983-1992 resulting in absolute population losses and/or declines in the rate of growth. Construction of the Project, however, diminishes the out-migration for the area and thus helps support the socioeconomic infrastructure of the area. This support may provide a useful time period for the Tri-Cities to diversify its economic base. One example of the S/NNP effects on the socioeconomic infrastructure can be drawn from the difference between the projected conditions of local schools without, e.g. Scenario 4, and with, e.g. Scenario 3, the Project. Scenario 4 (baseline) - Schools would experience 4 declines in enrollment of over 4,000 during the 1982-O 1986 period. This loss of students would mean reduced funding from the State and could result in reductions in the teaching and administrative staff. Special levies to support non-basic educational activities would be needed. Scenario 3 (Construction of S/HNP) - Declines in en-rollment would occur but would be less than in Scenario 4 due to the population effects of the S/HNP construction and secondary workers in the area over the 1983-1988 period. This maintenance of enrollment would provide for continuation of State funding and reduce the need for special levies and ~ staff reductions. Finally, the major addition of the S/HNP to the tax base of the Richland School District would virtually eliminate the District's special levy for residents. While projected school conditions are one example of the manner in which S/HNP will support the socioeconomic infrastructure of the Tri-Cities, other illustrations could be drawn from such dimensions of the community as housing, health care, fiscal condition and the impact on local businesses. In each of these areas, the S/HNP effects on the infrastructure would be of major benefit as compared to the declining economy and stagnant population depicted by the baseline scenarios. 8.5-1 Amendment 4
S/HNP-ASC/ER 9/16/82 In addition to supporting of the socioeconomic infrastruc-ture the Project will provide: l
- 1. Adequate Generation The Project will contribute to ensuring sufficient generating capacity for the region and decrease the probability of an inability to meet the load 4 in the future. The potential socioeconomic costs of power shortages and curtallments have been shown to be significant in the State of Washington (Ref 1).
- 2. Tax Benefits The Project's payment of direct taxes will have a significant positive impact upon Benton County as l7 well as the State. Based on 1981 tax rates, it is estimated the Project would generate the following revenues during construction over and above those revenues generated under Scenarios 1 and 4 at the 4 same points in time.
Estimated Revenues During Construction (1980 dollars) State S 178 million Benton County S 100 million Benton-Franklin Transit District S 7 million 7
$ 285 million Under 1981 tax rates, during operation, the S/HNP would annually provide Benton County with over $11 million (in 1980 dollars) in property taxes and in sales tax. The Benton-Franklin Transit District would receive nearly $370,000 per year (in 1980 dollars).
The significant increase in the tax base would allow Benton County to consider such options as (a) significantly improving services, (b) disbursing funds to local communities, and (c) 4 lowering tax rates by as much as 70 percent. Increased revenues for local jurisdiction will allow them to maintain and improve services and potentially reduce the property tax levy in the County. 7 8.5-2 Amendment 7 j
S/HNP-ASC/ER 9/16/82 l
"" I 7
y , 3. Employment Benefits There will be a reduced loss of jobs due to I construction of the facility. Employment will } range from.571 in 1983 to 4617 in 1988 to 1677 in j 1991. Over the period 1983-1991 S/ HUP will t provide almost 24,000 person years of employment. I I Secondary employment will also result during the l construction and operations periods. Previous research indicated a multiplier of 1.8 for nuclear 4 construction in the Tri-Cities (Ref 2) . Thus, I apart from commuters, it is projected that i construction will generate over 16,000 person ! years of employment in other sectors of the economy. { t f Operation of the facility will provide employment l for 295 individuals over the 40 year life of the j facility - 11,800 person years of work. This 5 L employment and income will support about 531 jobs [ in the local economy. ! l An additional 200 workers will be employed during periodic l refueling operations, and their expenditures will support ! the local economy.
~'}
- 4. Income Benefits 4 f During construction, it is projected that annual j income per worker will average $37,000 in 1980 ;
dollars for a total of $949 million over the ' construction period. j l During operation, it is projected that annual l income per worker will average $23,600 in 1980 5 dollars for a total of $244 million over the 40 l year operating life. { l These relatively high income levels will stimulate ! other sectors of economy and produce expanded l business activity throughout the SMSA.
- 5. Purchase of Local Materials and Services 4 During construction Puget intends to purchase t local supplies and services when they are readily !
available and competitively priced. Given the ' extent to which the local economy has developed in
/
l C}' 1 E l 8.5-3 Amendment 7 t
S/HND-ASC/ER 12/21/81 tandem with nuclear-related construction, it is expected that a number of local firms will provide materials and services. During operation, it is estimated that local purchases of materials and services will be approximately $5 million per year in 1981 dollars. Over the 40 year operating life of the facility, this figure totals to $200 million spent in the local area.
- 6. Benefits to Communities Outside the SMSA It is estimated that at any given time, 15 percent of the nuclear construction force on the Reservation resides outside the SMSA and commutes on a daily basis. Thus, towns such as Sunnyside, Grandview and Mabton will also benefit from the employment and income effects of the S/HNP.
! Under Scenarios 1 and 4 a number of these 4 residents will be unable to find employment in the area and will migrate from these communities. ! Scenarios 2 and 3 would each enhance the local l employment opportunities for such individuals and thereby diminish out-migration.
- 7. Maintain Character of Tri-Cities Perhaps the most commonly voiced socioeconomic concern regarding energy development relates to its incompatibility with the character of the local area. Since more recent energy projects have been nonmetropolitan communities, concern is often expressed that large scale construction would disrupt the rural lifestyle.
The S/HNP, however, will operate to support the l existing quality of life in the Tri-Cities SMSA. l The social economic, demographic, institutional and psychological profile of the Tri-Cities area has developed in tandem with nuclear power since 1943. The construction and operation of the S/HNP will be in harmony with socioeconomic trends which have characterized the local area for nearly two generations. O 8.5-4 Amendment 4
i S/HNP-ASC/ER 9/16/82 x ' 8.5.2 COSTS ; 7 I 8.5.2.1 Traffic Costs Local roads have been overburdened by the rapid growth l experienced in the Tri-Cities area, resulting in traffic j congestion and high accident rates in several places. In : 1981, for example, it is estimated that approximately 6,100 [ commuter vehicles were associated with the construction : force of WNP 1, 2 and 4 on the average for the year. ! r The difference between commuter vehicle traffic on the Reservation with S/HNP as opposed to without is projected ! to average approximately 2,100 additional vehicles per day ; between 1984-1990. i 4 I The greatest amount of commuter traffic will occur under i Scenario 2 when 4,960 total vehicles are projected. Even ; this peak, however, will only be 81 percent of the i estimated average of 6,118 construction union vehicles j associated with WNP 1, 2 and 4 in 1981. ! Under Scenario 3, in no year would the number of commuter [ vehicles exceed 45 percent of the estimated commuter vehicles in 1981. t
]
Although the construction scenarios indicate commuter l traffic well below that which existed in 1981, several ! improvements are being considered by Puget. These I improvements are described in detail in Section 8.3.10.5. 6 t It should be noted that construction and operation of S/HNP f will generate substantial revenues for the Benton-Franklin i Transit Authority. During construction, for example, S/HNP may generate as much as $8 million for the Transit 4 [ Authority between 1983-1992 over the revenues received : under Scenarios 1 and 4 for the same time period. During j operation nearly $400,000 more would be available annually l5 L under Scenarios 2 and 3 versus Scenarios 1 and 4. ; Finally, substantial revenues will accrue to the Road f District in Benton County through property taxes paid on ! the facility. These funds could be utilized to improve 4 i roads in the county. ! Under the baseline scenarios these revenues would not be available to either the Benton-Franklin Transit Authority { or the Benton County Road District. : i 8.5-5 Amendment 7 t i
S/HNP-ASC/ER 9/16/82 8.5.2.2 Potential Fiscal Costs, The uncertainties which characterize the socioeconomic future of the Tri-Cities make it particularly difficult to project the fiscal conditions which will exist during the construction and operation of the S/HNP. In general, how-ever, five points must be considered in evaluating poten-tial fiscal costs.
- 1. The case of S/HNP differs from other facilities on the Hanford Reservation because it will be pri-vately owned. Therefore, in addition to the indirect taxes it would generate through payment of wages and salaries to project-related em-ployees, S/HNP would also pay direct property taxes, beginning soon after the start of construc-tion. The indirect taxes are distributed to the local jurisdictions as the workers take their wages and salaries from their place of work to their place of residence. The cost / benefit impacts of these effects will depend upon the reve-nues produced and the costs of providing services in each jurisdiction.
- 2. 7 As in the case of any taxable industry which locates in any community in Washington State, the direct taxes paid on behalf of S/HNP will accrue to the taxing jurisdiction in which the plant is located. This means that direct taxes are not distributed proportionately with the population and household effects. Therefore, some jurisdic-tions may reap large tax windfalls, while other jurisdictions may provide public services to the project-related population without, at the same time, having access to the direct tax revenues.
This could be viewed by local jurisdictions as an inequitable distribution of costs and benefits even if they might not experience actual negative fiscal impacts because they collect indirect taxes.
- 3. In order to identify fiscal impacts as they emerge, the Applicants will develop and implement an approved monitoring program in cooperation with appropriate local and State agencies.
- 4. Apart from any individual jurisdictions, it is clear that the total tax revenues which will be generated by the S/HNP will far exceed the O
8.5-6 Amendment 7
S/HNP-ASC/ER 9/16/82 ! I aggregate public costs of serving the population associated with the S/HNP. ! i
- 5. Given the magnitude of tax revenues which will be !
generated by the S/HNP, a redistribution of direct i taxes from Benton County to other local tax dis- ! tricts would virtually ensure that all impacted 7 jurisdictions would benefit, even if not equally. l Distribution of such revenues could take place ; through voluntary agreement or through the Inter- ; Local Cooperation Act, RCW 39.34. j f i f: L i, l N v i , [ L i l i
/"~')
O i 8.5-7 Amendment 7
S/HNP-ASC/ER 9/16/82 j l References for Section 8.5
- 1. John McConnaughey, Bonneville Power Administration, Power Requirements Branch (December 9, 1981).
i ! 2. Socioeconomic Impact Study WNP 1 & 4, Volume 4: Final ! Report, prepared by Community Development Services, Inc. for Washington Public Power Supply System, Seattle, Washington (May 1979). l O i l l l l 9 8.5-8 Amendment 7
y S/HNP-ASC/ER 9/16/82 l CHAPTER 9.0 ALTERNATIVE ENERGY SOURCES AND SITES CONTENTS SECTION TITLE PAGE 9.1 Alternatives Not Requiring the Creation of New Generating Capacity 9.1-1 ' 9.1.1 No Action or Delayed Action 9.1-1 9.1.2 Purchase of Firm Power 9.1-1 9.1.3 Conservation 9.1-2 9.1.4 Passive Solar Systems 9.1-3 9.1.5 Baseload Operation of Existing Peaking Facilities 9.1-3 9.1.6 Reactivating and Upgrading Existing Older Plants 9.1-3 Os 9.1.7 Summary 9.1-4 9.2 Alternatives Requiring the Creation of New Generating Capacity 9.2-1 9.2.1 Evaluation of Energy Sources 9.2-1 9.2.1.1 Evaluation of Fuels 9.2-1 9.2.1.1.1 Fuel Oil and Natu'.O Gas 9.2.1.1.2 Synthetic Fuels 9.2-1 9.2-2 9.2.1.1.3 Agricultura] "'- fr s 9.2-2 9.2.1.1.4 Municipal Sid d P' 'en (MSW) 9.2-4 9.2.1.1.5 Wood 9.2-6 9.2.1.1.6 Coal 9.2-9 9.2.1.2 Other Sources of Energy 9.2-10 9.2.1.2.1 Wind Energy 9.2-10 9.2.1.2.2 Geothermal 9.2-13 9.2.1.2.3 Oceans 9.2.1.2.4 Hydroelectric Power 9.2-16 9.2.1.2.5 9.2-17 Solar Energy 9.2-20 9.2.1.2.6 Fusion Reactors 9.2-23 9.2.1.2.7 Breeder Reactors 9.2-23 9.2.1.2.8 Cogeneration 9.2-23 9.2.1.3 Advanced Energy Conversion Methods 9.2-25 9.2.1.3.1 Fluidized Bed Combustion 9.2.1.3.2 9.2-25 Fuel Cells 9.2-26 9.2.1.3.3 Combined-Cycle Concept 9.2-26 9.2.1.3.4 Magnetohydrodynamics 9.2-27 9-1 Amendment 7
S/HNP-ASC/ER 9/16/82 SECTION TITLE PAGE 9.2.1.4 Conclusions - Sources of Energy 9.2-27 9.3 Alternative sites 9.3-1 9.3.1 Background 9.3-1 9.3.1.1 Previous Consideration of Alternative Sites 9.3-2 9.3.1.2 The Relocation from Skagit to Hanford 9.3-3 9.3.1.3 The RSP Site Selection Study 9.3-4 9.3.2 RSP Study Site Selection Process 9.3-4 9.3.2.1 Region of Interest 9.3-4 9.3.2.2 Candidate Resource Areas 9.3-5 9.3.2.3 Candidate Sites 9.3-6 9.3.2.4 Site Comparisons 9.3-6 9.3.2.4.1 Geotechnical Ratings 9.3-8 9.3.2.4.2 Environmental Ratings 9.3-9 9.3.2.4.3 Economic Ratings 9.3-10 9.3.2.4.4 Composite Ratings of Candidate Sites 9.3-11 9.3.3 The Proposed Site 9.3-12 9.3.3.1 Licensing and Operating Experience 9.3-13 j 9.3.3.2 An Experienced and Supportive Community 9.3-13 9.3.3.3 Federal Controls and Programs 9.3-13 9.3.4 Summary Comparison of Alternative Sites 9.3-14 9.4 Environmental Comparison of Candidate Alternatives 9.4-1 9.4.1 Radiological Releases 9.4-1 9.4.2 Nonradioactive Emissions 9.4-2 9.4.3 Land Use and Aesthetics 9.4-2 9.4.4 Conclusion 9.4-2 9.5 Costs of Alternative Power Generation Methods 9.5-1 9.5.1 Capital Costs 9.5-1 9.5.2 Annual Costs of Operation 9.5-1 9.6 Alternative of Acquiring Washington Public Power Supply System Units 4 and 5 9.6-1 e 9-11 Amendment 7
S/HNP-ASC/ER 12/21/81 9.2 ALTERNATIVES REQUIRING THE CREATION OF NEW GENERATING ( CAPACITY 9.2.1 EVALUATION OF ENERGY SOURCES l Several alternative energy sources were given consideration during the early planning stages of the S/HNP. These considerations were previously documented in the S/HNP Environmental Report, Amendments 1 and 2, Section 9.2.4, pages 9.2-17 through 9.2-21, which concluded "Because the availability of oil and gas fuels for the years 1980 to 2010 is not assured, and costs are highly speculative, the only practical alternative to nuclear fuel is coal." There have been no changes in the availability, technology, and economics of these alternative fuels that would indicate that the S/HNP should be abandoned in favor of an alternative generation method. However, Applicants have programs which continually evaluate alternative energy sources. Some of these sources can provide some energy during the time frame of the S/HNP. As is described in the evaluations of these and other energy sources below, the moderate amount of energy 4 available from these sources is needed in addition to the output of the S/HNP. 9.2.1.1 Evaluation of Fuels Fossil, syi.thetic, and biomass fuels are discussed below in terms of their availability for meeting the identified need for power. 9.2.1.1.1 Fuel Oil and Natural Gas The need for power that the S/HNP is to meet is a need for a baseload-operated facility. The Power Plant and Indus-trial Fuel Utilization Act of 1978, except under very specific exemptions, prohibits installation of any new facilities of this size which would use oil or natural gas as a fuel. Thus, fuel oil and natural gas are not suitable alternatives to nuclear fuel. O 9.2-1 Amendment 4
S/HNP-ASC/ER 9/16/82 9.2.1.1.2 Synthetic Fuels The production of liquid or gaseous fuels from oil shale, tar sands, coal, or agricultural products or wastes has been the subject of much research in recent years, and the work continues. There are numerous research projects, and projects which are proposed to demonstrate the feasibility of producing some of these fuels on a scale large enough to meet the need for power previously identified. 4 One of the principal utility-sponsored projects of this type is the Coolwater Station, Integrated Coal-Gasifi-cation, Combined-Cycle Demonstration Project, sponsored in part by Southern California Edison. The technology and supporting industry for producing synthetic fuels as an economic fuel alternative is not yet developed (Ref 1). Thus, Applicants do not consider these fuels as feasible alternatives to nuclear fuel. 9.2.1.1.3 Agricultural Biofuels A possible source of boiler fuel for electrical generating - facilities is agricultural biomass, such as manure, crops, and crop residues. In most cases, utilization of agricultural residues as a source of boiler fuel is probably not the preferred societal use. Crop residues often serve as source of animal feed, and both manure and crop residues can act as a nutrient base and conditioner of farm land. Use of these wastes as a source of fuel could result in depletion of soil quality, thereby requiring greater fertilization and possibly resulting in a net energy loss (Refs 2, 3 and 9). The amount of agricultural residues available in the 7 Pacific Northwest is small and geographically diffuse, thereby rendering it expensive to collect and transport and therefore unattractive for use in electrical generation (Refs 3 and 9). Growing crops for use as fuel is estimated to be relatively expensive (S0.50 to $ 2.00/106 Btu), according to mid to late 1970's studies (Refs 2 and 3). Moreover, plantations for growing biomass for fuel require expenditures of land, water, fertilizer and energy which may be more profitably employed for supplying food and feed (Refs 2 and 4). It is estimated that, depending upon the crop, 230 to about 1000 square miles of farm land would be needed to supply sufficient biomass to generate 1000 MW (Refs 3, 5 and 6). 9.2-2 Amendment 7
