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Home My WebLink AboutAPA1281I .I I I I .I I I I I I I I I I I ~. I I . ' •,!, • .~· r-' '• / ·' l ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT SUBTASK 6.05 -DEVELOPMENT SELECTION ~EPORT FIRST DRAFT FEBRUARY 13J 1981 I I I i TABLE OF CONTENTS AND REPORT STATUS 1 -INTRODUCTION 2 -SUMMARY II 3 -CONCLUSIONS AND RECOMMENDATI"ONS These three se~tions have not been in~luded I and w1·11 appear in the second draft. I I I I I I I I I I I. I I 4 -PREVIOUS STUDIES 5 -RAILBELT LOAD FORECl\STS Fot first draft purposes, these two sections are identical to Chapters 4 and 6 in the Pl''Oject Overview Report/POR and are, therefore, not reproduced here. 6 -SUSITNA BASIN STUDIES Essentially complete. More details on energy yield sensitivity analyses is to be added to the end of the section. 7 -GENERATION EXPANSION PLAN This section requires more details on costs of thermal alternatives and are the results of generation planning work, particularly the sensitivity analyses. A section on the multiobjecttve project selection process (i.e. including economtc and environmental parameters) is to~be added. 8 -ENGINEERING STUDIES Thi's sectton will be expanded to incorporate more details of the ongoing dam site layout and dam design work. 9 -SUSITNA HYDROELECTRIC DEVELOPMENT Complete. ;~~~~~~~~,: ~:t~~1:.l~~~~~:~(~~~? ·:.: " .~ j :; .. ;,y :~ "· ... {) I I () I 0 . . ,,, : . . - I . . ···"·· ... _,_.;, 0 ... (• .[ .-=;:. ' " . f\ 'I !-· . i) r,O· '' v \.\' ·~ ,C _·_,_._ -~~~-. I' I .• I I I •• I I. I I I I I 6 -SUSITNA BASIN STUDIES 6.1 -Introduction This section outlines the preliminary Susitna Basin studies that have been carried out. The objective of these studies ·is to generate co~t and energy yield information on the more promising Susitna Basin hydroelectric development options as input to the railbelt generation pla.nning studies de'.)Cribed in Section 7. More detailed engineering studies of the selected 'Aatana/Devi1 Canyon development are desc:ribed in Sections 8 and 9. The first part of this section deals with pertinent climatGlogic, hydrologic, geotechnical and seismic aspects. A discussion of the site selection and screening process follows. It inco~porates the results of the preliminary engineering layout studies used to develop capital cost estimates associated witt. development of the hydro potential at various sites within the basin. The results of detailed energy s~imulations for the more promising development options are also presented. The section concludes with an evaluation of a proposed tunnel scheme which could be substitut~d for the Devil Canyon dam scheme. More detailed backup to the results presented here are crintained in Appendices A· through G. 6. 2 -Climate 1 ogy and Hydro 1 ogy " This section briefly summarizes the available.information for the Susitna Basin. For a more detailed outline of the existing data networks and data analyses carried out the reader is referred to Appendix E. 6.2.!. -Climate (a) General ·The climate of the Susitna Basin is generally characterized lsy cold, dry winters and warm, moderately moist summers. The upper basin up- stream from Talkeetna is dominated by continental climatic conditions \'lhile the lower basin falls with1n a zone of transition between maritime and continental climati'1 influences. Histor·;cal records of precipitation, temperature f,'\d other climatic parameters are collected by NOAA at several stations in and around the basin. Hm'fever, there are rw sta~:i ons 1 ocated upstream from · Talkeetna. Therefore, no long-term records are available at or near the dam sites. The closest stations where long-term climate data is available are at Talkeetna to the south and Summit to the north. ·Typical data collected at the various stations is presented in Table 6.1. A summary of all historical data collected in the basin is presented in Table 6.2. I I I I I I I I I I I I •• I I •• I R&M Consultants have established six automatic climate stations in the upper basin during 1980 (see Figure 6.1). The data collected at these stations includes a~~r temperature, average wind speed, wi'nd direction, peak wind gust, relative humidity, prec-:~itation, and solar radiation. Snowfall amounts are being measured in a heated precipitation bucket at the Watana ~tation. Data are recorded at thirty minute intervals at the Susitna Glacier station and at fifteen minute intervals at all other stations. (b) Precipitation . (c) (d) Precipitation in the basin varies from low to moderate amounts in the lower elevations to heavy in the. mountains. Mean annual precipitation of over 80 inche~ ~s estimated at higher elevations (El +3000 ft) of the Talkeetna !Vi':;, tains and the Alaskan Range whereas at Talkeetna station {El. 3_~ ft) the average annual precipitation recorded is ab0ut 28 inches~ The average precipitation reduces in a northerly dire;ction as the cot~tinen~~ul climate starts to predominate. At ~·ummit station (El. 2397 ft)~ 1:he average annual precipitation is only 18 inchese The seasonal distribution of precipitation ~s similar for all the stations in and surrounding the basin. At Talkeetna, records show the 68 percent of the total precipitation occurs during the warmer months -r~ay through October v1hile only 32 percent is recorded in the winter months. Average~ recorded snowfall at Talkeetna is about 106 inches. ·Generally, snowfall is restricted to the months of October through April with some 82 percent snowfall recorded in the period November to March. The u.s. Soil Conservation Servic;e has established a. network of snoltl course stat i uns in the basin and records of snm'i depths and water content are t:vailable for varying fJBr:ods extending from 1964. Stations within the Upper Susitna Ba':.in are generally located at elevations below 3000 ft and indicate that annual snow accumulations are around 20 to 40 inches and that peak depths occur in late March. There is no historical data for the higher elevations. The basic network was expanded durin£ 1980 with the addition of three. new snow courses on thP, Susitna glacier (see Figure 6.1). R&M are cooperating with SCS in collecting information from the network during the study period. Iemperatur~ Typical temperatures observed at the Talkeetna and Summit stations are. presented in Table 6.3. It is expected that the temperatures at the dam sites will be somewhere between the values observed at these stations • River Ice --~--~ The Susitna River usually starts to freeze up by 1 ate October. Ri vr~r ice conditions such as thickness and strength vary according to thE! rivet· channel shape and slope, and more importantly~ with river di.c;charge. Peri odic neasurements nf ice thi ckness,,.ess at sever a 1 locations in the rive~ have been carried out during the winters of 1961 through 1972. il1e maximum thicknessses obser 1ed at selected .. l I I I •• I I I I I I I I I -·· I I I I I locations on the river are given in Table 6.4.. Ice breakup in the river commences by late April or early May and ice jams occasionally occur ar river cJnstrictions resulting in rises in \'tater level of up to 20 ft. Detailed field data collection programs and studies are underway to identify problem areas and develop mitigation measures. The field programs involve undertaking extensive observation-of current freeze-up and breakup processes. This data will be used to ,dlibrate computer models which can be used to predict the ice cover regime under post project conditions. It will then be possible to anticipate potential problems and to develop solutions to them. 6.2.2 -Hydrology (a). Water Resources Tht~ 1 ength of streamflow records at the gaging stations on the Sus i tn-a River and its tributaries vary from 30 years at Gold Creek to about five years at the Susitna, ·station. There are no historical records of streamflow at any of the dam sites. The records at the gaging stations were extended using a multisite correlation technique (see Appendix E for deta i 1 s). Tne procedure used 30 year recorded data at Gold Creek and shorter records at other stations tu fill in 30 year flows at each of the stations. The derived flow sets have been used to estimate streamflows at the dam sites using drainage basin areas as a basis. A gaging station was established at the Watana dam site in June 1980 and continuous river stage data is being crillected. It is proposed to dev_elop a rating curve at the station with streamf~ow measurements taken over 1980 and 81 seasons. The flows \•Ji 11 be ca 1 cul a ted and used to r;heck the procedure used to extrapolate streamflow data to the Wata.na site • . Th~: Susitna River above the confluence wih the Chulitna River contributes approximately 20 percent of the mean annual flow mea5ured near Cook Inlet (at Susitna station.) The average annual flow at Gold Creek is approximately 9300 cfs. Average annual flow and maximum and minimum values at other stations within the study area are given in Table 6.5. Seasonal variation of flows is extreme and ranges from very 1 ov1 va 1 ues in winter (October to April) to high summer values (May to September). Fo~ the Susitna River at Gold Creek the average winter and summer flows are 2100 and 20~250 cfs respectively (i.e. a 1 to 10 ratio}u On avarage, approximately 88 percent of streamflow recorded at Gold Creek station occurs during the summer months. At higher elevations in the basin the distribution of flows is concentrated even more in the summer months. For the Maclaren River near Paxson (El. 4520 ft) the average winter and summer flows are 144 and 2100 cfs respec-t~vely (i.e. a 1 to 15 ratio). The monthly percent of annuatl discharge and mean monthly discharge for the Susitna River at the uaging stations are given in Table 6.6,, I I I I ,. I I I I I I I I I I I I I (b) Floods The most common cause of flood peaks in the Susitna River Basin is snowmelt or a combination of snowmelt and rainfall falling o·:Jer a 1 arge area. Annual maximum peak di scharg1es generally occur between May and October with the majority, approx-1 mate ly 60 percent~ occurring in June. Some of the annual maximum flood peaks have also occurred in August or 1 ater and are the result of heavy rains over 1 arge areas augmented by significant snowmelt from higher elevations and glacial runoff. Flood frequency analyses have been carried out for the recorded floods in the Susitna and its tributaries, Copper, Natanuska and resina- Rivers. These analyses were conducted for two different time periods within the year. One per1od selected was the open water period, i.e. after the ice breakup and before freezeup. This period contains the 1 argest f1 oods which must be accomodated by the project. The second period represented that p~rtion of time d~ring which ice conditions occur in the river. These floods, although smaller, can be accom- panied by ice jamming~ and must be considered. during the construction phase of the project and used to check the size ofcj coffer dams. Using the results of the frequency ana'lys is, a region a 1 index curve has been developed which may b£ used for estimating floods in ungaged t~ivers and streams and to <:h~ck the accuracy of the Gold Creek Station curve which is important ir~ determining spillway design floods for Susitna River projects. ~Mu1tiple regression equations have been developed using physiographic parameters of the basin such as catch= ment area, stream length~ mean annual precipitation, etc. to assess flood peaks at the dam sites and intermediate points of interest in the river. Detailed discussion of the analyses are presented in Appendix E. Some of the results are summarized in Table 6~7. Estimates of the probable maximum floods in the Susitna Basin were made by COE in th~ir study in. 1975. A river basin simulation model {SSARR) was used for the purpose. A deta1led revie'll of the input data to the model has been undertaken and discussions held with COE engineers to improve understanding of the model parameters used. A series of computer runs wi tn the mode 1 were undertaken to study the effects of 1 ikely changes in the timing and magnitude. of the three important parameters, i.e. probable maximum precipitation, snow pack and temperature. The objective of these runs v1as to examine the sensitivity of the estimated fl~od flows to changes in the principal parameters causing the floods. The results of these studies indicated that the changes in input data <4 d not increase ~he fl ~cd ~ea'<s ca 1 cu- lated by the COE by wore than t ·1 percent. Cons1derat1on 1s therefore being given to re-eva 1 uat i og the PMF for purposes of project design. The sensitivity analyses are described in .more detail in Appendix E.3. Table 6. 7 indicates the COE PMF va 1 ues which are currently used. I I I I I .I I I I I I I I I I I I I (c) River Sediment Periodic suspended sediment samples have been collected by the USGS at the four ga~ing stations upstream from Gold Creek (see Figure 6. ) for varying periods between 1952 and 1979. Except for three samPTes collected at Denali in 1958, no bed load sampling has been undertaken at any stations. Data coverage during high-flm'l high sediment ·events is poor and consequently any estimate of total annual sediment yield has a high degree of uncertainty. The most comprehensive analysis of s~~iments had in the river to date is that undertaken by the COE in 1975. Table 6.8 gives the COE estima~es of sediment transport at the gaging stations. 6.3 -Geology and Geotechnical Aspects 6.3.1 -Geology (a) Regional Geology The Upper Susitna Basin lies within what is geologically call~d the Talkeetna Mountains area. This area is geologically complex and has a . history of at least three periods of major tectonic deformation.. The o 1 dest rocks. (250-300 m.y. b. p. )* exposed in the region are vo 1cani c flows and limestones which are overlain by sandstones and shal.es dated approximately 150-200 m.y. b. p. A tectonic event approximately 135-180 m.y.b.p. resulted i~ the intrusion of large diorite and granite plutons, which caused intense thermal metamorphism. This was follwed by marine deposition of silts and clays. The argillites and phyllites at Devil Canyon were formed from the silts and clays during faulting and folding of the Talke~t(la Mountains area in the Late Cretaceous period (65-100 m.y.b.p.)l5J. As a result of this faulting and uplift, the eastern portion of the .area was elevated, and the oldest vo 1 cani cs and sediments were thrust over the younger metamorpfdcs and sediments. The major area of deformation dur'ing this period of activity was southeast of Devi1 Canyon and included the \.Jatana area .. The Talkeetna Thrust Fault, which trends northwest through this region, was one of the major mechanisms of this overthrusting rr~~m southeast to northwest. The Devi 1 Canyon ar( . was probably deformed and subj~cted to tectonic stress during this period, but no major · deformations are evident at the site (Figure 6~2). *m.y.b.p.: million years before prese.nt t,. h:i- 1 I I I I ~ I I I I I •• I . I I I :1 I - The diorite pluton that forms the bedrock of the vlatana site \-'.!..iS intruded into sediments and volcanics about 65 m.y.b.p. The anC-esite and basalt f1 ows near the site may have been formt:.'d immediately after this plutonic intrusion, or after a period of erosion and minor deposit'!oi1. During the Tertiary period (20-40 mey.b.p.) the area surrounding the sites was again uplifted as much as 3,000 f~et. 3ince then widespread et~osion has removed much of the older sed;tmentary and volcanic rocks. During the last several million years at 1r~3:it two alpine glaciations have carved the Talkeetna Mountains into the ridges, peaks, and broad glacial plateaus as seen today. Po~t-glacial uplift has induced downcutting of streams and rivers, resulting in the 500 to 700 feet deep V-shaped canyons that are evident todc-ly, particularly at the Vee and Devil Canyon dam sites. This erosion ~is believed to be presently active and so virtually all streams and rivers ~n the r~gion are considered to be actively downcutting. This continuing erosion has removed much of the glacial debris at higher elevations but very little alluvial deposition has occurred<) The resulting landscape consists of barren bedrock mounta.ins, glacial till covered plains, and exposed bedrock cliffs in canyons and along streams. The arctic climate has retarded development of-topscil. .. (b) Site Geo1l9_.l. The dam -site at ~Jatana is underlain by a dioritic intrusion (pluton). The site has a favorable configuration because the river has cut down through the intrusion, resulting in a narrow canyon. The ;;luton is bounded at the upstream and downstream edges by sedimentary rocks that show evidence of being deformed andtarched upwards by the plutonic fntrusi on ( Figure 6. 3). The evidence to date indicates that the sedimentary rock has been eroded from the top of the pluton at the immediate site. Following intrusion, at intervals that have not yet been determined, volcanics erupte.d into the area. These vo1 canics form the bas a 1 t fl ONS exposed in the canyon near Fog Creek downstream of the site, and the andesite flows over the pluton at the dam site. There is no indication of basalt flow.:::-~ithin the immediate dam site, but the andesite has been detected in several borings in the western portion of the site. The nature and characteristics of the diorite-andpsite contact will be further investigated in the 1981 program. The surfic~al material at the darr, site 1s ·predominantly talus and very thin glacial sediments on the abutments, with limited deposits of river alluvium and lake clay at tso1ated locations. The river channel is filled up to 80 feet of alluvial deposits derived from t.i'll and talus material. The drilling and seismic lines indicate that the bedrock weathering averages ten to twenty feet, with a very distinct gradation from weathered to um'leathered rock. The surficial. weathering processes seem to be primarily physic.al rather than chemical. Bedrock quality below 60 feet is uniform to the maximum depths drilled. The pattern of sound, unweathered rock zones are separated by shear zones of rock altered by injection of felsite and andesite dikes, with subsequent deterioration of the broken rock by groundwater. The basic conditions are favorable to construction of both surface and underground structures, with remedial treatment likely to be limied to shear zones. I I I I I I I -· I I I I I I I I I I I --1 .., Devil Canyon is a ver·y nar'"row V-shaped canyon cut through relatively homogeneous a""gi 11 i te and gray wack e. This rock was formed by . low-grade metamorphism {application of tectonic heat and pressure) of marine shales, mudstones, and clayey sandstones. The bedding strikes about 15° northeast of (subparallel to) the river alignment through the canyon and dips at about 65° to the southwest. The rock has been deformed and moderately sheared by the southeast to northwest acting regional tectonic forces, causing shearing and jointing parallel to this force (Figure 6.4). The glaciation of the past few million years apparently preceded the erosion of the canyon by the river. Glacial deposits blanket the valley above the V-shaped canyon, while deposits in the canyon itself are limited to a large gravel bar just upstream of the canyon entrances and boulder and tai us deposits at the base of the canyon wa 11 s. Bedrock conditions at Devil Canyon vary \'lithin a limited range due to changes of lithology, but the rock is basically sound and fairly durable.. Jointing and shears are frequently quite open at the surface, but there is a general tightening of such openings with depth. ·1 ;~e ma,ior joint set strikes about North 30° ~lest across the canyon, and may be an indication of shear zones in this direction. WPRS mapped shear zones at this orientation, with 80-90° dips. Two minor sets strike roughly North 60-9Qd East, with dips of about 50-60° south and 15° south. The orientation of the joints, ~nd particularly the shtar zones~ is not well defined. Further field mapping in 1981 should clarify this. 6.3.2 -Geotechnical Aspects The evaluation of the Watana and Devil Canyon dam sites required assessment of geology, rock mechanics3 foundation cond·itions and foundation treatment requirements. In addition, the influence of permafrost and site configuration on construction feasibility were considered and sources of concrete aggregate, impervious core material and embankment fill were investiga.teda The summary of data from these investi.gations is discussed by site. A description of the 1980 fie'fd investigations and geologic maps to date is presented in Appendix G. (a) Watana Site The Watana dam site lies predominantly on sound diorite with some portions of the downstream shell being on andesite. The upper t'en to forty feet of rock is weathered. Currently, a high rockfill dam with impervious core is planned at the site. The se~smic considerations for the site, as discussed in Section 6.4.3 dictate that the re 1 at i ve ly loose all uvi urn (up to 80 feet in depth) will be removed from underneath the entire ·dam.. In addition, up to 40 feet of rock excavation will be required under the impervious ·core and the supporting filters to found the dam on sound compe~ent rock. This type of foundation preparation is considered normal for large dams of comparable size. Shear zones and joints within the rock foundation have been located and will require consolidation and curtain grouting, and may necessitate the inclusion of drainge features within the foundation and the abutments. Permafrost is present on the left ~, I . I I I I I I I I I I I I I I I I abutment and may also be present under the river channe'l. The data i ndi 'Cates that this is a 11 Warm 11 permafrost and can be economically · thawed for grouting • A deep relict channel exists on the rigfit abutment. The overburden within this relict channel c~ntains a sequence of glacial till and outwash interlayered with silts and clays of glacial origin. The top of rock under the relict channel area will be below t~1e reservoir level. Further investigations will be undertaken to precisely define the characteristics of the channe 1. However·~ the data co 11 ected to date does not indicate that this relict channel will have. any major impact on the feasibility of the site. The rock conditions in the left abutment~ where the underground power- house is proposed, are favorable for an underground structure. The powerhouse cavern will require nominal suppo~t. The rock condition is expected to be favorabl~; although, additional investigations \"ill be conducted to determine the exact 1 ocati on and ori entatio.n of the features~ so as to minimize the impact of joints and any possible unfavorable stress orientation. Materials for construction of either a rockfill dam or related concrete structures are available within economical distances. Imper- vious and semi-pervious core and filter materials are available \'lithin three miles (4.8 km) upstream (Figure 6.5), and a good source of fil- ter material and concrete aggregate is available at the mouth of Tsusena Creek just downstream of the dam. Rockfill is available immediately adjacent to the dam in the left abutment w~ere rock is removed fro.n the core excavation and excavation for tunnels~ the powerhouse., and spillway structures. There is also a possi bi 1 ity of using rounded riverbed material for the she11 if adequate quantity is available. Further investigation will be conducted to better define the quantity and character·istics of material in each source area and the relative economic) of each borr·ow location. (b) Devil Canyon Site The Devil Canyon dam site lies on argillite and graywacke exhibiting significant jointing and frequent shear zones. The nature of the rock is such that numerous zones of gouge, alteration3 and fractured rock were caused during the major tectonic events of the past, in addition to the folding and internal slippage d!..cring lithification and metamor- phism. Consequently~ zones of deep weathering and alteration can be expected in the foundation. txcavat ion of up to 40 feet of rock wi 11 expose sound foundation rock, and consoli1ation grouting and·dental excavation of badly crushed and a 1 tered rock '-'li 11 be necessary to pro vi de adequate bearing surfaces for either a rock fi 11· or concrete dam. Overburden within the narrow V-section of the valley is minimal. I 'I I I I I I I I I I I I I I I I I The left abutment plateau, which is the location of a saddle dam, has a buried river channel paralleling the river (Figure 6.6). The overburden reaches 90 feet under a small lake in this area, so construct.ion of the saddle dam will r'equir~ excavation of considerable amounts of fill and lake deposits, or construction of a cutoff extending down to bedrock. Seepage contra 1 will be effected by two methods: first, by general contact and consolidation grouting to control flow at the dam foundation contact, and second by a deep grout curtain with corresponding drain hole curtain to limit downstream flow through the foundation. Permafrost has not been detected at trA site, .but if it does exist, it is not expected to be substantial or widespread. A thawing program can be incorporated with the grout hole installation if necessary. Construction materials for a concrete dam are available in the large gravel bar immediately upstream of the dam site (Figure 6.7).. The- materials in this bar are adequate in quantity for a.ll the needs of a concrete dam, or· can fill all concrete aggregate and filter requirements for an earthfill dam. The lakebed and till deposits in Cheechako Creek {approximately 0.25 miles upstream}, may be sources of a substantial portion of impervious material requirements for an earthfi 11 dam, and are felt to be fully adequate for construction of an earthfill saddle dam in the concrete main dam scheme. Sufficient local rock for rockfill shell material is available should a rockfill dam be decided on for Devil Canyon .. However, testing ltlill be performed to ensure that it is suitable for continuous exposure to water and freeze-thaw cycles. Additional sources of impervious fill material are needed before the feasibility of a rockfill dam at this site can be determined. 6.4 -Seismic Aspects. 6.4.1 -Seismic Geology • The Talkeetna Mountains region of south-central Alaska lies \'lithin the Talkeetna Terrain. This term is the designation given to the immediate region of socth-central Alaska that includes the upper Susitna River basin (as shown on Figure 6.8). T!1e region is bounded on the north by the Denali Fault, and on the west by the Alaska Peninsula features that make up the Central Alaska Range. South of tl)e Ta1keetna Mountains, the Ta.lkeetna Terrain is separated from the Chugach Mountains by the Ca~tle Mountain Fault. Susitna HydroelE:ctric Project dam sites are located in the \testern half of the Talkeetna Terrain. The eastern half of the region includes the relatively inactive,_ ancient zone of sediments under the Copper River Basin and is bounded on the east by the Totschunda section of the Dena 1 i Fault~ and the volcanic Wrangell Mountains. The studies and research conducted to date indicate that the Talkeetna Terrain is a relatively stable section of crust with· most of the seismic activity in the area attributed to the Denali and Castle Mountain Faults, which have a record of recent displacements, and to the Benioff Zone. "·r I I I I I I I I •• I I I I I •• •• I I The Talkeetna Terrain is being underthrust by the Pacific Plate, ~1hich is moving in a north\'lest direction in this area. The Benioff Zone is the contact surface betv1een the crustal (North American) plate and the subducted (Pacific) Plate, and is the source of the most of the large seismic events in Alaska. Within the 1·alkeetna Terrain, numerous lineaments and suspected featJres were investigated by Woodward-Clyde Consultants as part of their 1980 seismi"' ~l,udies. Utilizing available air photos, satellite imagery and airborne remote sensing data, a catalog of reported and observable discont:inuities and linear features .(lineaments) was Ct'mpiled. After elimination of those features that were judged to be ca·Ased by glaciation, bedding, river processes, or man's impact, the 216 remaining features were. .screened and those passing the screen \'lere classified as either being features that could positively be identified as faults, or' features which could possibly be faults but for which a definitive origin cou!d not be i denti fi ed·. The following criteria were used in the screening process: (1) All lineaments or faults that have been defi:'ed by the geologic and seismo1ogic communities as having been subjected to recent displacement should be included in assessing the suismic design criteria for the project and are not screened out. (2) If a 1 i neament exists within 6 mi 1 es of a structure site, or if a branch of a more distant lineament is suspected of passing through a structure site, then a more detailed investigation should be made to establish whether th~ feature is a fault, whether or not it can be considered to have recent displacement, and whether the potential for displacement in the structure foundation exists. It is therefore not screened out. (3) Investigation of features identified in Item 2 should determine whether these features have experienced displacement in the last 100,000 years. If they have not then they are screened out. (4) Lineaments more distant than 6 miles from a structure site, and for which.deterministic impact on the site may control the design of a structure, shouid be investigated to determine if the lineament is a fault and if it has moved within the last 100,000 years. (5) All features identified as faults which have experienced movement in the last 100,000 years should be considered to have had recent displacement. All faults with recent displacement warrant consideration when assigning design criteria for ground motions or for surface displacement at th~ structure sites. These guidelines were formulated after review of regulatory requirements of the WPRS, COE_, u.s. Nuclear Regulatory Commission, Federal Energy Regulatory Commission!) and several state regulations .. I I I I I I I I I I I I I I I •• I To support these studies, a 10-station microsaisrnic network was installed in June of 1980 and operated for three months. The results were integrated with the seismic geology and the historical seismicity data. As a result of the 1980 field in~estigations and microseismic network, the resultant group of 48 significant features were identified and analyzed for potential impact to the project even though these features are faults and lineaments for which no recent displacement (which is an index of activity) was found. They were selected as there is no direct evidence showing lack of displacement. This approach ·is conservative and compatible with the conservative design philosophy used for design of large projects. Of these 48 candidate features, only 13 features were judged to be significant for the design of th~ project. These thirteen features include four features at the Watana site (including the Talkeetna Fault ar;d the Susitna feature) and nine features at the Devi 1 Canyon sitrc. It is ~'lorth noting that no evidence of the Susitna feature was observed during the 1980 studies. These thirteen features will be further investigated during 1981 i:o establish their impact on the project design. 6.4.2 -Sei§mology The regiona'1 earthquake activity is closely related -co the plate tecton·fcs of Alaska. The Pacific Plate is underthrusting the North American Plate in this region .• 'fhe major earthquakes of Alaskd, including the Good Friday earthquake of 1964, have primarily occurred along the boundary between these plates. The historical seismicity within the site region is associated with the following sources: the crustal earthquakes within the North American Plate and the shallow and deep earthquakes generated with~n the Benioff Zone. The historical earthquake records for ~outh-central Alaska and the site region, in particular, were reviewed. Th~ data reveals that the major source of earthquakes in that region is the shallow portion of the Benioff Zone. Several large earthquakes during the twentieth century have been related to this source. The next major source of earthquakes in the site region is in the deep portion of the Benioff Zone, \'lith depths ranging between 24 to 36 miles (40 to 60 km) below the surface. Several moderate ·size earthquake~ have been reported to have been generated at these depths .. The crustal seismicity within the Talkeetna Terrain is very law based on historical records. Most of the earthquakes are reported to be re.lated to the Dena 1 i:.. Totschunda Fault or Castle Mountain Fault. As mentioned previously, a short-term micr·oseismic monitoring network was installed and operated for three months. The objective of this stu~ was to co 11 ect mi croearthquake data in order to ~va 1 uate the 1 ocati ens and focal depths of microearthquakes, study the types of faulting and stress orientation within the crust, study the association of mi croearthqua~es wii;h surface faults and 1 i neaments and to understand v1ave propagation C.iaracteristics. A total of 265 earthquakes with sensitivity approaching magnitude zero were recorded. Out of these events, 170 were recorded at shal1ow depths, the largest being magnitude 2"8 (Richter Scale). ~:inety eight events were related to the Benioff Zone, the largest being magnitude 3.68. None of the microearthquakes recorded at shallow depths were found to be related to any fault or : ineament within the Talkeetna Terrain, 0 fl I I I I I I I I I I I I I I I I I I • including the Talkeetna Fault. The depth of the Benioff Zone was distinctly defined by thi.s data as being 36 miles (60 km) under the Devil Canyon site and 39 miles (65 km) under the Watana s·ite. The subject of Reservoir Induced Seismicity (RIS) was studied on a preliminary basis using a world\'t'ide RIS study and site specific information. The phenomenon of RIS has been noticed in numerous large reservoirs with accepted correlation ~~~ween seismic tremors under or immediately adjacent to the reservoir and periods of high filling rate. In recent years, this subject has drawr considerable attention within the engineering and seismic community. It is thought that RIS may be caused by the increased weight of the water in the reservoir or ~f the increased pore pressure migrating through joints in the rock and 11 lubr·icating" and acting hydraulically upon highly stressed rock. Studies indicate that for a reservoir system to trigger a significant earthquake, a pre-existing fault with recent displacement must be under or very near to the reservoir. The presence of a fault with recent displacement has not been confirmed at either site~ The analysis of previously reported cases indicated a high probabi 1 i ty of RIS for the StJsitna system on the basis of its depth and volume, if fau1ts with recent displacement exist nearby. Most RIS is felt to be an early release of stored energy in a fault, so in s.~rving as a mech;,mi srn fOt"' energy release, the resultant earthquakes are likely to be sma 11 er' than if full energy bui 1 dup occurred. In no case studi ~d) has an RI~ event exceeded the maximum credible earthquake or any fault\3 • · Thereiore, RIS of itself does not control the design earthquake determinatiQn and is considered oltly for purposes of estimating recurrence intervalsl4J. · 6c4.3 -Preliminary Ev~luation of Design Ground Motion On the basis of the geologic and seismic studies, three main sources of earthquakes have been identified. These sources include the Denali Fault (39 miles) north of the sites, Castle Mountain Fault less than 60 miles (100 km) south of the site and the Benioff Zone 30 to 36 miles. The thirteen other faults and lineaments considered significant for the project design were not included in assigning earthquakes, as no evidence was found to indicate that these faults and lineaments experienced displacement during recent geologic times,. However, further field studies will be conducted on these features due to their proximity to the sites and resultant potential ground rupture considerations. The Denali Fault has been assigned a preliminary conservative maximum credible earthquake value of magnitude 8.5. This earthquake, when attenuated to the sites, is postul"ted to generate a mean peak acceleration of 0.2lg at the ~Jatana and Devil Canyon sites.. The. Castle Mountain Fault has been assinned a preliminary conservative value of magnitude 7.4, which will genet"ate R mean peak acceleration of 0.05g to 0.06g range at the sites. The Benioff Zone has been assigned an upper bound conservative value of magnitude 8.5, which will generate a mean pe.ak acceleration of 0.41g at the viatana site and Oa37g at the Devil Canyon site. The duration of strong motion earthquakes for both the Denali and Benioff Zone is estimated -b~ be 45 seconds. It is evident that out of these three potential sources., the Benioff Zone will govern the design. However) further studies will be undertdken to finalize these maximum credible y. • • .. • ... ;;·"'. ... • • • .· . . ~ ... ,.. . ,. · .. : ... ; . . " Jt ~.. . . . .. :· . . . . ~ .. b • a ' . · •· . . · ,.._ \ I I I I I I I I I I I I I I I I I earthquake magnitudes and to evaluate faults and features within the Talkeetna Terrain. Due to their distant lo(;ations, none of these faults have any potential for ground rupture at t~e site. Large dams ha~'e been designed to accommodate 9r--ound motions from relative-:-y large earthquakes located close to the dam. In California, dams are routinely designed to withstand ground motions from magnitude 7.5 to 8.5 earthquakes at distances of 12 miles. Dams have also been designed to accommodate up to 20 fteet of hori zonta 1 displacement and three feet of vertical displacement 2)0 A11 of these conditions are more severe than those anticipated at the Susitna sites~ Oroville Dam in central California was designed to high seismic loadings and has been progressively analyzed as new data and methods become available. Current evaluations indicate that the dam, which is comparable size to Watana, can withstand seismic 1 oa.di ngs comparab 1 e to those postulated for Watana. 6 .. 5 -Sus~tna Basin Planning Studies The objective of the planning exercise is to systematically e\·aluate all alter- native plans for developing power· from the Susitna Basin upstream from Gold Creek a.1d to se 1 ect the most promising plans for more detai 1 ed study. The process adopted involved several steps which included indentifying potentia~, dam sites within the basin and then proceeding through several screening exercises to eliminate most of the less economic and environmentally less acceptable sites~ Finally a more detailed evaluation of the costs and energy benefits cf the shortlisted plans was carried out. Throughout this planning process, engineering 1 ayout studies \'lere conducted to refine the cost estimates for developing power at specific sites. As it became available this cost data was fed into the ~creening process to ensure that earlier decisions based on orevious data were still valid. Th'2 basic planning steps are 1 isted belO\\' and are also illustrated on Figure 6.9: (a) Site selection (b) Preliminary screening (c) cinal screening (d) Refinement of Susitna Basin development options. Step 1 involved selecting previously identified sites and desk studies aimed at identifying any additional sites .. The preliminary screening (Step 2) exercise involved eliminating from further consideration the obviously less attracttve ·sites based on economics and potential environmental impact.. This exercise was initially based on published cost and energy data for the sites. As the in-house studies progressed, more up-to-date costs and energy values were incorporated. Final screening (Step 3) involved the application of a computer program to systematically investigate all possible combinations and permutations of dam site, dam height, and im:tal1ed capacity and the determinati.on of the economic optimum development for specified total power and energy production. The plans, thus identified, were then further refined utilizing a computer model to simulate monthJy energy and power production and detailed reservoir operating rule curves. These refined plans were then utilized as input to the generation planning and development selection studies described in Section 7. 0 I I I I I I I I I I I I I I I I I I The planning process is described i11 more detail in the sections that fol.lowo 6.6 -Site Selection and Preliminary Screenif}9 6.6ol -Site Selection In the previous Susitna Basin studies discussed in Section 4, twelve dam sites \·/ere i denti fi ed in the upper portion of the basin; i.e., upstream from Gold Creek (see Figure 6.10). These sites are listed below: (1) (2) (3) {4) (5) (6) {7) {8) (9) {1 0\ \•-; (11) (12) Gal d Creek Olson (alternative name: Susitna II) De vi 1 Cany-on High Devil ·canyon (alternative name: Devi 1 Creek Watana Susitna III Vee Maclaren Denali Butte Creek Tyone Susitna I) Figure 6.11 shows a longitudinal section th . Jgh the basin and the reservoir levels associated with these sites. Table 6.9 shows which sites are mutually exclusive and which can be grouped to develop the full potential of the basin. Study of these sites indicated that they covered the to~al._.basin an?.~here was no e\'idence of any additionall\sites .. potent1 ally econom1 c. ··- Al"l relevant data concerning dam type and capital cost, height, power and energy output was assembled and is summarized in Table 6.10,. In obtai:ni ng the information for these tables, the latest source was used in each case. At the Gold Creek, Devil Creek, ~acl arens Butte Creek and Tyone sites!!, no engineering or energy studies we:<e undertaken uy Acres and only data from previous studies was used. Costs were updated to 1980 1 eve 1 s. The results of the eng:i neeri ng and cost studies performed by Acres at other sites were us~d to review these costs. For a 11 the other sites Acres de vel oped ru~\v conceptual engineering layouts and the cap'i~al cost estimates have been revised using calculated qu~ntities and unit rates. For the sake of camp 1 eteness _, Tab 1 e 6.11 compares the costs deve 1 oped by Acres w·; th tEose developed in previous studies. b::s·./\t.... cu..N'IQ~ The results in Table 6.10 clearly show thatrHigh Devil Canyon and Watan are the most economic 1 arge energy producers in the basin. Sites such as Vee and Susitna III are medium energy producer·s although slightly more costly than these dam sitf!s. Other sites such as D.evil Gap,.y~ Olson and Gold Creek are competitive provided ttiey have additional upstream streamflow renulation. Sites such as Denaii and Maclaren are expensive compared to other sites. Preliminary environmental impacts associated with the various dam sites ? were derived from a review of available information and from the results of field reconnaisance trips. The type of information assembled is general in nature, but does serve to rank the im~acts at the various sites. I I I I I I I I I I I I I I I I I I To facilitace synthesis and presentation of the environmental information, the river is divided into six study reaches starting with reach A at the downstrecim end and finishing with ~each F located upstream of Denali (Figure 6.11). Within each of these reaches, the environmental r..Spects are assumed constant for the level of study ?+ this stage. The major environmental features for each of these r ~., .• ches are summarized as follows. Beach A -Talkeetna to Devil Canyon Under existing conditions, salmon migrate as far as Devil Canyon, utilizing Portage Creek and Indian River for spawning. lhe deve 1 opment of any dam downstream of Portage Creek •:;oul d result in ·a loss of salmon habitato; The necessary FERC license and permits for such development would probably be difficult to r.cquire. Reach B-Devil Canyon·to Watana The concerns associated with development in this secti'' of the river relate mainly to the inundation of Devil Canyon, whid. is con~;dered c. unique scenic a.nd white water reach of the river, and has dam safety aspects associated with the occurrence of major geological faults. In addition, the Nelchina caribou herd has a general migration crossing in the area. Reach C -Watana to Vee There are concerns which relate to the loss of some moose habitat in the Watana Creek area and the inundation of sections of Deadman and Loki na Creeks. Other aspects include the effect on caribou crossing in the Jay Creek area, and the potential for extensive reservoir shoreline erosion and dam safety aspects because of the possibility of geological faults. Reach 0 -Vee to Maclaren ~ - The inundation of moose winter range, waterfowl breeding areas, the scenic Vee Canyon-and the downstream portions of the Oshetna and Tyone Rivers are all potential environmental impacts associated with this reach of the river. In addition, caribou crossing occurs in the area of the Oshetna River. The area surrounding )is section of the river is relatively inaccessible and development would open large areas to hunters. Reach E -Maclaren to Denali Environmentally, this area appears to be more sensitive than Reaches B and c. Inundation could affect grizzly bear denning areas, moose habitat, waterfowl breeding areas and most alpine tundra vegetation. Improved access would open wilderness areas to hunters. I I I I I I I I I I I I I I I I I Reach F -Upstream of Denali This area is similar to Reach E with the exception o·f grizzly bear denning areas. Human access to this area would not impact to the same extent as in Section D and F.. However, due to the proximity to the .Denali highway, the inflow of people could be greater. This information was used in Table 6.12 for environmental site ranking .. Environmental impacts are divided into three basic categories, i.e. biologicQl (impact on fish and wildlife}, social (local and regional impacts) and institutional aspects which include lice~ses and permitting requirements .. . 6.6c2 -Preliminary Screening To reduce the number of sites for further deta i 1 ed study, sever a 1 were screened out. The screening criteria used .; nc 1 uded energy cost and potential environmental impact. One si.te , ~s automatically screened when .alternative sites ar·e located clcse to each other. This exer'cise resulted in elimination of the following sites: De vi 1 Creek -This site is c 1 ose to the High De vi 1 Canyon site and for planning purposes can be assumed to be an alternative for the latter. Butte Creek -This site is close to and alternate to the Denali site. Gold Creek -Severe problems would be encountered in obtaining an FERC license because of tbe potential ~environmental impact, particularly one anadromous fisheriesu 01 son -As for Go 1 d Creek. Tyone -Relatively low energy and power potential and anticipated severe environmental impact. 6.7-Engineering Layout and Cost Studies In order to develop a more uniform and reliable data base for studying the :seven sites remaining after· the preliminary screening exercise~ it was necessary 'to develop engineering layouts for these sites and re-evaluate the costs. In add it ion, it was a 1 so necessary to study staged deve 1 opments at sever a 1 o,f the largest dams. The basic.objective of.these layout studies was to establish a uniform and consistant cost of development at each site. These layouts are conceptual in nature and do not represent definitive and optimum proje~t arrangements at th~.: sites. Also~ because of the lack of geotechnical information at several nf the sites, th~se 1 ayouts do not i~ply that a 11 deve 1 c 1ents are necessarily technically feasible; •(J. """ 1 .. ~• I I I I I I I I I I I I I I I I I I I 6.7.1 -Design Assumption~ In order to maximize standardization of the layouts a set of basic design assumptions were developed. These assumptions were used as guidelines to deter·mine the size of the various project components and are described below. (a) Geotechnical Considerations -Main and Saddle Dams The geotechnical considerations are summarized in Table 6.13. -Temporary Cofferdams It is assumed that a 11 cofferdams are of a fi 11-type. Si nee muct~ of the original riverbed material under the main dam shell may have to be excavated~ all cofferdams are located outside the upstream and downstream limits of ;he main dam. (b) Hydrologic and Hydraulic Considerations Table 6.14 lists certain key hydrologic parameters. It should be noted that at this conceptual stage spillways \'/ere sized for the peak i nrl ow and no benefit of flood peak attenu ~ion due to reservoir storage was taken into account. The spillways v1ere sized for the 10~000 year flood and the energy dissipation in the stilling basins limited to a maximum of 45,000 norsepower per foot width. This maximum limit is based on international experience with other large dams. · Table 6-.15 summarizes the normal operating freeboard requirements. In addition to these freeboard t'equirements checks were undertaken to ensure that the dam was not overtopped during a PMF event and that the spillway design _flood could be passed even after a major seismic event had induced a further 1-1/2 percent settlement on a fill dam. (c) Engineering Layout Considerations Table 6.16 1ists guidelines for determinirg wn~t components are incorporated in the engineering iayouts.. The dam crest and full supoly levels associated with each site are listed in Table 6.17. It should oe noted that two different heights are considered at the De vi 1 Canyon, High Devil Canyon, and \-Jatana sites. In the case of the Watana site~ a staged development is considered and the lower dam freeboard has, therefore, been increased by 40 feet for cost estimating purposes. It is assumed that this top layer would have to be'stripped before construction of Stage 2 commences. 