S/HNP-ASC/ER 9/16/82 The reservations expressed above may not be relevant in all cases. Marginal lands and the oceans may prove to be viable sites for biomass plantations, farm land from diversion to energy production.thereby protecting However, at present, neither has been demonstrated as a feasible location for a biomass plantation. (Refs 2 and 4.) Similarly, in some high density agricultural regions, not all of the agricultural wastes are recycled and thus may be available as a source of fuel. For example, in Hawaii, bagasse from sugarcane is burned to provide process steam and electricity. (Ref 5.) With the exception of wood residues which is discussed in Section 9.2.1.1.5, no comparable example exists in the Pacific Northwest. Direct use of agricultural biomass as a fuel has several drawbacks. thus rendering First,itsitsuse moisture content relatively is relatively high, inefficient. Second, its heat content is relatively low. Agricultural biomass has an 3, 6energy and 9.) content of 6,500 to 10,000 Btu /lb (dried). (Refs Therefore, its transportation costs are correspondingly higher than other fuels if the agricultural biomass is delivered before drying. Finally, agricultural biomass is susceptible to spoilage, and its supply is seasonal in most areas of the country including the Pacific Northwest. Consequently, assured supplies of agricultural 7 biomass fuel for generating electricity are not available. These problems associated with the direct use of agricultural biomass can be somewhat alleviated by converting the biomass into a more conventional fuel by such processes as pyrolysis, gasification, and fermentation. (Ref 4.) However, conversion is estimated to be expensive (in the range of $0.70 to $3.50/10 6 according to a late 1970's study (Ref 2) and, once Btu), converted, a liquid fuel would appear to be in greater demand generation. for use in transportation than in electrical (Ref 4.) Construction and operation of generating facilities for burning biomass although its cost poses no insurmountable difficulties, a conventional boiler. is higher than a generating facility with (Refs 3 and 6.) Environmental impacts attributable to construction and operation of agricultural biofueled facilities are similar to those from wood-fired generating facilities and are described in Section 9.2.1.1.5. (Ref 3.) In general, these impacts are comparable to or slightly greater than that associated with construction and operation of an equivalent nuclear power plant. In light of its enviror.' ental and economic costs, the lack of an adequate and assured supply, and the existence of 9.2-3 Amendment 7
r S/HNP-ASC/ER 9/16/82 societally preferable uses, generating electricity by burning agricultural biomass is not a superior alternative to generation of electricity in whole or part by S/HNP. 9.2.1.1.4 Municipal Solid Wastes (MSW) Use of MSW as a source of boiler fuel for electrical generating facilities is attractive for several reasons. First, the combustibles in the MSW can be burned as fuel to generate electricity while reducing the volumes and difficulties associated with disposal of MSW in landfills or by other means. Second, utilizing MSW as boiler fuel presents an opportunity to recycle useful noncombustible material. In general, MSW would not be economical as a boiler fuel absent consideraton of these benefits. (Ref 3). MSW has a relatively low energy content of approximately 4500 Btu /lb, a high moisture content (25%-30%), and a high ash content (7%-25%). (Refs 3, 7 and 13). Dried MSW has a greater energy content of about 7000-8000 Btu /lb (Refs 3 and 13), but its energy content is still lower than 7 conventional fuels. It is estmated that more than a ton of municipal waste per person is produced each year. (Refs 3, 6 and 9). Nevertheless, one of the greatest barriers to using MSW as a boiler fuel for generating electricity is the lack of sufficient volumes of MSW. It is estimated that a minimum of 200 tons of refuse per day would be required to supply the needs of the smallest economical steam facility; this volume is beyond the capacity of most municipalities in the Pacific Northwest. (Ref 3). Several municipalities could combine to supply one generating facility. However, this type of arrangement would require additional transportation of the MSW, resulting in additional costs, consumption of fuel, and emission of air pollutants. In any event, the amount of electricity which could be generated from MSW would be relatively small. A 1977 study estimates that only 41 x 1012 Btu /yr could realistically be derived from the MSW produced by the total Pacific Northwest population. (Ref 3). This corresponds approximately to a 340 MWe generating facility at a 20% efficiency rate and an 80% capacity factor, or about one fourth of the size of one unit of S/HNP. MSW can be utilized to produce energy in three different ways. It can be converted to fuel gas by pyrolysis or other processes, it can be used as a supplement in a coal-fired generating facility, or it can be used as a sole 9.2-4 Amendment 7
S/HNP-ASC/ER 9/16/82 source of fuel in an electrical generating facility. A facility burning only MSW is not a preferred method of generating electricity (Ref s 3 and 5) , in part because of its high cost. It is estimated that the total capital costs for such a facility would be $2,790/kw (December 1980 S) (Ref 7). However, this cost varies significantly dependent upon the level of boiler redundancy and the amount of fuel processing in the system design. Use of MSW as a supplement to coal-fired generating facility appears to be more economically advantageous due to the lower capital costs for coal plants. However, it should be noted that co-firing MSW with coal necessitates processing of the MSW which, for a 1500 ton / day processing plant, was estimated to entail a capital cost of $10,000,000 (1975 $) over and above the cost of the generating facility itself, (Ref 6). To some extent, these high capital costs can be offset by the relatively inexpensive cost of the MSW. According to a 1977 study, the incremental cost of delivery of MSW is low, in the range of S0.11/106 Btu in excess of normal collection costs for MSW. Environmental impacts attributable to construction and operation of MSW-fueled electrical generating facilities are similar to those from wood-fired generating facilities and are described in Section 9.2.1.1.5. (Ref 3). 7 Combustion of MSW can emit different and more toxic gasses than burning of wood, but these can be controlled within required limits. (Ref 3). The ash content from MSW-fueled facilities ranges from 3 to 6 percent of the original volume of the MSW and requires disposal. (Ref 6). In general, the impacts of the MSW-fueled facility are comparable to or slightly greater than the impacts associated with an equivalent nuclear power plant. A number of MSW-fueled electrical generating facilities exist or are planned throughout the United States. The potential for such facilities in the Pacific Northwest is limited to highly populated areas, primarily in the Portland and Seattle areas. The Applicants have explored and are exploring the possibility of constructing such facilities, and in fact some facilities are listed as prospective generating resources in the Northwest Regional Forecast by the Pacific Northwest Utilities Conference Committee. (Ref 8). However, since the MSW-fueled capacity for the Pacific Northwest region is not significant, and since the environmental and economic costs of MSW-fueled generating facilities are equal to or greater than those for S/HNP, use of additional MSW as boiler fuel to generate electricity is not considered to be a superior alternative to operation of S/HNP in whole or in part. 9.2-5 Amendment 7
- +. ,"J.J .g f .j_ .. b f t g g f .; . y % " ;; .
.. , _ y y y ' b y - 3 g y 7 a T ; 31 S/HNP-ASC/ER 9/16/82 0.2.1.1.5 Wood Several forms of wood are available as a source of boiler fuel to generate electricity. The most prominent forms include forest or logging residues, mill wastes and tree harvests.
In general, harvesting trees for use as fuel is not promising. Commercial grade trees have a higher value in the wood products industry than as a fuel. It has been postulated that biomass farms could be developed consisting l of fast growing trees such as red alder, populars or eucalyptus. (Refs 4, 6 and 9). However, the same problems noted in Section 9.2.1.1.3 with respect to biomass plantations also apply to tree farms. Enormous amounts of land would be required to supply significant amounts of wood for fuel. One report estimates that 4,560 square miles of cool temperature forest would be needed to supply the fuel demands of a 1000 MWe plant. (Ref 9). In contrast, biomass plantations of corn or sugarcane would only require 25% and 5% as much land, respectively, to l provide an equivalent energy output. (Ref 9). Additionally, it is likely that intensive cultivation of tree farms would deplete the soil, resulting ir even lower 7 yields. In light of such considerations, use of mill and forest and logging residues is preferred for generating electricity. Mill residues are attractive as a source of boiler fuel. Mill residues are relatively easy to collect and do not require shipment from the forest. Consequently, mill residues tend to be fairly inexpensive and their prices have been quoted in the range of S0.12 to S1.10 per 106 Btu. (Refs 3, 4, 5 and 14). These same attributes have led the forest industry to make extensive use of mill residues. Ninety percent of the mill residues presently produced by the forest products industry is being used either for the generation of energy or for other purposes. (Refs 3 and 9). In fact, the industry generates about half of its energy requirements by burning mill residues. (Ref 4). As a result of the extensive use of mill residues by the forest products industry, it is estilated that only 0.34 to 1.3 x 106 oven dry tons of mill warae are available each year in the Pacific Northwest (Ref 14), which corresponds to the amount of electricity generated by 50 to 200 MWe unit operating at a 75% capacity factor and 20% efficiency. Forest and logging residues are more difficult to collect and transport and therefore are more expensive to utilize as boiler fuel. Costs for forest and logging residues 9.2-6 Amendment 7
S/HNP-ASC/ER 9/16/82 9 range range from $.66 to $5.00 per 106 Btu. (Refs 3, 9 and 14). Additionally, the use of forest and logging residue may have some ecological impacts. Although uncertainty exists on this point, removal of residues could deprive forest soil of nutrients. (Refs 3 and 12). However, use of forest and logging residues may be attractive due to its greater availability than mill residues. It is estimated that 2.5 to theoretically 15 x 106 oven dried tons per year of forest and logging residues in the Pacific Northwest could be collected for generation of electricity. (Refs 9, 12 and 14). This corresponds to the output of a 380 to theoretically 2275 MWe plant. Use of wood residues as boiler fuel presents similar difficulties agricultural to biomass. those encountered in the use of MSW and Wood contains high moisture content 5 (about 50%) (Ref 9), and dried wood has a relatively low heat content (averaging about 7500-9200 Btu /lb) (Refs 6 and 9), which tends to vary from piece to piece. Additionally, given its low heat content and its geographic dispersion, collection and transportation costs are high and probably K are the economically limiting factors. (Refs 3, 4, 9 and 7 12). Transportation costs for an average forty mile haul 1 range from $5.20 to $17.60 per dried ton (Refs 3, 9 and
- 14), and hauling distances greater than fifty or sixty
- miles probably With other typeswould of fuel. render wood residues uncompetitive 7
; (Ref 9). This factor restricts p the size of wood-fired generating units to about 50 MWe due to the limited amount of residue available in any given area. (Refs 3, 4, 9 and 14).
Perhaps the greatest detriment to relying upon wood residues as a source of bioler fuel for generating i electricity by utilities is the inability of utilities to obtain long-term supply contracts. The supply of wood residues of the economy. is seasonal and tends to fluctuate with the state Additionally, there are already competing markets for wood residues and it is possible that additional markets will develop for wood residues if the price of wood itself continue to increase. (Refs 9, 11 and 14). However, it may also be noted that the price for wood has not and probably will not escalate es rapidly as the cost of fossil fuels, because of the ability of the lumber industry to expand supply more readily to n:atch demand. (Refs 5 and 9). In any case, suppliers have not been inclined to make long-term commitments in the face of such uncertainties. (Refs 3, 4, 5, 9, 12 and 14). This facter, together with the existing large use of mill residues by the wood products industry, indicates that the greatest potential use of wood residues for generating energy lies with the wood products industry itself. (Ref 3). 9.2-7 Amendment 7
S/HNP-ASC/ER 9/16/82 Wood-fired generating facilities are more costly to , construct than equivalent capacity fossil fueled facilities. Price estimates range from about $1200 to
$1400 per kw in 1981 dollars. (r.efs 3, 9, 12, 14 and 15).
The environmental impacts attributable to construction and operation of wood-fired generating facilities are generally greater than those from a nuclear plant such as S/HNP. Although the majority of particulate matter can be removed from the combustion gases (Refs 3, 9 and 12) , wood-fired units emit amounts of air pollutants (including particu-lates, hydrocarbons and carbn monoxide) which are comparable to those emitted by fossil-fueled facilities, (though less sulfur dioxide than a coal plant). (Refs 3 and 11) . Similar to other steam producing facilities, a wood-fired unit will require condenser cooling and thus will release heated effluent to the environment. (Ref 12) . This effluent will also contain trace metals and other constituents (Ref 12) . Finally, it should be noted that a wood-fired unit will cause other impacts, such as water 7 usage, ash disposal (80 tons per day for a 50 MWe unit), and congestion and emissions from transportation of the residues to the plant (about one truck every twenty to thirty minutes). (Refs 3, 5 and 12) . These impacts may be somewhat offset by a reduction in waste burning of residues which might otherwise occur. (Ref 12) . Despite some of the drawbacks noted above, the Applicants are exploring the possibility of generating electricity by burning wood. In fact, one of the Applicants, The Washington Water Power Company, is planning to construct a 42 MWe unit fired by mill residue at Kettle Falls, Washing ton . This unit has been included as a planned resource by PNUCC. (Ref 8). Additionally, the Boardman coal-fired unit owned by Portland General Electric Company is designed to accommodate co-combustion of coal and biomass. (Ref 5). Thus, the Applicants believe that wood-fueled generating units can make a contribution in the Pacific Northwest. Nevertheless, in light of its environ-mental costs and the lack of an assured and adequate supply, generating electricity by additional burning of wood is not considered to be a superior alternative to the generation of electricity by S/HNP in whole or part. O 9.2-8 Amendment 7
S/HNP-ASC/ER 9/16/82 9.2.1.1.6 Coal The use of coal as a fuel for baseload power plants will continue to increase as the demand for electricity in-creases. The U.S. Geological Survey has identified U.S. coal resources of more than 1,700 billion tons at depths of less than 3,000 ft. (U.S. production in 1979 was less than one billion tons.) The U.S. Geological Survey also esti- 4 mated the existence of additional ccal resources of more than 2,200 billion tons. The Bureau of Mines estimated in 1976 that, of the 1,700 billion tons of identified re-sources, approximately 438 billion tons are in deposits of the type and depth considered minable at present mining and economic conditions. An estimated 46 percent is found in states east of the Mississippi River, and 54 percent is in tne western states and Alaska (nef 25). There are two operating coal-fired plants in the Oregon / Washington area. One is located at the mine at Centralia, Washington. Although exploration continues, presently it does not appear that an additional major power plant can be supplied from the Centralia coal resource. The second plant is at Boardman, Oregon. The coal for this project is transported approximately 1200 miles by unit train from northeast Wyoming. An additional four 508 MWe units are 9 planned at Creston, in the eastern part of Washington. Fuel for these units will be transported from one or sev-7 eral of the western coal states cr from Canada. All prac-tical coal supplies are being evaluated for that project by its sponsor, The Washington Water Power Company. Several Applicants have expressed an interest in a partnership in the Creston Project. Coal for any plant to be considered as an alternate would
' have to be mined in Eastern Montana, Wyoming or Canada.
Because of the many factors associated with obtaining coal 4 from Canada on an assured basis for a 35 year period, 1 Canadian coal should be considered a less reliable supply. l7 Eastern Montana and Wyoming coal is availtble in the quantities needed to support a plant the size of an alternate and can be used in a mine-mouth plant, or can be transported closer to the load centers and used in a generating plant located nearer the load center. Additional coal-fired capacity constructed in either Eastern Montana or Western Wyoming would require construction of new transmission lines to carry the power 4 from generating plants to load centers. An alternative to electrical transmission is to transport the coal via unit trains to the Pacific Northwest and to construct the steam-electric generating plant in Central or Western Washington 9 or Oregon. Such a transport would require coal to be moved some 900 to 1200 miles from coal field to plant site and 9.2-9 Amendment 7
S/HNP-ASC/ER 9/16/82 l about 100 railcar loads per day arriving at an 800 MWe plant. 7 1 Environmental costs of a coal fueled plant are compared to l the S/HNP in Section 9.4. The economic costs of a coal fueled plant are given in Section 9.5. The cost when compared to the S/HNP costs in Section 8.2 show a clear advantage tive. for the S/HNP over the coal fueled plant alterna-4 There are coal reserves in Alaska. Transportation of the raw coal to a western Washington power plant would be relatively expensive because of the high content of non-combustible material and the long distances involved. Development of commercially competitive synthetic fuel production processes would improve this situation. As was discussed above, these processes are not yet developed to this stage. Because of this, these reserves cannot be currently considered a cost-effective alternative fuel. Although coal reserves have been identified in Washington and Oregon, none appear to be as cost effective as the large western supply in Eastern Montana, Wyoming and Canada. 9.2.1.2 Other Sources of Energy 9.2.1.2.1 Wind Energy The power of the wind can be harnassed to provide the driving force for generating electricity. The theoretical power which can be obtained from the wind is proportional 7 to the area swept by the wind turbine generator (WTG) and to the cube of the wind speed. Consequently, siting of wind turbine generators in non-turbulent high wind velocity locations is crucial to the maximum utilization of wind power. In general, average wind speeds on the order of 12-15 mph are considered necessary to support operation of a commercial WTG. (Refs 6 and 17.) The Pacific Northwest has a relatively abundant supply of wind energy potential available. The areas which appear to have the greatest wind potential are the coastal regions, the Columbia Gorge, and south central Idaho, and portions of western Montana, Wyoming, and northern Nevada. (Ref 17.) Because wind velocity is such a crucial factor in power generation, extensive data regarding wind speed, direction, sheer, frequency, distribution, and turbulence are 9.2-10 Amendment 7
S/HNP-ASC/ER 9/16/82 O essential to siting a WTG and determining its design characteristics (Ref 3). A small percentage difference in any of these factors could correspond to a significant difference in electrical generation (Refs 3, 12, 17 and 32). In general, one to three years of site-specific wind data is necessary before a prudent decision can be made regarding the siting of a commercial WTG (Refs 16, 17 and 32). These data are not currently available for most prospective WTG sites in the Pacific Northwest, since wind energy is extremely site specific. The variability of wind speed in space and time is an l important characteristic of wind generated power, accounting for the relatively low capacity factors for WTGs, which are estimated to be 20-40 percent (Refs 3, 4, 6, 7, 12 and 16). Consequently, it is not prudent to rely upon WTGs to provide firm power for either baseload or peaking requirements. Studies are currently underway to evaluate whether or not dispersed siting of wind farms can provide a degree of a firm power production, but the extent to which this is possible has not yet been determined. Similarly, it has been proposed that the capacity of the hydroelectric system in the Pacific Northwest could be used to store and shape the energy to be generated by the wind; however, system integration studies are needed before this proposal can be proved viable. Furthermore, constraints O placed on the hydroelectric systems by fisheries enhancement requirements may significantly reduce the 7 potential for integration of a wind system with the hydroelectric systems. Therefore, at thir time, it is not possible to determine whether WTGs could be used to provide baseload capacity such as is planned for S/HNP. If systems integration and dispersion of wind farms are eventually determined to be impracticable for generating firm power, the problems discussed above can be mitigated to an extent by employing some type of energy storage system, such as utilizing pumped hydro storage. However, storage systems are net energy consumers and impose additional capital and operational costs. Consequently, storing energy produced by the wind would serve to increase the cost of WTGs and at present such storage systems appear to be prohibited economically. Two types of wind turbine generators have been considered for utility application. The first is the horizontal axis WTG, which consists of various numbers of blades rotating about an axis which is parallel to the plane of the earth. The second design is the vertical axis WTG, which consists of various numbers of blades rotating about an axis which is perpendicular to the plane of the earth. Large WTGs 9.2-11 Amendment 7
l S/HNP-ASC/ER 9/16/82 (greater than 100 kw) are still in the design development stage. The most advanced designs developed to date are the Boeing MOD-2, rated at 2.5 MW, and the Hamilton-Standard WT3-1, rated at 4 MW. Five of the Boeing MOD-2 machines have been built and three of these units are operated by the Bonneville Power Administration at Goodnoe Hills near Goldendale, Washington (Refs 4 and 16). A larger third generation MOD-5 WTG is still under design by Boeing and General Electric with respective capacities of 7.2 and 6 MW (Refs 4 and 16). A number of smaller vertical axis WTGs (Darrieus design) are presently being developed. One of these units developed by Flow Industries rated at 100 kw has been installed near Ellensberg, Washington. Both the horizontal and vertical axis prototype WTGs have experienced accidents such as broken rotors and overspeed damage (Pef s 4 and 17) . However, such incidents are not uncommon during the development of any new technology and may be anticipated to decrease in frequency as additional operating experience is accumulated and design changes are made. Nevertheless, at the present time, WTGs remain an unproven commercial technology with an uncertain relia-bility (Ref s 17 and 32) . Prototype WTGs built to date have been relatively expen- 7 sive, on the order of several thousand dollars per kilowatt (Refs 2 and 6). However, it has been estimated that, if WTGs were mass-produced, costs could be reduced significantly. Cost estimates for a mature technology range as low as $750 to $1000/kw (1980 S) (Refs 3, 6, 7, 12 and 17). Further innovations could be expected to reduce these costs even further (Refs 6, 12 and 16). Current estimates of future costs contain great uncertainty given the facts that WTGs are still in the developmental stage and are not being mass produced. Nevertheless, the potential for cost-competitive WTG does exist, especially toward the later part of the 1990s. Generation benign. of electrical power by wind is environmentally TV and radio interference can occur at distances up to 5-6 kilometers as a result of operation of WTGs, depending upon blade size and material, number of wind turbines, and the locations of transmitters and receivers with respect to each other (Refs 16 and 17). However, it is expected that such interference can be mitigated (Refs 16 and 32) . Operation of WTG has been postulated to result in bird kills and weather modification; but no signi-ficant impacts from either has been observed to date (Refs 12 and 17). Finally, public reaction to the aesthe-tic impacts of WTGs is expected to be a factor in the devel-opment and siting of large WTGs. 9.2-12 Amendment 7
. -______ _ __ __________-________ _ - - _ )
l S/HNP-ASC/GP 9/16/82 Another important impact from WTG is associated with changes in land usage. Since effective operation of TUG requires unobstructed access to the wind, the area around the WTG must be cleared of trees and other obstacles. Such obstacles include other WTGs in the event that " wind farms" are developed. Although supporting operational data are not yet available, it is estimated that each WTG should be separated by a distance of at least 7-10 rotor diameters to minimize turbulence effects and optimize generation (Refs 7, 12, 16, 17 and 32). Such distances may not be necessary if the wind is largely monodirectional, thereby permitting units to be aligned in a row perpendicular to the wind flow (Refs 16 and 17). One study calculates that 45 square miles of land would be required to support a wind farm with a capacity comparable to one unit of S/HNP (Refs 6 and 12). In general, it is estimated that 10-15 acres of land should be allotted to support one WTG (Refs 3 and 17). However, it is possible that the impact of this land commitment could be somewhat mitigated by using the land between the WTGs for purposes such as grazing or nonintensive agriculture (Ref 12). Wind power offers the potential for a cost-competitive environmentally benign source of energy, especially toward 7 the end of this century. The Applicants plan to continue participation in the development of wind power in the Pacific Northwest. In fact, Pacific Power & Light Company has an existing wind facility at Whiskey Run in Coos Bay, Oregon, and has a prospective facility at Cape Blanco with Portland General Electric Company (Ref 8). However, wind technology is unproven and has an uncertain long-term relia-bility, and presently it is not cost competitive. Thus, ' for planning purposes, the Applicants cannot afford to abandon the option of constructing and operating all or part of S/HNP in the hope that wind power will eventually beco.ae a reliable and cost-effective source of energy. Moreover, unless studies can demonstrate that operation of wind systems and the hydroelectric systems can be inte-grated, it is not possible to equate the power from WTGs to the baseload power to be generated by S/HNP. 9.2.1.2.2 Geothermal There are various types of geothermal power. The two types which. appear to have a potential as a source for generating electricity in the near term are natural steam and hot water. Since there are no known natural steam reservoirs in the Pacific Northwest (Refs 3, 6, 12 and 18), the only reasonable geothermal alternative to S/HNP for generation. of electricity is utilization of hot water reservoirs. 9.2-13 Amendment 7
S/HNP-ASC/ER 9/16/82 Hot water reservoirs contain heated pressurized water with temperatures ranging from ambient up to 3600C. (Ref 6). However, the vast majority of hot water reservoirs contain relatively cool water. Approximately 90% of the studied geothermal resources in the Pacific Northwest have been found to have temperatures of less than 1500C. (Ref 3). The temperature of the geothermal resources is an all-important consideration. Although generation of electricity with water temperatures below 1500C is not impossible, efficiencies at such temperatures are extremely low. It is generally agreed that generation of electricity does not become practicable until water temperatures reach 1500 to 1800C, and that hot water with lesser temperatures is best used for direct heating or other purposes. (Refs 2, 6 and 18). Information regarding the geothermal potential of the Pacific Northwest is largely unavailable due to the lack of extensive investigatory drillings. The USGS has identified a theoretical potential of 2400 MWe of geothermal resources in the Pacific Northwest, with the possibility of an additional unidentified 12,000 MWe. (Refs 3, 6, 12 and 18). The PNUCC has estimated a theoretical potential of over 7000 MWe from identified resources, with an engineering potential of 1475 MWe. (Ref 18). Two different systems are used to convert geothermally 7 heated water into electricity. First, the heated pressurized water can be allowed to flash to steam and drive a turbine. Second, the heated water can be passed through a heat exchanger, and a second fluid with a lower i boiler temperature, such as isobutane or isopentane, could be used to drive a turbine. The latter is classified as a
" binary system," and is the preferred system with lower water temperatures due to its higher efficiencies.
(Refs 4, 12 and 18). At the present time, the only operating geothermal generating plant in the Pacific Northwest is a 5 MWe demonstration facility at Raft River, Idaho, which is a binary system operating at about 1500C. The estimated cost of energy from this plant is 200 mills /kwh. (Ref 18). Throughout the entire United States, generation of electricity using geothermal resources is uncommon, and the only major generating facility is a cteam resource at the Geysers in California. Consequently, the technology for development of geothermal generating facilities is not mature commercially. This is substantiated by the fact that the first flash steam pilot plant in this country just i i recently began operation at Brawley, California (although l flashed steam systems are operating worldwide). (Ref 4). ! 9.2-14 Amendment 7
S/HNP-ASC/ER 9/16/82 O Similarly, the first large-scale binary system (45 MWe) is not scheduled to begin operation until late 1984 at Heber, California (Refs 4 and 18). Moreover, before commercial operation becomes feasible, other problems with utilizing geothermal power for electrical generation must be solved, such as scaling and corrosion caused by the geothermal fluid and the lack of adequate geothermal resource assessments (Refs 4 and 18). Uncertainty also exists regarding the costs of a geothermal facility, in large part due to the cost impact of site-related factors, such as the amount of drilling needed to support a facility (Refs 6, 12 and 18) . Exploratory costs alone are estimated to be $1,500,000 to $5,000,000, and drilling costs are on the order of $1,000,000 (1980 $) per well (Refs 3 and 18). The number of wells needed is dependent upon flow rate of the geothermal fluid and its temperature. More importantly, temperature greatly influences costs because of its relationship to plant efficiency, which is generally expected to be in the range of 8 to 12% (Refs 18 and 19) . This efficiency is extremely low compared to conventional generating facilities. Finally, the amount of noncondensible gases in the geothermal fluid varies and will affect the cost of measures designed to remove such gases from flashed steam 7 systems (Ref 18) . In all, cost estimates vary from $700 to
$2000 per kw for a plant coming on line in the 1990s (1980
$) (Refs 2, 3, 6, 7, 12 and 18).
From an environmental standpoint, geothermal plants have several drawbacks. First, many of the geothermal resources in the Pacific Northwest are located in forested areas and one resource is located in a national park (Ref 18). Construction of geothermal facilities in these areas would disrupt wildlife and land use patterns. .cecond, all geothermal fluids contain varying amounts cf non-condensible gases which must be emitted from flashed steam systems. Included among such gases is hydrogen sulfide, which has an odor similar to rotten eggs at low concentrations and which is toxic at higher concentrations (however, 90% 2H S removal is achievable with current pollution control technology) (Ref 18) . Third, geothermal fluids contain various amounts of mineral and other contaminants. Unless these fluids are reinjected into the geological formation (at a relatively high cost of 10-20% of power rates), their discharge to water bodies, ground surface or the air through cooling tower operation could have significant ecological consequences (Ref 18). Fourth, fairly large amounts of land are needed to support a geothermal facility, on the order of 3000 to 4000 acres for 1000 MWe of capacity (Refs 6, 12, 18 and 19). Finally, O there may be other impacts, such as noise from 9.2-15 Amendment 7
S/HNP-ASC/ER 9/16/82 drilling and venting of wells, thermal impacts attributable to condenser cooling, and subsidence of the ground surface, especially absent reinjection of the geothermal fluid. Despite these negative factors, two of the Applicants are involved with a 10 MW demonstration project in northern Nevada. Others of the Applicants are participating in the project at Raft River, Idaho. Nevertheless, the Applicants cannot at this time commit to utilizing geothermal energy to provide baseload power. Uncertainties exist regarding the time at which geothermal plants will become techno-logically, commercially, and economically viable in the Pacific Northwest. Although geothermal plants may one day make a significant contribution, the Applicants cannot afford to abandon S/HNP in the hope that geothermal power will eventually become economically feasible. This is especially true in light of the estimate that exploratory investigations, licensing, and construction will require ten years to accomplish after geothermal plants become commercially available (Ref 18). Moreover, the environ-mental impacts from construction of geothermal facilities appear to be comparable to or greater than that of S/HNP. Consequently, geothermal power is not considered to be a superior alternative to S/HNP. 9.2.1.2.3 Oceans Four types of ocean power have been postulated as being possible sources for generation of electricity. These are ocean thermal energy conversion (OTEC), tidal power, wave power, and power from the ocean currents. OTEC would make use of the approximately 400F differential in temperature between the ocean surface and the water 1000 feet or more below the surface. In an OTEC facility, a working fluid, such as ammonia, would be heated and vapor-ized by the warm surface waters, would be expanded through a turbine to generate electricity, and then would be condensed by the cool subsurface waters. The water tempera-ture differentials needed to make s"ch a system feasible are generally found in tropic and subtropic regions, such as around Hawaii, south Florida, and the Gulf of Mexico, whereas the cool waters off the coast of Oregon and Washington almost assuredly would not support such a system (Refs 3, 4 and 6). In any case, OTEC presently is not commercially available. The first test facilities have just recently been constructed and no pilot plants yet exist (Refs 2 and 4). Furthermore, problems associated with operation in severe 9.2-16 Amendment 7
4 ~ I .. ; l R l_.+'.lf.:}.;lm ~ V V:.,l~.5?.lb.l $ Q & W j k b.W )JlQ f . W , 'y. _.l ; 3 S/HNP-ASC/ER 9/16/82 marine environments must be solved before commercial opera-tion will be possible. Even if commercial operation proves reasonable, its cost is predicted to be expensive (Refs 2, 3 and 6), and its environmental impacts uncertain (Refs 2 and 6). Another possible means of generating electricity is by uti-lizing the energy available in tides. One tidal facility presently exists at Rance, France. To produce significant amounts of electrical energy, a tidal power system requires a large flow of water; this en result from either a large tidal range or a large surface area behind a dam or both. Within the United States, only two areas appear to have sufficient tidal ranges and areas to support the possibil-ity of large scale power production: Passamaquoddy Bay in Maine and Cook Inlet in Alaska (Refs 3, 4 and 6). More-over, the cost of such facilities is predicted to be expen-sive and the environmental impact to be significant due to the large areas which must be dammed to support operation (Refs 3 and 6). Finally, tidal power is intermittent, and expected capacity factors are about 25%; consequently, tidal facilities would primarily be used for fuel displace-ment (Refs 4 and 6). It has been postulated that the action of the waves could be utilized to generate electricity. However, the power in waves is relatively weak and variable (Refs 3 and 6). As a 7 result, it has been estimated that a mile of coastline would be required to generate only 2 MWe of electricity (Ref 4). No large scale use of wave power currently exist. Similarly, use of ocean currents for generation of electri-city has been proposed but no systems presently exist. Thus, concepts employing the ocean to generate electricity have not been commercially developed, are expensive and generally unsuited for the Pacific Northwest, and can entail significant environmental impacts. Consequently, ocean power is neither a feasible or reasonable alternative to the generation of electricity by S/HNP in whole or part. 9.2.1.2.4 Hydroelectric Power Hydroelectric power has provided an abundant source of inex-pensive power to the Pacific Northwest. Approximately 80% of the existing peaking capacity in the region is attribut-able to hydroelectric power, corresponding to about 29,000 MWe peak capacity and 15,000 MWe average capacity. Of this amount, 64% is embodied in the Federal Columbia River Power System, 14.4% is Columbia River hydroelectric projects owned and operated by PUDS in the State of Washington, and the remainder is owned by public and private utilities O (Ref 20). tric capacity. The Applicants own about 2650 MWe of hydroelec-9.2-17 Amendment 7
S/HNP-ASC/ER 9/16/82 The total potential hydroelectric power in the Pacific Northwest has been estimated at 100,364 MWe, (Ref 12) . However, the Pacific Northwest only has a theoretical hydroelectric capacity of about 39,000 MWe based upon streamflow that would probablistically be surpassed 30% of the time, which is 10,000 MWe more than existing capacity. (Ref 20). Although the Pacific Northwest has a relatively large untapped hydroelectric potential, environmental and economic considerations have militated against its further development. Most of the sites suitable for large economical hydro projects have already been developed and only a very few additional sites remain unutilized. Those that do remain have been strongly opposed on environmental grounds. For example, the Ben Franklin Dam project (848 MWe) proposed for the Hanford Reach of the Columbia River lies dormant, and likely will remain so, due to concerns regarding flooding of salmonid spawning grounds. As a result of the unavailability of sites for large hydro projects, small hydro projects appear to be a more feasible means for increasing the hydro generating capacity of the Pacific Northwest. However, even the small hydro projects face environmental barriers, and many of the most promising sites are located in existing or planned national or state wild and scenic river systems, thus rending them unavailable for development. (Refs 6 and 11). 7 In general, a small hydro project can take one of several forms. These include additions to the capacity of existing units, installing capacity at existing dams which are not currently producing electricity, and construction of new projects. The first two possibilities are usually economically and environmentally superior since they do not require building new dams, and in fact such additions are being planned and have been included in the PNUCC resource analysis. (Refs 6, 8, 12 and 18). Similarly, new small hydro projects, including projects by each of the Applicants, are being planned or are prospective and have been included in the PNUCC resource analysis. (Refs 6, 8, 12 and 18). These projects are not alternatives to S/HNP but are additional resources to S/HNP. It is expected that most of the new small hydro facilities will be either low head, high flow units such as those on i major irrigation canals or will be high head, low flow i units. In either case, the units will have limited or no storage and will be run-of-the-river projects (Ref 21) . As a result, it is likely that the output of most of the small hydro projects will be subject to the vagaries of natural stream flow or artificial discharges unrelated to power operations. Consequently, such projects will provide 9.2-18 Amendment 7
S/HNP-ASC/ER 9/16/82 l little additional firm capacity and their primary benefit will generally be as an energy producer (Ref 20). The extent to which further small hydro projects can be developed is being investigated by the Applicants. At present, the possibility of adding capacity beyond that currently planned is uncertain due to environmental and economic constraints. The costs of small hydro projects is extremely site specific (Refs 6 and 20). Capital costs of constructing existing projects were extremley low, in the 7 range of $100 to $1000/kw (1980 $) (Refs 6 and 20). However, these projects represent the least costly sites available for hydroelectric generation. Cost of planned and prospective projects are higher, generally in the range of $1000 to $2000/kw (1980 $) (Refs 6, 12, 20 and 21). Costs of projects in addition to these can be expected to be the same or even higher. Nevertheless, there undoubt-edly exists projects which are cost-competitive with other forms of new generation. O 9.2-19 Amendment 7 ; I
l S/HNP-ASC/ER 9/16/82 In summary, the Applicants are actively pursuing the addition of hydro facilities and are planning to augment their present hydroelectric capacity. The extent to which increases in hydroelectric capacity can be made beyond that currently planned is uncertain due to economic and environmental constraints. However, even if such increaser are possible, it is likely that any new facilities would be small hydro projects whose primary effect would be to displace fuel use and not to obviate the need for additional baseload capacity such as S/HNP. As a result of these considerations, the Applicants do not believe that it is prudent to foreclose the option of constructing and operating S/HNP. 9.2.1.2.5 Solar Energy There are currently two means by which radiation emitted by the sun can be converted directly into electricity. The first utilizes the warming effects of the sun's rays to vaporize a fluid, typically water, to drive a turbine. This process is termed " solar thermal." The second process directly converts solar radiation into electricity through 7 use of solar photovoltaic chips. The potential for employing either of these techniques in the Pacific Northwest is relatively limited compared to j other parts of the country due to its northern latitude and the large proportion of overcast days in much of the region. The most promising locations in the region for utilizing solar energy to generate electricity are in eastern Washington and Oregon and southern Idaho, especially in southeastern Oregon where the average solar insolation is approximately 75% of the intensity in the southwestern portion of the United States (Refs 3, 6, 12, 23 and 24). This area of Oregon receives average solar energy equivalent to 4 to 6 kwh/m2 per day. (Refs 12 and l 23.) This is the maximum theoretical energy which can be generated at this location. However, the practical energy 0 9.2-20 Amendment 7
S/HNP-ASC/ER 9/16/82 potential is far lower given the efficiencies of solar conversion systems. At the present time, solar thermal appears to offer the greatest near term hope for economical utility generation ' of electricity using solar energy. Of the various solar thermal systems, the most promising is the " central solar thermal" plant due to its cost and the high temperatures which it is capable of producing. (Refs 6, 12 and 24). This system consists of a circle of mirrors called heliostats which track the sun's movement and reflect the sun's rays onto a central tower. The central tower contains the working fluid, which is vaporized by the heat
, and expanded through a turbine to generate electricity.