1.t-:£ . t5 I I I "' I I I ? I I I I I I I I I I I I (d) Mechanical -Number of Units In general~ a decrease in the number of units will result in a reduction in power plant cost. For these preliminary studies it was assumed that a minimum of two and a maximum of four units would be installed. -Turbines Vertical Francis type with steel spiral cases are used. It is assumed that the turbines will be directly connected to vertical synchronous generators. -Spillway Gates The spillway gates are fixed wnee1 vertical lift gates operated by double drum wire rope hoists located in enclosed tower and bridge structures. MC!ximum gate size for preliminary design are: -width: -height: 50ft 60 ft A three-foot freeboard is provided for gates over maximum operating wate~ level. The gates will be heated for winter operation. -Miscellaneous Mechanical Equipment Cost estimates provide for a full range of power station equi~"llent including cranes, gates, valves, etcG (e) Electrical Considerations -Powerhouse Separate transformer galleries are provided for main and stati~n transformers.. Provision is made in the cost estimates for a f~:·~l range of miscellaneous operating and control equipment including where necessary allowance for remote station operation. -Switchyard and Transmission Lines Switchyards are located on the-surface and as close to the powerhouse as pass i b 1 e. The size of the yards is approximately 900 by 500 feet~ Cost estimates should allow for transmission iines and substations (see Table 6.16). 6. 7. 2 -Site Layouts A brief description of the site 1 ayouts is given be 1 ow. Dra\ti ngs 1 to at the end of this report illustrate the layout details. I I I I I I .. I I I I I I I I I I I I (a) Devil Canyon (Note: At this stage the dam costs incorporated in the gr rterati on . planning is a rockfill dam. The concrete dam costs will be substitu- ted as soon as they become available and will be incorporated in the final ;eport). In order to provide· a common basis for cost comparisons between the various sites a common rockfill dam type has been assumed for all development ex6ept Olson. The dam at Devil Ga~yon c?mprises a~proxi mately~x 10 in yards of rock, gravel, and 1mperv1ous mater1a1s, has a maximum height of approximately 650 feet above foundation 1 eve1. · Spillway fac~~ities consist of a gated overflow structure, intermedi- ate and downstream stilling basins and concrete line chutes and are located in the right abutment. The power intake structure is also founded deep within this abutment and consists of multi-1eve1 intakes serving individual penstocks leading to the underground powerhouse. The powerhouse ~~comrnodates 4-100 MW tur•bi ne/generator units. The switchyard i$ situated at the surface fi11 cofferdam. Diversion is effected by an upstream rock and earth cofferdams and twin concrete lined tunnels on the right side of the river. As an alternative to the full power development, a staged alternative has been investigated with the dam completed to its full hejght, but with an initia1 installed capacity o: 200-300 MW. The complete powerhouse would be excavated together with penstocks and tailrace tunnel for 2-150 MW units. The ·comp1ete intake would be constructed except for gates anc rocks required for the second stage. The second stage installation \'IOUld include installation of the remaining gates, construction of the corresponding penstocks and tailrace tunnel for the new 2-150 MW Utlits and completion of civil, electrical and mechanical installation within the power·house area together with enlargement of th~ surface switchyard .. · (b) Watana The development is comprised of a 900 f~ height rockfill dam with an overall volume of approximately 70 x 10 cu. yd. and a crest elevation of 2,225 ft. The spillway facilities are similar to those at Devil Canyon and are located in the right abutment. The power facilities are located within the 1 eft abutment and are s·imi 1 ar in concept to De vi 1 Canyon with 4 units giving a total installed capacity of 800MWs The switchyard is on the surface. The diversion consists of an earth/rockfill cofferdam and twin lined tunnels within the right abutment. . ;, "~· -----·~·~~ .t!, I I I I ~ I I I I I I I I I I I II I I As an alternative staged version, a reduced height, broad cr~sted fill dam has been investigated for a 200ft. lower surface elevation in the reservoir. The first stage powerhouse would be completely excavated and would house three oversized 135 MW units. A low level control structure and twin line tunnels leading into a downstream stilling basin. would form the first stage spillway. For the second stage the dam would be completed in its full height with addtional rockfi11 being placed on the downstream face and crest. It is assumed that before construction commences on the second stage the top 40 ft. of the f'ir?t ~tage c;r~?t is removed t,a prev~nt any danger of .... -· /; ~~ .... -e..~ e..<". 't)~.,~-o~ ~'--\.""'"V""""''ov ~ G.o~·L. ~"0'-'~"--~~:,~ ~-r"Sij' ihx':r !'~~._...c...~t-. Two additional 200 MW units would be installed and corresponding penstock and tailrace tunnels constructed. The rurners on the first sta~1e units waul d be replaced and the turbines upgraded to provide 200 MW e~ach giving a tot a 1 of 800 M\~ with the new unit.. Rotors on the existing generators could be altered to cater for the new operating spe(:!ds by making predetermined connections within their windings .. (c) High De vi 1 Canyon The development is located between Devil Canyon and vlatana gnd is comprised of an 850ft high rockfill dam containing 48 x 10 cu. yds. of rockfill with a crest elevJtion of 1775 ft. The left abutment spillway and the right abutment powerhouse fatilities are similar in concept to Devil Canyon and Watana. The installed capacity is 800 MW> The left hand diversion is formed by an upstream earth/rockfil1 cofferdam and twin lined tunnels. Sto,ging is envisaged a.:; two stages of 400 MW each in the same manner as at Devil Canyon with the dam initially constructed to its full height. (d) Susitna III The development is comprised of a rockfill gam approximately 650ft. high with a volume of approximately 55 x 10 cu. yds. _and a crest elevation of 2360 ft. The spillway consists of t\llo-sta.ged spilling oasin as for Devil Canyon c4nd Watana, located on the right abutment. A surface p~werhouse of 350 MW capacity is located on the left bank and diversion is through twin tunnels in the right abutment. (e) Vee A 650 ft high rockfill dam has been considered with foundations on bedrock. The spillway in the form of a chute and flip bucket is situated within the ridge forming the right abutment. ··)0 I I I I I I I I I I I I I I I (f) (g) The power facilities consisting vf a 400 MW underground power station are located beyond the left abutment with the intake founded within a low saddle which is filled by a rockfill secondary dam at its low poi"lt. Maclaren The development consists of a lrJ ft high earthfil1. dam founded on · pervious riverbed materials. Ctest elevation is 2405 ft. The reservoir is purely for regulatinu pur-poses and no generating capacity is included. Flood diversion is via a side c·hute spillway and stilling basin on ·the right abutment. Denali Denali is similar in concept to Maclaren with a 200ft high earthfill dam of crest elevation 2555 ft. A combined diversion and spilhV"ay facil-ity is formed by twin concrete conduits founded in open cut excavation in the right bank and discharging into a common stilling basin. Capital Costs Quantitic~ \'/ere determined for items compri!>ing the major ttorks and structures at the sites. Where detail or data was not sufficient for certain work, estimates have been made based on previous experience. In order to determine total capital costs for v~rious structures unit costs have been develop~d for the items. These have been determined after a review of rates u~ed in previous studies, a review of rates used on similar works in Alaska, and elsewhere with an adjustment factor where applicable based on geography, climate, manpower, accessability, etc. Technical publications have also been reviewed for basic rates and escalation factors. An overall mobilization cost of 5 percent has been assumed and camp and catering costs have been b~sed on a preliminary review of construction manpower and schedules~ An annual construction period of 6 months has been assumed for placement of fi 11 materials and 8 months for a 11 other operations. Night wo~K has been assum~d throughout. \ 20 percent allowance fer non-pr·edictable contingencies has been added as a lump sum together with 12 percent for engineering and administration. 6.8 -Final Screening A computer screerdng model was developed to undertake the next, more detailed screening process. Basically, the model selects a least cost basin development scheme for a given total basin power and energy demand; i.e .. it selects the sites, approximate dam heights and installed capacities. I I I I I I I I I I I I I I I I I I 6.8.1 -Screening Model Description The model incorporates a standard Linear Programming (LP) algorithm for determining the optimum or least cost solution. It is provided with basic hydrologic data3 dam volume-cost curves at all the sites, an indication of which sites are mutually exclusive and a total power demand required from the basin. The model then incorporates a time period by time period energy simulation process for individual and groups of sites and systematically searches out the least cost system of reservoirs and selects installed capacities to meet the specified power and energy demand. A detailed description of the model as well as the input and output data is given in Appendix A. A summary of this information is presented below. 6o8.2 -JBEYt Data Input data to the model takes the following form: (a) Streamflow ~n order to ~educe the complexity of the model~ a year is divided into two periods, summer and winter, and flows are specified for each. For the smaller dam.sites such as Denali, Maclaren~ Vee and Devil Canyon which have little or no overyear stora.ge capability, only two typical years of hydro 1 ogy are input. These correspond to a dry year { 90 percent probability of exceedence) and an average year (50 percent probab1lity of exceedence). For the other larger sites, the fu11 thirty years of historical data are speci~ied. (b) Site Characteristics For each site, storage capacity versus cost curves are provided. These curves were developed from the engineering 1 ayouts pre:1ented in Section 6.7. Utilizing these layouts as a basis the quantities for lower level dam heights were determined and used to estimate the costs associated with these·1ower levels. Figures 6.. to 6. depict the curves used in the model runs. These curves incorporatethe cost of the generating equipment. Interactive computer model runs were required to ensure that the installed capacities calculated by the model are reflected on the rrservoir storage capacity versus cost curves fed into the mode 1. (c) Basin Characteristics The model is supplied with information on the mutually exclusive sites as outlined in Table 6.10. (d) f..ower and Energy Demand The mode:l must be supplied with a power and energy demand. This is achieved by specifying a total generating capacity required from the river basin and an associated annual plant factor \'lhich is then used to calculate the annua 1 energy demand. I I I I I I I I I 1-' I I I I I I I 6o8.3 -Model Runs and Results A review of the energy forecasts discussed in Section 5 reveals that between the time a Susitna project could come on line in early 1993 and the end of the planning period, 2010, approximately 2200, 4250, and 9570 Gwh of additional energy would be required for the low, mediums and high energy forecasts, respectively. In terms of capacity, these values represent 400, 780 and 1750 MW. Based on these figures, it was decided to run the screening model for the following total capacity and enerlY values: -Run 1: -Run 2: -Run 3: -Run 4: 400 MW -1750 Gwh 800 MW -3500 Gwh 1200 M~~ -5250 Gwh 1400 MW -6100 Gwh The results of these runs are shown in Table 6.18. Because of the simplifying assumptions that are made in the screening model, both the best and second best solutions from an economic point of view are presented. It will be noted that in terms of economics these two solutions are extremely close .. The most important cone 1 usi ons that can be dravm from the results shm·1n in Table 6.18 are as follows: (a) For energy requirements of up to 3500 Gv1h the High De vi 1 Canyon and Watana sites are the most economic; · (b) Up to energy requirements of 5300 Gwh the combinations of either l~atana and Devi 1 Canyon or High De vi 1 Canyon and Vee are the most economic; (c) The tot a 1 energy product {on capabi 1 i ty of the Watana/Devi 1 Canyon developments is considerably larger than that of the High Devil Canyon/Vee alternativeo The reasons why this screening process rejected the other sites is as follows. · Susitna III was rejected aue to its J:igh capital cost. The marginal cost of the energy production is very high in co'Tlparison with Vee~ even allowing for the 150 feet of the sy~tem head that is lost between the headwaters of High Devil Canyon and the tai 1 water of Vee. Mac 1 aren has a very sma 11 impact on the system's energy and is very expensive. A scheme involving Denali and Devil Canyon or Denali and Vee giving 400-500 MW are not competitive with vlatana or High De vi 1 Canyon for the same installed capacity. Both Watana and High Devil Canyon have enough regulating cap·acity even at sma11 heads. I I I I I I I I I I I I I ._, I I I I 6.9 -Susitna Basin Development 6.9.1 -Potential Susitna Schemes The results of the final screening process indicate that the Watana -Devil Canyon and the High Devi 1 Canyon -Vee plans ~~arrant further, more detailed study. Associated with each of these plans are severa1 options for staging the development. These include staging construction of the dams and/or the power generation facilities. For this more detailed analysis of these two basic plans, a range of different approaches to staging the developments are consider~rl, In order ~o keep the total options to a reasonable number and also to maintain reasonably large staging steps consistant with the total development size, only staging of the larger two dams, i.e. Natana and High De vi 1 Canyon, is considered. Powerhou~e stages are considered in 400 MW blocks.· The basic staging concepts adopted for these two large dams involve staging both dam and powerhouse construction or alternatively just staging powerhouse construction. A to+al of nine basic plans were developed. These are summarized in Table 6,1~ and are briefly described below. Plans 1 to 3 dea,l with the Watana - De vi 1 Canyon sites and Plans 4 to 6 with the High De vi 1 Canyon -Vee sites • .(a) p·fan 1 The first stage involves con·structing Watana dam to its full height ( 2,225 foot crest e 1 evat ion) a~d installing 800 M~J. Stage 2 i nvo 1 ves constr-·ucting Devil Cahyon Dam (1,470 feet) and installing 600 ~1\~. (b) Plan 2 For this plan, construction of the \o.Jatana Dam is staged from a crest elevation of 2,060 feet to 2,225 feet. The powerhouse is also staged from 400 MW to 800 MW. As for Plan 1, the final stage involves Devil anyon with an installed capacity of 600 MW. (c) Plan 3 This plan is similar to Plan 2 except that only the powerhous-e and not the dam at Watana is stagP~ Plan 4 This plan i nvo 1 ves constructing the High De vi 1 Canyon Dam first wi.th a crest elevation of 1~775 feet and an installed capacity of 800 lMW. The second stage involves constructing the Vee reservoir to a crest e:evation of 2,350 feet and install·ing 400 MW of capacity. (e) Plan 5 For this plan, the construction of High Devil Canyon dam is staged from a crest elevation of 1,63v to 1~775 feet. The installed capacity is also staged from 400 to 800 MW. As for P·lan 4, Vee follows \*lith 400 MW of installed capacity. -1 ,:: ~ 1' I I I ••• I I I I I I I I I I I I I I· (f) Plan 6 This plan is similar to Plan 5 except that only the powerhouse and not the dam at High De vi 1 Canyon is t'taged. In addition to these six plans, several additional plans were studied for other specific redsons,. The,se include: (g) Pl art ' (h) This plan v1as studied to inves·cigate the feasibility of constructing the De vi 1 Canyon dam first anc. then the ~4atana dam. Due to the shorter construction period associated with Devii Canyon dam, this plan can be brought on line approximately 2-3 years before plans involving Watana as a first stage. The plan involves constructing the Devil Canyc dam to a crest elevation of 1,470 feet and installing 250 MW ~enerating capacity. The secoud stage i nvo 1 ves con~~truct i ng Watana to a crest 1 eve 1 of 2,225 feet with an installed capacity of 800 MW. The final stage involves adding 350 MW capacity to the Devil Canyon dam. Plan 8 As discussed in more detail in the following Section 6~10, the Devil Canyon dam in Plans 1 to 3 could be replaced by lower re-regulation dam located between the Dt:vil Canyon and Watana site and a tunnel leading from this dam to the currently proposed f.\evi1 Canyon dam site. The plan involves constructing \•Iatana to a crest elevation of 2 2 225 feet and installing 800 M\~ of capacity. The next stage is the construction of the downstream re:-regul at ion dam to a Ct"est elevation of 1,500 feet and a 15 mile long tunnel. A total of 300 MW would be installed at the end of the tunnel and d furthe~ 30 MW at the re-reg~lation dam. ( i) Plan 9 This plan was developed in order to assess the economics of developing the two most economic dam sites, Watana and High Devil Canyon jointly. Stage 1 involves constructing Watana to a crest elevation of 2~225 feet v-:ith an installed capacity of 800 MW. Stage 2 involves constructing High Devil Canyon to a crest e 1 evati on of 1, 470 feet. In order to develop the full head between Watana and Portage Creek;, a sma 11 er Jam is added dmvnstream of High De vi 1 Canyon. It would be located just upstream from Portage Creek so as not to i nterfer \>Ji th the anadromous fisheries and would ·have crest elevation of 1,030 feet and an i nsta 11 ed capacity of 150 MW. Table 6.19 also lists pertinent details such as capital costs, construction periods and energy yields associated with these plans. The cost informa- tion \vas obtained from the engineering layout studies described in Section 6.7. The energy yield information was developed using a multi-reservoir computer model. This model simulates, on a monthly basis, the energy. production from a given system of reservoirs for the 30-year period for I I I I II II I I •• I I I I I I I which streamflo\'J data is available. It incorporates daily peaking operations if these are required to generate the necessary peak capacity. All the model runs incorporate preliminary environmental constraints. Seasonal reservoir drawdowns are limited to 150 feet for the larger and 100 feet for the smaller reservoirs; daily dra\-Jdowns for daily peaking operations are limited to 5 feet and minimum discharges from each reservoir are maintained at all times to ensure all river reaches remain watered. These minimum discharges were set approximately equal to the seasonal aVt; c.ge natural low f·tows at the dam sites and are iisted in Tab1e·6._. The model is driven by an energy demand which follows the seasonal distribution shown in Table 6"20... This distribution corresponds to the seasonal distribution of the total system load as discussed in Section 5. the model was used to evaluate for each stage of the plans described above the average and firm energy and the installed capacity for a specified plant factor. This usually required a series of iterative runs to ensure that the number of reservoir failures in the 30-year period we:re 1 imited to one year'» The firm power was assumed equal to that delivered during the second lowest annual energy yield in the simulation period and corresponds approximately to the 95 percent level of assurance. . c A more detailed description of the model_, the model runs and the average monthly energy yields associated with the development plans is given in Appendix B • The above plans were subjected to economic analysis using the system generation planning model (OGPV) discussed in Section 7. These studies revealed that the staged Watana dam concept (Plan 2) was not as economic as constructing the dam to its full height. The additional capital cost associated with staging the dam is higher than the savings in carrying charges achieved by delaying construction of the second stage within the schedule required to meet load growth~ As a result of these preliminary economic analyses, it became evident that Plans 3 and 6 offered the best economic means of generating power from the Susitna basin. In the process of evaluating the schemes, it becomes apparent that there would be environmental problems associated with allowing daily peaking operations from the most downs tram reservoir in each of the plans des·cri bed above. In ord~r to avoid these potential problems whfle still· maintaining operational flexibility to peak on a daily basis, re-regulation schemes were incorporated in the basic Plans 3 and 6. Details of these ne\'1 plans, referred to as 3A and 6A, are listed in Table 6.2lo The brief description of the changes that were made are as follows: I I I I I I I I I I I I I I I I I I (a) PL.rn 3A This plan follows the same basic stages as Plan 3. A low temporary re-regulation dam is constructed downstram from Watana during Stage lo This dam would regulate the outflows from Watana and allow daily peaking operations. In the final stages only 400 MW of capacity is added to the dam at Devil Canyon. Reservoir operating rules are changed so that Devil Canyon dam acts as the re-r-egulation dam for Watana. The cost of the re-regulation dam has been e~timated at $100 million and is incorporated in the total p1an cost. (b) Plan 6A This plan is essentially the same as Pla.n 6 except that a permanent re-regul ati on dam is 1 ocated do\-Jnstream from the High De vi 1 Canyon site. As this re-regulation dam is permanent, it has been developed as a power dam. To obtain the maximum head, it is located as far downstream as possible, i.e. at the Portage Creek sit~. The crest elevation of this dam is 1,030 feet and it would have a total installed capacity of 150 MW. 6.9.2 -Sen~jtivity Analysis A range of sensitivity runs using the multi-reservoir computer model were undertaken to study the effects of the seasonal drawdown constraints on the energy yield from the selected development plans (3A and 6A). The results of these simulation runs are given in Table 6.22 and indicate that drawdown constraints of 50 to 150 feet severely effect firm and average energy production. Relaxing the constraints to 200 foot or more does not yield a s i gni fi cant increase in energy production. 6.10 -Tunnel Alternative to a Dam at Devil Canyon A 1 ong power tunnel caul d conceivably be used to replace the Devil Canyon dam in the \~atana/Devil Canyon Susitna development scheme. It could develop similar head for power generation at costs comparable to the second large dam. Obviously, because of the lm'l winter flows in the river., a tunnel alternati\'~ could be conceived only as a second stage to the Watana developmente Conceptually.,. the tunnel alternatives would comprise the following major components in some combination in addition to a Watana dam reservoir and associated powerhouse: (a) Pov1er tunne 1 intake works; (b) One or two power tunnels of up ~o forty feet in diameter and up to thirty miles in length; (c) A surface or underground powerhouse with a capacity of up to 1200 MW; (d) Are-regulation dam if the intake works are located downstram from \~"tana; (e) Arrangements for compensation of the flow in the bypassed river reach,:, -----~~·~·~.