The thermodynamic efficiency of the system is estimated to be 30 to 50%, with actual system efficiencies lower than this. (Refs 3, 12 and 24). The central solar thermal system is not yet commercially available at competitive prices. However, a 10 MWe test facility was recently constructed at Barstow, California, at a cost of $120 to S140 million and should provide useful i information regarding operation of this type of facility. l (Refs 2 and 23) . It is estimated that the cost of the central solar thermal system will drop to $1400 to $4000/kw (1980 S) in late 1990s, depending upon the technology (' development and plant location. (Refs 6, 7, 12, 23 and 24). The lower end of this range is competitive with other 7 sources of electrical generating capacity. In contrast to the central solar thermal system, photovoltaics is presently commercially available for small , specialized applications such as in the space program. Essentially, photovoltaics consists of a chip of silicon or similar material which is light sensitive and directly converts solar radiation into electricity. At this time, the efficiency of solar photovoltric chips is only about 6-10%, with a 15 to 20% efficiency being achievable for chips which are not subject to mass production. (Refs 3, 4, 12, 23 and 24) . Theoretically, efficiencies up to 27% are possible using photovoltaics (Ref 4); however, efficiencies in this range are not anticipated absent substantial technological innovations. Presently, the price of photovoltaics is prohibitive for large scale generation of electricity. The cost of the photovoltaic chips alone is currently about $10,000/kw (Refs 2, 4, 23 and 24), with an added cost of $5000 to
$20,000/kw for balance of plant items. (Ref s 4 and 23) .
The cost of the chip is expected to decrease to $500 to
$2000/kw as a result of technological innovations.
{} v (Refs 2, 3, 23 and 24). However, the cost of the balance 9.2-21 Amendment 7
r S/HNP-ASC/ER 9/16/82 of plant components is not expected to decrease significantly unless substantial increases in chip efficiency permit a reduction in the number of chips and support equipment needed to generate a given amount of electricity. Even under the most optimistic scenario, balance of plant items are expected to cost $500/kw and total plant costs are expected to be $1700/kw. (Refs 23 and 24) . Thus, unless the most optimistic cost estimates are realized, it is likely that photovoltaics will not be cost-competitive within this century. Regardless of which solar system is selected, it suffers from a similar problem. Since solar insolation is by nature intermittent, and since the weather can disrupt the amount of energy which can be received from the sun, the plant capacity factor will be low (20-26%). (Refs 12, 23 and 24). Thus, solar generating capacity is similar to wind generated capacity discussed in Secton 9.2.1.2.1. Solar facilities generally can only serve as an intermediate load system or as a fuel saver with no firm capacity. (Ref 24). To an extent, these problems can be mitigated by employing storage systems, by providing companion generating facilities for use during these periods of time when the solar facility cannot operate, or by constructing a hybrid solar-fossil facility. (Ref 24) . However, utilization of any of these alternatives would force a utility to incur additional costs, and neither the 7 storage systems nor the hybrid systems have yet been fully developed. Similarly, it may be possible to integrate operation of the solar system and the hydroelectric systems, but no studies have yet demonstrated the feasibility of integration. The environmental impacts of solar systems are relatively minor compared to those of conventional facilities, except for the impacts of land usage. It is estimated that 6 to 18 acres /MWe of land would be required to support a solar plant. (Refs 2, 3, 6, 12, 23 and 24). Other potential impacts include slight changes in local weather, increased glare, possible mortality to avifauna, and thermal discharges from the central solar thermal facility. (Ref s 12 and 23) . Additionally, it may be noted that one study has indicated that the total atmospheric pollutants emitted as a result of utilization of solar facilities would actually be greater than that from utilization of a nuclear plant, if manufacture of facility components is accounted for. (Ref 2) . The Applicants believe that solar power may eventually prove to be a viable means for generating electricity. In fact, The Washington Water Power Company is a co-sponsor of the pilot plant at Barstow, California. However, at 9.2-22 Amendment 7 l
S/HNP-ASC/ER 9/16/82 present, photovoltaics is not cost-competitive and has little potential of becoming cost-competitive in the near future. Solar thermal is not currently cost-competitive and pilot plants have just recently begun operation. The l Applicants do not believe that it is reasonable to cancel plans for adding capacity with only the hope that solar power will become viable within the time frame in which new 7 capacity is predicted to be needed. This is especially true given the estimate that five to six years lead time would be required to bring a solar thermal plant online. ' (Ref 24). Moreover, given the nature of solar power, it does not present an alternative means of generating the baseload power to be produced by S/HNP. 9.2.1.2.6 Fusion Reactors 4 The research on the fusion reaction faces decades of problem solving connected with the construction of a reliable, safe, and economical fusion power plant (Ref 26). l7 Thus, fusion reactors are not available as an alternative to the S/HNP. 9.2.1.2.7 Breeder Reactors A breeder reactor, while generating electricity, produces 4 excess resources. fissionable fuel from abundant uranium and thorium Research in the United States has been dela by the debate surrounding the future of nuclear energy.yed Construction of the nation's first large-scale demonstra-tion project, a 380-MW Liquid Metal Fact Breeder Reactor (LMFBR) at Clinch River, will not begin until the early to mid-1980s. Also, higher than projected inflation and interest rates as well as project delays have contributed to increase the original cost by large amounts. Most 7 observers agree that LMFBRs will not be commercially available in time to meet the baseload power requirements 4 that are proposed to be met by the S/HNP (Ref 27) . 9.2.1.2.8 Cogeneration Cogeneration is the process by which both electricity and productive heat are generated simultaneously by one 7 facility. A plant is termed a " topping-cycle facility" if the waste heat from generation of electricity is utilized for a useful purpose. A plant is classified as a
" bottoming-cycle facility" if the heated fluid rejected from a process is utilized to generate electricity.
9.2-23 Amendment 7
S/HNP-ASC/ER 9/16/82 Regardless of which method is used, heat must be produced by one of the means described in Section 9.2. The primary advantage of cogeneration is the ability to increase the useful proportion of total energy which is created in the heating process. For example, a conventional single-purpose electrical generating facility typically has a thermodynamic efficiency of 30 to 40%. By employing cogeneration, beneficial use of heat can be increased by another 25 to 35%. As a result of cogeneration, it is possible to achieve fuel savings of 15 to 30% over what would be incurred if the useful heating process and generation of electricity had occurred separately. (Ref 12) . Cogeneration can be realized either by converting single-use facilities into cogeneration facilities or by constructing new cogneration facilities. A recently conducted study identified 425 MN of existing cogeneration capacity in the Pacific Northwest and an undeveloped cogeneration potential of another 1000 MW which is theoretically obtainable at existing facilities. About 82% of this potential exists in the forest products industry which burns wood and wood residues. (Pef 12) . Additional potential capacity may exist for newly constructed facilities. Utilities in the Pacific Northwest, including members of Applicants, are planning to add cogeneration capacity and this capacity is included in the PNUCC resource analysis. (Ref C). The extent to which the Applicants can augment their cogeneration capacity with additional units beyond that presently planned is problematical and in any case depends upon the willingness of owners of industrial facilities to engage in cogeneration. Since the interests of industry and utilities are not always compatible, barriers to development of cogeneration capacity often exist. As mentioned above, over 80% of the potential cogeneration capacity lies with the forest products industry. As discussed in Section 9.2.1.1.5, this industry is subject to seasonal and business cycles. Consequently, many cogeneration facilities do not offer a source of firm capacity which would be suitable for generation of baseload power. (Ref 12) . Capital costs for cogeneration facilities are extremely site-specific. A study estimated that the cost for a new 25 MWe steam topping-cycle cogeneration would be $63 to $66 million (1979 $); conversion of existing single-use facilities may be far less expensive, depending upon the l 9.2-24 Amendment 7
S/HNP-ASC/ER 9/16/82 i nature of the conversion (Ref 12) . In general, electrical generating equipment costs for cogeneration facilities will be proportionally higher than the costs for equivalent stand-alone capacity since cogeneration facilities are usually. smaller than stand-alone plants. The environmental impacts of a cogeneration facility are generally the same as the impacts of the technology which produces the heat used in the cogeneration facility, except that less fuel is used and waste heat and pollutants are rejected than if the electrical generation and industrial . process were carried out separately. Conversion of an existing single-use facility into a cogeneration facility may cause the emissions and effluents from the facility to increase, since often more fuel must be burned at the 7 facility to support both the industrial process and the generation of electricity (Ref 12) . In general, cogeneration does not offer the Applicants with a reasonable means of generating electricity as an alternative to S/HNP. The realistic potential for adding cogeneration capacity beyond that already planned is uncertain and limited since it requires concurrence of i parties which are outside of the control of the Applicants.
- Furthermore, since the addition of cogeneration capacity f' requires the concurrence of industry, the Applicants cannot afford to rely upon the mere prospect of additional cogeneration to the exclusion of other generating sources due to the uncertainty that industry will find it in its I interests to develoment cogeneration.
, 9.2.1.3 Advanced Energy Conversion Methods Increased efficiency and reduced emission of pollutants may be achieved through the use of newly developed combustion methods, and combined in coal-fired plants. l 9.2.1.3.1 Fluidized Bed Combustion 4 Implementation of boiler construction,' based on fluidized bed combustion techniques, may provide an alternative to fuel gas desulfurization, thereby allowing more economical use-of coal within air quality regulations. Savings in plant capital investment can be realized from reduced pollution-control equipment requirements and boiler costs. The U.S. Department of Energy and the Electric Power Research Institute (EPRI) are supporting phased projects ;
?.2-25 Amendment 7
.~. _ _ _. _ _ ._
1 l S/HNP-ASC/ER 9/16/82 ) l which are aimed at demonstrating both pressurized and 4 atmospheric fluidized combustion techniques in utility-scale applications (Refs 28, 29). Applicants are partici- l7 pating in these demonstration projects through their mutual support of EPRI. Until development is completed, and reliable electric power generation is demonstrated, fluidized bed combustion cannot be considered as an alternative to conventional design fossil boilers, or to the S/HNP. l 9.2.1.3.2 Fuel Cells The main advantage of fuel cells is that they can be . located closer to the load center, with potentially less impact on the environment than gas turbines. In addition, they convert energy to electricity more efficiently than gas turbines. The disadvantages of fuel cells is that they currently have a high cost, and must currently depend on oil or natural gas for fuel. These two fuels have a relatively high cost, and may not be used in large-scale power plants because of the restriction in the Power Plant and Industrial Fuel Use Act of 1978. It is possible that fuel cells may use synthetic fuels discussed in Section 9.2.1.1.2. However these fuels are not yet available on a competitive basis. 4 Since the technology for commercial production has riot been demonstrated, and since the devices do not have fuels available for a baseload operation, fuel cells cannot be i considered a practical alternative to satisfy Applicants baseload requirements. 9.2.1.3.3 Combined-Cycle Concept The combined-cycle utilizes the waste heat from combustion turbine exhaust gases to produce steam in a waste-heat boiler. This boiler, in turn, produces steam for use in conventional turbines. The waste-heat boiler can use auxiliary firing to supplement the heat from the combustion turbine exhaust gases. Significant increases in efficiency over the more tradi-tional fossil-fueled unit designs are predicted for this combined-cycle concept. While the concept is not new, only recently have commercial designs become available. The dependability of this technology using coal-derived 9.2-26 Amendment 7
S/HNP-ASC/ER 9/16/82 l l synthetic fuels has not been demonstrated (Ref 30), and the use of oil or natural gas as a fuel is constrained by the Fuel Use Act. Further development and demonstration of the adequacy of the equipment designs would be required before Applicants would rely upon such a design to supply baseload requirements. 9.2.1.3.4 dagnetohydrodynamics Magnetohydrodynamics (MHD) is a pr) cess for generating direct current electricity by passing extremely hot (3,600 to 4,5000F), partially ionized gases through a magnetic field within a duct lined by electrodes. The gases that 4 emerge from the generator are still very hot, and can be used to fire a conventional steam cycle. Goals of 50 to 60 percent thermal efficiency for the total plant, when this process is coupled with the combined-cycle technology, provide the incen'cive for continuing research. MHD also holds the potential for cleaner burning of coal, both through increased efficiency and the facilitating of ash and sulfur removal. The current research on this technology is being funded by the U.S. Department of Energy, and is being conducted at ! the Montana Energy R: search Institute. There is general agreement that this technology is a long way from commer-cial availbility, and thus cannot be considered an alter-native to the S/HNP (Ref 31) . l7 . 9.2.1.4 Conclusions - Sources of Energy To adequately and reliably meet the baseload demand for 4 electricity identified as the need for the S/HNP, Appli-cants believe they must rely on proven technology and energy supply. Some of the energy sources discussed above can provide some of the energy on this bases. Applicants believe they will need that energy, and the output from the , S/HNP as well. Based upon the above analysis, the only practical alternative to nuclear fuel is coal. 7 4 I
~
9.2-27 Amendment 7 l l l I' - - , _ . _ . - , . . - . . . . - . . _ , _ . - .-
r S/HNP-ASC/ER 9/16/81 References for Section 9.2
- 1. U.S. DOE, Final Environmental Impact Statement: The Role of the Bonneville Power Administration in the Pacific Northwest Supply System, U.S. Doe, DOE /EIS-006 (1980), pp. IV, 197-199.
- 2. National Research Council, Energy in Transition 1985-2010, Final Report of the Committee on Nuclear and Alternative Energy Systems, National Academy of Sciences (1979), pp. 364-419.
- 3. Johnson, Leonard R., Simmons, George, and Peterson, James, Energy Supply and Environmental Impacts, Unconventional Energy Sources, Study Module III-B Final Report, Northwest Energy Policy Report (1977).
- 4. EPRI Journal, Earth's Renewable Resources, A Special Report on Technology Development, Electric Power Research Institute (December 1981) .
- 5. Electric Power Research Institute, Biofuels: A Survey, EPRI ER-746-SR (June 1978) , pp. 7-1 to 7-9.
- 6. Bonneville Power Administration, Draft Environmental Statement, The Role of the Bonneville Power Administration in the Pacific Northwest Power Supply System, Part 1, The Regional Electrical Power Supply Sy_s t em , Department of the Interior ( DES-7 7- 21) (July 1977), pp. V-5 to V-24 and V-108 to V-174.
- 7. Electrical Power Research Institue, Technical Assessment Guide, EPRI P-2410-SR (May 198 2) , App. B-88 to 97.
- 8. Pacific Northwest Utilities Conference Committee, Northwest Regional Forecast of Power Loads and Resources, July 1982 - June 1993 (May 198 2) , pp. I-17 l
to 21, III-6 to 12, and VI-l to VII-4. 1
- 9. Bergvall, John A., Bullingtn, Darryl C., Gee, Loren, and Koss, William, Wood Waste for Energy Study, Inventory Assessment and Economic Analysis, State of Washington Department of Natural Resources l (September 1, 1978).
1 O 9.2-28 Amendment 7
.- .__. . .. . _ . . .- . - _ . . ._= . - - . , - - - - . . _ -
S/HNP-ASC/ER 9/16/81 l t
- 10. Office of Applied Energy Studies, Washington Energy !
Research Center, Washington State University / University of Washington, Independent j Review of Washington Public Power Supply System : Nuclear Plants 3 and 4, Final Report to the Washington ! State Legislature (Maren 1982) , pp. 84-108. ! l
- 11. Northwest Energy Policy Project, Energy Futures i Northwest, Northwest Energy Policy Project Final Report (May 1978), pp. 95-114. ,
- 12. U.S. Department of Energy, Final Environmental Impact l Statement, The Role of the Bonneville Power !
Administration in the Pacific Northwest Power Supply ! ! System, DOE /EIS-0066 (December 1980), pp. IV-126 to [ 3 169. ;
- 13. Municipal Solid Waste as a Utility Fuel, Electric !
Power Research Institute (May, 1980). l ) 14. Wood and Biomass Subcommittee of the Alternative Researces Committee, Wood-Residue Energy for Utilities, Pacific Northwest Utilities Conference ; Committee (April 1982) . ;
- 15. The Washington Water Power Company, Environmental l l Assessment Report for the Creston Generating Station ;
(January 1981) , p. 3.2-17. j
- 16. Cadogan, John B., and Ancona, Daniel F. III, " Wind -
Turbines at Work," IEEE Spectrum, Vol. 19, No. 8 (August 1982), pp. 46-51. ',
- 17. Wind Energy Subcommittee of the PNUCC Alternative Resources Committee, Wind-Energy for Utilities - Part l' 1, Pacific Northwest Utilities Conference Committee TJanuary 1982) , i
- 18. Fassbender, L.L., Assessment of Electric Power f Conservation and Supply Resources in the Pacific !'
Northwest - Volume VI, Geothermal Electric Generation (Draft), Battelle Pacific Northwest Laboratories (June ; 1982). ;
- 19. Equitable Environmental Health, Inc., Environmental !
- -Impacts of the Generation of Electricity in the Pacific Northwest, Volume 1 (September 1976), pp. 20- ;
4
- 28. l t
i i l l , 9.2-29 Amendment 7 l
S/HNP-ASC/ER 9/16/81
- 20. Shafer, J.M. Assessment of Electric Power Conservation and Supply Resources in the Pacific Northwest - Volume VIII, Hydro (Draft), Battelle Pacific Northwest Laboratories (June 1982) .
- 21. Chen, Henry H., " Economics of Low-Head Hydro: U.S.
Case Studies," Low-Head Hydro -- An examination of an alternative energy source, University of Idaho (September 1978), pp. 65-69.
- 22. Bonneville Power Administration, Draft Environmental Statement, The Role of the Bonneville Power Administration in the Pacific Northwest Power Supply System, Appendix A, BPA Power Resources, Acquisition, Planning and Operations, Department of the Interior
( DES-7 7- 21) (July 1977) , pp. III-150 to 188.
- 23. PNUCC Solar Subcommittee to the Alternate Resource Committee, Solar Electric Generation A3ternatives for the Pacific Northwest, Pacific Northwest Utilities Ccnference Committee (June 198 2) .
- 24. Michalsky, J.J., Drumheller, K., Smith, S.A., Watts, R.L., Assessment of Electric Power Conservative and Supply Resources in the Pacific Northwest, Volume IX, Solar (Draft), Battelle Pacific Northwest Laboratories (June 198 2) .
- 25. Energy Information Administration, Annual Report to Congress, DOE /EIA-0 173 (79)/2 (1979), pp. 107-123.
- 26. Schur, S.H., et. al, Energy In America's Future, Resources for the Future, John Hopkins Press, London (1979), pp. 299, 319.
- 27. EPRI, Technical Assessment Guide, In Publication.
- 28. Electric Power Research Institute (EPRI), Assessment of Atmospheric Fluid Bed Recycle Systems, EPRI RP l T180-1, In Publication.
- 29. EPRI, Preliminary Assessment of Alternative PFFBC Power Plant Systems, EPRI CS-1451 (July 1980).
- 30. EPRI, Gasification - Fuel Cell and Gas Turbine Power Plans, EPRI AP 1542 (September 1980).
- 31. EPRI, Open Cycle MHD Systems Analysis, EPRI, AP-1316, (February 1980).
O 9.2-30 Amendment 7
S/HNP-ASC/ER 9/16/81 I a t !' [$ *
- 32. Fung, K.T., Scheffler, R.L., and Stolpe, J., " Wind Energy - a Utility Perspective," IEEE Transactions on ;
Power Apparatus and Systems, Vol. PAS-100, No. 3 r i (March 1980), pp. 1176-82. l i i i i i i 1 l l l l
/
i i i i - i I l . I i w
+
k 9.2-31 Amendment 7 ,
S/HNP-ASC/ER 9/16/82 9.6 ALTERNATIVE OF ACQUIRING WASHINGTON PUBLIC POWER SUPPLY SYSTEM UNITS 4 AND 5 At this time, it is not possible to determine whether the Applicants should undertake acquisition of WPPSS Units 4 and 5 as an alternative to constructing and operating S/HNP. Many important economic, contractual, licensing and operating factors are presently encertain. Among these are issues related to the purchase terms, such as price, date of ownership transfer, guarantees of clear title, protection against claims, financing, and purchase price payment schedules; issues related to workmanship, such as existing and future warranties, possible discovery of construction errors after purchase, and assumption of any unresolved existing problems; potential problems related to transferring the licenses; potential problems in sharing facilities and sites; issues related to disposition of purchased systems and equipment for S/HNP; and potential problems related to existing contracts for WPPSS Units 4 and 5, such as any contracts with the Architect / Engineer and fuel contracts. Until these and other uncertainties are resolved, it will not be possible to make reliable economic comparisons between the various alternatives, such 7 as the comparative cost of power over the anticipated
\
operating livec of the respective units, or the comparative cost to the ratepayers of the region of the various alternatives. Puget Power is willing to explore these questions in cooperation with the other parties in interest. It seems only realistic, however, to suggest that developing reliable answers may be a rather time consuming process. It should also be noted that the key answers are dependent upon parties and events beyond the l, control of Puget Power. In addition to these f~ctors, the future power needs in the region will be a signit' cent factor. Should a high rate of , growth be experienced, .._ WPPSS units may well be needed ; in addition to the S/HNP. Consequently, both WPPSS Units 4 i t and 5 and the two S/HNP units should be among the resource options available in the f-ture to meet regional power i needs. The question of ti- proper mix of generating resources and the time when each will be needed are questions that can only be answered in the future, as some ; of the uncertainties now present are resolved. s Pending the emergence of reliable answers, it is only l reasonable to continue on schedule with efforts to obtain construction permits for the Skagit/Hanford units. 9.6-1 Amendment 7
.=. ___ _-. .
1 S/HNP-ASC/ER 9/16/82 1 J 4 l t f I APPENDIX A i i i NORTHWEST REGIONAL FORECAST OF ' POWER LOADS AND RESOURCES ! July 1982 - June 1993 I i t i i l 1 i l i l I I I , I i i Amendment 7 l l
- . - . - . - . . . . . , - , , . , . . . , . . - . . - - . . . . - - . , , , , . . . - - , - _ - . . . . , - - ~ , , , _ , . - - - .
i 1 i I I 1 l 1 NORTHWEST REGIONAL FORECAST OF POWER LOADS AND RESOURCES f I ! 1 ! ! for l 1 1 4 i JULY 1982 - JUNE 1993 4 l r ,. l i i l l !- Compiled by l PACIFIC NORTHWEST UTILITIES i CONFERENCE COMMITTEE ! Portland, Oregon !
- MAY,1982 i -
- l.
} e ( . 1 r
O ACKNOWLEDGEMENTS All dato included in this report has been submitted by the indicated utility or agency. Bonneville Power Administration prepared the regulations that provided the hydroelectric-system copobilities and the studies of the probability of energy shortages. O l ORDERING INFORMATION 1 Requests for copies of this report should be directed to the PNUCC 520 SW Sixth Avenue, Suite 505 Portiond, Oregon 97204 l (503) 223-9343 O
1 G TABLE OF CONTENTS SECTION PAGE Letter of Transmittal Memorondum -
Subject:
1982 BPA Draf t Regional Load Forecast i
SUMMARY
DATA Description of Report 1-I Definitions I - 1I Figure of Peak Loads and Resources I - 12 Figure of Energy Loads and Resources I - 13 Requirements and Resources I - 14 Summary of Requirements 1- 15 Summary of Peak Resources 1 - 16 Summary of Energy Resources 1- 17 Schedule of Planned Resources I - 18 Summary of Prospective Resources I - 20 11 LOADS Total Northwest Region II - I p Firm Northwest Region ll - 2 Regional System Diversity Adj sstment 11 - 3 Benton County PUD 11 - 4 Bonneville Power Administration 11 - S BPA Diversity Adjustment II - 6 BPA Transmission Losses 11- 7 Chelon County PUD 11- 8 Clark County PUD ll - 9 Cowlitz County PUD 11 - 10 Douglas County PUD 11 - 1 I Eugene Water & Electric Board 11 - 1 2 Grant County PUD 11- 13 Grays Harbor County PUD 11 - 1 4 Idaho Power Company II - 15 Industrial Customers of BPA II- 16 Montano Power Company II - 17 Other Public Utilities 11 - 18 Adjustments to Other Public Utilities 11 - 19 Pocific N.W. Generating Company II - 20 Pacific Power & Light Company II - 21 Pend Oreille County PUD ll - 22 Port!and General Electric Company II - 23 Puget Sound Power & Light Company 11 - 2 4 Seattle City Light 11 - 2 5 Snohomish County PUD 11 - 2 6 Springfield Utility Board 11 - 2 7 i Tocomo City Light 11 - 28 .d be Utah Power & Light Company II - 29 The Washington Water Power Company II - 30
SECTION PAGE ll LOADS (Cont.) Top Quartile Bonneville Power Administration II - 31 BPA Diversity Adjustment 11 - 3 2 BPA Transmission Losses 11 - 3 3 Industrial Customers of BPA 11 - 3 4 Interruptible Utah Power & Light Company 11 - 3 5 Total Company Firm Loads Montona Power Company 11 - 3 6 Pacific Power & Light Company 11 - 3 7 111 RESOURCE CAPABILITY Summary of Hydro 111 - 1 Existing Cool-Fuel lli - 2 Existing Nuclear-Fuel til - 3 Existing Combus ion Turbine ill - 4 Existing Cogeneration 111 - 6 Existing Renewable 111 - 7 Existing Miscellaneous ill .8 Planned Combustion Turbine ill - 9 ( Planned Cogeneration 111 - 1 0 Planned Renewable lli - 1I Thermal Energy Available for Reserves lil - 12 IV HYDRO RESOURCE CAPABILITY January Peak Columbia Moinstem IV - l Seasonal IV - 2 Pondage and Minor Hydro IV - 3 Miscellaneous IV - 4 Critical Period Columbio Mainstem IV - 5 Seasonal IV - 6 Pondoge and Minor Hydro IV - 7 1 Miscellaneous IV - 8 l 40-Year Average Columbio Moinstem IV - 9 Seasonal IV - 10 Pondoge and Minor Hydro IV - l l Surplus Energy in Excess of FELCC IV - 12 V EXPORTS / IMPORTS Summary of Exports V-I Summary of Imports V-2 Contracts to East V-3 Contracts to Southwest V-4 Contracts from Conodo V-5 Contracts from East V-6 Contracts from Southwest V-7
i SECTION PAGE VI NEW GENERATING CAPACITY Actually Installed - VI - 1 Jonvory 1981 through December 1981 i i Planned Resource Schedule - VI - 2 Jonvory 1982 through June 1993 Prospective Resources - l January 1982 through June 1993 VI - 5 ) Portial List of Plants Under Consideration VI - 7 Vil NAMEPLATE RATINGS t Existing Installations Vil - I
- Vill MISCELLANEOUS Grand Coulee Project Pumping Requirements Vill - !
USBR Local Use Vill - 2 I l l 1 i 1 4
s PNUCC ( ) PACIFIC NORTHWEST UTILITIES CONFERENCE COMMITTEE xs May 4,1982 Mr. John Ellis Puget Sound Power & Light Company Puget Power Building 10608 NE 4th Avenue Bellevue, Washington 98009
Dear Mr. Ellis:
The Northwest Regional Forecast of Power Loads and Resources is a compilation of estimated loads and planned resources of the Bonneville Power Administration (BPA) and electric utilities in the Pacific Northwest. It has been compiled by PNUCC's System Planning Office from information supplied by member utilities and from estimates of the region's hydroelectric capability determined with a BPA computer model which simulates coordinated operation of the hydroelectric system. It is the result of regional planning efforts by PNUCC and project specific o planning efforts of individual utilities. I \
\ i V The primary value in the Foreca st is as a document of projected regional loads and planned regional resources. A.'though not a planning document in tne sense of evaluating alternatives to develop an optimal plan, it provides a base for examining alternative utility plans, conservation and renewable resource programs, and project schedules. In addition, it serves as a basis for evaluating the sufficiency of the planned resources.