--• I' I I I I I I I I I I I I I I I I I~ I Four basic ·alternative schemes were developed and studied. All schemes assume an initial Watana development with full supply level {FSL) at 2200 feet and associated powerhouse with an installed capacity of about 800 MW. Figure 6. ___ is a schematic illustration of these schemes. Schemes 1 and 3 involve develop- ment of the head avai'iable at the ~evil Canyon dam site. Scheme 1 considers peaking operaticn through the tunnels, while Scheme 3 considers base load operation. Schemes 2 and 4 i nvo 1 ve deve·l c~mant of the full head represented by both the Watana and the Devil Canyon dams. These schemes involve locating the major portion of the generating equipment in the tunnel. As before, Scheme 2 considers peaking operatiou through the tunnels while Scheme 4 considers base load operation of the tunnel flow. Scheme 1 comprises a small re-regulation dam about 75 feet high 'llith power tunnels leading to a second powerhouse at the end of the t'Jnnel near Devil Canyon. This power station would operate in series with the one at Watana~ since the storage behind the re-regulation dam is small. Essentially the re-regulation dam provides for constant head on the tunnel and deals with surges in operation at Watana. The two powerhouses would operate as peaking stations resulting in flow and level fluctuation downstream from Devil Canyon. Scheme 2 a 1 Sf! pro vi des for peaking operation of the two powerhouses except that the tunnel intake works are located in the Watana reservoir. Initially, the powerhouse at Watana would have 800 MW installed capacity which would then be reduced to some 70 MW after the tunnels are completedo This capacity would take advantage of the required minimum flow from the Watana reservoir. The po\ver flow would be diverted through the tunnels to the powerhouse at Devil Canyon~ with an installed capacity of about 1150 MW. Daily fluctuations of water level downstream would be similar to those in Scheme 1 for peaking operations. Schemes 3 and 4 provide for base load oper.ation at Devil Canyon powerhouse and peaking at Watana. In Scheme 3 the tunnel develops only the Devil Canyon dam head and comprises a 245 foot high re-regulation dam with a capacity to regulate diurnal fluctuations due to peaking operation at Watana. The site for the re-regulation dam was chosen to provide sufficient re-regulation storage and what appears to be a suitable dam site. In Scheme 4~ the tunnel intakes are located in the WatJna reservoir. The Watana powerhouse remains at the stage-one installed capacity of 800 MW and is used to supply peaking demand. Table 6.23 lists all the pertinent technical information, and Table 6.24 the energy yields and costs associated with these schemes. In general, development co~t~ are based on the same unit costs as those used in other Susitna developmentst9J. Tunnel costs are estimated on the assumption that excavation will be done by conventional drill and blast operations and that the entire length may not have to be lined. Tentative assumptions as to the extent of lining and support are as follows: (a) 34 percent unlined (b) 33 percent shotcrete lined {c) 25 percent concrete lined {d) 8 percent lined with steel sets Based on the foregoing economic information, Scheme 3 produces the lowest cost energy. '(_ I I I I I I I I I I I I I I I I. I I A review of the relative environmental impacts associated with the four tunnel schemes was undertaken. It revealed that Scheme 3 would have the least impact primarily because it offers the best opportunities for regulating daily flows downstream from the project. Based on the above review of energy, costs and environmental impact, Scheme 3 was selected as the most appropriate alternative. Consequently, only detailed engineering layout and cost studies were undertaken for Scheme 3 (see Drawings and · ; ). Energy calcu·tations were undertaken using the same multi-reservoir computer prcgram discussed in Section 6.9.1. A detailed co:-nparison of tunnel Scheme 3 with the Devil Car.yon dam scheme is presented in Table 6.~. ·A comparison of the costs of the ~am scheme versus the tunnel scheme shows that the tunnel scheme is the more costl_y.~ However, the tunnel cost estimates are not as reliable as those associated with the dam schemes due to the lack of available geologic information on the tunnel and the inherent lo\'Jer accuracy associated with estimating tunnel costse A comparison of the potential environmental impacts associated v1ith the tunnel and the dam scheme revealed that the tunnel scheme should have the lesser effect. This is determined by the much smaller size of the second dam involved (245 feet versus over 600 feet), producing less flooding of river length and terrestrial habitat, as well as a lower> aesthetic impact (see Appendix I). The tunnel scheme may, in fact, improve anadromous fisheries between the re-regulation dam site and Portage Creek due to the regulation of flows. One negative environment aspect of the tunnel scheme is that of the disposal of tunnel muck. An increase: in costs of up to 1 percent may be required to dispe~e of the excavati.on material ·ln an environmentally acceptable manner. A comparison of the costs of the dam scheme versus the tunnel scheme shO\'lS that the tunnel scheme is the more costly. However, the tunnel cost estimates are not as reliable as those associated with the dam schemes due to the lack of avail able geologic information on the tunnel and the inherent lower accuracy associated with estimating tunnel costs. A comparison of the potential environmental impacts associated with the tunnel and the dam scheme revealed that the tunnel scheme should have the lesser effect. This is determined by the much smaller size of the second dam involved (245 feet vet~sus over 600 feet), producing less flooding of river length and terrestrial habitat, as well as C.l. lower aesthetic impact. The tunnel scheme may, in fact, improve anadromous fisheries between the re-regulation dam site and Portage Creek due to the regulation of flows. One tJegative environment aspect of the tunnel scheme is that of the disposal of tunnel muck. An increase in costs of up to 1 percent may be required to dispose of the excavation material in an environmentally acceptable manner. The preliminary assessment of the tunnel scheme indicates that it should not be ruled out as an ~lternative for hydroelectric development at this stage. It is, therefore, recommended that additional geologic and geotechnical work be done on the tunnel alternative over the next few years to firm the cost estimates and technical feasibility. I I .. ,.· .. ii (f. J) -. .. HEALY • .. CLIMATE ANn 0 CLIMATE STATION (I) SNOW ~OURSE • • ~ 1 I I I I I I I I I I I I I I I I I I ~ EXPLANATIOM Of MAP SYMBOLS· ----- ------------- At~Proxf•te c:onblct of surfic:tal dlposfts " __. ___ ,J)~------, ........ Fqlt , ~ dlmtcl t.t..re approx1•telJ Joeabd; ftart' aned illwre inf~; cl!tted lilhlr. c:ancNled. U 1adiates QIPthnl. side \ftnt 4frec:ttc. ef dfspla.::-t fs mo.. Arrows 1ndfcat. relatt~ lateral a~~. . " . ..........._.......,.... ___ "·········· Thrust f&lllt Long dashe4 .,.. APfi"'x1•b171iiCIItell; short tllsW whm! taffti'MMI. iiDtted *re COflallllld. Tath tnclltate IIIJtfti'OIIII stdl. -v--·--,-.. ~ ................ . Approx1•t.a axt;:\ of fntese shelr %11M of warfablc w1dtll, posstbl7 Drt1"1 a tllnBt faa1t Dotted lllheh COI'lc:M114; tacrtl! 111dfeate possible uptiii"'OII1 side of JIOStw11 .. tH thnlst. I. --....... ' . .• -_-:... . "'tfclt~te. -.thwtttt crnt H11e; -S,Y11Cl1n. sk:I:MRt ~ H• l.oftg f&sl*f *"-·~•telyloattod; arrow 1;;4fcates JlYifl. t.uc.t•• .r· sapl,w *'-' ~ u. 1J.s. lilolo;ieal 5wwt7 11$W"' ·u. 110tus1_.....,_ ""'·-"" 1N4-a1pha •UIOII. slaltrlllf •P tNifller, ffell .-.r . .,.. ·u. eala~l&..,lli~tm"al .,.¥ •t :-•1ottta. Jlt .,....,..,~. ~~u •• Act-ildtao"Hte. Zr-zf1"CUU, w • llilllole 1"'lCt;: ... .._ ~-.......... .... ... .. ,. ' "' .. "'~ El_., locatt~ of ~le dated b7 TU\'MI" elM! S.ltll (lt74) usfng f.• potasst .... j ·~ •thod. showing•p alllllbw. fteld itllllber, -~ the ealc.l~t.M • 111Mm1 .,. •• !It • 'tilt1ta •• -llof'ftblt1114r!, x4: . · fossU 1cx:a1tt,y in •its ••• Pls. MICI DSls. Str1!la ... 1111' .r· .... _.. T 111cu ... -r-~ J5 +-Ytlrttc:Al -.--J.ppmxi•'-• estt•W. fl'la i1au.tt ...... t1aes .2.0 · Strtb _, ltfp et fr-.et.e cleaw" r-r' 111!:11 ... • 10 .r+-' ~teal ,..--, IM:lt ... to 1--i ~\rttcal - i}" ----. ,:_ ..... l· ; . . ~-~ -,..--bcHW 30 -+-Yertfeal -.-lK11aM 3Cf ....._ lertic:Al -c-lad1MII 4(0 ..;.e-'l'ertic.a 1 --. R EfEJtENCI: ~ Cll".olttie I. fi.AL. lltECGMMl11AIItl IJEOLOitc JiWt ft SEOCM~ • TAUCE!TIH IIOWTAIR ~JAOftMILE, JIOUHEM PART·.OJ; MCHC~r; ~La& AJID .$0U1lt11Df ~NI:Jt Qlf HEALY (l~• A& t.SU. U.l •• ;l. OJ'l• Fli.Z M:PQIIr ?a•!IMA.fW'l.i. REGJONAL GEOLOGY ..... ------··; --.... --~------rrtllllllllllllliilii'····'~---···-·L\l -... : ;= - 0 6 12 SCALE IN" MILES NOTE~ ROCK UNITS ARE USTa) IN FIGURE FIGURE f, .. l_ if __ l_·lt .... , .•• LIIJJ ;1 ·-;-.......... ..........J !~ ll,o I~ I I I I I I I I I I! I & I I ' I i • I l I I, I, GEOLOGIC MAP OF WATANA ----F§ VC1.CANJCLASTJC SEDaENTS. a.axDNS TUFFAcEaJs Sl.l"S1t'H3 Me S8i:JS'ItN:S. ~ PORPK:lRrr!: ~IE. Nll·mrs NaSm: ~ BA.CAIT,. fW:fl'E. AND ~'lE ' .~<)· .. -..' DIGRITE. iNCl..ll)tNG OUfRlZ OOR'IJE Nl)· -··-·-~ 0 OUTCROP -r-S'TRIKE MD r:!eP OF BalC.lWS ---STii!IKE .ANI) DIP (F .JOINTS .~~·AM> FRAA':TURE ~SHOntG --c.tlN11Cr~ ~. NOTES: I) FIELD MAPPN; ~AT A S\CAS..E OF .a::s.oco (AERIAL~) 2)~~ARE~ FIGURE 6.3 t··:. I I I I I I I I I I I I I I I I I I - • ~·USGS. TALKEETNA MalWTAHS (D-5), AtASKA Ql~, SEWfiRO MERIDIAN: T32H, ~UE, S32 AK:J 33, . . "" . ' . \ • • tt •• • GEOLOGIC MAP OF DEVIL CANYON LEGEND ~ _MAJOR OUTCRCPS CF ARGILUTE UNT ...>-STRIKE AND DIPOFBEDS --STRIKE AND DIP a:-JOINTS ..P-STRIKE AND l)p OF OPEN .x:>ltns , ...... ;."' SHEAR AND FRACTURE ZONES NOTE~ I) GEOLOGIC 'MAPPING UNDER-mKEH AT THE St.:!U..E OF. l :24.000 (AERIAL PH010GRAPHS) 2) TOPOGRAPHIC CON10URS ARE AP~XIMATE ~ NlBMl ~ FEET ~ED C0NT0..R 25 F-Er . FIGURE 6.4 .., I ll l'j ......... . I l_/ '- ~~ II . C)C)C> 4 '6 I ~ I I I I I I I~= I . ~ ·~ I rEJ!/; I I I I I f77) PRES. E. NTLY IDENTtAED \LLJ AREA VJ.· PROPOSED Nf, ;v AREA .~ FOR lNVESTlGATION ·FIGURE. I I I I I I I I I I I Ra'"ERea: USGS, TAL.KEETNA ~ANS (p~s), Al.ASI<A OIJADRAH:;LE, SE\IWID MER!t)IA.~: T32N, RIE •. S32 AtiJ· 33. ISOPACH MAP OF OVERBURDEN- DEVIL CANYON LEGEND DATA POINTS • DRILL HOt.£ A SEISMIC LINE S'""~TJON ----DEPTH TO BEDROO! CONTOUR APPROXIMATE ·:~~£;~~ .MAJOR BEDROCK CLUICRO?S' NOTE: I} CONTOURS HAVE :BEEN AOJUS'rm . TO TOPOGRAPHY 2) TOP03RAPt£ ·.CCifiT()lRS .ARE APPROXIMATE ~~!iOR:ET DASHED COHTOUR .:25 .fEET FIGURE S .. 6 1111···· I I I I I I I· I I I I I I I I I I ·I REFE:RSCE• USGS. TAl.JCEETNA IOJNJAIEi CO-S). AlASKA CUADRAIG.£. .SEVIARf) MERIDIAN: T32.H. JUE. S3Z ANl 33. DEVIL. CANYON LOCATION EXPLORATION MAP LEGEND • DH BOREHOI..ES-BUBEAU OFR~noN 1960 • BH BOREHOLES-SUMlr.ER 1990 PROGRAM • TPaS, TEST PITS AND "tRENCHES " BUREAU OF REct..AMATlON" t9SO a AUGER HOLES-SOMMER t9SQ, PR'~ SW SEISMIC UNES.- I CORP OF ENGINEERS. 1978 SL SElSMIC LINES- . 1 SUMMER 1980 PROGRAM & DCJ LOCATION OFJOUIT MEASUREMENT t J CROSS SECTiON NOTE: TCf'OGRAPt£ CCJtlTOt.RS ARE APPRCOOWAYE SECTION SHOWN. ON Flt3URE --~~~ SCAt.£ IN (TE!:T CDI'll'tllR ·lfTER'AL 50 .fEET M.SH~ CbH'ra..R 25 FEET FIGURE fiil I I I II I I I I I I I· I I I I I I I PREPARED BY: WOODWARD-CLYDE CONSULTANTS LEGEND ~u -..:---D __ __.._..._, y' •• 150<? Mapped stri~~ -slip fault With dip slip campo, ~;: 1t Mapped st• :~e..:~:Jip fault~ ariows show t ;; of displacement Mappeo fault, sense of displacement not defined Inferred strike--slip fault Mapped thrust fault. teeth indicate upthrown side of block, dashed \Vhere inferred Mapped thrust fault. teeth indicate inferred upthrown side of bloek ---·-===========::::=======::::::::::::::::::~~ ·-· -·--. -·-· ---· .... -~ ._,..,.,.;:...:..... ,..., 146° RANGE .MOUNTAINS NOTES <D 0.9-2.0 cm/yr Hickman an·d Campbell. (1973}; and Page, (1972). 0.5-0.6 cm/yr Stout and others,, (1973}. ~ <3> @ av <ID (}) ® (9) 10. tt. 12. 3.5 cm/yr Richter and Matson, (1971}. 1.1 cm/yr, no Holocene activity farther east, Richter and Matson, ( 1971). 0.9 -3.3 cm/yr Richter and Matson, (1971} tnfeired connection with Dalton Fault; PI afker and others~ (1978)~ Inferred connection with Fairweather Fault; Lahr and Plafker. (1980). Connection inferred for this report. 0.1 -1.0 cm/yr Detterman and others (1974}. Slip rates cited in notes (1) through ® are Holocene slip rates. All fault locations<and sense of movement obtained from Beikman. ( 1978). Figure 5-2 presents Section A-A'. 0 I ' ' '-.,;;,...;,...· .. -. ' ' 1 13s0 TALKEETNA TERRAIN MODEL 25 50 100 Miles T I I ., 3 0 25 50 1.00 Kilometers FIGURE 6. 'fer. ... ,, I I I I I I I I I I I -I I I I I I I INFORMATION • AND FIELD RECONNAISS.ANCE ENG!" '::ERING LAYOUT AND COST STUDIES POWER AND ENERGY SIMULATION L 2. 3. 4. . .PLANNING SITE SELECTION PRELIMINARY SCREENING FINAL SCREENING REFINEMENT OF SUSITNA BASIN DEVELDPMENT OPTIONS f • ·.PRODUCTS SITES ·THAT WARRANT STUDY DEVELOPMENT PLANS REQUIRING INPUT TC GENERATION PLI~NNING STUDIES SCtfEMATIC REPRESENTATION OF PROCESS USED TO SELECT SUSITNA BASIN DEVELOPMENT OPTIONS FIGURE 6.9 w -.. -·~ l' 1 ---- N ~ TALKE£T~ 2927 . StftLE; 0 10__ lO lt:::-:o::-.-==~=-· .,..::-~ ~ILES . ---- --· -- - CANTWEll 2915 -- NAME: $. 'LOCATION 'VF US;~ :.GAGINU STAll~ SUSITNA HYDROELECTRIC PROJECT DESIGN OEVElDPMENl l~OCATION OF JJAMSITES PROPOSED BY OTHER$, .. -HSURE-{r.~.. I --~~~~~~~~~~~~~~.·! . - __, __ _ PORTAGE CR. ... lOO .,..,~ ~ . . . ..-. Jill .. -·~--. -·------ .. I . I -·H <t z !:: en :l (/) - i20 I 140 I cr 0 Cl) ...J > l!.l 0 1750 1 RIV.ER MILES_..., I <t 2 <t ~ ~ /'( OSHETNA R1VER 1'3ooo' ~----f..--' 25001 .------' 2000 1 ' . .-----A----. ,_.,1-c · B--- REACHES ~ NOTE~ Figure to be changed to incorporate only dam deights previously studied. : oo ru::· t t r.-__________________ .............. ~~ . . --···-- .. ---.. .... ___________ _ .A GOLD CREEK OLSON OEVlL CA~rtON HIGH DEVIL CANYO.N DEVIL CREEK WATANA SlJSITNA :m VEE OLSON LEGEND COMPATIBLE ALTERNATIVES D DAM !N COLUMN 1$ MU ~ ~,.:.tLLY EXCLUSIVE IF FULL M::·::~:;_-_·:~:_-'_-_ .. ):i:~;r:f:]_ SUPPLY LEV~L tN DAM lN ROW EXCEEDS THIS VALUE·r'T. l ··~········t··· . -;c-...... ):~~l\~~!\!i~:~~\\1\\~j~\ . .i\ll VALUE IN BRAC¥-:ET REFERS TO APPROXIMATE DAM HEI_GHT. ~ ........ ::1 I MACLAREN MACLAREN DENALI TYONE fvlurlJALl_Y EXCLUSIVE DEVELOPMENT ALTERNATIVES BUTTE: CREEK - FIGURE 6.8-_______________ , ____________ --~·-......;,.-.---·---.--·;.:··--__________ ...,, __ • ___ ,<\;,:,_ • .,. ___ _ ----... r TYONE r:;---J t~llnlmmlt· Iii m ·l •. )~ I I I I I I I I I I I I I I I I I I I' ........ -(j) Q - .,:. ..... tDo )C .. ..... U) 0 (..) 200 400 600 800 :ooo REsERVOIR STORAGE ( 103;( A F ) DEVIL CANYO!i 1000 ~00 LEGEND • COST DEVELOPED DlRECTLY FROM ENGINEERING LAYOUTS COST BASED ON AOJUsrMENTS TO O VALUES DETERMINED FROM LAYOUTS I ..., 1200 OL-----~------~------~-------~~·-0 1000 2000 3000 4000 RESERVOIR STORAGE ( 103 x A F) HIGH DEVIL CANYON DAMSITE COST \(S RESERVOIR ST 10RAGE CURVES:. [iJ FIGURE 6 • 2400 2000 r.D Q 1600 X .... t-en 0 u LEGEND e COST DEVELOPED DIRECTD' FROM ENGINEERING LAYOUTS COST BASED ON ADJUSTMENTS TO 0 VALUES DETERMINED FROM LAYOUTS o ....... _~...:--I I . L._, --l)P~ 0 2000 4000 6000 8000 !0000 12000 J400v RESERVOIR STOR:4$E ( to3x A F) WATANA 1500 1000 -tao )C .. -I ln 8 ooo J r I 0 -.,_,--~.....-.. __ ...,~, ___ 1 __ -...,~._! _.,.,. e 1000 zooo ~ooo 4000 RE!;ERVOIR STORAGE ( to3 ~ A F) SUSITNA .D! i~ OAMSITE COST 'VS RESERVO~R STORAGE CURVES [iJ . . ·~ I I I I I I I I I I I I I I I I I I· I 1000 800 ub GOO ·JC ;w 800 600 ~ X ~ -400 ,_ ·f/) 0 (.) LEGEND· • COST OEVELOFt!D DIRECTLY FROM ENGINEERING LAYOUTS COST BASED 00 ADJUSTMENTS TO 0 VALUES DETERMINED FROM LAYOUT'S 200 400 600 800 1000 1200 1400 RESERVOIR STORAGE { JQ3x A F) VEE 0 -..... o zoo 4oc soo aoo 1000 1200 1400 RESERVOIR STORAGE ( l03x AF) MAC LAREN - 200 1000 zooo 3000 4000 RESERVOIR STORAGE CI0 3 xAF} 5000 DENALI t ___ --....--DA--M""'"""'S-IT_E_C~O-ST-· · _v_s_R_E_S.,.._ER_ .. V-O-IR_.S_T""""""!"O=U-~-V-Es_· __ ··......;;ri;;;;;;;;l;;;;;;.j];;;.,i 0 .· ()) 0 X en=- 1- (f) 0 () ~ <( l-. ·0 -···------ "3.0 3A 3b, .. ... Jl I .. • • 2.0 , . 1.0 -r-----t------t-1 -· ----i------+----ii------+-1 ----·--· --+---- 0 1000 2000 3000. 4000 5000 6000 7000 . . •. ANNUAL ENERGY -10~ KWH. Ft6 ·? . .ff/~----- .~__:_----~·--. •• ... k.tl i ..... • • ~ ~ i.,. .... ---t: ~ ... : i • e ... _ ., a ... - ---·- ~~--··--~ ___ ,_ f'O.vE~ TUNNfL INTAKE SE-CTION '!><.All A. SPillWAY PROFllE ........ ~ .. ··- I l -.,.c•t..L.A f • \ ........... TYPtCAl -~-. -·- 5 .. l I -----·- ........... ,~ -. ---.......__ ---... ~ -....... DE.TAIL !i --· --- I ·: ----·~ ..... ~-.. ._ . --.. ---·~ . --......... DEVIL Cf,NYON POWER FACILITIES PROFILE sc.•&.••" @!! QQ.. .. i'~'$. l.C.WJ~~· '~t.C) £J~t'N '!lf1LL tllf»C ... "' CO. ~;;to.l.r.. 11.:1(; ... '!.n>tOIII~ ·. •. ·. \ \ . \ \ n ll ~ J • --······-- •tooo ·--· ---···--~·· <o • ···~ _./' f ... ___ _,__" \ ~· ·---.. .. . .,..,.~~ I ... _____ _ ..__ ___ , ~--------· •, . . . ~- PL'"N '•c:g ..... -· .................. .. .•'"" - ... ... . " . ) r GENERAL AQR4~G£M~~T OEYlt fAliyQN _A?Yli£.~~U5~ -~-\ . " :.onrGI. ,,....._ ,(c-&~JL C.:...'f004 l't>wi"-MOVU . ., ~no. I \ "' j _,.., Jl>dooa. ...-POW& <t YU-41..~ . ' _.c;o"o•a. ""# ·~~-~ .. ~ .... -' I .aq ~~ ... --,-~~:~ '· . " ' ' ,, (Jl ·'f'' : ~ ·"r' ·--~-,. 5-~ r;;•.i ·o .:';) ", ,___, .. '" ') ~;::~. _, .. 0,, '·('_ ( .. ,.·o ;·;') 0 . . ~;' [_~ (.,-Of c:· .-·,-. : ~ ~,->~~--'-. :• >:t" '-~; ___ , __ ,,.,-..,..._{ c' " ·-:_,_i ~-~ ._..._., ____ } 'I -. , .. ---- ~- ~-) 0 ,, I H ,, I I - i' ·- •' '( ~} ,., 0 '· : t~ --::7::. I .._, ~- --~) / j ' ·.; ,.. ~ I - ·' \ I ' ', ;,;::::;:. I ; ~;:_-;( !;==-. I' ; ... _ ,;. c . ~ ';_ n I _.'<! ._ ·,, ,.. . .., \...:~ 'o -;;- I fi ... -~ I I_; (\ \ l .. C\ ;J: I 0 Ji ;; '·' •'';:: I ;:.-:;l ,, '\ ,-'-· ~~ ' ' i ~"- •,' ~- I ., ..... - -~·--"-1,; ; ;,' ',{ ( .. ' '' ~-· ,-,_ ·u I 0 -;l --:.:::--" :• .... ; ';· '.~ ' ... I ;;.-::, ;. ~:'. {\ r !I .. : •,. .. \' . . I " (i ., .. : ._. •i' '~ ;J -·Ci.: /.1'\ <') '· l,J ., /: <~~ -::~ {J ::-" •, 0 l .- .•. .1 : .D Q ' .:..' '' !;. -~-- !J ( ·,, -f.: .:::) c, -.. ~ ~~ -,.'> ~~ '".;···, ':':; f,.\ 11 ·--~· ... . \\ ~ 0 ~~ ~.::- 1\ ;,~ '• •' \:J •-' ·~ .::-' !!. ·" ,:· : !! l) 'l;,c::..::=:..~-;:;:--=. ·''\:;,, -~-'0 i) '<'t :: ~' . .,Q, .. .,.:,' '.·,. u, -~-~ . .. ·:-, ;~-;-~."' .i ' ~--·. --- - •• ----------- TABLE 6.1 TYPICAL NOAA CLI~~TE DATA RECORD (Source: Ref. ) Meteorological Data For The Current Year Station: SUIIIIlT 1 AUSKA SUHKIT AlkPORT Srancl.ad tlma U..O: ALASKA It ulltuda: U • 20' H longhude: 149" 01 ' V Elavatlon !ground): 2191 N-It Yel(: l~ ----.-~·~2~·~41~·~----------~--·-----r--------r----------------------------~------------~--------------------~~-r--~--------------------------------------------·~· Preciphatlon In inchn !Wiatlve Wind .g Number ol days t · :;..ft!fiOgl! o~~· r---·-----------.r-----------~~-roo-~~~--·~,---4---------~----------~ ~----------~--~--~--~--~----------~--~,,~.~ Bo• 65 "F ..!! i "" Temperature·~ T>~re Watrr equwat.nt Snow, Ice ~)'!IItts Rnultant Fastasl mitt .c ~· Sunrla to 11.1...-1 .. 1------..:..:..:::r.:-..;_..,---,.,r flib ~ ~ } ,! 1---r--1 l . 1---.----.----1} § i 1--.....-~---1 ~ j !: E ~ Mlllim\111\ Minim~ [' , :f :f :f ->~ c ~ lE ;s ~ 1! lbl . ~,,=,e;;--- T emperatun: •f Monthr----r----r---~--T---~~---4----~--~----~--~----+----T--~--~ 0~·~ l:J ~ ~ i .I { s i~ ii Oi o~ 14 u i t1 ~~ § i! ~~ >~ 1 1~-~ !~ \ {i ~s ~-.!! ~.!1 1~!\ !o' E ;; ·f ~ ~ 15 .J ~ •• u {! d ~ ~ ] ~ ~ ! I local tlnul i5 1 t l c ~ c ! ! l! 1 l i A l ~ D t Sl-;! :>' ar; 'i r; r; b !\:;' 'ttl.'-I. ----;---~----4---~--~--~--~--~---+---+-----+----~--~----~--~--~--+--.r---+---4---4--4~--r---~--+---~~~o~.~~~--·4---~~~~~--~--~~~~---6;1 ,: n n u n Jo 11.0 u ,.. to u 7 o z o u :n z0;\, Jii.H FU lUI\ A fOil. IIJY JUII, Jl'il. AIJG SEP oeT 9,0 _, •• 4.2 -to.• u.~ z.z lt..) l4.5 .,... ~··' 60,6 40.1 2.6 -3.1 10.2 u.• )6.5 !Ool n.t n.J 40.1 34 JO ]l ' JO 6 Sl 10 '~ 2 14 27 16 ~J 'tl 2 59 14 •26 ' ~21 ll -14 15 -l 15. 1l 1 14 • H 6 ll 29 16 30 1Ul U1~ 1696 1U() 171 to20 )61 lll ''111 0 0 0 0 0 0 0 Q 0 2.11 t.ll loU o.H z.u o.n 1.05 o.t6 1.!9 lo1!1 ·o.5o o.u o.oo 1.90 o.Jo o.n 0.20 0,48 18-19 " ,_, 26 I 30 23 7 9 o.o o.o o.o o.o o.4 o.l 1o '! tt5 65 n u 01 21 J.9 11 4 a 1 6 o (I o n 2t ~..;.;, I 15 n , 01 n 1.o 4 4 u 11 • o o o n u 1'-'!t 91 20 oa u t..z s a 14 , z o o o 1 10 ~'i " n 14 u 1 1.5 s 6 zo 1 ,. o o o o n ~·, 69 U U ll ••• 6 I 16 ~ 0 : 0 0 1 0 0 (t;' 1 :A ~~ ~! 2~ •·, , 1 21 ~; ~ o 1 ~ g ~ ~\! 76 u u ,, ,~· J • u u 0 0 2 0 0 17 J.bil zo 01 u !l vu• H l! - £ 6 :i 1•1 . f " A II J .I A s 0 H D n H H u Normals, Means, And Extremes -ntROUiill 19751 < T MIPI"turll "f l'reclpitatlotl In lnehn RtiAtlva Wind Mun numbtr of days Ncmnol hlmldl~~ ! t. -~ Dl9fH daya -tbtlon 1 Horll'lll f!xtrtmn e-ss "F Water oqulv&lfl'll Snow, leo! pelltll Frmnt mlloa ~ .. Survl• to,....,..,, f ~ j R ~ Temper11um ·•f: ~ & ~ l I • 7.i Mall Min. . mb.. I!t ·~b;~ $ E E .l-~~ E> ~i E> ,...{ i·l !' .~ ~-£ 11 11 l ii ~~ Eow _ii I l :r j ~ 3 l~ l ~ il ~i . I 15 ~~ cr.c )-> z )-· 15 l5 3S 35 JS ,~ 7.9 -~·· 1-.1 u ·~s f-•" 1911 1965 0 o.n loU 1941 o.ot l9U o.ao 19H u,a tl.i ... , 6.6 .. , 942 r-~s 1947 1615 0 l.H 4.31 951 T 195"0 2.19 1951 44",5 19.4 leO 11.2 4'i 961 foolS 1911 1661 0 .!~04 ... 53 9411 o,ol 1961 loU l'l4' 59"1 Hot 14·1 2),5 57 ""'"' 30 1944 lZH 0 0,67 "·" 96o o.o6 1944 Ou97 1961 u:1 45.1 Zt•l n.~ 76 '60 14 1945 U6 0 o.n 1.66 966 o.o11 1949 o.t6 1946 17.4 u.o ,.., u.o 19 961 25 19H IiilO 0 Z.1.,4.H ""' o • .u tuz z.~t 1967 9oill - 60.1 u.a !i.O 11 p. 9111 J2 1970 ftC) 0 3.09 '·'8 9!19 loll "" 1.95 l9U 917 56.0 4ht .... 11 96l 20 \95S 50& 0 1.30 6.a;l 'i~S 0,70 ltH 2.10 1944 t,o 47ol n.t. "·' .,, ,.,., 6 1956 'l'l 0 1.1\ 6.\3 1965 0,29 1969 Z.Ol 1944 21,5 10.4 n., u.o 59 •n l-15 975 1171 0 1.6;! J.H 1952 o.u 1967 1.24 196) ,. .. t.7 ~-962 f-29 1.9C.il 1659 0 lo!l 4.15 952 o.o6 l~U 1.10 1964 '75.1 U.ll>-1 t.z o)o4 z.t 42 9U 41 l'J61 l192j 0 1.~0 ... , 951 ~.24 1945 1.09 19&1 so.7 2~~, l .. UN ~ltl j&UG IFn FU n.o u.o 9iit l-45 1911 4361 0 zo.o~ •• '74 ~944 T uo 2.79 1951 15,\ (i} lenQth of neon:l, yurs, tltrough th!! rurrer.t }'elr 111\len othe.-..fse noted, butd on Januotey dab. (b) 70' and t!lov.e at Aluhn 5hllen5. • leu tlltn oni half. T Tract. IIORtW.$ -llued on record for the 1941·1970 period. DATE OF Nl EXTRE!!E -lhe 1110st recent in cases; of mltlple occurrence. PRE.VAIUitG liiiiD· DIRECTIOII -Record tl!rougll 1963. WI liD DtR£CT10!4 -·IILJ~~erals lnd1t~te tens of deg~es c:locbhe. frban true north. 00 tndtcatu cal•. fASTEST MIL£ WIIIO-SptM Is fastest ob5l!rvtd 1-•lnule valui wher. the direction b f!l tens of degrees. • ii 7i J ~ e X X ~~ l lbl l:IH. ii !'g j ~-: :! ji~iill!I~ _o i& 02 oa 14 20 li l1 j o I! 1& ~~ ~05 -·-ct • j~ • J! .;! :i.!i (local dmel ,.,.-1:11 , I )-0 )-..,.! tn.Ll. I 15 ' 7 1 6 a $ , 1 l ., 7 7 20 • 1\ •• )4 llo u l\ 2 1'1111 U,l 1973 61 u 69 61 H.1 liE "" 0' 196t s.z l) ' u • 4 0 • 0 lO ll tti 9Uo4 1951 u.o 1'64 16 1!1 75 16 11,9 H£ lo6 01 1974 7.0 6 ' :1 10 • ' 0 l 0 16 u u tu,a 1946 11.1 1941 '16 '1'6 l·l n 11~1 HE 41 10 Ull 6o1 9 6 ill 10 ll 0 ' 0 Zl n \' 917o2 19'70 9ol ltU eo 15t6511' 7,6 HE :n 01 lfll 7.2 ' 7 u 1 4 0 1 0 n 10 l 9U,t lUI "·' lf46 u 71{5e 67 1~7 II 21 01 1'f69 "·' ) 9 1.9 ., z • 1 • 1 22 • 9Uol 1974 1.7 ltl-\ u 7) 'J1 lc~ w.l 5W 21 22 U7o a.z z. 6 22 12 1. z 1 3 0 2 (I n.;.l ti 1970 tel 1'70 Ill 71 ~~ 72 7.1 sw 30 n l.H4 e.z z 1 \6 • 2 1 ' 0 • \) U9.1 l95' 6,0 1'55 •• ,11 6il 76 "·' Sll n 22 1975 1.3 2 6 u 11 0 • 1 1 0 2 0 no.J 1951 14o0 1955 :r !19 75 7~5 HE u u un ;., 5 5 20 l$ 2 • 1 • 1 14 0 924.1 1910 U,6 19"/0 76 81 1.0 tiE ,, n 1970 1.6 5 ' H n 7 0 2 0 u )0 I 'H6,l 1967 "1.9 ltlD " .,, 71 19 n.J HE )9 u 1970 lol 7 • l'i 9 ' 0 l 0 Zl JO n tu.:a tnn Uo4 lt70 16 71 76 17 u-.t HE J 44 11 1970 ~., 9 ' 11 \1 6 c. l 0 )0 ll lt tl4.l HOV 1 Fll Klk 1967 u.o 196.4 11 16 67 n 9~? liE ... \0 1!71 l.z 68 10 221 Ul 41 ' 1Z ' 173 25\ Ill 922.0 NOTE: Due to leu tban full time operation m a variable echedutl!, manually ~ecorded eleme•~t• 111:e from broken aequcmce1 in incolllplete record.. Dally temperature e11tremea t.."ld pr.,clpltf.Uon totah for pardon• of the recon uy be for other than a calendar dajl. The period o 1 ncord for eome elementa ta for othQr than conaecutlve yeara. $ For calendar cay prior to 1968. @ For the period 1950·195f.--11d JanUI.ry 1968 to «Ute wen ·available for full year. For the period 1941•1953 atld January 1~'68 to date llhen avalbble for full ,year. I [li.ou for thb atation tit~t. avallable for arehlvlng nor· ..,.,..'-tl.fii-""" .. _.,..._ .,.,f! ...... -.......... , r.r •«: ""' , .,.,.. .. .,.. r------~------~-~---~ TABLE 6.2 -Summary of Climatological Data -MEAN MONTHLY PRECIPITATION IN INCHES STATION JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV > ~-DEC 'kl\'NNUAL ) . Anchorage 0.84 0.56 0.56 0.56 0.5~ 1.07 2.07 2.32 2.37 1.43 1_.,02 1.07 ' Big Delta 0.36 0.27 0.33 Oe3l 0.94 2.20 2.49 1.92 1.23 0.56 0.41 0.42 ;_1!1 .• 44 Fairbanks 0.60 0.53 0.48 0.33 0.65 1.42 1.90 2.19 1.08 0.73 0.66 O.bb · _J!l.~Z Gulkana Q.58 0 .. 47 Oe34 0.22 0.63 1.34 1.84 1.5'3 1.72 0.88 0.75 0.76 ~ .U.l.11 Matanuska Agr. .. EXQ. Station 0.79 0.63 0.52 0.62 0.75 1.61 2.40 2.62 2.31 L.39 0.93 0.93 l1.5. 49 McKinley Park 0.68 0.61 . 0.60 0.38 0.82 2.51 , 3.25 2.48 1.~. O'l42 0 .. 90 0.96 .Q:S.~4 - Summit WSO 0.89 1.19 0 .. 86 0.72 0.60 2.18 2.97 3.09 2.56 1.57 1.29 1.11 _lt9.03 Talkeetna . I 1.63 lo79 1.54 1.12 1~46 2.1] 3.48 4o89 4~52 2.54 1.79 1.71 ~~.64 ~ MEAN MONTHLY TEMPERATURES --~ Anchorage 11.8 17.8 23.7 35.3 46.2 54.6 57.9 55.9 48.1 34.8 21 .. 1 13.0 : Big Delta 4 a 4.3 12.3 29.4 46.3 57.1 59.4 54.8 43.6 ~5.2 6.9 -4.2 ~ 4?.f! ... " 5 -OJ Fairbanks -11.9 -2. 5 c• 9.5 28.9 47.3 59.0 60.7 55.4 44.4 25.2 2.8. -10.4. IZS 1 . . • I Gulkana -7.3 3.9 14.5 30.2 4;i.8 54.2 56.9 53.2 43.6 26.8 6.1 -5.1 -~45-8 ~ Matanuska Agr. E'~P· Station 9.9 17.8 23.6 36.2 46,8 54.8 57.8 55.3 47.6 33.8 20.3 12.5 34.7 McK i n 1 e.Y. Park -2.7 4.8 11.5 26. 11,. 40.8 51.5 54.2 50.2 40.8 23.0 8.9 -0.10 .s~.~s Summit WSO -0.6 5.5 9.7 23.5 37.5 u 48.7 52.1 48.7 :-iY.b Z3.U 9.8 3.U '.~~-J! Talkeetna 9.4 15.3 20.0 :.12.6 44.7 55.0 57.9 54.6 46.1 32.1 17 .. 5" Y.U .. -~~.~ .•. Source: ~eference -- TABLE 6.3 -Recorded Air Temperatur~s at Talkeetna and Summit in oF Talkeetna Summit Daily Daily Monthly Daily Daily Monthly Month Max. Min. Averag~ Max. Min. flverage I Jan 19.1 -0.4 9.4 5.7 -6.8 -0.6 I Feb 25 .. 8 4.7 15.3 12.5 -lo4 5.5 Mar 32.8 7.1 20 .. 0 18.0 1.3 9.7 I Apr 44.0 21.2 32.6 32.5 14.4 23.5 May , 56ol 33.2 44.7 45.6 29.3 37~5 I June 65.7 44.3 55.0 52.4 39.8 48.7 I Jul 67o5 48.2 57.9 60.2 43.4 52.1 Aug 64.1 45.0 54.6 56.0 41.2 48.7 I Sept 55.6 36.6 46,1 46.9 32.2 39.6 Oct 40.6 23.6 32.1 29.4 16.5 23.0 I NOV 26.1 8.8 17 .. 