Recent events, such as the recession's disproportionate impact on the Pacific Northwest economy, the uncertain impact of ongoing conservation efforts, the termination of WNP 4 and 5, and the impending development of a Regional Plan, have presented a rapidly changing environment from which to project future energy loads. This year, more than any period since World War 11, a great deal of uncertainty surrounds future economic growth and policy decisions affecting projection of future energy loads. Forecast Methodology The sum of utilities (SOU) loads, estimated by the Region's utilities and by BPA with respect to the Direct Service Industry (DSI) loads, is used in this report as the basis for comparison of loads and resources. There are other and widely dif fering load forecasts for the region which are referred to below for comparison and which will be described in a separate document intended primarily to explain the SOU forecast. This document, entitled, Sum of Utilities Load Forecasts, Northwest Region, will describe the sum of utilities load forecast in greater detail, focusing on the forecasting assumptions, conservation estimates, methods, and the customer l lg ), class breakdown embodied in the load forecast. v PNUCC 520 SW SIXTH AVENUE. SUITE 505 PORTLAND. OR 97204 - (503) 223-9343
l Page 2 Regional requirements and resources for the ten year period 1982-83 to 1992-93 are summarized and compared in Figures 1-1 and I-2, and Table I-1. Although energy deficiencies are shown in all but one year, the deficiencies are slightly less than projected in last year's forecast despite the termination of WNP 4 and 5, the slipping of Creston #1, #2, and #3 and the extension of construction on WNP 1. Figures 1-1 and I-2 display requirements and resources, and indicate surpluses or deficiencies as single values for each year. Table 1-1 also shows those single values, but indicates energy deficiencies also by giving the probability of not meeting the firm loads in any four month period of each forecast year. Neither provides a complete answer for the decision maker. The single value procedure compares the sum of utilities requirements with resource capabilities based on the assumptions of critical year water, average thermal performance, and all plants being on line on their probable energy dates. The probability procedure uses the same single value load estimates, but considers uncertainties of resource capabilities. The Energy Reserve Planning Model, with which these probabilities are determined, utuizes all historic water years, with one as likely to occur as another. It also considers the probabilities of projects being operable on their estimated probable energy dates and of 6perating during each period at levels greater or less than those estimated to be most likely. With these two values given, it can be seen that, even in a year with a near balance Q of firm energy resources and load, based on a critical water assumptions, there is the possibility energy losses from thermal project slippages or greater than average forced outages will exceed the energy gain provided by water conditions being better than critical. Table 1-1, for example, indicates a negligible 118 MW f3rm energy deficit in 1984-85 with critical water and yet a significant probability (13 percent) that resources will be insufficient to meet firm loads for some pericif in that year. Ten Year Growth Rates The total Northwest Region energy loads are forecast by the utilitics to grow at an average annual rate 2.7 percent over the ten year period 1982-83 to 1992-93. The firm energy loads are forecast to grow at a 2.L percent rate over the same period. Regional peak loads are projected to grow at 2.9 percent per year on both a firm and total load basis. These energy loads are a summation of forecasts made by individual utilities and BPA, which forecasts loads for its 051 and Federal Agency customers. It shnuld be noted that these loads represent mid-point forecasts by the submitting utilities, and could vary substantially above or below the median estimate. As in recent years, this year's utility loads are forecast to grow at a slower rate than they have in the past. This is primarily due to revised projections of the , economic and demographic assumptions and conservation savings which are included in individual utility load forecasts. Key among these are projections of ! population and employment, which are lower than last year's projections, and electricity price, which is higher than was projected last year. Compared to last year's forecast, projected Regional firm energy loads are 730 average MW lower in (O s 1982-83 and 1,444 average MW lower in 1991-92. Regional firm peak loads are also lower in this years forecast; 2,973 MW lower in January 1983, and 5,149 MW lower in January 1992. Depending upon the year, from 25 to 35 percent of the reduction
n Page 3 (V) from last year's estimate in projected peak loads is a result of an adjustment for Regional diversity among utility systems, which was done by PNUCC for the first time this year. These figures are used to reflect the uncertainties discussed above, but should not be confused with an individual system's utility peak load responsibility. Econometric Model Forecast In recognition of the uncertainty in projecting future loads, PNUCC has for the sixth year made its Econometric Model Forecast of energy sales as a cross-check on the reasonableness of the aggregated utility forecast. The Econometric Model Forecast is based, in part, on economic, demographic and conservation assumptions provided by 64 participants at PNUCC's Model Input Workshop, which was held in Seattle, Washington in September, 1981, with non-utility as well as utility participation. The Econometric Model Forecast predicts a mean average annual rate of growth of electricity sales over the ten year period of 2.1 percent, with a 90 percent confidence interval ranging from 1.5 to 2.7 percent. Other Regional Forecasts in addition to the PNUCC sum of utilities forecast and Econometric Model Forecast, several other projections of Regional loads have been published this year. For the period 1980 to 1990, a load forecast done for the Independent Review of WPPSS 4 and 5 study projects an average annual compound rate of growth for firm (a) s/ loads of 1.8 percent, adjusting for treatment of cogeneration as a load reduction. For the same period, BPA's baseline projection of firm loads grows at 1.6 percent per year. The rates of growth for both of these forecasts fall within the range of uncertainty as measured by the PNUCC Econometric Model. The window of uncertainty depicted by the PNUCC Econometric Model in 1990 is equivalent to plus or minus three years of load growth. Whether the Region will experience the projected 1990 load level in 1990,1987, or 1993 depends upon mar 9 factors, not the least of which are the timing of the economic recovery from the current recession, the timing and results of new cost effective conservation programs, and the successful completion of power plants now under construction. Twenty Year Growth Rates Examining recent forecasts, the range of mean growth rates varies from a low of 1.6 percent annual load growth (the BPA forecast) to a high of 2.8 percent (the SOU forecast). As was explained above, these are 10 year growth rates. The 20 year mid-range firm energy growth rates for each forecast are as shown below.
- 1. SOU 2.5
- 2. Econometric Model(with PNUCC Workshop Inputs)* 2.1
- 3. BPA Draf t Forecast 1.7
- 4. WNP 4/5 Review *
- 1.7
- Total Sales
** Cogeneration treated as a resource addition p1 Although the PNUCC SOU Forecast is principally a 10 year forecast, these 20 year i
,V projections are shown for comparative purposes, since: (1) they are the l i i I i
\
I d Page 4 growth rates which have received widespread publicity in recent months; and, (2) the Regional Council's upcoming forecast will span a 20 year range. It is not surprising that results of the BPA Draf t Forecast and the WNP 4/5 Independent Review are quite similar. While there are differences in detail, both , forecasts use the Oak Ridge National Laboratory residential and commercial sector models, as well as similar approaches for the residual manufacturing portion of the industrial sector. Resource Changes A number of significant changes have been made in the planned energy resources since the 1981 Forecast. The WNP 4 and 5 projects have been terminated, all three of the Creston plants have been delayed one year, construction on WNP 1 has been extended by three years, the Probable Energy Date of Colstrip #3 has been slipped four months and Skagit #1 six months, and the Oregon site certificate application for Pebble Springs has been withdrawn. Three of the additional 4 units at the Libby project (315 MW) have been removed from the planned catagory and an additional 9 hydro projects totaling 607 MW have been transferred from the planned to the prospective category. There are also some additions to the planned resources with two combustion turbines, having a combined capacity of 247 MW and 6 MW of average energy, added in 1983 and Skagit #2 added in 1993. Additional capacity
,m totaling 269 MW has been added at five existing hydroelectric projects, 23 MW at / new hydroelectric projects, and a total of 13 MW at two new cogeneration projects.
( )) In addition, the Hanford nuclear plant has been included as a resource through June 1988, but at a level reduced from 515 MW to 400 MW after 1982-83. The firm energy capability of the Beaver combustion turbine has been increased to 301 average MW through 1995. Other impacts on System Hydro Capability There are two potentially significant developments which could reduce the firm hydroelectric energy summarized in this report, to a greater extent than were included in the hydroelectric operations studies. One is an allowance for increased flows to improve downstream migration of juvenile salmon on the mainstream of the Columbia River. The other is a possibly greater expansion of irrigation development on the Columbia Basin Project. First, if the Fish and Wildlife plan developed by the Regional Council were to incorporate minimum flows recommended by the Fish and Wildlife Agencies and Indian nations, it is estimated that a loss of at least 490 MW of firm energy would result. An additional 80 MW would be lost if a recommendation limiting the draw down of Hungry Horse storage were adopted. An interagency study entitled " Main Stem Columbia River and Snake River Instream Fish Flow Report" and dated March 1982, reports on investigation of numerous scenarios of fish flow levels and their impact on firm power. Second, a large undeveloped portion of the Columbia Basin Project, for which the
, yet unused second Bacon Siphon was constructed, continues to be under active (m).
( ,/ investigation. The schedule for future development of this potential is uncertain and hence, a modest allowance has been made for reduction in flows from Grand , Coulee downstream. U.S. Bureau of Reclamation's estimated pumping load are included
d I Page5 Prospective Resources i The listing of Prospective Resources in Table I-6 indicates, by the increased number of projects included, a more intensive effort by the utilities to bring , cogeneration and renewables into their resource plans. These projects are in a preliminary stage of active planning but have not yet progressed far ersugh to be included as planned projects. There are many more renewables (small Sydro, wind, and solar) being investigated as a result of the high priority utilities have placed on their development. , Despite this activity, uncertainties of cost effectiveness, environmental acceptability, and permitting processes have prevented the inclusion , of any substantial amounts in the planned resource category at this time. Active investigation continues and, as these bacome firmed up, they will be included in the , utility plan.
- In addition to resources in Table I-6, several existing and potential conservation programs are already included in utility load forecasts. This trend should continue in future years.
Ranste of Uncertainty The comparison of requirements and resources in this report indicates some probability be correct. of Should shortage in each of the next ten years if the SOU forecast proves to j one of the lower forecasts be correct, there could be brief ! periods the of surplus which would require the marketing of additional power outside region. Should some of the potentially greater demands on the power system from the fisheries requirement or increasas in C lo umbia Basin irrigation be realized, some schedules might need to be accelerated or purchases from outside l the area be required. ; The SOU forecast, PNUCC's econometric crosscheck and other regional forecasts indicate to a range of annual energy growth rates, for the 20 year estimates, from 2.5 percent. .. t7 Such a wilde spread is perhaps inevitable given: (1) the different methodologies growth; .(3) involved; (2) disparate assumptions about long term economic estimates of outthe changing nature of major demographic variables; (4) varying year growth in electricity and fossil fuel prices; (5) the unpredictability of'such future strategic events as oil embargos or international conflicts; and,(6) the effect of nationa! and regional policies. While differences of opinion eliminated.regarding these variables can be narrowed, they can probably never be In view of such future uncertainties, the most prudent course of action for the present, to ensure a cost effective and environmentally acceptable system, is to > maintain current schedules. By early 1983, publication of the Regional Council's Forecast, and subsequent iterations of the BPA and SOU forecasts, should hopefully-narrow the range of uncertainty for resource planning purposes. Sincerely,
-(
3d' 1 Randall W. Hardy Executive Director
- -e, ,-_ e - , - ,n . , -e. -+ .r- ,
/ PNUCC (v ) PACIFIC NORTHWEST UTluTIES CONFERENCE COMMITTEE MEMORANDUM To: EXECUTIVE COMMITTEE From: EXECUTIVE DIRECTOR Date: May 3,1982
Subject:
1982 SPA DRAFT REGIONAL LOAD FORECAST The PNUCC Load Jorecasting Committee, at the direction of the PNUCC Executive Committee, has begun a detailed review of BPA's recent load forecast, Bonneville Power Administration Forecasts of Electricity Consumption in the Pacific Northwest. Draf t, Bonneville Power Administration, Division of Power Requirements. April 1982. While the detailed review is not complete at the present time, we have identified several items which potentially affect regional resource planning. These are summarized below. The Load Forecasting Committee's detailed review will be completed before June 2,1982, the end of the public comment period on BPA's load forecast. Base Year Values Based on PNUCC analysis,I BPA's forecasted 1980 regional loads are approx-imately 147 average MW too low. This is due primarily to the fact that BPA's base year (1979) energy sales have not been adjusted to reflect " normal" temperature conditions in the region. Since calendar year 1979 was warmer than normal, this omission would have a tendency to understate expected loads used in the BPA forecast. The effect of this understatement grows over time. By 1990 it will reach 216 average MW and by the year 2000 it will total 251 average MW. PNUCC believes that these normalized estimates should be incorporated into the final BPA forecast. BPA Programmatic Conservation Savings Savings estimates for BPA's FY 81, 82 & 83 budgeted conservation programs, after adjusting for conservation savings that would occur do to rising electric prices, were subtracted from the load forecast. For calendar year 1990, this amounted to 505 average MW. Of this reduction,200 average MW was for FY 81 programs and 305 average MW was for FY 82 and 83 programs. The overall impact in the year 2000 totalled 485 average MW, of which 128 average MW was attributable to FY 81 I Pacific Northwest Utilities Conference Committee, Load Forecasting Committee, " Estimation of Base Year Values for Pacific Northwest [ Electricity Forecasting Models," April 1982.
~ ,/
PNUCC 520 SW SIXTH AVENUE. SUITE 505 PORTLAND. OR 97204 - (503) 223-9343
Wh
\
(U) Page 2
/
programs and an additional 357 average MW resulted from FY 82 & 83 programs. While there is some logic to BPA including savings from all three budget years, we feel it would be more appropriate, for purposes of forecasting Regional loads, to include only those program savings attributable to FY 81 programs (since those programs are already being implemented). The FY 82 & 83 programs would be more accurately handled through BPA's ongoing conservation potential assessment because the structure of these programs has not yet been defined, nor have the contracts under which these programs would be offered been negotiated. This observation is especially true for FY 83 programs which are only in the very preliminary program design stages. Forecast Probability in the draft forecast document2 BPA indicates that its " base line" forecast falls below the 50 percent probability level. Since, at least in concept, all other regional forecasts (CRA, PNUCC, etc.) reflect the midpoint of expected outcomes, PNUCC believes BPA's forecast should also be adjusted to reflect a true midpoint, if this adjustment were made, regional leads would be higher by 245 average MW in 1990 and 463 average MW in the year 2000. Model Structure [ h () Residential & Commercial Sectors in its residential and commercial sector forecasts, BPA utilized the Oak Ridge National Laboratories energy forecasting models. The models allow detailed analysis of usage characteristics by structure type and "end-use". They are also amenable to policy analysis regarding the effects of such programmatic actions as more stringent building standards, insulation retrofits, and appliance efficiency improvements. These models do, however, have disadvantages. First, a large number of detailed assumptions are required to produce a forecast. Not all the data exists upon which to base such assumptions, particularly in the commercial sector. As a result, the residential and commercial models are calibrated upon information which is largely synthetic in nature. This leads to the second disadvantage: the models are not capable of being "backcast" over some historic period to test their reliability. BPA's residential and commercial forecasts appear plausible given the input assumptions used. Any regional planning decisions made using the results of these models, however, should be tempered with the realization that they are somewhat experimental in nature. The ongoing process of developing these models and the required data may ultimately lead to alternative forecast results. 2 Bonneville Power Administration Forecasts of Electricity Consumption in the Pacific Northwest, Draft, Bonneville Power Administration, Division of Power Requirements, April 1982, Table #2, p. 7.
Page 3 Industrial Sector BPA is currently using the " revised" Northwest Energy Policy Project (NEPP) industrial energy use model to forecast non-DSI industrial electricity sales. The NEPP model is an econometric forecasting tool which forecasts total energy demand for specific industries and then distributes this total to the various industrial energy inputs (electricity, natural gas, oil, coal) on the basis of relative prices. The NEPP model was specified on national energy data, as published by the U.S. Department of Commerce. Like many other models specified over this data, the NEPP model suffers from both " aggregation" and "locational" biases. As a result, elasticities in the NEPP model tend to reflect factors other than pure response to price considerations. Aggregation bias occurs because industries using very different processes to produce many different types of products are aggregated into the same industrial classifications. Locational bias refers to the tendencies of industrial firms to locate near their sources of supply and energy inputs in the most cost effective manner possible. \ The practical impact of these two effects is that long run electricity price coefficients are of ten overstated. The long run industrial price elasticity in the NEPP model is approximately -1. We consider this estimate to be too high. The effect of this elasticity is most evident in the first five years of the BPA baseline industrial forecast. Between 1980 and 1985 overall industrial output grows approximately 20 percent while electricity sales fall over 7 percent. This implies that electricity consumption per unit of output falls nearly 30 percent during the first five years of the forecast; the very period when the region is supposedly recovering from the current recession. On the basis of discussions with BPA, we have learned that they are reviewing the model's " lag structure." It is our opinion that this may result in changes which may partially mitigate but not necessarily eliminate the above mentioned problems. One area in which the industrial forecast is too high -chemicals - may tend to offset these additional underforecasting problems. Although we cannot yet quantify the magnitude of any high side variance in the chemicals industry, we do not believe it will completely cancel out lower growth in other industrial sectors, created by the impact of artificially high coefficients for long run price elasticity. Hence, overall the industrial sector forecast is probably still too low. Summary We have identified specific adjustments to the BPA forecast which we think are appropriate. These are: 1) shif t of budgeted but not implemented Bonneville FY 82
& 83 conservation programs from the forecast to the BPA conservation assessment; } 2) incorporation of revised " lag" adjustments in the industrial sector; 3) adjustment u of the forecast to the " midpoint" or -50 percent probability level; and, 4) alteration of base year values to reflect weather adjusted estimates.