5 15.6 4.0 9.8 I Dec 18.0 -0.1 9.0 9.2 -3.3 3.0 I Annual Average 32.8 ,25.0 I I I 1 I "' I I I I I I I I I I 1- ·- I I I I I I I •• TABLE 6.4-Maximum Recorded Ice Thickness on the Susitna River Location Sus itna River at Gold Creek Susitna River at Cantwell Talkeetna River at Talkeetna Chui itna River at Talkeetna Maclaren River at Paxson Maximum Ice Thickness in Feet --- t; .., ·.-• I 5.3 3.3 5.3 5~2 ---.. -.. --------------· TABLE 6.5 -Streamflow Summary Maximum In stan-Minimum Instan- Drainage Average Annual taneous Stream-taneous Stream- Gage Areo.-mile2 Streamflow -cfs flow -cfs Date flow -cfs Date .. Maclaren River necr· Paxson 280 976 9,260 8-11-71 l'tQ .3-1-65 Susitna River near Denali 950 2,695 38,200 8-10-71 :34 3-l-5-59 Sus itna River near Cantwell 4,140 6,295 55,000 8-10-71 400 3-16-64 Susitna River near Gold Creek 6,160 9,288 90,700 6-7-64 600 2-18-50 I I I. I I I •• I I I I I I I I I I 'I 0 MONTH JANUARY fEBRUARY MARCH· APRIL MAY JUNE JULY AUGUST SEPTEMBER OCTOBER NOVEMBER DECEMBER TABLE 6. 6 -Month·ly Percent of Annual Dischar-ge and t4ean .Mon~hly Discharge at Susitna River Stations_ STATiu~~, Susitna River Susitna River Susitna River Maclaren River at Goid Creek Near Canttt-~e 11 Near Denali Near Paxson % Mean(cfs) % Mean(cfs) % Mean(cfs) . % Mean(cfs) 1 1,438 1 824 1 245 1 90 - 1 1,213 1 722 1 204 1 78 1 1,085 1 692 1 187 1 71 1 1,339 I 853 1 233 , 82 J. 12 13,400 10 7~701 6 2,063 7 845 24 28,150 26 19,330 23 7,431 25 2,926 21 23,990 23 16,890 29 9,428 27 3,171 19 21,950 2U 145)660 24· 7,.813 22 2,557 12 13,770 10 7,800 10 3,343 10 1,184 5 5,580 4 3,033 3 1,138 3 407 2 2,435 2 1,449 '"' 502 1 168 "' 2 1,748 1 998 1 318 1 111 ~-~----~----------~ TABLE 6.7 -Flood Peaks at Selected Locations on the Susitna River Flood Peak cfs PMF** Drainage Mean Summer Spring location Area-rnile2 Annual I :100 yr 1:10,000 yr (Au9) . (June) ___ Gold Creek Gage 6,160 53,000 118,000 185,000 232,000 236,000 Devil Canyon 5,810 50,000 103,000 175,000~. 223,000* 226,000* Dam Site Watana Dam Site 5,180 44,600 91,000 155,000 213,000 233,000 ·Cantwell Gage . 4,140 33,700 68,000 118,000 94,000 156,000 Denali Dam Site 950 17,800 43,600 63,000 60,800 61,700 * Incorporating attenuation by the watana Dam. ** COE estimates for Watana and Gold Creek; others were interpolated based on drainage bas ·1 n area .. TABLE 6.8 -_Suspended Seljiment Transport (Sources: Ref._) Station Susitna at Gold CV'eek Sus·itna near Cantwell Susitna near Denali Maclaren near Paxson Sediment Transport (Tons/year) 8,734,000 5,129,000 5,243,000 614,000 Initial Unit Weight jLb/ft3 ) 65.3 70.6· 70.4 68e6 ,7 ---------_______ ,_ TABLE 6.10 -Pctential Hydroelectric Development .... Capital Average l:.conomlc~ Dam Insta1led J\nnual Cost of Si'ource Proposed Helght Up~~:ream . Cost Capacity Energy l:Jergy .of Site Type Ft. Regulation 4 X 10 6 (M~l) Gwh $/1000 kWh !Data •. Gold Creek Fill 190 Yes 900 260 13140 41.9 U.5mR 1953 Olson (Susitna II) Concrete 160 Yes 500 200 915 34.6 USlB'R 1953 KJW!SER 1974 1 CfllE 19~1 5 I De~il Canyon Concrete . 660 No 800 250 1,415 : 30.6 Tllniis Study Yes 1,000 600 1'\ 0""~0 19.0 1\ c.,Jt· High Devil Canyon No 1,530 ' 800 3,615 24.6 " I · (Susitna I) Fi 11 330 Yes I 1,530 800 3,615 24.6 II ·~ Devi 1 Creek Fi 11 830 No ----- ~J":ttana Fi 11 860 No 1~.860 800 3,250 31.4 " Susitna I II Fi 11 665 No 1,500 350 1:~730 46.3 II ·I Vee Fi 11 650 No 1,060 400 1,32( 37.7 " Maclaren Fill 50 No 500 10 45 550.0 II Dena.l i fi 11 200 No 500 70 370 68a1 II· = Butte Cret:k Fi 11 Appro.x No ----USSR 1953 100 T_yone Fi 11 35 No -,_ -... USBR 1953 " 0 *Includei AFDC, Insurance and Amortization~ and Operation & Maintenance Costs. ' -- - - - - - - - - - - --·-- TABLE 6.11 -Cost Comparisons ~--~--------------~;-------~------~--------r~~~~Tr~~~~~nrr~----------------·~ Ca_Qital Cost Estimates 11980 11 Site Gold Creek Olson (Susitna II) Dev·il Canyon Dam Type Fill Concrete Concrete High Devi 1 Canyon Fi 11 {Susi tna I) Devil Creek, ~~atana l Susitna · Vee J Dena 1 i I I II *Dependable Capacity Fill Fi 11 Fill Fill Fill Fill Acres 1980 ··----r-----~---:O~t-.h._er-s~----------------4 Capital Cost Installed Capital Cost Installed C~aci t_y -MW 600 800 - 800 350 400 10 70 $ X 10 6 Capacity -MW $ x 10 6 Source . .;and Date of' Ri)~ta - 1~000 1,500 - 1,860 1,500 1,060 50\1 5.oo 260 200 776 700 - 792 445 300* - None 900 600 USBR 19~ USBR l9'S3 KAISER 1!{74 COE l9Ja:S 914 . -GOE 19'1~ 1,846 COE l91S -- 1,961 COE 1978 . -- -- ----: 496 COE 1975 I I I I I -' I I I I •• I I ..,. TABLE 6.12 -Environmental Ranking of Sites \ iver Section Gold Creek Olson (Susitnt.. II) Devil Canyon Devil Canyon ~Susitna I) Devil Creek Watana Susitna III Vee Maclaren Denali Butte Creek Tyone Degree of impact: Biolosical Social F fsh W 11 d 1 if e Local Reg. 'nstitutional M M L L L L L-M L-M L-tJl l L L M M L X M M L X L M-H M-H M M M-H M-H M M M-H M M M-H M-H L-M M M-H M-H M-H M-H M-H M-H M M-H M-H M L-~~ M-H M-H M M M-H M-H L-M L-~1 M M-H L-M H M-H L -Potential for Low Impact M -Potential for Moderate Impact H -Potential for High Impact X -Potentially Unacceptable " Overall M-\-\ M-11 M M M M M-H M-H ~1 M M M~H I I I I I I I I I I GENERAL CONDITIONS 1. Dam Type 2.. U/S Slope 3. 0/S Slope 4. General Foundation Conditions 5. Required Foundation Excavation (in addition to overburden) 6. Requir·ed Foundation Treatment & Grouting 7,. 8. 9. Seismic Considerations (MCE = Maximum Credible Earthquake) '?owerhous·e Location Permafrost / . · L.-.,b~i:5 _ T"'B' F ~~ •• '"\ !..- GEOTECHNICAL DESIGN CONSIDERATIONS DENALI -- Earth-Rockfill 4:1 (H/V) 4:1 All structures would have soil foundations. Depth to bedrock is believed to be 200'+. Inter- stratit~ed till and alluvium foundation material, local liquefaction potential. 40 1 + alluvium in valley. · r, Abutment Channel Total Excavation Depth Core Shell 30 I 10 I 70 I 501 Assume core-grout in five rows of holes to 70% of head I!!P to a maxi- mum of 300 • • Pro ba b-1 e drain curtain or drain blanket under downstream shell. Foundation surfa~e -no specia 1 treatment. High exposure., no known site faults. MCE ~ Richter 8.5 @ 40 miles. Underground powerhouse unsuitable. MACLAREN Earth-Rockfill 4:1 4:1 Assume soil foundations. Depth to bedrock estimated at zoo·~ Compressible, permeable and liquefiable zones probably exist. Unknown. Assume same as for Denali. Assume same as for Denali. High exposure~ no known site faults. MCE = 8.5 @ 40 miles. Un~erground powerhouse unsuitable Probably> 100'. 110. Construction Material Availability > 100' deep in abutments, probable lenses under river. No borrow areas identified. Assume suitable materials are available within a five-mile radius. Pr-ocf'!S- sihg of impervious material will be required. Assume same as'for Denali. I I I Remarks Based on Kachadoorian 5 1959. NOTE: No report on site. Parameters based on regiona 1 geo 1 ogy. l) Actua 1 estimates on. \>Jatana & Devil Canyon have been taken from overburden contour maps. 2) Data compiled prior to January 1, 1981. Estimates made after this date have used updated excavation criteria. VEE Earth:-Rockfill 2.25:1 ?·" "-• I River alluvium 1251 , drift 0r-talus on abutments is 10~40' thick. Saddle dam located on deep Dermafrost alluvium. . . Assume: Core -R,;move average of 50' of rock Shell -Remove top 10 1 of rock Assume <::routing same as for Watana. No special treatmen-t under-shell. Assume extensive sand drains ir> saddle darn permafrost area. H.igh exposure, no knm'ln site faults. .MCE = 8.5 @ 40 miles. ' Unknown. Assume suitable for underground \'lith substantial rock support. . . > 60 1 in saddle area:l sporadic in abutments. ' Assume available 0.5 to 5 mile radius. Impervious wi 11 requit~e processing. . . Based on USBR studies. I I I I GENERAL CONDITIONS 1. Dam Type 2. U/S Slope 3. D/S Slope I 4. General Foundation Conditions I I I I I I I 5. r o. 7. 8. 9. 10. Ill. I I I I I Required Foundation Excavation (in addition to overburden} Required Foundation Treatment & Grouting Seismic Considerations {MCE = Maximum Credible E1rthquake) Powerhouse Location Permafrost Construction Material Availa':>ility Remarks 6·1~ TABLE l (cont'd) GEOTECHNICAL DESIGN CONSIDERAT;IONS SUSITNA III Earth-Rockfill 2.25:1 2:1 Unknown but rock probably over 50' in depth. Possible permeable compressible and liquefiable strata. Assume same as for Hatana. Assume grout and drain system full width of dam, dependent on founda- tion quality. Drain gallery & drain holes. High exposure. MCE = 8.5 @ 40 miles. Also near zone of intense shearing. Unknown.. Assume suitable for under- ground with substantial rock support. Probably sporadic and deep. Assume available within five miles. Processing similar to that at Watana. No reports available. Parameters based on.regional geology of the area. ~1ATAUA Earth-Rockfill·or concrete arch 2.25:1 (for earth) 2~ 1 Abutments -assume 15 1 overburden(OB) Valley bottom -48-78' alluvium . Assume 70 1 • Right bank upstream- approximately 475 1 deep relict channel on right bank, upstream 0~ dam site. Core: Remove top 40' of rock Shell: Remove top 10' of rock Extensive grouting to depth = 70% of head but not to exceed 300 1 • Drain gallery & drain holes. MCE = Richter 8.5 @ 40 miles or 7.0 @ 10 miles. Underground favorablej extensive support may te required. > 100 feet on left abutment. More prevalent and deeper on north facing slopes. Available within 0-5 miles. Processing required. Based on Corps studies and 1980 Acres exploration .. HIGH DEVIL CANYON Earth-Rockfi 11 2. 25:1 2.1 Assume 30-60' overburden and alluvium. Core: Remove top 40' of rock Shell: Remove top 15' of rock Assume same as for Watana. Same as for L-Jatana. Probably favorable for underground but assume support needed. Sporadic, possibly 100' +. No borrow areas defined. Assume available within 5 miles. No geotechnical data available. Parameters based on regional geology. 4) I I I I I I I GENERAL CONDITIONS 1. Dam Type 2. U/S Slope 3. D/S Slop"e 4. General Foundation Conditions 5. Required Foundation Excavation (in addition to cverburden) ,I 6. I I 7. I a. I 9. 10. I I I I I ll. Required Foundation Treatment & G-routing Seismic Considerations (MCF: = Maxi111Um Credible Earthquake) Powerhouse Location Permafrost Construction Haterial Availability Remarks b· f3.. TABLE~ (cont'd) GEOTECHNICAL DESIGN CONSIDERATIONS DEVIL CANYON Concrete arch or gravity DEVIL CANYON Rofkfi11 2. 25:1 2:1 Assume 35 1 alluvium in river bottom. Shears and fault zones in both abut- ments~ 35-50' of weathered rocke Saddle dam overburden up to 90' deep. Assume excavation for spillway totals.90' to sound rock on valley walls~ Remove 50' of rock. Extensive dental work and shear zone over- excavation will be required •. Saddle dam: Excavate 15 1 into rock Extensive grouting to 70% of head, limited to 3oo•. Allow ·for long anchors into rock for thrust blocks. Extensive dental treatment. ueep cutoff under saddle dam, 15' into rock ... Same as for Ha ta na. Favorable for under!:l,ound powerhouse, assume moderate support. None expected, but possib1y sporadic. Concrete aggregate within 0.5 miles, . embankment materia 1 -assume Vii thin 3 miles. . Based on USSR~ Corps and 1980 Acres exploration. Core: Exca\·ate 40' into rock Shell: Excavate 15• into rock Allow for surface treatment. Saddle dam: Excavate 15 1 into rock~ Extensive grouting to 70% of head, limited to 3oo•. Extensive dental treatment under core~ Deep cutoff under saddle dam, 15' into rock. Same as for Watana. ·Favorable for underground powerhouse, assume moderate support. None expected, but possibly sporadic. Concrete aggregate within 0.5 miles, embankment material -assume \vi thin 3 miles. Ba~ad on USBR~ Corps and 1980 Acres exploration. PORTAGE CREEK Concrete gravity Unknown -assume same as fov-.Devil Canyon,. Rock type is similar to Devil Canyon, so assume foundation conditions are similar. Assume same as Devil Cany-on~ MCE = Richter 8.5 @ 40 miles or 7.0 at 10 miles .. Probably favorable for underground powerhouse, assume moderate support. Non~ expected, may be local areas on north exposurP~ or 1n overburden. Unknown -expect adequate sources 2-5 miles dovm.stream. No previous investigations are available on this site. . . ,. . . -. ~ . . . .a • .. •• . ' ' · r· ,. t . . . . -.. --• • ,1' ~ ~·~-------~-----------------------------1:..,. f t f ll I .... 'I I i I I I I I I I I I I TABLE 6.14-Hydrologic Design Consider·ations I I I I I I Parameter h .2 C ate ment area-sq .m1 : Mean annual flow-cfs: Inflow flood peaks* - cfs -50 year: Inflow flood peaks* - cfs -10,000 year: Inflow ;load peaks* - cfs -Pt1F: 50-year sediment accumulation Acre-ft: Denali 1,269 3,290 ·43,000 89,800 290,000 ~1aclaren Vee Susitna III 2,320 4,140 4,225 4,360 6,190 6,350 50,000 63,000 65,000 106,000 133,000 137,000 189,000 243,000 162,000 165,000 * Not accounting for any reservoir attenuation unless indicated otherwise. ** After upstream dam has been completed High Devil Devil Watana Canyon _fan yon_ 5,180 5,760 5,810 8,140 9,140 9,230 83,000 94,000 94,000 175,000 198,000 200,000 235,000 262,000 270,000 204,000 oil 252,000 Portag·e Creek 5,840 9,230 20,000** 200,000 270,000 Tunnel Alternative 20,000** Remarks assumes no up- stream development !MI l I I I I I - I I I I I I I I I I I I I TABLE 6.15 -Freeboard Requirements ' Allowances for: dry freeboard wave runup & wind setup spillway design flood surcharge (10, 000 year flood) post-construction dam settlt!ment Total difference between full supply 1 evel and dam cost Fill Dam 3 ft. 6 ft. 5 ft. Concrete Dam 3 ft. 6 ft. 5 ft 0 1% dam height nil 14ft. + 1% 14ft. dam height ---- COIIM>onents Oam Spillway ~\,wea· F~ .... ,ties In take: Pm1er Tunnel: Penstocks: POwerhouse: led l race Tunne 1: tm-1 level Outlet Works Intake and Tunnel: Construction Facilities U/S & \J/S Cofferdams: Diversion Tunnels: Access Road Access: Transmission Une Local -- - ----.. --.. --- ~, ~w t TABLE7-Engineedng layout ConsideratiOJ\S ~ Sinttle Develm~ments Denali r~aclaren Susitna Ill Watana !liclh Devil Canyon Devil Canyon Tunnel Al ternat't~ ---~-~ •,, . (--Conventional earth/rock fill ------·--------------~Concrete Earth/l·ock fill (--Service: Gated, open chute with downstream stilling basin---------------------~ r Emergency: (if requi.-ed) as above with downstream flip buc~et ---------------------~ (-Single level --~ <~Multilevel ------------------------------------·~ (-Single conct·ete-1' (----~Hnimum of twoo concrete 1 ined ---l\'lO partially H~~d 1 ined tunnels {l/3 co~ ... lined, 1/3 shot- ere ted, 1/3 un U~) {-... tccl Hning where necessary (neat· lJ.G. Powerhouse)(length=l/6 turbine head} ·---------·-------"'-"'-~ t-Underground H feasible ------------------------~---T ~ lli~ lined/unlin~ ~~~~do lined/unlin~~~~--~~~~~~--~~·-~~~~~~~~~~--~ ,_(lined or unlined -based on cost/energy loss optimization . -~ {-One or i.wo with gates -us~ diversion tun c-Earth m· t·ockfill --- (-Hinimum of two -----· o;,) if possible-------------------.. •4 ~Fill or --) <-Fill-------..}. cellular ,_To Oenali llighway -) t--to Gold Ct'eek ---------·--------------------~) To Cantwell along (-OcnaH lligll\·laY ~ (.---to Gold Creek -----------------------------------------------~---) (-Roads/tunnels and bd dges as required ---------------------· --------·--~-~ -. l~.~~~---------...-.... ~uJ111· -~Cw:~--.:..-.,.-••-------•• ... ..,,·•mur ... •-•-••·""'''_lllliiiii.._ ______________ ~ ..... .-----MF;~---·------~~oo~; --- - -b·- TA8L~.{£Q_nt'd) Conp51nen ts Conqlensatkn Flow Outlet Surge Chamber ----~--.. -· _ .. - 4 • Denali Haclaren Sus~' tna l! I We tan a IIi gh Oevll Canyo11 Devil Canyon Tunnel Alternati~..\Q!S ·-- ~ Independant intake with control valve discharging through low level outlet works or independent co.ului t ----7 ~Upstream surg~ tank t·cquired if net head on mai:hines < 1/6 of distance beb;een reservoir and machine~-~-~-....~ ~ Downstt·eam surge tank is required if tan~ace is (Zressurized -----------------------~--------------~ ~Size differential surge chambers for all locations where required--------------------~-""~ NOTE: Portage Creek development will be similar to Haclav·en except that access roads and tr;msmtss'ion lines will be to Cold Creek. -. -------------~--·----------------------------------~----.u--------------------------~----------------------------~ I I I I I I I I I I I I I I I I I I I TABLE 6.17 -Dam Crest and Full Supply Levels .. Staged Full Dam Dam Supply Crest Site Construction Level -Ft. Level -Ft. - Gold Creek No 870 880 Olson No 1,020 1,030 Portage Creek 1,020 1,030 Devil Canyon - intermediate height N::,. 1,250 1,270 Devi 1 Canyon No 1,450 1,470 (rockfill) 1,460* (concrete) High Devil Canyon No 1,610 1,630 No . 1, 750 1,775 Watana Yes 2~000 2,060 Stage 2 2,200 2,225 Sus itna III No 2,340 2,360 Vee No 2,330 2,350 Maclaren No 2,395 2,405 Denali No 2,540 2,555 * plus 4 foot hight wave wall. .. Average Tai lwater Level -ft. 680 810 870 890 890 890 1,030 1,030 1,465 1,465 1,810 1,925 2,320 2,405 ----~----~--------~ Run 1 2 -- 3 . 4 TABLE 6~18 -Results of the ?creening Model Total Opt irna 1 So 1 ut. ion .F irs.t Subopt ima 1 Demand • f'-'lax imum Inst. Total Cap Ener Sit~ Water Cap. Cost Site MW GWH Names Level-ft MW $ X 109 Names --· 400 1750 Watana 2060 400 770 High Dev i1 Canyon 800 3500 High Dev i1 1750 800 1320 Watana Canyon t watana 2200 800 1360 High Devil Canyon 1200 5250 . Devil 1450 400 850 t Vee Canyon . Watana 2200 800 1360 1400 6100 Devil 1450 600 1040 Canyon .• Note: Values on tnis table are currently being revised to reflect 1 at est cost ~nformat ion. Max1mum Water Level-ft 1640 2200 1750 2350 . Solution Inst, Tota"IT- Cap. co~~ ..... ~.~> MW $ X tv9· 400 78Q· .. 800 . 136Q 800 132{1· . 400 910 . .. . --- Plan Stage 1 1 2 ? L.. 1 2 3 4 3 1 2 3 4 1 2 ·--------........ ---·- Construction Watana 2225 ft 800MW Devil Canyon 1465 ft 600MW TOTAL SYST81 Watana 2060 ft 400MW Watar1a raise to 2225 ft vJate.na. add 400MW capacity Dev i 1 Canyon 1465 ft 600MW TOTAL SYSTEM 1200MW Watana 2225 ft 400M~J Watana add 400MW capacity Dev i 1 Canyon 1465 ft 600 MW TOTAL SYSTEM 120m4W High Devil Canyon 1775 ft 800MW Vee 2350ft 400MW TOTAL SYSTEM 1200MW " '~ TABLE 6~-Susitna Development Plans Incremental ~· Annual Gw~ Capital Cost Earliest Reservoir Maximum Energy~ fl'1 ant $Millions Construction On-line Full Supp1y Seasonal Productio F~tor (1980 values) Per~odf yrs. Date Level -ft. Dr~wdown Firm vg. ~ lft. 1860 9 1993 2200 150 2669 3252 4l~6.4 1000 6-1/2 +1996 1450 150 2640 2975 ..... 'iio. 2860 5309 02'27 ~9 .. 9 1570 8 1992 2000 100 1708 2109 60.2 ~ 360 3 --2200 150 961 881 ........ 130 2 2200 150 0 262 -- 900 6-l/2 +1996 1450 150 2'640 2975 2960 '5!09 6227 59.2 1740 9 1993 2200 150 2669 2990 85.3 150 3 2200 0 150 0 262 ... _ 900 6-1/2 4199\5 1450 150 2640 2975 .... _ 2790 5309 6227 59.2 1500 10 1994 1750 150 2546 3615 51.6 1060 7 1330 150 1323 1292 2560 ...... 3869 4907 46.7 "" 6' .. C/\ 0'--, p ' -- ----·-----·---.. -7 --. TQ~lQfo.~ s,w-llt(o.. }?Q~to-\lw\e.:A,t 't\u.W>. ( (_OV\.hVlu~" ., 6"" . ~ ' Incremental Annua 1 Grti'J:~~ \r' Capital Cost Earliest Re~ervoir M-'~imum Energy ~PTI!Illt $Millions Construction On-line Full Supply Seasonal Production ac~or Plan Stage Construction (1980 va~ues) Perio rse Date Level -ft. Drawdown Firm -Av . %~ 5 1 ..,High Dev i1 Canyon 1140 7 1992 1610 100 ~.1849 2106 Gm~l lb~.fi 4ooMLN r 2 High Dev i1 Canyon )( add 400Mxnpacity . raise da o 1775 ft . 500+ 3 1l50 100 697 1F09 --3 Vee 2350 ft 400 MW 1060-7 2330 150 1323 1292 --TOTAL SYSTEM 1200MW . '2700 ~f69 4907 ¢$.? 6 1 High Devil Canyon 1775 ft 400MW • 1390 8 J992 1750 150 2397 2732 ~--G 2 u;,..h n" .. ~, I II ~U Ut:V l I Canyon add 400MW capacity 140 5 ·~ 150 534 1276 ,.1'. -"""' 3 Vee 2350 ft 400MW 1060 7 .. "• ,_ ~ft'!.;: ~,...ll 150 1437 1536 --TOTAL SYSTEM 1200 3240 ~-442'8 5544 'ft6 .. 9 7 1 Devil Canyon 1465 ft 250MW BOO 6 1450 100 1250 1415 ~\6 'l Watana c: -z.z.zS @ f t 400MW 1740 9 1993 2200 150 2669 2990 85 .. 3 3 Watana add 400MW 150 3 2200 150 262. --4 Devi 1 Canyon l~)bo ari~ 350MW 200 3 1450 150 2640 g.9-f5 --TOTAL SYSTEM 1400MW 2890 5309 ~"27 59'02 8 1 Watan~ 2225 ft 850MW 1900 9 1993 2200 150 2833 3194 -.... 2 Tunnel 330MW 1220 2052 2241 TOTAL SYSTEM 1180MW 3120 4885 5433 52.6 9 1 Watana 2225 ft BOOMW 1860 9 1993 2200 150 2669 3;~52 46.4 2 High l!ev i1 Canyon 1410 ft 400MW --.. .,. .. ...... 3 Portage Creek 1030 ft 150MW . 650 ,..._,_ TOTAL SYSTEM 1350MW 2510 -----·-------.. -----~ TABLE 6-20 -Monthly Variation of Peak Power Demand OCT NOV DEC JAN FE_B ____ ~~R--~A~P~R----~~~Y ____ ~J~UN~E~--·~J~UL~Y--~A~U~G--~S~EP~J . 80 0.92 1.00 0.92 0.87 0.78 0.70 0.64 0.62 0.61 0.64 - -- ------.. - ---(J' -- ----""' ...0 ~ TABLE 6 .. 21 -Selected Susitna Development Plans . .. Incremental Annual ~ Gt-WH: Capital Cost Reservoir Maximum Energy Pl amt $Millions Full Supply Seasonal Production Factmr Plan ~tage Construction (1980 va1 ues) Level -ft. Draw~ own Firm Avg. % 2A 1 Watana 2060 ft 400MW 1570 2000 150 ft. 1708 2109 6U.2;: 2 Watana Raise to 2225 ft 360 2200 150 961 881 85 .:s 3 W-~tana ·add 400MW capacity and Re-regul at ion .&+a4m d~~ 230 2200 150 0 262 46 .. ~ 4 Devil Canyon 1470 ft 400MW 900 1450 150 2640 2975 59 ... ~ TOTAL SYSTEM 1200MW 3060 5309 5227 3A 1 Watana 2225 ft 400MW 1740 2200 150 2669 2990 85 ~ ' .. ~. 2 Watana add 400MW capacity. and Re-regul at ion e-1 aim d.-A.~ 250 2200 150 0 262 46 .. '4 3 Devil Canyon 1470 ft 400~~ 900 2640 2975 59~ ' ........ TOTAL SYSTEM 1200MW 2890 ~309 6227 6A 1 High Devil Canyon 1775 ft 400MW 1390 1750 150 2397 2732 78: .. il) 2A High Devil Canyon add 400MW· capacity 140 1750 .....-1-50 584 1276 4"8-.e.-.... .. -"\ 48; ~'5 28 Portage Creek 1030ft 150MW +650 1020 150{ 534. 1276 ' . .. ~ 3 Vee 2350 ft 400MW T060 2330 100 1437 1536 46"9 TOTAL SYSTEM -44r8 5544 4~b~ ,.,,.,, .... -· I I I I I I I .I I I I I I I ·II II I I I Development vJatana 2225 Ft. High Devil Canyon 1775 Ft. TABLE 6.22 -Energy Simulation Sensitivi_~- Installed Capaci'ty MW 800 BOO 800 800 800 800 Reservoir Full Supply Level FT 2200 2200 2200 1760 1760 1760 Maximum Reservoir Drawdown FT 100 "150 2000 100 150 200 Annual Firm 2350 2670 2770 2930 2550 2550 Energ~ Gwh Average 3260 3250 3230 3630 3620 3600 Plant Factor % 46.5 46.4 46.1 51.8 51 .. 7 51.4 I I I I I I I I ·I I I I I I I I I I TABLE 6.23 Information on the Devil Canyon ~ ·rsnel Schemes Tunnel Scheme Devil Canyon . . ____ D_a_m ____________ 1 __________ 2 ___________ 3 __________ 4 __ _ Reservoir Area (Acres) 7,500 320 0 3,900 0 River Miles F1ooded 31.6 2.0 0 15.8 0 Tunnel Length (Mi 1 es) 0 27 29 13.5 29 Tunnel Volume (yd3) 0 11,976,000 12,863,000 3,732,000 5,131,000 Compensating Flow Release From Watana sool (cfs) 0 1,000 1,000 1,000 , Downstream c:. ·Reservoir Volume (Acre-Feet) t,lOO,OOO 9,500 350,000 · Downstream Dam Height (feet) 635 75 245 Typical Daily Range of Discharge 6,000 4,000 4,000 8,300 3,900 from Devil .Canyon to to to to to Powerhoure ( cfs) 13,000 14,000 14,000 8,9(\0 4·, 200 Approximate Maximum Daily Fluctuations in Oownst~ e am Reservoir (feet) 2 15 4 1 1000 cfs compensating flow release from the re-regu1 at ion dam. 2 Oownstrecm from Watana .. ------------------- TABLE 6.24 Devil Canyon Tunnel Sche·,Jes Costs, Power, Output and Average Annual Energy Devil Canyon Increase 1 in ttnst3 of Installed Increase 1 in l11erage Annual Average Tunnel Scheme ;t\:dditional CaEacit~f (MW) Installed Capacity Energy Annual Energy Total Project .Energy 1 Watana Devil Canyon (MW) (GWH) ( GWl-1) Cost ($ x10 .2 ;{mills /kWh) Scheme 1 800 550 550 2,050 ~,050 1,979,000 42.6 Scheme 2 70 1j150 420 4,750 1,900 2t317,000 52.9 Scheme 32 850 330 380 2,241 2,183 1"1,221,000 24.8 Scheme 4 800 365 365 2,490 890 1,494,000 73.6 1 Increase over sin~le Watana (E1.2200) 800MW development with an average annual energy production of 3250: !Swh. 2 Includes power an energy produced at re-regulation dam. 3 Energy cost is based on an economic analysis (i.e. using 3% interest rate) as discussed in Section 9.5. I I I I I I I I I I I I I I I I I I I Installed Capacity: Watana Devil Canyon Re-regulation TOTAL Average Annual Energy: Watana Devil Canyon Re-regulation TOTAL Annual Firm Energy: Watana Devil r;:mvnn ..,,.,. .. J-·· Re-regulation TOTAL TABLE 6.25 Tunnel Scheme 3 2-30' Diameter 1-40 1 Diameter Tunnel 850MW 300MW 30MW 1,180MW 3,192 2,~53 138 5,433 2,833 1,925 127 4,885 Tunnel 850MW 300MW 30MW 1,180MW 3,194 2,064 195 5,453 2,810 1,927 't 1')-, l.C.I 4,864 •I I ~------' ' Watana-Devil Canyon D~~ 800MW 400MW 1,200MW 3,250 2,977 6,227 2,669 2,640 5~309 .. ;__I " 'I : -· -·!· i( . '. •..... o··· ··~.· . ' ,"",. : . .[\ , . ...-) .. ..,~, ,.;. . -) \' ;l ·;) :j _,:__. -"2'1-. 0- C·' .. :; \.\ '.~ ,, .. ~; -~ ...... ':J -. u ii ,_· .·o .· ;.. '/( u \}.' .. · I I I I I I "I I I I I I I I I I I I -· 7 -GENERATION EXPANSION PLAN I I I I I I I I I I I I I I I I I I 7 -GENERATION EXPANSION PLAN<- c... c:....7.1 -Introduction The Susitna Project will provide for the bulk power needs of the Railbelt Region when it is implemented in the 1990's and early twenty-first century. Due to its large size relative to the existing electrical system, proper planning of its capacity and coi11T1ercial operation date is art important activity toward insuring maximum benefits from the project for the Railbelt. The generation planning effort responds to this need by synthesizing the Railbelt electric system in the 1990's through 2010 dynamically evaluating the benefits of Susitna and other generating resources under various power needs and levels of economic activity in order to establish the best generation expansion plan. Among the generation options available to the Railbelt, thermal generation based on available Alaska fuels (coal, natural gas and oil) is obviously an important one, since it is cw·rently the primary means of producing electricity and is a conventional method worldwide of p•·oviding for new capacity and energy requirements. Other undeveloped hydroelectric s·it~s in addition to Susitna, also provide significant potentials for providing for a diversity of capacity and energy needs. The generation expansion. plan will define the type, capacity and schedules inservice data for generating facilities needed to meet projected loads for the Railbelt electric system between 1980 and 2010· including basically thermal and hydroelectric power projects. Hydroelectric includes Susitna and other smaller projects Which may be developed. Thermal includes coal-fired steam, gas-fired combined cycle, and gas or oil-fired gas turbine and diesel electric generating plants. The plan is a result of an extens~ve effort in simul atirtg the electrical loads (and variable load projections), the existing Railbelt generating facilities, and the optional facilities avail able for future development. Based upon plant systen costs, as well as system reliability (reserve capacity), the generating resour~..~es to be included in the expansion plan are screened and selected. However, the selection must be tested to confirm that it does not result in significant adverse system impact if load patterns or economic factors do not follow expected patterns. This is accomplished in the sensitivity analysis phase of the planning effort which precedes selection of the preferred generation plan. 1 .&Th~rmal Power The de vel opnent of thermal generating fac il it i es would all ow consumption of Alaskan nonrenewable resources within the State t0 benefit the consuming public directly, as compared to resource export which would bring in benefits in the form of state revenue and jobs. Using these nonrenewable resources locally, as compared to exporting them, may or may not be the most economic ally rewarding opt ion fat"' the State and represents a pol icy issue which will not be answered here. The selection of future generating facilities within this study is based on economic superiority, resource availability and environmental adequacy. The thermal types of generation considered within the p·rc-sent study include existing and new generating resources which could fill the full spectrum of load requir.ements projeted for the future of the Railbelt region. Types of plants include coal-fired steam, oil and natural gas-fired gas turbines and combined I I I I I I I l1 I I I I I I I I I I I INFORMATION SUSITNA BASIN DEVElOPMENT OPTiONS ALTERNATl VE HYDROELECTRIC DEVELOPMENT THERMAL DEVELOPMENT OPTIONS INFORMATION ON ENVtRONMENTAL1------l~ IMPACT * INCLUDING SENSITIVITY ANALYSIS PLANNING ECONOMIC RANKING OF GENERATION PLANS * GENERATION PLAN SELECTION PRODUCTS GENERATION PLAN INPUT TO FINANCIAL ANALYSIS SCHEMATIC REPRESENTATION OF GENERATION PLAN SELECTION PROCESS [jjJ ------------------·~.~--------~~------------------------·~----------~· FiGU.'~E 7 .I I I I I I I I I I I I I I cycle plants and diesels. Development of costs for facilities, incremental fuel and operations were required, and performance parameters were established in order that the resources could be ev a:1 uated for the future Rail belt ~:.~ystem. Fue 1 costs were deve 1 oped based upon a comb in at ion of the existing market and the currently expanding export world market. Since the planning effort is aimed at conditions in the period after 1990, it was necessary to define what the possible market costs will be. Based upon the current world ~nergy situation, activity in the A 1 ask a energy market and the extent of fue 1 reserves, it was necessary to determine whether significant development of the energy exports should raise the market costs to an opportunity cost level during the study period . . I.?-Hydr·oelectric Power Previous studies on the Alaskan hydropower potential. concluded that in general, develcpments on Susitna River are among the most .economically attractive in the area. A significant number of economic parameters used in hydropower evaluations .::hanged significantly in recent years since the issue of the last studies done by the Cor.ps of Engineers. Consequently, some hydroelectric options to Susitna potentially being among the better sites economically and environmentally were re-estimated based on current price 1 evel?. The site's location, allowing specific watershed development, or presenting the advantage of proximity to load centers and/or to the Anchorage-Fairbanks Intertie, were other factors considered in the screening process. Var icus s·i zes of hydropower developnents were considered to confer a range of options in meeting the needs of a system corresponding to various future demand scenarios. J· ~Generation P 1 ann in,[ The Railbelt genera1.in~a resources for the 1990 1 S will consist of existing generating facilities, a proposed transmission intertie between the primary Railbelt load centers of Anchorag~ and Fairbanks and other new generating facilities to be determined. Ba~ed upon scheduling limitations and costs·for the various thermal and hydro facilities, and with due consideration to currently planned generation, a base 1990 system is developed. The economic viability of va'tious thermal and hydroelectric developments in the Railbelt region for the post 1990 period ~,s then tested against future electrical system needs with and without inclusion of a Susitna Project. Further of the various expansion plans ar-e evaluated to determine the overall s-ensitivity to the range of potential load growth patterns and other variations of financial and economic conditions. I I 7 .!:-Ex~sting System Characteristics I (d-)· )§ .=+~=-S:l -System Description I I The generation plants considered as existing capacity in the Railbe1t for the generation planning studies includes the capacity of all utilities in the region, inclerling the Alaska Power Administration {APAd). To identify the existing generation system for planning pu"·poses·, a number of sources were consulted: · I I I I I I I I I I I I I I I ·I TABLE 7.2.1 · 1980 RAILBELT EXISTlNG CAPACITY Installed Capacity (1980) wee IECO DOE RAILBELT UTILITY* 1980 1978 1979 AMLPD 184.0 130.5 148.0 CEA 420.0 411.0 402.2 GVEA 211.0 218.6 230.0 r-..... ·-a-!•IU.::> 67.0 65.5 68.2 CVEA 18.0 13.0 MEA 0.9 0.6 3.0 HEA 2.6 9.2 1.7 eE' .,J ~ 5.5 5.5 5.5 ' APA 30.0 30.0 TOTAL 909.0 870.9 901.6 ft~LPD -Anchorage Municipal Light & Power Department CEA -Chugach Electric Association GVEA -Golden Valley Electric Association FMUS ~ Fairbanks Municipal Utility System CVEA -Copper Val1e.y Electric Association HEA -Homer Electric Association MEA -Matanuska Electric Association· SES -Seward Electric System APA -Alaska Power Administration ELEC .WO. 1979 108.8 410.9 211.0 67.4 0.9 3.5 5.5 30.0 838.0 MW ACRES Gr4 215.4 411.0 211.0 67.2 0.9 2.6 5.5 30.0 943.6 " ~/ I I • I I I I I I I I I I I I I I I I I I I -Woodward Clyde Consultants 11 Forecast ing Peak Electrical Demand for Alaska's Railbelt," September!) 1980. -IECO Transmission Report for the Railbelt, 1978. -U.S. DOE, "Inventory of Power Plants in the U.S.," April, 1979. -Electrical World Directory of Public Utilities 1979 -1980 edition. -FERC Form 12A for the following utilities: Anchorage Municipal Light & Power (AMLP) Chugach Electric Association (CEA) Homer Electric .1\ssociat"rn (HEA) Fairbanks Municipa1 Util ~ty System (FMUS) -~Jill iams Brothers Engineering Company, 1978 Report on FMUS and GVEA (Golden Valley Electric Association) Systems -Discussions with: AMLP -Mr. Hank Nichols FMUS -Mr. Larry Co 1 p GVEA -Mr. Woody Baker A PAd -Mr. Don Gotscha 11 Table 7.2.r summarizes the information received from these sources. Some discrepancies were apparent especially with respect to JV~L&P and Copper Valley Electric Association (CVEA). The column: ACRES GM represents the installed capacity used in the OGP-5 Generation Model for Task 6.36 studies. This column represents a resolution of all data sources collected. The total railbelt installed capacity of 943.6 MW as of 1980 consists of ·fifty three units. The units are categorized into the following six types of capacity; No. Units Type Capacity (MW) 1 Combined Cycle 140.9 Hydro 45.0 NG Gas Turbines (Anchor age) 470.5 ,. Oi 1 Gas Turbines (Fairbanks) 168.3 "" 5 Coal-Fired Steam 54.0 21 Small Diesels 64.9 53 943.6 I I I I I I I I I I I I I I I I I I I \Jn) \1 -1~ -Existing Capacit1 Tab 1 e 7. 2. 2 1 ists the complete 'Capacity of the rail belt by unit. The information for each unit is that which has been gathered from the references listed in Section 7.1. ~) ~3 -Schedule of Additions and Retir :' · '1ts In order to establish a retirement pol icy for Rail belt utilities, several references were consul ted including the APA draft feasibility study guidelines 9 FERC guidelines, experience within the industry, historical records and consultation with ut n ities, particularly in the Fairbanks area. From consideration of all of these sources, the following t"'et irement pol icy is proposed for use: -(Large Steam Turbines (> 100 MW) = 30 years b) · Sma11 Steam Turbines ( < 100 MW) :':: 35 years ( c (.Oil-Fired Gas Turbines = 20 years ( ) LNatural Gas-Fired Gas Turbines = 30 years ·-~fe) LDiesels = 30 years --{r) ltombined Cycle Units = 30 years -W Lconventional Hydro = 50 years /'. ~ese scheduled operating 1 ives and those used for the economic 1 ives of the projects are identical. The impact of these project lives on the existing capacity in the railbelt can be seen by the set retirement dates on Tab-, e 7 . 2 • 2 . Only two new projects are considered to be committed for the railbelt system. Those '•/ill he developed by CEA and the U.S. Army Corps of Engineers ( COE) . CEA is in the process of adding 60 MW of gas-fired combined cycle capacity in Anchorage. The plant will be called Beluga No. 8. F"or study purpose~~ the plant is assumed to be operating on 1 ine in January 1982. The COE is currently in the post-authorization planning phase for the Bradley Lake project, located on the Kenai per 1nsula. The project is currently planned to include 94 MW of installed capacity and 420,000 HWh of annual energy, on the ?.'Jerage. For study purposes~ the project is S(;hedul ed to be on 1 ine i.n 1988. 7 .b-Options Available to Meet Future Capacity Requirements . . , \· (This sect ion outlines the basic da.ta on cost .o and power and energy ~5·capabil ity. form the range of generating far: il ity outlined above required as input to the generation planning studies. ., - - - - - - - - - - -..... - - ----- - TABLE 7.2.2 (Cont • d) RAILBELT STATION UTILITY NAME Fairbanks Chen a Municipal Utility System (FMUS) FMUS Homer Elec. Homer- Associ at ion Kenai (HEA) Pt. Graham Seldovia Matanuska Talkeetna Elec. Assoc. (MEA) Seward SES Electric System {SES) A 1 ask a Eklutna Power Administration (APA) GT = Gas turbine CC = Combined cycle HY = Conventional hydro ST = Steam turbine NA = Not available NG = Natural gas MBTU = Million Btu \ } UNIT UNIT INSTALLATION # TYPE . YEAR 1 ST 1954 2 • ST 1952 3 ST · 1952 4 ft 1 .·~:-.-., ... i 1963 5 ST 1970 6 IC }' -1976 : i. ..:-' t 1 IC 1967 2 IC 1968 3 IC 1968 1 IC 1979 1 IC 1971 1 IC 1952 2 IC 1964 3 IC 1970 .J. IC 1967 1 rc 1965 2 IC 1965 3 IC 1965 HY 1955 *Retirement policy: HEAT RATE INSTALLED MINIMUM BTU/KWH CAPACITY CAPACITY (MW) (MW) 14,000 5.0 ?. 14,000 2.5 1 14,000 1.5 1 16,500 7.0 2 14,500 20.0 5 12,490 23.1 10 11,000 2 .. 7 1 11,000 2.7 1 11,000 2.7 1 15,000 0.9 NA 15,000 0.2 NA 15,000 0.3 NA 15,000 0.6 NA 15,000 0.6 NA 15,000 0.9 NA 15~000 1.5 NA 15,000 1.5 NA 15,000 2.5 NA 30 .. 0 NA La'l'ge steam tur·bines >100 MW Small steam turbines <100 MW Hydro Diesels Natural gas gas turbines Combined cycle Oil-fired gas turbines Q MAXIMUM FIJEL CAPACITY TYPE (MW) 5 2 1.5 7 2Q 29 3. 3 3 NA NA NA NA N~ NA NA NA NA NA 30 ye.ars 35 years 50 years 30 years 30 years 30 years 20 years COAL COAL COAL OIL-2 COAL OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 OIL-2 !P.age 2 of 2 FUEL RETIREMENT COST YEAR $/MBTU 1.40 1989 1.40 1987 1.40 1987 4.01 1993 1.40 2005 4.01 2006 4.01 1997 4.01 1998 4.01 1998 3.50 2009 3.50 2001 3.50 1982 3.50 1994 3.50 2000 3.50 1997 3.50 1995 3.50 1995 3.50 1995 3.50 2005 1. I I I I I I I I I I I I I I· I I I I ·7~~-Susitna Basin H,ydroele~trh: Section 6 dexcr,ibes the Susitna Basin studies that lead to the selection of the range of Susitna Basin development options outlined in Tables 6.19 and 6. 2L. -?.~2?-Otr_. Hydroelectric (Write up to be shortened and simplified in next draft. J ~ j ', i."8. -Site Se 1 ect ion and Screening Previous studies on the Alaskan hydropower potential concluded that in general, develoJEent on Susitna River is among the most economically attractive in the area. A significant number of planning parameters changed significantly in recent years since the issue of t~e last studies done by the Corps of Engineers part icul::J.ry incl ud,ing lower system electrical growth and capacity needs. Consequently, some hydroelectric options to Susitna, located in adjacent watersheds within the Railbelt and presenting the advantage of proximity to load centers and/or to the Anchorage-Fairbanks Intertie, were re-estimated based on current price levels. Various sizes of hydropower development options were. considered to span a range of options to meet the needs of the Railbelt system. ~~ Site Selection \n order to select the most suitable sites for development~ a multi-step screening and evalu~tion process was used {See Figure 7.3.1 for a step by step flow diagram of the entire process). Data for the hyd·~oelectric potential in the Railbelt Region were obtained fr-om previous studies issued by federal agencies: lJ.S. Army Corps of Engineers, "Natio·nal Hydropower Study" (Form 2, Data Base including physical parameters of the site, cost data and environmental data) and Alaska Power Administration's 11 Hydroelectric Alternatives for the A l ask a R a i 1 belt 11 • Cost data. provided by the Corps of Engineers and by the Alaska Power Admin1 strat ion were updated to estimate the current 1 evel of costs and benefits of hydropower devel opnent for a total of 91 sites inventoried within the Rai1belt Region. Construction costs were developed by standardizing the field costs provided by the Corps and APA, since the two agencies had used different 1 ocat ion factors in their estimates to account for higher price levels in Alaska. Contingencies of 20 percent and engineering-adfl1inistration adjustments of 12 to 14 percent were added to calculate the· project cost. Project costs were updated to a January 1, 1980, price level based on the "Handy-Whitman Cost Index for Hydropower Production in the Pacific Northwest ... Using updated project costs as we11 as .::, series of plant size- dependent economic factors se 1 ected Hlr the rough economic screening (construction periods, annual investment carrying charges and ' . .. $ $ -... -..... INITIAL ECQC~IC SCREE!IIHS {65) SITES PASSING ECONCX11C ROUGH SCREEHIHG IHITIAl EHVIRONMOOAl SCREENING . . {46) SITES · PASSING ROUGH SCREEHIHG ' l I . . - ..:....---........ . . • . L •' ,..., ,.., ... --. . . :-···l . ... ... ...._,.._, ~·--- (26) SITES ELIMHIATED . . . . . . • 11 ' f . . ' ....... ----• . i . -. .. I ' . • -·-. ....., ..-----~· ... (19)SITES ELIMIHATfD I • -·----·· • ! l ··~ (10) SITES . ~ SELECTED fOR t . · ·--OETAILEO $ IHYESTIGATIOft '--------~· .... -~ ---.. -~ -. ., -.... -..... . ;_ ~ .. -. r.. . . ' . - • .... _ .. ....... . . . . . .. _ .. _ . . .... IDENHFICAllO'f OF EHVlRONMENTAt.LY SUPERI~.SlltS· -· ---------- $ ~ SUSITHA. OGP ALTERNATIVE computer program ld---1::::==;;.;;..;.;......_.; ~R~~~ runs EVALUATE GEHERATilfG Pl.AHS '-------....1 'l RECOM:'IEHD PREFERRED PL~ -------..J planned •ctb1ty $ . I .. :_ .... . ---· ! i . ,_ . i--+-. ____ ,.. econa~de considel"atfon --~ D 0 process blcek Input/ output block ---.• . • • •• ..,....!.---:.J' ·f.. environmental ; ! · cons1deratfl)ft ·-r; .. --·--·--l £ G E H 0--·---··· : I ; .. . -·-- I· I I I I 0;J I I I I I I I I I I I I I I operation and maintenance expenditures), the average annual production costs in mills/k~Jh were estimated for the 91 sites using an annually charge of 10.62 percent nn the investment cost. Plant capacity factors ranged from 50 to 60 percent, based on source data. A range of average annual production ~osts were developed for most of the sites, as they were initially e5t imated by both the Corps and the APA. Site with development costs less than 120 mills/kWh were selected for initial environmental screening (to be changed to economic parameters for consistency) . ~~!.2.2-Initial Screenin.9. Sixty-five sites with production costs less than 120 mills/kWh on either the Corps of Engineers or Alaska Power Administration inventory were exposed to a preliminary environmental evaluation. This initial screening was based on critical environmentc:l restrictions~ Sites were eliminated from further consideration if they: (1) ~roduce a significant change within the borders of an existing National Park. (2) ~roduce a significant change within an area withdrawn as a National Monument Proclamation. (3) .fdre on an anadromous fish river where three or more species are present, the run Jxceeds 50,000 fish annually and the proposed power devel op11ent is 1ocated downstream of the confluence of any major spawning tributary or in a major fishing area. Sites excluded by initial environmental screening were: Site r Crit~ria Healy Car1o Yanert -2 C.l eave Wood Canyon , Tebay Lake Hanagita Gakona Sanford Lake Creek Upper McKinley River Tekl anika Crescent Lake National Park O·tt. McKinley) Nation a 1 Mo n urn en t ( Wr an g e 11-S t . El i as Nat'l Park) and Major Fishery National ~1onument (Wrangell-St. Elias Nat '1 Park) National Monument (Denali Nat'l Park) National Monument (Lake Clark Nat • 1 Park) j '~ I I I I I I I I I I I I I I -I I I I I Kasilof River Vachon Island Power Creek Mill ion Do 11 ar R :impart Junction· Island Major Fishery An additional pre1 iminary analysis was perfot~med to determine the transmission cost impacts on the sites' feasibility. Transmission costs necessary to connect the site to the Anchorage-Fairbanks Intertie were estimated based on a generalized level of expected cost. Tab 1 e 7. 3.1 is a summary of the results of the in it i a 1 economic and environmental screening. A total of 46 sites passed the kritial screening: 11_sites in the 0-25 MW range, 26 sites in the ~5-100 MW range and 9 sites greater than 100 MW. JJI ~ 7,3 2.3--Final Selection of Candidate Sites The 46 sites passing both init.;al economic and initial environmental screening were divi.ded into three groups in terms of the installed capacity. These groups were (1) 0-25 MW, (2) 25-100 MW~ and (3) greater than 100 MW. Within each of the capacity groups, the economically superior sites were identified. This resulted in a 1 ist of 22 sites. Based on review of previous environmental studies, six sites were identified as environmentally superior and added to this 1 ist, leaving a total of 28 sites. The following table 1 ists the n LJTiber of sites evaluated in each of the capacity groups. Site Group 0 -.25 MW 25 -100 MW >100 MW TOTAL No. of Sites Evaluated 5 15 8 28 The s :tes were then eval_uated numerically by a categorical scoring system as descr1oed 1n 'l;:l~D.i&6-below. They were subsequently 1 isted in ascending order of their scores for each of the size groups and labeled as good~ fair, or poor, based on the scores. The sa11e general standards (e.g., cutoff points) were used for all size groups. For the purpose of evaluating the relative erivironmental impacts of the 28 selected hydropower developments, a methodology for ranking and ev al uat ion was formula ted. A review of the ev al uat ion process was provided to che Susitna Study Steering Committee for the.ir consideration and comment. I I I I I I I I "I I I I I ~ I I I I I .SUMMARY OF RESULTS OF INITIAL SCREENING List of 91 sftes considered for hydroelectric development. (*) ind kates the 1 ist of 65 sites passing economic initial screening. ( )undr:rl ine indicates the 1 ist of 46 sites passing initial -environmental screening~ * 1. * 2. * 3. 4·. * 5. 6. 7. * 8. * 9. * 10. 11. 12. * 13. * 14. * 15. 16. * 17 18. * 19. * 20o * 21. * 22. * 23. 24. 25. 26. * 27. * 28. * 29. * 30. * 31. * 32. * 33. * 34A * 35. 36. '* 37. * 38. * 39. * 40. * 41. * 42. * 43. 44. 45. * 46. A 11 is on Creek Beluga Lower Beluga Upper Big Delta Bradley Lake tremner R. -Salmon Bremner R. -S.F. Browne Bruskasna Cache Canyon Creek Caribou Creek Carlo Cathedral Bluffs Chakachamna Chulitna E.F. Chulitna Hurricane Chulitna W.F. Cleave Coal Coffee C.rescent Lake Crescent Cake-2 Deadman Creek Eagle River Fox Gakona Gerstle Granite Gorge Grant Lake Greenstone Gulkana River Hanagita Healy Hicks Jack R·iver Johnson ~unction Island Kantishna River Kasilof River Keetna Kenai Lake Kenai Lower Killey River Ki.ng Mtn K 1 utina ---- 47. * 48. * 49., * 50. * 51. * 52. 53. * 54. * 55. 56. *57. 58. 59. * 60., * 61. * 62~ 63. * 64. * 65. * 66. 67. * 68. * 69. * 70. * 71. 72. * 73. 74. * 75. 76. 77. * 78. * 79. * 80. * 81. * 82. 83. * 84. 85. * 86. * 87. * 88. * 89. * 90. * 91. Kotsina Lake Creek Lower Lake Creek Upper Lane Lowe Lower Chulitna Lucy McClure Bay McKinley River McLaren River Million Do 11 ar Moose Horn Nellie Juan River Nellie Juan R .-Upper Ohio Power Creek Power Creek -1 Rampart Sanford Sheep Creek Sheep Creek -1 S ilvet· Lake "Skwentna Snow Solomon Gulch Stfll ters R~nch Strandl i Of: Lake Surrmit Lake Tal achul itna Tal achul itna River Talkeetna R. -Sheep Talkeetna -2 Tanana River T azl ina Tebay Lake Tekl ani ka T~eke 1 R i Vt:i lokichitna Totatl ani ka Tustumena VaChon Is 1 and Whiskers Wood Canyon Yanert -2 Yentna I I I I I I I I I I I I I I I .I I I I ( /l]'}. -1~ -Data Survey A survey of information was performed to locate existing and -published sources of environmental data. The 24 v-eference sources used in preparing the evaluation matrix included publications and maps for which data was collected, prepared and/or adopted by the following agencies: · (a) (b) (c) (d) (e) (f) (g) (h) University of Alaska, Arctic Env ircnmenta 1 Inform at ion and Data Center A 1 ask a Department of Fish and Game Alaska Division of Parks National Park Service Bureau of Land Management, U.S. Department of Interior U.S. Geological Survey U.S. Army Corps of Engineers, Alaska District Joint Federal State Land Use Planning Commission. In add it ion, representatives of state and federal agenc-ies ( including AEIDC, ADNR, ADF&_G, ADEC and Alaska Power Administration) were interviewed to provide subjective input to the planning process. ~7-J3,2.5 -.Environmental Ranking ~1ethodology Eight evaluation criteria were used to define the environmental sensitivity of the sites. The criteria and their associated concerns were the following: Evaluation Criteria General Concerns 1. Anadromous Fisheries -Protection of fisheries 2. Big Game -Protection of wildlife resources -Protect ion of recreation, corrmerci al, and subsistances resources 3. Waterfowl, Raptors, -Protection of wildli·~=~ resources and End angered Species 4. Agricultural Potential -Protection of existing and potential 5. 6. 