d Page 4 The precise cumulative effect of such actions is difficult to determine, since they are all interactive. Recognizing this limitation, incorporting the suggested PNUCC adjustments will make regional loads approximately 147 average MW higher in 1980, and at least 766 average MW higher in 1990 and 1,071 average MW higher in the year 2000. With these adjustments Regional loads will grow at an annual rate of 1.9 percent over the 20 years compared to the Draf t BPA Forecast result of 1.7 , percent. These do not exhaust the necessary adjustments to make BPA's Forecast reflect a more probable median range estimate. In particular, additional work is probably required in the industrial sector to eliminate problems already noted. Further comments will be included in the more detailed analysis currently being prepared by the PNUCC Load Forecasting Committee. O , i k I L t 'V l l
g j NORTHWEST REGIONAL FORECAST DESCRIPTION OF REPORT The Pacific Northwest's publicly and cooperatively owned systems, investor- 6 owned utilities, the Bonneville Power Administration (BPA), the Industrial t Customers of BPA, and the Corps of Engineers have historically cooperated in i informal, long-range planning with respect to future regional power l requirements. As port of this process, the Northwest Regional Forecast is , prepared by the Pacific Northwest Utilities Conference Committee (PNUCC) to show estimated loads and capabilities of resources. Details of loads and resources for 1982 through 1993 have been submitted by the indicated utility I or agency and are tabulated in this report. Procedures employed in preparing , the report are described in the remainder of this section. O \ Planning Area The Northwest Regional planning area is that crea defined by the Pacific Northwest Electric Power Planning and Conservation Act. It includes the States of Oregon, Washington, Idaho; Montana west of the Continento! Divide; portions of Nevado, Utah, and Wyoming that lie within the Columbia River , drainage basin; and any rural electric cooperative customer not in the geographic area described above, but served by BPA on the effective date of the Act. Essentially, the Region encompasses the operating systems of the Bonneville Power Administration, Portland General Electric Company, Puget Sound Power and Light Company, The Washington Water Power Company, Idaho Power Company; portions of Pacific Power and Light Company, Utah Power and Light Company rand The Montano Power Company; and the Region's public , electric utilities. It does not include service creas of these utilities of the Northwest Power Pool (NWPP): B. C. Hydro and Power Authority; West Kootency Power and Light Company, Ltd; and TransAlta Utilities Corp. m Firm contractual arrangements between utilities operating in the Regional Areo and utilities outside this crea are included in summary tabulations. 11
l Lood Estimates The loods used for planning are the sum of system peak loads and system energy loads estimated for the utilities operating in the Region. The Regional loods, by month, are shown in Section 11 of the report, which also contains a breakdown of loads by major utilities. In addition, o monthly tabulation of all adjustments to the food is given. Section ll also details BPA's top qucrtile loads and Utah Power end Light's interruptible loads. Load forecasts for the total service areas of the Montano Power Company and Pacific Power & Light Company are tabulated for information purposes only and are shown of the end of Section 11. Table 1-1 compares resources with both firm and total requirements for the Region. Northwest Regional firm lood equals the sum of the individual utility firm loods shown in Section Il plus the firm lood for Other Public Utilities, the industrial Customers of BPA, BPA transmission losses, BPA Diversity Adjustment, and the Regional system diversity adjustment. Northwest Regional total load equals the som of Northwest P.egion firm lood, BPA top quartile food, and Utah Power and Light Company interruptible load. Peak Load Estimates Peak loads tabulated for each system in Section 11 are the highest estimated 60-minute clock-hour overage demand for each month. The total Regional peak load listed in Toble 1-2 is the sum of the January peak values in Section 11 offer adjusting for system diversity and to o consistent expected occurrence level. Peak load diversity is the difference between the sum of the individual utility non-coincidental peak loods and the sum of the ir.dividual utility peak loads coincident with the Northwest Regional peak. This diversity exists because individual utility monthly peak loods tend to occur at different hours of the month. The adjustment of peak loads to o consistent occurrence level is mode to arrive of the level of peak demand consistent with normo! weather. While most utilities submit peak forecasts that assume normal weather, others submit peak forecasts based on extreme weather. The peak loads summarized in Table 1-2 represent coincidental Regional system peak loads that are consistent with normal weather. 12
BPA System Loads BPA firm system Icods are the sum of the following loods tabulated in Section 11: Benton County PUD, Clark County PUD, Grays Harbor County PUD, Pacific N.W. Generating Company, Snohomish County PUD, Springfield Utility Board, Other Public Utilities, Industrial Customers of BPA. BPA transmission losses, and BPA diversity adjustment. BPA's top quartile foods include the Industrial Customers of BPA top quartile loads, top quartile BPA transmission l losses, and BPA diversity adjustment. The peak and energy loads shown as Other Public Utilities include the loads of all public utilities not shown in o l separate table in Section 11, BPA Federal Agency loads (e.g., military bases), and the Adjustment to Other Public Utilities. BPA system loads exclude Grand Coulee and Rozo pumping loads and USBR local use at Grand Coulee. Compensation for these loads is accomplished by reducing Grand Coulee and Rozo resources by equivalent amounts. I An adjustment to Other Public Utilities was made this year by PNUCC. The load shown as Other Public Utilities represents opproximately 9 percent of total Regional lood. The primary reason for this adjustment is that the individual "unodjusted" forecasts that make up this category were from one to five years old. Current expectations for future electricity rates and ecnnomic and population growth, among other factors, necessitated that on adjustment be made to update these older forecasts. A detailed description of this l odjustment as well os the individual load forecasts shown in Section ll will be presented in a PNUCC report entitled, Sum of Utilities Load Forecasts, Northwest Recion. BPA transmission losses are shown separately in Section 11 for both firm and top quartile loads. These losses represent the difference between energy generated by the BPA System (or delivered to o BPA System interchange point) and the amount of energy sold to BPA customers. Resources All firm generating resources have been itemized in one of the following categories: Hydro, Cool-fuel, Nuclear-fuel, Combustion Turbines, Cogenero-tion, Renewable Resources, or Miscellaneous. They are detailed in the tables i.3
of Section Ill. Planned cool and nuclear resources are shown by plant in Tables 1-3 and I-4. Prospective Resources Prospective resources are those that are in a preliminary stage of active plonning, but for which planning has not progressed for enough to permit a potential sponsor to commit itself in terms of funding, size, or shoring of ownership. A summary of these resources is shown in Table I-6. Hydro Resources Hydro-resource capabilities are estimated from several analyses of post hydrologic conditions. The historical record used covers the 40-year period from July 1928 through June 1968. The peak capobility of hydro plants is the estirnated maximum power output l that could have been obtained in January,1937. The water year, 1936-37, represents the most severe streamflow conditions that would occur in a single season with reservoirs full of the beginning of the storage drowdown period. There are however, other (multi-year) water conditions in which the capability of the hydro plants is less. The energy capability of hydro plants is the amount of energy produced during the " critical period". The critical period is the multimonth period in the 40 years of record during which the hydro system would have generated a smaller amount of energy than it would have in any other period with the reservoirs starting full, operating to o prescribed pattern of monthly output, and ending empty, in order to estimate hydro-energy capability during years in which streamflows are greater than those during the critical period, reservoir operation was simulated, using a BPA computer model, for the 40 years of record for each year of the forecost. All reservoirs were assumed full at the beginning of the period, and they were operated in accordance with requirements for refilling. O I4 l
l i l m The simulations indicate energy potenti@ ovailable in excess of critical period capability without consideration of the energy market. This excess is nbulated in Section IV. Energy resources include generation in the United States resulting from storage regulation of three Conodian reservoirs: Duncan, Arrow, and Mico, in coordination with Libby reservoir and other power facilities in the Region as required by the Pacific Northwest Coordination Agreement. Conodion Entitle-ment is included because the energy has been purchased on a long-term basis by utilities in the Pacific Northwest. The Forecast assumes Libby generation will be reduced starting in July 1987 due to water being diverted from the Kootency River to the Columbia River at Canal Flats in Canada. Requirernents for irrigation at Grand Coulee were simulated by reducing streamflows in the amounts shown in Toble Vill-l. Although construction of the Bocon Siphon and Tunnel No. 2 for the USE3 Columbia Basin Project is ^ finished, only a modest amount of irrigation is included in this report because there are presently no firm agreements between the USBR and water users. Requirements for downstream migration of fish were simulated by deliberately spilling wat(r of certain mainstem Columbia River projects during April, May and June. However, the hydro system simulations do n_ot account for any instream flow requirements. All power-production restrictions on hydro projects were observed in setting up draf t schedules in these analyses. Restrictions on Useability of Hydro Copacity Peaking copobilities of individual Federal projects in Tables IV-l and IV-2 assume that the pools of the run-of-river projects are at or near their optimum levels. Imbalances between installed generating capacities of these projects and operational constraints, however, do not permit projects to achieve these levels of peaking in octual operation. Further, operational useability of j peaking capacity is reduced by the inability of projects to sustain peaking levels during extended 6 to 10-hour daily heavy-load periods. Therefore, on , adjustment amount hos been determined frem studies, simulating daily and l weekly operation of the system in hourly time increments, by which the total a of tabulated peaking capacities of the Federal projects must be reduced. 1-5
Reduced values represent sustained peaking capabilities of the Federal system O for each January. An additional reduction of 1543 Megowotts has been imposed on the Federal system from 1983 through 1985 because of temporary limits placed on permissible toilwater fluctuations at Grand Coulee. All these reductions are combined in the Hydro Realization Adjustment in Table lil-l. New Hydro Resources New hydro projects included in determining January capabilities are those considered assured. All Federal projects included are authorized projects which are under construction or have been funded for construction or preconstruction planning. Non-federal hydro projects include additional cop-obility at High Ross. A license application has been issued by the Federal Energy Pegulatory Commission (now pending before the international Joint
- Commission) to raise the height of Ross Dom to a new loke elevation of 1725 feet over the present lake elevation of 1602.5 feet.
New projects scheduled as port of the Region's resources through 1992-93 are listed in Table VI-2. Hydro projects categorized as prospective resources are listed in Toble VI-3. Table VI-4 includes on enumeration of hydro projects that are under consideration but were not included in the calculations. Hydro Maintenance Estimates of hydro maintenance os a percentage of total hydro generation are provided by the Northwest Power Pool Coordinating Group and are used to develop the energy adjustments indicated in Table ill-l. Thermal Resources All existing thermal plants, regardless of size, are included in amounts submitted by each plant operator. This information is shown in the tables of Section Ill. PP&L's two-thirds shore of the Jim Bridger plant in Wyoming continues to be available for a number of years to serve Regiono! loads. This share and any of PP&L's Wyoming ystem generation in excess of PP&L's Wyoming firm loads are reflected in imports. Where small fossil-fuel plants and combustion turbines are included as peaking resources, and where their I-6
/
1 i (3 tabulated energy capabilities are only the amounts necessary for peaking l operations, some additional capobility is considered available for reserves. This odditional energy capability is estimated by the project owner and is shown in Table 111-11. New Thermot Resources New thermal plants are those for which siting certificate applications have been mcde and which PNUCC considers essential. New thermal projects include some from which only a portion !s scheduled as a Regional resource in t meeting 'ood requirements. These include portions of Colstrip units #3 and #4 and Volmy unit #2. The energy capabilities of large new thermd plants were computed on annual planning capacity factors submitted by the sponsors of the projects. The factors include allowance for scheduled maintenance (including refueling)'ced , forced outages. O Scheduled dates of new thermal resources are shown in Toble I-5 as submitted by project spensors. Experience throughout the United States has demon-strated that many more large thermal plants are delayed beyond their scheduled completion dates than are completed on time. The reasons are many and may be caused by delays at any point along the paths of their respective development programs. Which plants may be delayed and for what recson or for how long cannot be anticipated in advance. Yet, on the overage they will be delayed. !f the Northwest Region were relying on firm resources based on every project being completed on its scheduled commercial operation date, the Region's planned capacity and energy would not be realized. Timing . of large new thermal plants is, therefore, based on " Probable Energy Dates". Probable Energy Dates Proboble Energy Dates are determined from o standardized schedule reflecting l anticipated overage planning and construction times. Probable Energy Dates provide o means for utilizing a stonderdized schedule without upsetting the developmental program of each project planned by its sponsor, it is considered V essential that each sponsor vigorously pursue its planned schedule in order I-7
r that the Region's planned levels of energy and capacity con be achieved despite inevitable delays at some projects. Toble I-5 compares thermal plant schedules as submitted by project sponsors and Probable Energy Dates. Probable Energy Dates are determined by using Milestones during the planning phase and Construction Progress Curves during the construction phase. They are designed to reflect possible plant delays in excess of those considered in scheduled commercial operation dotes. Couses for these delays include many which are not under the control of the building agency or utility; these include environmental considerations, litigation, ever-changire procedures affecting site opprovals, construction permits, and lic-ensing. It is not onticipated that delays will occur at each plant, but rather that delays will be greater at some and less at others, with the consequence that the Region's energy and capacity resources will be properly estimated by applying on overage delay to each plant. Milestones and Construction Progress Curves are reviewed and modified whenever required by changed conditions. A project sponsor may select a schedule of greater duration than indicated by the Probable Energy Date, and it is assumed that where this is done the schedule of activities leading to the indicated date for commercial operation is such that the scheduled date is the most probable date. Thermal Maintenance Maintenonce schedules for base-lood thermal plants are submitted by plant operators and are used in developing the residua! lood to which the hydro system is operated. No attempt has been mode to re-schedule maintenance on a regionally coordinated basis. Annual energy and peak capabilities credited to each of these projects have allowed for scheduled maintenance. Contract-Year energy capabilities claimed for small thermal plants make allowance for energy lost during maintenance outoges. Reserve Requirements in the derivation of Regional requirements, reserves have been computed and added to the load. Regional peak reserves are the greater of (1) forced-outage reserves as computed under the Pacific Northwest Coordination Agreement, plus one-half year's load growth for utility-type total loads, plus hydro I8
)
f q k)'" maintenance; or (2) 12% of the total peak load for the first year of the study, increasing 1% per year to 20% and remaining at 20% thereaf ter. This yeo-1 peak reserves for the month of January as computed by (2) are the greater and ' are tabulated in Toble 1-2. They are intended to cover, for planning purposes, all elements of uncertainty not specifically accounted for in determining loads and resources. These include forced outage reserves, unonticipated load growth, temperature variations, and project-construction delays. An increasing reserve requirement reflects greater uncertainty about load levels and of achieving construction schedules in the future. Regional energy reserves shown in Table 1-2 ora one-half year's load growth for utility-type total foods. These reserves are also intended to cover uncertainty associated with load forecasts and resources. Interchonoes With Systerns Outside the Region Resources include firm orrongements for interchanges with systems outside O the Region. These arrangements comprise firm contracts with utilities to the b East and Canada, assignment of Canadian Entitlement Exchange Power to California, and capacity sales and exchanges with California utilities. Contracts to the Pacific Southwest are amounts delivered at the California-Oregon border, incremental losses to the border associated with deliveries of the Conodion Entitlement assignment and peak / energy exchanges are shown in Table V-l. These losses were included in determining peak and energy available to meet Regional requirements. Further details of interchanges with systems outside the Region are tabulated in Section V. Section V also details "Irdro-Company Transfers", on interchange category that opplies to utilities whose service territories extend beyond the Region boundary. Table V-l shows those utilities with resources within the Region that will be used to serve their load outside the region. Table V-2 shows transfers for utilities with loads inside the region that will be served by resources that are outside. The estimates do not consider any transmission [ /q bottlenecks that may occur in the future. i
- \ !
[ be I9
.\dequocy of Resources One measure of the adequacy of the Region's planned resources in meeting energy foods is provided in lines 6a and 6b of Table I-l. They list the net difference between expected resources and exper.ted requirements.
Differences listed there, however, provide for each year only one of many possible values. This is because single-value estimates have been used for important components of the load-resource picture that are really random in nature: hydro energy is assumed of critico!-period values; overage availabilities are used to estimate thermal energy production; and probable energy dotes are used for completion of new thermo! units. An additional and more comprehensive analysis of the adequacy of resources is given in lines 7 through 10 of Table I-l. Probabilities listed there have been calculated by Bonneville Power Administration with the Energy Reserve Planning Model. The Model is o probabilistic simulation program, designed to treat rigorously *hree general components of the resource adequacy question -
-hydro availability (based on historical water conditions), thermal plant arrival dates, and thermal plant availability-combined with a logic which operates the system model realistically in response to simulated conditions of these components. It is based on a Monte Carlo simulation technique in which statistical results are derived from o mass of repeated trials. Within each triol, the model system is operated into the future continuously, and the state of each variable in each time interval is determined by a rondom draw from on appropriate probability distribution. Each trial, therefore, represents a possible real outcome, but many trials are necessary before a statistically valid conclusion con be drawn about the future. Probabilities shown in the table are based on a study comprising 2000 trials.
O I-10
i l O l i DEFINITIONS Adverse Water Years: Historical water years during which the critical period occurs (August 16,1928 through February 1932 for this year's report). Averone Megawatts: (Ave. MW) Unit of energy for either load or generation that is the ratio of energy (in megawatthours) expected to be consumed or generated during a period of time to the number of hours in the period. Conodion Entitlement: Canodo is entitled to one-half the downstream power benefits resulting from Canadion storage os defined by the Columbia River Treaty. Cooeneration: Cogeneratim is the technology of producing electric energy and other forms of useful energy (thermal or mechanical) for industrial, commercial, heating or cooling purposes through sequential use of an energy N source. Contract Year: Twelve-month period beginning on July I of any year and ending on June 30 of the following year. Milestone: A significant event in the critical path from conception of a thermal project to the time it is placed in commercial operation. Once construction is started, the Milestones are represented by a continuous curve relating percentage of completion to the date of commercial cperation. Total Load: The total load is the summation of utilities' firm and inter-ruptible loads and Bonneville Power Administration's loads which consist of: (1) Federal Agencies - Firm; (2) Public Agencies - Firm; I (3) Industrial - Firm and Top Quartile Losses associated with delivery and Regional System Diversity are also ircluded in the total loads. (mV) Utility-Type Loads: The total Region load minus Bonneville Power Adminis-tration's federal and industrial loads (including losses). I-i l
- .. I
r FIGURE I - I PEAK LOADS AND RESOURCES TOTAL REQUIREMENTS
- FIRM REQUIREMENTS %
45 - '* "
- C.ESTON 1 2 and 3 40 '" ;;a COLSTRsP 3 ana 4 I M P O. 7 5
'~
i nt!W%3%%%%%%%%%%%4 k . 1983 1984 1985 19'86 19'87 1988 1s89 1990 1991 1$92 1593 YEAR
<o........... ... ..... m
=:= =r - . . - ...... m g I 12
FIGURE I - 2 ENERGY LOADS AND RESOURCES ())
- TOTAL REQUIREMENTS FIRM REQUIREMENTS * [
n AGif i
@ CRESTON 1.