7. Restricted Land Use agricultural resources -Consideraiton of 1ega1 restrictions to 1 and use Wilderness Consideration -Protection of wild and unique features Cultural, Recreation, and Scientific Features -Protection of existing and identified potential features 0 -I I I I I I I I I I I I I I I I I I I 8. Access Identification of areas where the greatest change would result from deve 1 opnent The first four criteria were chosen to reoresent the most valuable ' . and sensitive aspects of the existing natural environment. The remaining criteria were chosen to represent opinions of various legislative and interest groups regarding the use of the 1 and at the site$ Data relating to each of these criteria was compiled separately and recorded for each site, forming a c!ata-base matrix. Based on this collected data, a system of sensitivity scaling was developed to represent the relative sensitivity of each environmental resource (as represented by the criteria) at each site. These scale ratings were defined: A -Exclusion (used for sites excluded in preliminary screening, not used in final selection) B -High S:::nsitivity C """ t~oderate Sens it iv ity D -Low Sensitivity A relative weight was assigned to each criteria to represent its relative sensitivity to development. A high value indicates greater importance or sensitivity than a low v~ue. Relative Weights Big Game Agricultural Potential Birds Anadromous Fisheries Wilderness Values Cultural and Scientific Ft'atures Restricted Land Use Access 8 7 8 10 4 4 5 4 The weights for the first four criteria were then adjusted down, depending on re 1 a ted technical factors of the devel opm~nt scheme. . Dam height was assumed to be the factor having the greatest im[Jact on anadromous fisheries. All sites were ranked by dam height as follows: Dam Height . <150 I 150 l -350 I >3so• Rank + ++ +++ I I I I I I I I I ·I I I I I I I, I I I A dam with the lowest height (+) would have least impact, thArefore the fisheries we i9ht was adjusted down by two points. .S'r;dl ai~ly, a dam of height (++) was adjusted down by one po·int. A dam of height (++'') would have the greatest impact and the weight remained at its maximum value. · The amount of new land flooded by creation of a reservoir was considered to be the factor with greatest impact on agricultur€, nird habitat, and big game habitat. Sites were ranked in terms of their new reservoir area as follows: Area <5, 000 ac 5,000 -100,000 ac >100, 000 ac Rank + ++ +++ For developments which utilized an existing lake for storage, the new area flooded was assumed to be minimal (+)., The same numerical adjustments were made for the big game, agricultural potentials, and bird habitat weights as the fisheries. These adjustments are surrrnarized in Table 7.3.2. TABLE 7.3. NUMERICAL ADJUSTMENT VALUES Adjusted Weiahts Initial Dam Height Reserv. Area Weight + ++ +++ + ++ +++ -· - Big Game 8 6 7 8 Agric. -Po ten. 7 ·5 6 7 Birds 8 6 7 8 Fisheries 10 8 9 10 The three scale ratings were given a weighted value as follo~Js~ High Sensitivity = B ~ 5 Moderate Sensitivity = C = 3 Low Sensitivity = D = 1. To compute the ranking score, the scale weights were mu1tip1 ied by the adjusted criteria we·~ hts for each cri~r""ria c ,d t1e resulting products were added. Two scores were computed. The total score is the sum of all eight criteria. The partiCll score is the sum of the first four criteria only, which gives an indica~ion of the relative timoortar1ce of the existing natur,a1 resources 1n compar1son to tne otal s ... ore~ I I I I I I I I I I I I I .... I I I I I I \) se .fri 4. c:£ -Analysis ,-.-~.-~·,--· -· . ---. 0 -24 MW Of the four sites evaluated, all were determined to be acceptable, based on the overall standards. Three of these sites were judged as a group to be better than the fourth which had a higher partial and total score. 25 -100 MW A cutoff point of apprtx imately 134 for the total score and approximately 100 for the partial score was used. Sites scoring higher were eliminated. The seven sites scoring lower were re-examined. The first three, Bruskasna, Bradley Lake, and Snow were the best sites identified. Of the remaining four, Coffee anj Keetna were identified as questionable because of anticip<.Lted S"~"'mon fisheries problems.. Lowe and Cache scored only slightly better, but Lowe has minimal fisheries problems, and the Cache site is farthest upstredffi on the Talkeetna River, beyond Which the salmon migrate 0;1ly about five miles. > 100 MW ' The same cutoff point for acceptab'le sites with total and partial scores were used. The result was that only one site, Chakachamna was considered to be acceptable. For this reason, four more sites: Browne, Johnson, Tazl ina and Cathedral Bluffs, were included fur environmental t"aview. The ranking rc.;ults are presented in Table 7.3.3. Fifteen sites were selected for further consideration .. n~~"ee constraints were used to identify these 15 sites. F,;rst, the most ecm·.omical sites which had passed the environmentd.l ro~tJh screening were chosen. Secondly, sites with a very good environmental impact rating which had passed the economic rough screening were chosen. And finally, a repr~sentative number of sites in each capacity group were chosen. I I I I I I I :';! I I I I: I I I I I I I I TABLE 7.~~ ~NTAL RANKING SCORE BY CAPACITY GROUP Sites -0 -25 MW *Strandline Lake Upper Nellie Juan Tustumena Allison Creek Si 1 ver lake Sites -25 -100 MW *Hicks Bruskasna Bradley Lake Snow Lm'le Cache Coffee Keetna Whiskers Ta lkeetna-2 lower Chulitiua Klutina Upper Beluga Ta1achultna Skwentna Sites -> 100 MW . . *Browne *Johnson *Tazl ina *Cathedral Bluffs Chakachamna Lane Tokichitna Yentna Part i a 1 Score 51 37 37 65 65 62 71 71 71 89 86 101 98 101 98 106 101 117 126 13.6 69 96 89 101 65 106 117 139 Total Score 85 96 106 82 111 79 104 104 106 122 127 126 131 134 134 139 142 142 159 169 94 121 124 126 134 139 150 172 * Sites selected for evaluation due to superior environmental conditions. . •I I. I I I I I I I I I II I I I I I I I I I Env h'onmenta 1 Rating 0 -25 MW Good -S~rand 1 ine Lake* f\11 ison Creek* Tustumena Silver Lake Fair Poor C apacit~ 2s -r-o Mw Hicks* Srrvw* Cache* Bruskasn a* Keetna* Ta 1 keetn a-2* Lower Chulitna >roo rv1W Browne* Johnson !I Chah:achamna* Lane Takichitna Thi!l ·list of 15 sites was provided to the Steering Corrmittee for their evaluation and recommendations. The Committee has also provided a list of a.l terr.at:e sites from which to choose in the event that none of the 15 were acceptable to tneir review. To date, a response has not been received. From the list of 15 sites, 10 were selected for detailed deve:opnent and cost estimates required as input to generation planning. The ten sites chosen are indicated v1ith a(*) on Table7.3.4 above. Of the ten sites, Strandl ine Lake, Hicks, and Browne were identified in the Ch2M-Hil ~ Report to the Army Corps of Engineers, 11 Review of Southcentral Alaska Hydropower Potential," as being environmentally very good. These sites were included, even though their associated costs wer-~ higher than rr~any o~~ ti{e other sites which had also passed the econo.«ict, rough screening. The Chakachamna site had both a very high economic ranking and a good environmental rating in ·terms of the 5ensitivity of its natural resources to development. ~Chakachamna wa~ also identified by the Ch2M-Hill report as having minimal environmental impactso One unresolved question that remains with the Chakachamna site is the newly passed ~ongressional ·legis1 at ion (Public Law 96-487) regarding the Alaskan Natioral Interest Lands \~ouid restrict implementation of the project. While the final rulings, resolutil'\ns and boundary maps have yet to be ~ubl i sr i, it appears that the civil works of the project wi 11 '10t affec \. protected 1 and s. The eff3cts of the 1 ake on p~otected 1 1:1, js, and the actual status of those protected 1 ands are not clear at ·.:his t·,me: .. BPcause the ChaJrachamna Site is so desirable in other respects'/ it has been kept in consideration as a viable hydropower resource for the future in the Ra i1 be 1 t Reg ion. I I I I I I I I • I I I I I I I I I .. . ' ' . .. . , . ' .. . • ·• • • : • • ' ~ • ',__r .... ' • • • • Three sites were chosen on the Talkeetna River. These are Cache, Keetna, and Talkeetna-2 which are being studies as an integrated system alternative. Although the identified environmental problems are significant5 the system is being studiec' for several reasons. It is-believed that with the system approach, tt1e incremefital impacts of building a second or third plant on the same river systan would be smaller than the impacts associated with building plants on competP.ly separate rivers. The integrated system not only improves the economic potential of the operating capacity, but also allows for better control over regulation of strean flows as needec! by th~ downstream ecosystems. Secondly, the choice of the Talkeetna River was made over other rivers with potential for develop11ent of similar systems, because the environmental sensitivity of the Talkeetna was not as great as that of the Yentna-Skwentna basin, the Chulitna River or the lower Susit·na basin, particuiarly with reaards to the presence of anadromous fish or big game. And finally, the Talkeetna River developments were some of the best sites economically, thus providing an econanically effective future generating resource. The remaining sites of the ten studied in detail are Allison Creek, S:1ow, and Bruskasna. These are sites that where identified by the environ@ental evaluation as being the best environw~n~~lly of the 22 economically superior sites . (~ ~~ -Power Studies Dete·rmination of tile recommended installed capacity for each project was based on analysis of 1 ong-·term power and enet''gy product hm. The cmnputer model discussed in Section 6 was used to simulate the reservoir oper,ation under the constraints imposed by a given operating regime. The power analysis was cari'·iet.. out on a monthly basis using at 1ea3t 13 years of mean monthly streanflows at each project. This period is considered to be a rather long one for the Alaska streamflow records. In this phase of the formulation studies, monthly flows were used to establish e.<pected power a.'ld energy production and, consequently, the ins t a 11 ed capac it i es . A summary of annual average energy production ·is given in Table 7.3.5. The month1y ~nergy values are given in Appendix B. (b) 9.!.!::'7"-Engineering and Cq~t Stu<!,1.es The costs of the hydroei ectric facilities were estimated at each site. Quantity takeoffs P-civil items based on preliminary layouts and unit rJrices adjusted :or Alaska conditions v:ere used to establish costs for specific installations at each site. Pecent experience with prices of mechanical and elactrica,l equipment on similar projects was also used. The estimates are at the January 1, 1980 pr·ice level and include the land requirement5 and transmission line I I I I I I • I I I I I I I I I I I 1- .~ .. costs~ as well as contingencies (20 percent) and engineering and administration adjustments (10 percent). The final figures include also an allowance for interest during construction. Operation and maintenance costs were ad.':>pted in 1 ine with average experienced costs cf existing hydro projects in the Railbelt Region as presented in FERC data. The annual costs are $22 per kilowatt for all plants considere~. The project cost results by major account are presented in Table 7. 3.16. The conceptual 1 ayouts frar1 which the estimates were developed are presented for each site in Figure 7.3.11, inclusive .. TABLE 7.3.5 OPERATING AND ECONOMIC PARAMETERS (Ten Selected Hydroelectric Plants, Rail belt, Alaska) Rated Installe~/ Head Capacity No. Site River Ft. MW 1 s~ow Snow 640 120 2 &, uskasna Nenana 210 70 3 Keetna Talkeetna 295 110 4 Cache Talkeetna 266 75 5 Browne Nenana 162 210 6 Ta 1 keetna-2 Talkeetna 304 83 7 Hicks Mo.tanuska 262 265 8 Chakachamna Chakachatn a i'93 485 J Allison A 11 i son Creek 1,170 7.3 10 Str andl ine Beluga 710 28 Lake 1/ Based on operating the. projects for power production. 2/ For capacity f3.ctors between 0.11 and 0.55. -r; Includes interest dur~ng Consttut.tion. Annualf./ Capital~./ Energy Costs GWh $/kW 300 2.475 114 4460 463 4760 180 6750 360 4990 245 5080 246 1'1"'70.1"\ t:.l .u 1938 2870 34.7 8050 85.7 4980 I .I I I I I I I I I I I I I I I I {• {p, Jo 7.3~ -Thermal Generating Resources-Fuels The purpose of this section is to define the thermal generating resources available to the Railbelt during the 1980-2010 studj period. To addres!:; thermal resources~ it is necessary to review the existing thermal capacity, fuel availability and associated costs future plant capacities and capital costs for development. To develop the parameter~ necessary for generation planning studies, it is also necessary to assess ooeration and maintenance costs and planned and forced outages. The contents of this section document the data used in the generation planning study phase described in Section 7.4. 7·(o.s;:el Availability and Costs Fuel supplies available in the Railbelt region for future electric generation plants are primari· . .f coal and natural gas resources. Oil and geothermal resources, althougf", not expected to play major roles, are discussed briefly. It is un~ikely that oil will be used as the primary fuel for additions tc.. the generation system in the Rail belt due to public policy and high value for other uses. Tables 7.3.6, 7.3.7 and 7.3.8 summarize estimated fuel reserves. Table 7.3.9 lists current (1980) fuel prices in the Railbelt Region while Table 7.3.10 sumnarizes the developed fuel costs which represent shadow (opportunity)· values assuming active :~~~¥:tional mar•,eting of Alaska fuels. -Coal \)) Coal Avail abi·l ity Alaskan coal reserves include the following coal producing fields. (Reference 2): ' ~ Nenana ~ Matanuska ~ Beluga ~Kenai . ~ Bering River ~ Herendeen Bay .ffi Chignik Bay Of these eight regions, only four have potential for Rai1be1t use. Table 7.3.6 lists pertinent information of these coal reserves. The Nenana coal field, rrimarily leased by the Usibell i Coal Mine Incorporated, is located in the vicinity of Fairbanks. The field ranges from less thl'n ~ mile to mm~e than 30 miles in width for about 80 miles along thr north flank of the Alaska Range. Nenana coal is primarily mined by surface methods. An estimated 95 million tons of potetial stripping coal is -·~ ·-- -... - - - - -... -.. - --- TABLE 7.3.6 AL.~ RAILBELT COAL DATA {Proximate and Ultimate Analysis) 1-EATIMJ APPROXIW\TE % % % % VJlJ.J.f ~ ASlM RESERVES MJISTlRE \Kl.ATILE FIXED ASH BTIJ/LB % % % % SllliFI.R mJlL FI ELO RJW( M-1 TOOS (RJV«) Ml\TIER CJlRBON OW«) (RAta:) c H N 0 (~) ~ 2400 {12-33) (3-25) (7200-(llt..2) tna Coal District) 8900) Water Fall Sub Bit C 20.56 36.62 34.68 8.14 8,665 49.9 6.0 0.56 35.2 a~lls Y~ntna #2 Lwr Ligtite 29.00 38.26 28 .. ·1 3.33 7,943 45.2 6.8 0.53 44.1 OU!.l Kenai Cabin Sub Bit C 23.01 35.63 32.71 8.65 8,1028 47 .. 2 6.1 0.62 37.2 0~3 Nencrta Sub Bit (17-27) (3-13) {7500-{@t.~ .... o.3 > --9400) Poker Flat #4 Sub Bit C 25.29 32.51 32.55 9.85 7,779 45.3 6.3 1.10 . 37.1 (\~ ' .. Poker Flat #6 Mid Sub Bit C 25.23 35.71 31.40 7.66 8,136 46.1 6.3 0.60 39.2 O.,t2 ~se Sean Sub Bit C 21.42 36.62 34.88 7.68 8,953 51.7 6.3 0.81 33.3 o" ~s . .,..u.,., Caribou Sean 500 Bit C 21.93 35.88 32.85 9.34 8:;567 49.4 6.1 0.69 34.3 0,13 #2 Sean Sub Bit C 26.76 33.12 32.25 7.87 7:;966 46.4 6.4 0.63 38.5 Q,lq Jarvis Creek Sqb Bit C a>.58 36.20 34.16 9.(X) 8,746 49.8 5.8 0.86 33.4 1~05 Matanuska 100 (2 -9) (4-21) (10,300-(OJ~ ... l.O) (1 imited) 14,£m) Castle ~buntain UvAb 1.78 28.23 52.20 17.78 12,258 69.3 4.7 1.60 6.3 0 .. 46 Pre,nier lN Bb 5.87 35.73 43.96 14.44 11,101 63.6 5.1 1.60 15.3 o .. ss Kenai Sub Bit C 30J (21-30) (3-22) (6500- ' (0~1-0.4) 8500) References: Alaskan Coal and the Pocific, 1977 Ref (2) AStl£. "Burning Coa1 in Alaska-A Winter Experience", Jl~, 1980 Ref (1) fvM = million. ·~ . I I I I I I I I I I I I I I I I I I I TABLE 7.3.7 ALASKAN GAS FiELDS Remaining Reserves* LOCATION/FIELD North Slope: Prudhoe Bay East Umiat Kavik Kemik South Barrow+ TOTAL Cook Inlet: Alber~. Kaloa Beaver Creek Be lug a B,irch Hill Falls Creek Ivan River Kenai Lewis River McArthur River Moqu awk i e Nicolai Creek North Cook Inlet Nm·th· Fork North Middle Ground S~oal Sterling Swanson River West Fore 1 and West For!< TOTAL Gas (BCF) 29,000 Unknown Unknown Unknown 25 29,025+ Unkr,own 24G 767 20 80 5 1313 Unknown 78 None 17 1074 20 125 2: 300 120 7 4189+ D Product Destination or Field Status Pipeline construction to lower 48 underway Shut-in Shut-in Shut-in Barrow residential & commercial users. Shut-in Loca 1 , Beluga River Power Plant (CEA) Shut-in Shut-in Shut-in LNG Plant, Anchorage & Kenai Users Shut-in Local Field Abandoned Granite Pt. Field LNG Plant Shut-in Shut-in Kenai Users Shut-in Shut-in Shut-in Reference: (14) From Alask~ Oil and Gas Conservation Commission. + Producing . * Recoverable reserves t~stimated to show magnitude of field only. BCF = billion cubic feet I I I I I I fj I I I I I I I I I I I TABLE 7.3.8 ALASKAN OIL FIELDS LOCATION/FIELD North Slope: Prudhoe Ba,v+ Simpson Ugnu Umiat Cook Inlet: Beaver Creek Granite Point McArthur River ~iddle Ground Shoal Redoubt Shoa 1 Swanson River Trading Bay Recoverable Reserves* Oil (MMbb 1) 8375 Unknown Unknown Unknown TOTAL 8375+ 1 21 118 36 None 22 4 TOTAL 198 Product Destination or Field Status Pipeline to Valdez Shut-in Shut-in Shut-in Refinery Drift River Terminal Drift River Terminal Nikiski Terminal Field Abandoned Nikiski Terminal Nikiski Terminal Reference: (14) From Alaska Oil and Gas Conservation Commission. + Producing * Recc~'erable reserves estimated to show magnitude of field only. MMbbl =million barrels I I .I I I •• I I I I . I I I I I I I I I TABLE 7.3.9 EXISTING ALASKAN FUEL PRICES FUEL SOURCE/USE Coal Healy/Mine-Mouth (G\/EA) Healy/Fa i roanks {FMUS) Average Lower 48 DOE Region 10 DOE U.S. Average Natural Gas Kenai~Cook Inlet/ Anchorage Utilities AMLPD CEA Be 1 uga Other Average Cook Inlet/LNG export to Nikiski Average Lower 48 DOE Region 10 DOE U.S. Average Oil Prudhoe Bay/Fairbanks Utilities GVEA FMUS Average Lower 48 DOE U.S. Av1::2rage Healy Coal = 8,500 Btu/lb Natural Gas = 1005 Btu/cf COST $80/MMBTU REFERENCES 1.25 (1) & (14) 1.40 (1) & (14) 1.35 (9) June 1980 1.55 (45) October 1980 1.46 (45) October 1980 1.00 (31) 0.24 (9) June 1980 1.04 (9) June 1980 0.34 (9) June 1980 4.50 -4.65 (46) 1.98 (9) June 1980 4.89 (45) October 1980 3.58 (45) October 1980 3.45 (31) 4.01 (32) 5.44 (9) June 1980 4.63 -4.93 (45) October 198C I- I I I I I I I I I I I I I I I I I I () TABLE 7.3.10 SUMMARY OF FUEL PRICE ANALYSES MARKET PRICE TRANSPORT COST FUEL Mfl.RKET VIA $/MMBTU COA!. r'aC ific NW barge 1.55 Lower 48 barg@. 1.46 Japan barge N/A Japan Pl acer-Amex N/A Japan barge N/A Japan 8-H-W N/A NP,TURAL Region 10 LNt:. tanker 4.89 GAS Region 10 Pipeline spur 4.89 Lower 48 LNG-tanker 3.58 Lower 48 Pipeline spur 3.58 Japa.n LNG-tanker 4.50-4.65 OIL Lower 48 Pipeline- tanker N/A * from Beluga Coal Studies Reference (16 ,27 and 50) ** estimated $/MMBTU 0.50 0.63 N/A N/A N/A N/A 2.50 1. 97 2.50 1.97 3.00** N/A ALASKAN OPPORTUNITY VALUE $/f.'1MBTU 1.05 0.83 1.33 1.33* 1.00-1.30* 1.00 1.30 2.39 2.92 1.08 L61 1.50-1.65 4.00 0 I I I I ~· I I I I I I I I I I I I I I ·~ I \ \ potential stripping coal is\available. Underground mining could extract total coal resources in excess of 2 billion tons. The Matanuska coal fields occupy most of the Matanuska Valley to the east of Anchorage. Although stripping and undergound mining occur; however, stripping is limited due to relatively steep dips and increasingly thick overburden. Reserves are estimated at 50 million tons, and ultimate resource value may be 100 million tons. Local limited usage is possible; however, potential ~s a Railbelt source in .. . unlikely. (Reference 3) The Kenai coal field is in the Kenai lowlands, south of Tustumena Lake on the eastern shore of Cook Inlet. Resources ar·e estimated at 300 million tons. However, these coal seams are thin and vertically separated vertically making mining extremely difficult .. The fourth potential coal producing 11gion, the Beluga field, which is part of the larger Susitna Coal District, is located 45 to 60 miles west of Anchorage on the west bank 'Jf Cook Inlet, would require the establishment of a mining operation, transportation system and supporting community and infrastructure where none exists. A number of studies have been conducted on the reserves 1 ocated in the Beluga Coal Fields. It has been estimated that three are~s--the Capps, Chuitna and Three Mile field--contain 2.4 billion tons of coal and that in excess of 400 mi 11 ion tons can be stripped Y~rithout exceeding the coal/overburden ratios for commercial coal extractions. A . .....,, i - I I I I I I I Ia I I I I I I I I I I I Current and Potential Coal Use Limited use of coal in the Railbelt at present is a result of an undeveloped export market and the re·latively small local demand for this fue1. Currently! the Usibe1li Coal Company mines Nenana coal at a facility located in Healy that produces approximately 0.7 million tons/year. This coal represents the only major commercial coal operation in Alaska.. The coal is trucked several miles from the mine site to a 25 M~J power· plant owned and operated by tre Golden Valley E1ectric Association (GVEA) at Healy~ where the delivered cost is $1.25/Mr4Btu. The Nenana coal is also trucked to a railway spur loading station at Suntana 8-1/2 miles away for transport to Fairbanks (111 miles). The Chena Station {4 units, total capacity 29 . MW) is owned by Fairbanks Municipal Utility System· (FMUS) and uses this coal at an extra cost of approximately $0.34/MMBtu for .,) transportation costs tarrifs bringing the price for FMUS to $1.40/MMBtu. Healy coal is also used for generation in utlits at Fort Wainwright rlrmy base and the University of Alaska power plants. Interest in the Nenana coal field f.Jr expanded production includes four identified scenarios. Expansion plans for Healy coal propose to nearly double the production. Options include: I I 'I I I I I I I I I I I I I I I I I to the Pacific Northwest (Reference 28). Supplying Anchorage with coal via a new i"ailroild tie does not appear to be an option considered in the referenced report for the near future. The study of the Beluga Coal Field potential at the Bass-Hunt-Wilson (BHW) coal leases in the Chuitna River Field 1t1as completed by Bechtel Corporation in April 1980 (Reference 27). This study r-esulted in a 7. 7 MMTPY economic export production rate with no consideration of local coal-fired generating developments. Coal P ric~ An a l ys is Potential export markets for Beluga coal as defined in the previous section include: Lower 48; California and Pacific Northwest markets and Japan. The average market price for coal in the Pacific Northwest and California reg ion, as reported in June:. 1980 to the U.S. Department of Energy, t'anged from $1.t16/MMBtu to $1.55/~Btu which is slightly higher than the ave1age U.S. price. The costs for transporting a Beluga mined coal to the Pacific Northwest or to California were estimated in a 1977 Report (Refer~nce 2) on "Alaska Coal and the Pacif·icn. These prices were estimated and appear in 1 Tab 1 e 7 • 3 .1 0., A Teport .~sued in December 1980 by Battelle Pacific Northwest Laboratcr·y (Reference 50) analyzed marked opportunities for Belugil Coal; with results generally consistent with earlier Bechtel and DOE reports. I I I I I I I I I I I I I I I I I I I 1 The two Be lug a Coal studies done for P 1 acer-Amex and the Bass-Hunt-Wi1son vem:ure have resulted in opportunity costs for coal of $1.00 -$1.33/MMBtu. For purposes of this study the value of $1.15/MMBtu will be used for future coal generating plants to be cons~~ucted in Alaska as seen in iable 7-5. ~ ~-~ -Natural Gas \S) Natural Gas Availability Natural gas resources available or potentially available to' the Railbelt region include the North Slope (Prudhoe Bay) reserves and the Cook Inlet reserves. Information on these reserves is summarized in Table 7.3.7. The Prudhoe Bay Field contains the largest accumulation of oil and gas ever discovered on the North American continent. The in-place gas volumes in the field are estimated t.o be in excess of 40 trillion cubic feet (Tcf). Estimates of the portion of in-place gas that can ultimately be recovered range up to 75 to 80 percent. ~Hth losses consid~red, recoverable gas reserves are estimated at 29 Tcf. Gas can be made available for sale from the Prudhoe Bay Field at a rate of at least 2.0 billion cubic feet per day (Bcfd) and possibly slightly more than 2.5 Bcfd. At this rate, gas de,tiveries can be I I I I I I I I I I I I I I I I I I I sustained for 25 to 35 years, depending on the ~ales rate and ultimate gas recovery efficiencyo The Cook Inlet Reserves as seen in Table 7.3.7 are relatively sma1l in comparison to the North Slope reserves. Gas reserves are estimated at 4. 2 Tcf as compared to 29 Tcf in Prudhoe Bay. Of the 4.2 Tcf, approximately 3.5 Tcf is available for use 7 the remaining reserves are considered shut-in at this time. ~Current and Proposed Natural Gas Use During the mid-seventies, three natural gas transport systems were proposed to market natural gas from the North Slope Fields to the lower 48. Two overland pipeline routes (Alcan and Arctic) and a pipeline/LNG tanker (tl Paso) route were considered.· The Alcan and Arctic pipeline ~outes traversed Alaska and Canada for some 4000-5000 miles, transporting natural gas to the central U.S. for distribution east and west. The El Paso proposal involved an overland pipeline route that would generally follow the Alyeska oil pipeline utility corridor for approxmately 800 miles. The liqusfaction p·lant would process approximately 37 million cubic meters of gas per day and the transfer station was proposed at Point Gravinia south of the Valdez termination point,. Eleven 165,000 cubic meter cryogenic tankers would transport the LNG to Point Conception in California for reg as ificat ion. ...... • , : • o • • • :·_".yl • • -•: ' '"• f., 0 :_; \o 0 ~ ,'t-· ._ ,· •, ,. I I I I I II I I I I I I I I I I I I I The results of these studies was the ·initiation of a 4800-mile, $22 - $40 billion1 2.4 Bcfd~ Alaska-Canacta Natural Gas pipeline project expected to be operational by 1984-1985. The pipeline project passes approximately 60 miles northeast of Fairbani<s. The gas production capability in the Kenai Peninsula and Cook Inlet region far exceeds demand, as no major transportation system exists to export markets. As a result of this situation, the two Anchorage 2lectric utilities utiliz" natural gas at a very economical price. Export markets for Cook Inlet natural gas include one operating and one proposed L~G scheme. (1) The Nikiski terminal owned and operated by Phillips-Marathon on the eastern shore of Cook Inlet trru Jports LNG some 4000 miles to Japan vi.:.i two l iberian cryogenic tankers. Volume produced is 185 MMCFD with raw natural gas requirements of 70 percent from a platform in Cook Inlet and 30 percent from existing onshor-: fields. (2) Pacific Alaska LNG (PALNG) Company (as of 1979) intends to ·;hip LNG to Ca 1 iforn·i a from another term ina 1 to be constructed at Nikiski on the Kenai Peninsula. The plant will utilimately process up to 430 MMCFD for shipment via two cryogenic tankers •• I I I I I I I I " I I I I I I I I I I • ..,, . . . · .. -~ . ,.J-i. f • • .. ~. ~ • I \. ....