; # q ::::
15- / 10-
'~
E l 1983 1984 19'5 8 1956 1987 19'8 8 19'89 1990 1991 1992 1993 p' YEAR c I' AS$uutS MANFORD GENERATION THROUGH 1988 PLANNED EXIST l-13
TAllLE I.I
, REQUIREMENTS APO RESOUR S 1982-83 1983-84 1984-85 1985-86 1986-87 1987-88 1988-89 1989.90 1990-91 1991-92 1992-93 JANUARY PEAK - MW
- l. Requirements II
- o. Total 35.278 36,516 37,983 39,402 40,558 41,374 42,748 44,241 45,724 46,703 47,736
- b. Firm 34,355 35,582 37,040 38,448 39,531 40,284 41,650 43,140 44,(16 45,594 46,627
- 2. Resources 36,I58 36,445 38,749 40,284 y ,725 41,771 42,475 44.154 45.330 45,203 46,815
- 3. Surplus (Deficit)
- o. Total 880 (71) 266 882 1,167 397 (273) (89) (394) (1,500) (921)
- b. Firm 1,803 863 1,209 1,836 2,194 1,487 825 1,014 714 (391) 188 EPERGY - AVE. MW
- 4. Requirements II
- o. Total 19,615 20,105 20,707 21,278 22,049 22,777 23,278 23,794 24,309 24.801 25,291
- b. Firm 18,572 19,046 19,635 20",193 20,892 21,553 22,038 22,549 23,057 23,548 24,038 h 5. Resources 18.592 18,782 19,517 19,800 20,237 20,325 20,292 21.351 21,878 22.334 22,971
- 6. Surplus (Deficit)
- o. Total (1,023) (1,323) (1,190) (1,478) (1,812) (2,452) (2,986) (2,443) (2,431) (2,467) (2,320)
- b. Firm 20 (264) (118) (393) (655) (1,228) (1,746) (1,198) (1,179) (1,214) (1,067) l I
PROBABILITY THAT RESOtRCES WILL BE INSUFFICIENT TO MEET:2/ Total Energy Lood in of Least i Four-Month Period of
- 7. Year Shown % 30 37 42 45 45 47 48 51 50 50 49
- 8. Cumulative % 30 50 68 80 88 92 95 97 98 99 100 Firm Energy Lood in at Least i Four-Month Period of
- 9. Year Shown % 9 9 13 19 21 24 25 26 27 27 25
- 10. Cumulative % 9 16 26 39 49 60 68 76 81 86 89 I
1/ Includes loods, exports and reserves. 2/ Based on some dato os used in comparison of energy requirements and resources, except that there is no consideration of reserve requirements. l O __ __ O O _
f \
'V % ~
TABLE l-2 REQUIREMENTS 1982-83 1983-84 1984-85 1985-84 1986-37 1987-88 1988-89 1989-90 1990-91 1991-92 1992-93
.lAMJARY PEAK - MW
- l. Load Forecosts
- o. Total 28,671 29,641 30,616 31,530 32,711 33,727 J4.673 35,584 36,473 17,253 38,076
- b. Firndl 27,748 28,707 29,673 30,576 31,684 32,637 33,575 34,481 35,365 36,144 36,967
- c. Top Quartile (BPA) 839 850 859 870 943 1,006 1,014 1,019 1,024 1,025 1,025
- d. Interruptible (Utah) 84 84 84 84 84 84 84 84 84 84 84
- 2. Exports 2,050 1,857 1,868 1,882 I,294 541 All 426 435 445 456
- 3. Reserves2 / 3,560 3,987 4,435 4,894 5,416 5,933 6,458 6.996 7,548 7,710 7.880
- 4. Regional System Diversity Adjustment 997 1,031 1,064 I,096 1,137 I,173 I,206 1,237 1,268 1,295 1,324
- 5. Requirementd/
- o. Total 35,278 36,516 37,983 39,402 40,558 41,374 42,748 44,243 45,724 46,703 47,736
- b. Firm 34,355 35,582 37,040 38,448 39,531 40,284 41,650 43,140 44,616 45,594 46,627 G EPERGY - AVE. MW
- 6. Load Forecasts
- o. Total 18,916 19,522 20,129 20,707 21,501 22,198 22,759 23,280 23,797 24,283 24,762
- b. Firm 17,873 18,463 19,057 19,622 20,344 20,974 21.519 22,035 22,545 23,030 23,509
- c. Top Quortile (BPA) 913 925 935 946 1,019 1,085 1,102 1,107 1.114 1,115 1,115
- d. Interruptible (Utah) 130 135 137 138 138 138 138 138 138 138 138
- 7. Exports 424 314 320 325 332 337 272 272 275 280 285
- 8. Reserves"I 275 269 258 246 216 242 247 242 237 238 244
- 9. Requirements
- o. Total 19,615 20,105 2J,707 21,278 22,049 22,777 23,278 23,794 24,309 24,801 25,291
- b. Firm 18,572 19,046 19,635 20,193 20,892 21,553 22,038 22,549 23,057 23,548 24,038 II includes Regional System Diversity Adjustment.
l 2I Peak reserves are based on total food orw! do g account fc,r Regional System Diversity Adjustments. l 3/ Requirements do g account for Regional System Diversity Adjustments. l "I Energy reserves are based on utility-type loods. l l l . . . . .
TAIM.E l-3
SUMMARY
OF PEAK RESOURCES JANtJARY PEAX CAPABILITY - MW 1982-83 1983-84 1984-oS 1985-86 1986-87 1987-88 1988-89 1989-90 1990-91 1991-92 1992-93 HydroN 28,086 28,168 28,365 29,980 30,221 30,307 30,292 30,260 30,213 30,243 30,142 2 Existino / Cool 2,871 2,941 2,941 2,941 2,941 2,941 2,941 2.941 2.941 2.941 2,941 , Nuclear 1,080 I,080 1,080 1,080 1,080 1,080 1,080 1,080 1,080 1,080 1,080 i Combustion Turbine I,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 , Cogeneration 151 52 52 32 52 52 52 52 52 52 52 Renewable 0 0 0 0 0 0 0 0 0 0 0 Miscellaneous 123 123 123 123 123 123 123 123 123 123 123 Imports 2,552 2,494 2,390 2,320 2,280 2,240 2,451 2,404 2,352 2,195 2,125 l Pkmed l Cool Colstrip #3 - - 490 490 490 490 490 490 490 490 490 Volmy #2 - - 121 121 121 121 121 121 121 121 121 Colstrip #4 - - - 490 490 490 490 4M) 490 490 490 Creston #1 - - - - - - 508 508 508 508 508 E Cresto, #2 - - - - - - - 508 508 508 508
- Creston #3 - - - - - - - - - - 508 Nuclear WNP #2 - - 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,100 1,800 WNP #3 - - - - 1,240 1,240 1,240 1,240 1,240 1,240 I /40 WNP # 1 - - - - - - - 1,250 I,250 1,250 t,250 Skogit #1 - - - - - - - - 1,275 1,275 1,275 Skogit #2 - - - - - - - - - - 1,275 Combustion Turbine - 247 247 247 247 247 247 247 247 247 247 Cogeneration 13 13 13 13 13 13 13 13 13 13 13 Renewable - 45 45 45 45 45 45 45 45 45 45 TOTAL RESOURCES 36,158 36,445 38,249 40,284 41,725 41,771 42,475 44,154 45,330 45,203 46,815 1
1/ inciudes both existing and planned resources. See Table lll-l. 2/ Sections lil and V contain details. e o e
N [N [~ N N TABLE I-4
SUMMARY
OF EERGY RESOLRCES CONTRACT YEAR EMRGY CAPABILITIES- AVE.MW 1982-83 1983-84 1994-85 1985-86 1986-87 1987-88 1988-89 19A9-90 1990-91 1991-92 1992-93 HydroN 12,715 12,701 12,'t38 12,730 12,761 12,713 12,711 12,697 12,694 12,684 12,677 ExistinoU Cool 2,037 2,112 2,112 2,112 2,112 2,112 2,112 2,112 2,112 2,112 2,112 Nuclear 1,280 1,165 1.165 1,165 1,165 1,165 765 765 765 765 765 Combustion Turbine 362 362 362 344 344 344 344 344 344 344 344 Cogeneration 122 41 41 41 41 41 41 41 41 41 41 Renewable 3 3 3 3 3 3 3 3 3 3 3 Miscellaneous 5 5 5 5 5 5 5 5 5 5 5 Imports 2,062 2,C33 1,933 1,877 1,744 1,504 1,493 1.561 1,479 1,454 1,444 Plamed Cool Colstrip #3 - SI 316 357 357 357 357 357 357 357 357 Volmy #2 - - 79 95 95 95 95 95 95 95 95 Colstrip #4 - - - 308 357 357 357 357 357 357 357
,, Creston #1 - - - - - - 305 381 381 381 3J1
- 4. Creston #2 - - - - - - -
152 343 381 381 Creston #3 - - - - - - - - - - 152 Nuclear Wtf #2 - 298 715 715 738 770 770 770 770 770 770 Wre #3 - - - - 467 811 818 851 874 874 874 Wtf #1 - - - - - - 68 812 812 818 875 Skagit #1 - - - - - - - - 398 845 892 Skagit #2 - - - - - - - - - - 398 Combustion Turbine - 6 6 6 6 6 6 6 6 6 6 Cogeneration 6 8 8 8 8 8 8 8 8 8 8 Renewable 0 27 34 34 34 34 34 34 34 34 34 IOTAL ESOCRCES 18,592 18,782 19,517 19,800 20,237 20,325 20,292 21,35I 21,878 22,33't 22,971 1/ Includes both existing crut planned resources. See Table 111-1. 2_/ Sections Ill ed V contoin details.
g T ABLE I-5 Sheet I of 2 SCFEDULE Of PL APfED RESOURCES JANUARY 1982 ilf TOUGH JUTE 1993 SCt[DULED PROHABLE NAMEPLATE COMMERCIAL Ft4.RGY RA TING PLANT 014 f tATION DATE (MW) Hydro Anderson Ronch (Rewind #I & 2) Apr 1983 13 Bonneville (Units #11-15) Oct 1982 359 Bonneville (Uproting # I) Sep 1983 10 Coscode (Units #1 & 2) Jon 1984 13 Chief Joseph (Uprating #1-16) Sep 1986 205 Eltopio Branch Conot (4.6) Mar 1983 2 Grand Coulee (Rewind G-10) Apr 1982 17 Grand Coulee (P/G #912) Apr 1983 200 High Ross (Pool Roise) Jul 1985 251 Idaho f alls (3 Units) Jun 1982 24 Libby (Unit #5) Oct 1984 105 Moyfield Apr 1983 40 Pelton Reregulating Mar 1982 18 Poriland Hydro Projeet Jon 1982 36 g Potholes East Canal (66.0) Mor 1983 3 Ovincy Chute May 1984 8 Russell B. Smith Mor 1982 6 South Fort < Tolt River Jun 1985 15 Sutton J'>l 1984 112 Summer Falls May 1984 94 Cool l Colstrip #3 ' Jon 1984 May 1984 Colstrip #4 jf Jul 1985 Jul 1985 700 700 Creston #1 Jul 1988 Jul 1988 5(X) Creston #2 Jon 1990 Jon 1990 500 Creston #3 J n 1993 Jon 1993 500 Volmy #2 2/ Sep 1984 250 O Only 70% of this unit is dedicated to the region. 2I Only 50% of this unit is dedicated to the region. O O O
O ~ T ABLE l-5 (Cent.) Sheet 2 of 2 SOEDULE OF PLA>@ED RESOURCES JAFAJARY 1982 TtftOUGH ARE 1993 SOEDULED PROBABLE NAMEPLATE i COMMERCIAL EPERGY RATING PLANT OPEftATION DATE (MW) Nuclear Skogit #1 Jan 1991 Jul 1991 1330 Skogit #2 Jon 1993 Jon 1993 1330 WNP # 1 Jun 1989 Jun 1989 1373 Feb 1984 Feb 1984 l100 WNP #2 Dec 1986 Dec 1986 1316 wtP #3 Combustion Turbine 247 Fredonio #1 & 2 Nov 1983 Cooenerotion 9 Boeing #I Oct 1982 Dec 1982 4 Metro Westpoint Renewohle 42 Kettle Falls (Wood Fuel) Nov 1983 Jun 1983 6 Tomorock i G 1 i I l l i 1 i i f
- - _ _ .____ _ - _ _ ___----_- - - - - -- - - - - - - - - - - - - , - - - - . - , - - - - n - - - - , . - - - , -
TADLE 14 Sheet I of 2
SUMMARY
OF PROSPECTIVE RESOURCES JANUARY 1982 THtOUGi JUtf 1993 ASSUMED ASSUMED ASSUMED NAMEPLATE EPERGY PLANT OPERATION DATE RA IING-MW AVE. MW Hydro Anderson Ronch (Unit #3) 1985 30.0 Blue River (Units #1,2) Jul 1988 10.0 Bonneville (Fishway Units #I-3) Jul 1986 12.0 7.6 Corter Ferry Jon 1992 75.0 35.0 Cougar (Unit #3) Jul 1987 35.0 Crystal Springs Hatchery Jul 1985 0.2 Dike Jon 1991 70.0 Dry Falls Jun 1984 22.0 Elk Creek Jul 1988 5.0 Foll Creek Jul 1988 6.0 Hogermon Hatchery Jon 1985 0.1 Houser Addition Aug 1988 25.0 John Day (Fingerling Bypass) Jul 1985 3.0 Konoko Rapids Jon 1988 20.0 5 Kerr (Upgrade) Dec 1989 28.0 o Kootenai River Project (Units #l-5) Jon 1991 180.0 70.0 Lucky Peak (Units #1-4) Sep 1985 81.4 14.0 Mormot Jun 1984 3.7 1.7 McNory (Fish Attraction Unit) Jan 1988 7.0 McNory (Second Powerhouse) 1990 780.0 Milner Canal Oct 1987 60.0 36.0 Minidoko 1986 40.0 Moro Canal Jul 1984 1.9 1.0 North Fork Bonks Apr 1986 99.0 NF Fernerof f Apr 1988 174.0 O'Sullivan Dom Jun 1984 1.I Polisades 1987 90.0 Priest Rapids (Units #Il-14) Jul 1986 323.0 14.0 Ryan Addition Aug 1987 40.0 4.8 Strube Lake Jul 1987 4.5 2.4 Sullivan Creek Jul 1985 18.0 4.0 Swan Falls (Rebuild) Jul 1986 12.2 The Dolles (Fishway Unit) Jul 1987 4.5 Thompson Falls Addition Sep 1988 50.0 Twin Falls Lowline May 1984 9.0 4.0 0 0 0
{s p s
\ s k
v T ABLE l-4 (Cont.) Shaet 2 of 2
SUMMARY
OF PROSPECilVF RESOURCES JANUARY 1982 TINOtrJi JUK 1993 ASSUMED ASSUMED ASSUMED NAMEP!. ATE EW.RGY PLANT OPERATION DATE RAllNG-MW AVE. MW Hydro (Cont.) UprP 'iton Feb 1984 9.0 3.0 Wonopum (Units # 11 - 14) Nov 1985 322.0 Wiley Nov 1989 85.8 41.0 Wynoochee Jul 1988 10.2 5.0 Cool Unit #'
- idaho Power) Jun 1992 250.0 188.0 Nuclear Pebble Springs I/ Jon 1993 1,260.0 Combustion Turbine Montono Power #1 Dec 1987 50.0 Montano Power #2 Dec 1989 50.0 Montort ; ... - 43 Dec 1992 25.0
':- Cooeneration Idaho Power #1 Jun 1985 15.0 Idaho Power #2 Jun 1987 20.0 Idaho Power #3 Jun 1989 20.0 idaho Power #4 Jun 1991 25.0 Kinzuo 1983 6.0 4.5 PGE Industrial #1 1989 30.0 22.0 PCE Industrial #2 1983 1.0 0.5 Renewable Cape Blonco Wind Forms Dec 1987 80.0 16.0 Columbio Blvd. Sewoge Treatment Plant 1985 2.0 1.0 Marion County Solid Waste 1985 15.0 10.0 MSD/ Publishers Oregon City Jun 1985 10.0 7.0 MSD/St. John's Landfill 1985 2.5 1.0 Rossman Londfill Jun 1984 3.0 2.0 4
Il The twin 1,260 MW unit Pebble Springs project is a possible regional resource. Federal approvols have not been received and the Oregon Site Certificate opplication was withdrawn on April 9,1982. A January 1993 in-service date represents the earliest date Unit #1 could be available if oil permits and opprovals are received by 1984-85. I l
S/HNP-ASC/ER 8/20/82 RESPONSES TO NRC QUESTIONS Question N220.06 (Water Quality - Question 6) Reference page 5.3-2. Will acidification of cooling water alter the form and thus, the toxicity of those metals which are already in excess of water quality standards?
Response
See revised Section 5.3.1.2. 6 i ( l l N-27 Amendment 6 i
S/HNP-ASC/ER 9/16/82
^
RESPONSES TO NRC QUESTIONS Question N230.01 (Need for Facility - Question 1) How does the possibility of purchasing WPPSS 4& 5 impact your analysis of alternatives?
Response
See new Section 9.6. 7 O l O N-28 Amendment 7 l
S/HNP-ASC/ER 3/17/82 RESPONSES TO EFSEC QUESTIONS f Question E200.09 (Alternative Sites - Question 9) At the point of water intake and discharge, what is the shoreline management plan designation? Response: i i This information has been provided under separate cover by letter from Mr. F. T. Thomsen to Mr. Grant Bailey dated February 5, 1982 (see Question E200.07 Attachment 1). i i j i f l i i l 1 l . i f ! l l l t I t E-9 Amendment 5 ;
..---u , - - - - , - , . - - - - - - - - - - . - , . , , - . - - - , - - - - - - ,--- -,-,----. .,rv n--- - - -
S/HNP-ASC/ER 9/16/82 RESPONSES TO EFSEC OUESTIONS Question E201.01 (Alternative Energy Sources - Question 1) Is the acquisition of Washington Public Power Supply System Projects 4 and 5 a viable alternative option? What is the Puget Sound Power and Light Company's position regarding this question?
Response
See new section 9.6. 7 O I l i i O ? E-10 Amendment 7 l}}