--..,.A.;Po ~ •• • , • • "' • • • ~ -~· ~ , •' .t 4-. .,. , F ..:.~.: j . .. :: ' '· • , •. to Little Cojo near Point Conception, California. The Federal E'"'ergy Regulatory Commission (FERC) has plact~d a rider on the project permit, stipulating that in-place and ~ommitted gas reserves must total 1.6 Tcf before a license is granted. To date PALNG estimates 1.0 Tcf is in place. (3) There i.s also some potential for a gasline spur to be ' constructed from ~he Cook Inlet region some 310 miles north to intersect with the Alaska-Ca.nada Natural Gas pipeline project in order to market the Cook In 1 et gas. This concept has not been exteniively studied but could prove to be a viable alternative. ~ Natural Gas Price Analysis Markets for Prudhoe Bay gas were not considered in developing a cost for Railbelt fuel alternatives since ~n existing market and transportation system has been developed· with the inception of the Alaska-Canada pipeline project. Markets for Cook Inlet gas include the lower 48 via two transporta·~ion modes; LNG tankers or a pipeline spur cnnstructed fr·om Anchorage to Delta Junction and inter~.·ect with the Alaska-Canada •\ '· .. . .. . '· ,· ,, I I I I I I I I I I I I I I I ·I I I I pipeline. The regulated ceiling market price for natural gas on the west coast as reporte~ in the Federal Register, Department of Energy, Tuesday October 27, 1980 was $4.89/MMBtu 111 the Region 10 area (Washington, Oregon, California) and $3.58/MMBtu as the average U.S. price. The LNG tanker scheme as proposed by PALNG was estimated to cost $2.50/MMBtu for transportation and processing. A 310 mile pipeline sp~r was estimated based on cost data available from the current pipeline r· ject and would be expected to be $1.97/MMBtu which represents tne incremental cost of the Alaskan-Canada pipel1~e and the c.ost of the tap frr~m Cook Inlet ($1.27/MMBtu plus $0.70/MMB\'U respectively). Table 7.3.10 lists the ~esulting Alaskan opportunity values under these assumptions for markets in Region 10 and the Lower 48 based on the two transpor"tat ion routes; LNG-tanker and Pipeline Spur. The current Japan market price for natural gas from the Nikiski LNG project sales is $4.50 -$4.65/MMBtu per Dr. Charles Logsdan of the I State of A 1 ask a Department of Revenue (Reference 46). Based on information collected from Nikiski the transportation/proce~sing costs·were estimated to be $3.00/MMBtu which results in an Alaskan opportunity value of $1.50 to $1.65/MMBtu. The prices developed in this analyses range from $1.08 to $2.92/MMBtL:. For purposes of this study $2.00/Mt~Btu was adopted as th0 opportunity value of natural gas in Alaska. .. : -. . ·_ :.. . . . ---:----.; _, . ~, .~. . . · .. ·· :_ · ..... '. ~-. r·.·· ,. /... . ., . . . •. • I . . :: . I . ·. . ' . ~ . I I I I I I I I I I I I I I I I I I I ~) 4=.3.3\3 -Oil 0 Oi 1 Avai 1 ability Both the North Slope and the Cook inlet Fields have significiD~ quantities of oil resour·ces as seen in Table 7.2.8 .. North Slope reserves are estimated at 8375 million barrels. Oil reserves in the Cook Inlet region are estimated at 198 million barrels (Reference 14). As of 1979, the bulk of Alaska crude oil production (92.1 percent) came from Prudhoe Bay, with the remainder from Cook Inlet, and net productiJn was increased to 1.4 million barrels ~er day (Reference 11). ~Current and Proposed Oi'l Use Oil resources from the Prudhoe Bay field are transported via the 800 mile t_rans-Alaska pipeline at a rate of 1.2 million barrels per day. In excess of 600 ships per year deliver oil from the. port of Valdez to the west, Gulf and east coasts of the U.S. Approximately 2 percent (or 10 millicm barrels) of the Prudhoe Bay crude oil was used in Alaska refineries and along the pipeline route to power the pump stations (Reference 14). . . 1· ..... ~ I I II I I I I I I I I I I I I I I 1 . ' .I'. . I . . ~ . ,. . ; .. . , . . . . .. f . . . ·. . 1 • . ... . . . The North Pole R1:finery processes 25,000 barrels per clay at a plant located 14 miles southeast of Fairbanks connected to the pipeline via a spur. The refinery produces home heating oils, diesel and jet fuel. Much of the installed generating capacity of Fairbanks utilities rely on oil for muc~ of their generation. FMUS has 38.2 MW of oil-fired capacity and GVEA has 186 MW using oil as fuel. Du~ to the high cost of the oil, these utilities use the coal-fired capacity as much as possible with oil used as standby and for peakjng purposes. ... • Crude oi 1 from Kenai offshore and onshore oil fie ids is refined at Kenai primarily for use in state. Thermal generating stations in Anchorage have need for stand by capacity fired by oi 1. ~bil Price Anal.ysis Since the installation of the Alyeska oil-pipeline, which has made Alaskan oil marketable the opportunity cost to Alaska has been experienced as the existing price. The contracts for oil to utilities has ranged from $3.45/MMBtu to $4.01/MMBtu as reported to FERC. For purposes of the generation expansion study where oil is considered only available for standby units the price adopted for bse w i 11 be $4. 00/MMBtu as shown in Tab 1 e 7. 3 .10. . I I I I I I I I I I I II I I I I I I I 7.3.3.4-Geothermal Of the numerous geothermal sites identified in the state, only a few are located in the South Central Region encompassing the Railbelt (Reference 35). Of these, all but one are low temperature (100-200~F) and therefore feasible only a~ sources for building or process heating. The Klawasi site, located east of Glenallen 9 has been recently investigated for electric power generation potential. A proposa1 for devel orxnent was made, but hc.s not been funded. No user of the power to be !Ji ~j!~-:ca was identified~ undoubted 1 y because no major transmission connection bet\'leen or near the site to populated areas to the south or west exists. Geothermal energy would be petent1a11y used as suggested in the reference, if the Alaskan pipeline corridor becomes populated, s ·!nee the geothermal site is near the route of the ') , , 1ne. Based upon available data~ a potentia_, site capacity on the order of several hundred MW may exist, although only a 25 MW development is discussed. Unless a transmission loop paralleling Alaskan highway Routes 2/4 or 1 is constructed, the likelihood of a geothermal development at this location supplying any of the Railbelt needs is remote. I I I I I I I I I I I I I I I I I I I 7.3.4-Thermal Generating Resources Engineering, Environmental and Co~~t Studies 7.3.4.1 -Environmental The inclusion of air pollution control equipm~nt for thermal generating resources is based on $atisfaction of the national New Source Performance Standards (NSPS) and the National Ambient Air Quality Standards (NAAQS) (Reference 36). It is assumed that compliance with NSPS and NAAQS for the final site selection for specific facilities will as~.wre compliance with the Prevention of Significant Deterioration (PSD} aspects of air quality regulation. The State of Alaska has adopted the National Ambient Air Quality Standards, with the addition of a standard for reduced sulfur compounds (Reference 37). The State may also require measures for contra 1 of ice fog (Reference 38). Three New Source Perf Jrmance Standards cover the plant types under consideration. The NSPS for Electric Ut :ity Steam G~neratin9 Units is applicable to coal-fired ste001 units. Specific standards are set for control of sulfur riioxide, particulate, and nitrogen oxide·s. For the ·coal-fired units, the use of avail able combustion technolOi1Y is accepted for control of NOx. Flue gas desulfurization is required .. -.. . . . • ' -! ' ~ • -"1..-. . ' . I I I I I I I I I I I . I I I I I •• I I . . . .., t. ~ ~... !~ .~.. . .. ... -~ ~... .. ~ l • • ~~ •.•• •• . • : .()... • ~. .. • • • -~ • • •• ~ ·". r~t. McKinley ~ational Park is designated as Class I area. A plant located in the vicinity of the Park would be subject to the scrutiny of the effects of its emissions on visibility and air quality within the park. A few other Class II areas are in noncompliance with one or more of ambient air quality standards (Anchorage and Fa.irbanks - North Pole urban areas are presently the only examples) or are very close to exce~ding the PSD increment allowed for the airshed {3uch as Valdez). Complianr.e with stricter regulations in any of these. $ensitive areas could incur higher pollution centro; costs, or could effectively result in barring the development of a thermal p1ant in that area. It is ·fikely that new thermal plants will not be located in these areas if the cost of additional pollution control equipment substantially affects the cost of-energy supplied to the consumer. These siting limitations, however, barely touch the number of possible plant locations within the Railbelt .. Therefore, the assumption of compliance with NSPS is felt to be satisfactory for -air pollution control costs. The costs for other environmental controls are also included in the cost estimates. These controls are mandated by national and state water discharge standards, solid waste disposal standards, and occupational health and safety standards. These controls will have the greatest relative. impact on thE! cost of coal-fired pl~nts • I I I I I I I :I I I I I I I I I I ••• I 7,3.4.2 -Engineering and Cost Studies The capital costs of four different types of thermal generating plants considered avail able to the Railbelt region were estimated. Capital cost estimates for coal-fired steam 7 combined cycl~, gas tu·rbines and diesels appear in Tables 7.:.11 to 7.3.17. Table 7.3.18 summarizes ~ther generation parameters necessary for description in the generation planning studies. These tables are located at the end of Section 7.3 due to their length. Estimating the cost of thermal plants in Alaska 1s accomplished based on existing lower 48 data and research. Smaller gas turbine and diesel plants are modularized units sold in packages, so capital cost is readily obtainable from manufacturers. Coal-fir1.:d steam and combined cycle unit costs have been repnrted by EPRI which are used as the key reference in this study. I I I I :1 I I I I I I I I I I I I I I ·> Alaskan Location Adjustment Factors This study incorporate~ the use of Alaskan location adjustment factors. These factors represent cost increases to account for Ailaskan conditions, which differ from the contiguous 48 states. These conditions are Alaska's adverse weather, remoteness, lack of infrastructure and transportation facilities, 1 imited constr -.."" t ion season and high 1 abor prem1ums. All of these co•1ditions increase the cost in Alaska over a similar f~cility constructed in the contiguous 48 ~tates. The exact increase (factor) depends on the type of facility and actual location. Research by several organizations documented in the 1978 Battelle Report (Reference 3) 1 i st a range of factors fran a 1ow of 1.1 to a high value of 2.8 with a wide variation t1 values for a single location. Research by the Corps of Engineers (Reference 25) proposed a composite value of 1.5. For purposes of this study three values, 1.6, 1.8 and 2.2, were adopted from the Battelle Report to reflect condit 4;ons in Anchorage, Beluga and the Healy/Nenana/Fairbanks regions respectively. Coal-Fired Steam As previously reported there are currently at least four coal-fired steam plants in operation. Fairbanks Municipal Uti1ities System ( FMUS) operates the Chen a Plant with 29 MW capacity .. Another is operated by Golden Valley Electric Associat·ionQ(GVEA) in Healy with a 25 MW capacity. Two more supply Fort Wainwright and the University of Alaska at Fairbanks with heat and electric power. I I I I I I I I I I I I I I I These plants are small in comparison to the new electric ut n ity units under consideration in the lower 48 so that direct cos.: comparison is difficult. Another f~ctor that influences the capital costs is that any 1 arge, new, coal-fired plant will require extensive emission control equipment to meet EPA emission standards, pa·rticul arly in the Fairbanks area. This additional equipment as well as a longer construction periods and current high interest and escalation rates, has driven capital costs of new plants in the lower 48 states to much higher levels than previously experienced. These factors are reflected in the costs developed fer this study. Based on the projected plant capacity additions developed in previc:us studies, three coal-fired unit sizes were adopted for capacity additions; 100, 250 and 500 MW. It is unlikely that a 500 MW plant would be proposed in the Fairbanks region due to the large coal and demand requirements as well as the remote location. Therefore costs for 250 and 100 MW stean fac il it ies only were developed for Fairbanks. The basic cost of a coal-fired plant was extracted from Coal-Fired Power Plant Capital Cost Estimates, EPRI-AF-342 (Reference 17). EPRI . models the cost for a 1000 MW plant situated in a remote, western U.S. site (Reference Plant #4) having maximum emission control devices; flue gas desulfurization (FGD) and a heat rate of 10,500 Btu/kWh. This plant burns Wyoming coal which js very similar in properties to Alaskan coals (Reference 2 and 17}. The plant cost I I I I I I I I (I I I I I I I I I I I I was determined by first obtaining the base plant cost for two 500 MW units as seen in Tab 1 e 7. 3 .11. The 1976 cost estimates were upd~ted by the use of the Handy-Whitman Indices for the utility industry to ' . represent 1980 dollar estimates. In order to scale the 1000 MW co~~ estimate down to 100"' 250 and 500 MW, two methods were used. The first assumes that the cost for the first 500 MW unit is 54 percent of the total construction cost (Reference 3), therefore the estimate for a 500 MW plant was developed based on 54 percent of the cost of the 1000 MW plant. The scaling exponent was then ca leu l at~d to be r---Cost of ~000 MW X P 1 ant ...! .85 based on the (X)MW J ·85 1000 i'v1Wj following equation: = Cost of X MW plant Where X for this study is 100, 250 and 500 MW. . This equation was used to determine the costs of 500, 250 and 100 MW plants on the lower 48. These figures appear in Table 7.3.11. Using the Alaskan location adjustment factors; the total construction costs in the Rai lbelt area we'te estimated. To this ~1as added contingency of 16 percent, utilities and other constructioo costs (10 percent), engineering and administration (12 percent). Interest during construction costs were calcu I ated using symmetric S-shaped cash flow · model (Reference 23), 0 percent escalation, a six-ye.ar construction period for 500 and 250 MW plants; five-year construction period fo~ I I I I I I I I I I I I I I I I I I II I 100 MW plants. Total capital costs calculated are shown in Tables 7.3.12, 7.3.13, and 7.3.14). The cost values presented in these tables reflect total capital cost for building a coal-+"ired steam plant in the different Alaskan locations. Outages for coal-fired steam plants are reported as planned (scheduled) and forced outages as a percent of time. Edison Electric Institute (EEI) (Refer~nce 41) reports a forced outage of approximately 5~4 percent for large coal-fired plants. The EEl figure of 5.4 percent was rounded to 5 to represent forced outages. Planned outages, as reported by GVEA for their Helly, A1aska plant are in the 5.1 to 16.3 percent range. An average of 11 percent, which corre 1 ates with the EEl data, was adopted as the plan ned outage rate for coal fited plants for this· study. Operation and Maintenance (O&M) costs are divided into two compone,nts; fixed costs and variable costs (not including fuel). Fixed O&M is quoted as $/yr /kw in the DOE Steam Plant Construct ion and Annual Product ion Expenses (Reference 21) and trends indicated a fixed cost of 0.50, 1.05 and 1.30 for a 500 MW, 250 MW and 100 MW plant respectively. Variable costs are also quoted in the DOE publication. The costs decrease with increasing unit size. The .. values used i~ this study are $1.40, $1.80 and to $2.20/yr/kW for a 500 MW, 250 MW and 100 MW plant respectively. I I I I I I I I I I I I I I I I I I I ~ Combined Cycle There are two combined cycle plants in Alaska at present. One is operational and the othei~ is under construction. The operational unit is owned and opera ted by Anchorage Municipal Light and Pott1er Department (AMLPD). This unit, the George M. Sullivan plant, () consists of three units \>Jhich when operating in tandem producL a net capacity of 140.9 MW. The plant under construct·~on is the Beluga tf9 unit owned by Chugach Electric Association (CEA) and will add a 60 MW steam turbine to the system sometime in lq82. A new combined cycle plant of 250 MW capacity was considered to be representative of future additions in the Anchorage are~ based on projected designs ';n the lower 48 states and experience in Alaska. A combined cycle plant in Beluga was not considered. A heat rate of 8500 Btu/kWh was adopted based on Alaskan experience and EPRI AF-610; Combined Cycle Power Plant Capital Cost Estimates (Reference 18). General Electric Corporation quoted a lower 48 cost for the combined cycle unit which appeaYs in Table 7.3 15. An estimate was made for the costs of foundations and buildings, fuel handling facilities,. other mechanical and electrical equipment and a cost of 25 percent for transportation of the basic unit anywhere in the lower 48. These costs were based on prior combined cycle power plant capital cost {EPRI-AF-610) (Reference 18): To this in-place total cost 16 percent I I I I I I I I I I I I I I I I I I I contingency, 10 percent for utilities and construction facilities, and 12 percent for engineering and administration was added. A$suming a construction period of three years, 0 percent escalation and 3 per~ent cost of money and an S-shaped cash flow model, the total capital costs were obtained. Using the location adjustment factors of 1..6 and 2.-2, the values were adjusted for a plant located in Anchorage and Fairbanks as seen in Table 7.3.15. Based on information provided by Anchorage Mur.icipal Light and Power Department (AMLPD) on their G.M. Sullivan units 5-7 combined cycle plant (140 MW), the planned outages are approximately 11 percent. Assuming for a larger plant at ?50 MW and correlating with EEI data a 14 per~ent planned outage was 5elected. Forced outages of 6 percent were also considered appropriate from the AMLPD and EEI. 6 Operation and Maintenance (O&M} costs for large combined cycle plants as reported in EPRI AF-610 (Ref@r~nce 18), is approximately $2.75/yr/kW fixed O&M and $0.30/~1Wh variable 0&\1. ~ Ga~ Turbines Gas turbines are by far the main sourc.e of thermal power generating resources in the Railbelt area at ~resent. There are 470.5 MW of installed gas turbines operat fng on n;;tural gas in the Anchorage area r:tnr: approximately 168.3 MW of oil-fired gas turbines supplying the I I I I I I I I I I I I I I I I I I I Fairbanks area, Their low initial cost, simplicity of construction and operation as well as currently available low cost fuel (gas) have made them very attractive as a Railbelt generating alternative. A unit size of 75 MW was cons'idered to be representative of a moder·n gas t·Jrbine p-!ant addition in the Railbelt region .. However, the possibility of installing gas turbine units in Beluga was not considered, since the Beluga mine-mouth development is intended for coal. The potential for coal conversion to methanol (synfuel) may be a possibility; however, that consideration is t tond t~~ scope of this study. The gas turb-ine plants are assumed to be built over a two year construction period. (Reference 22) The base plant costs are obtained from the Gas Turbine World Handbook (Reference 19), which lists awarded contracts and 11 turnkey 11 costs in 1978 dollars in Anchorage, and are quoted in Table 7.3.16 along with the average heat rate of 12,000 Btu/kWh. The costs were escalated using the Handy-Whitman indices to 1980 dollars. A 10 percent increase was included for construction facilities and utilities as well as a 14 percent Engineering and Administra~ion fee and a two year IDC cost. Fairbanks costs are estimated using a factor of 0.6 (2. 2 ·· 1. 6) to adjust the Anchorage figures. I I I R I I I I I I I I I :I I I I I " Three sources of data were consulted for p1anned and forced outages of gas turbine units--the EEI report, information from AMLPD and from GVEA. Planned outages are approximately 11 to 12 percent and forced outages estimated at 3.8 percent appear to be valid based upon utility experience. Operation aud Maintenance (O&M) co~ts ar·e simil iar to combined cycle units and are adopted as $2.50/yr/kw and $0.30/MWh for the fixed and ~ariable components. These values reflect intermediate levels of 0 & M costs in the FMUS/GVEA Net Study (Reference 32). D iese 1 s Most diesel plant-s in operation tuday are standby units or peaking generat~on equipment. Nearly all the continuous duty units have been placed on standby service for several years due to the high oil prices which have made them very expensive to operatr:. The situation in Alaska has required the installation of many small diesel units •• '· I ,. I I I I I I I I I I I I I 'I I estimate was made of the auxiliary plant facilities (building, foundations, etc.} as well as fue.l facilities a.nd switchyard in Alaska. A transportation charge for bringing the basic unit to Alaska was estimo.ted and included in total construction costs. A construction perio~ of one year was assumed since these plants are modular and quick to assemble. The three sit~ estimates along with contingencies (16 percent), construction facilities and utilities (10 percent), engineering and administration (14 percent) and IDC for the one-year cr.:n;struction period appear in Table 7.3.17. An average cost of $778/kW was developed and used for the ehtire Railbelt region regardless of location ba5ed on the modular and rapid construction techniques associated with these sm--11 diese1 units. Di ese 1 tJnits have very lo~f (1 percent) p 1 an ned outage rate based on EEl utility experience. Forced outages ~~e reported as 4~4~5.0 percent for diesels .·and 5 percent was adopted· for the system planning studv. ' D·iesel Operating and Maintenance (O&M) costs as quoted in the Williams Brothers Report for GVEA and FMUS (Ref~rence 32) are -:onsidered typical to the Alaska Region and are used for th~is study. Fixed cost equal to $0.50/yr/kw and $5.00/MWh variable costs. .. I' I I I I I ~I I I I I I I I I -· I I I TABLE 7.3.11 1000 MW COAL-FIRED STEAM PLANT COST ESTIMATE* LOWER 48 -· ACCOUNT/ITEM 10 Concrete 20 Civil/Structural/Architect~ral 21,22~24 Structural & Misc. Iron & Steel -25 Archi'tectural & Finish 26 Earthwork 28 Site I1nprovements 30 Steam Generators 41 Tut"bine Generators 42 Main Condenser & Auxiliaries 43 Rotating Equipment, Ex. T/G 44 Heaters & Exchangers 45 Tanks, Drums & Vessels 46 Water Treatment/Chemical Feed 47 _foal/Ash/FGD Equipment 47.1 Coal Unloading Equipment 47.2 Coal Reclaiming Equipment 47.3 Ash Hand1 ing Equipment 47.4 Electrostatic Precipitators 47.6 FGD Removal Equipment 47.8 Stack (Lining, Lights, etc.) 48 Other Mechanical Equipment Incl. Insulation & Lagging 49 .!:Leating, Ventilating, Air Conditioning 50 Piping 60 Control & Instrumentation 70 Electrical Equipment (Switchgear /Tr· ansformers/ MCCs/Fixtures) 80 Electrical Bulk Materials 81,82,83 Cable Tray &.Conduit 84,85,86 Wire & Cable Switchyard CONSTRUCTION COST TOTAL 1976 $ .. $ 22.40 ' 23.70 11.90 23.70 14.80 119.70 48.40 4.20 12.80 3.70 1.50 2.40 3.50 3.40 1.40 61.30 87.90 5.20 9.70 1.70 44.60 11.10 11.30 11.6 0 13.40 11.30 $ 566"6 * Reference 17 EPRI-A-342, Plant #4, p. 8-5. ·$ MILLIONS HANDY--WHITMAN ADJUSTMENT 547/394 559/397 500/361 500/361 500/361 571/407 413/293 518/361 518/361 518/361 . 518/361 518/361 461/338 461/338 461/338 461/338 46li338 461/338 518/361 518/361 629/422 461/322 461/332 173/123 173/123 173/123 1<?80 $ -- 31.10 33.37 16.76 32.82 20.50 167.93 68.22 6.03 18.36 5.31 2.15 3.44 4.n 4.63 1.90 83 .. 60 119.88 7 .. 09 13.92 2 •. 43 66.47 15 .. 41 15 .. 69 16.31 18.85 15.89 I I I I I I I I I I I I I I I I I I I $ MILLIONS (1980) · SCALING FACTOR 500 MW .85 1000 MW $ 792.82 250 MW .85 1000 MW $ 792.82 $ 792.82 100 MW .85 1000 MW i .... I $ MILLIONS (1980) = $ 439.84 for 500 MW plant = $ 244.01 for 250 M~l p 1 ant = $ 111.98 for 100 MW plant I I TABLE 7.3.12 I 500 MW COAL-FIRED STEAM COST ESTIMATES - I I $ MILLIONS (1980) ACCOUNT /ITE~1 LOWER 48 ANCHORAGE BELUGA (1.6) (1.8} I 10-20 Civil/Structural/ I Architectural 72.66 1:.6.26 130.79 30-46 Mechanical Equipment 146.57 234 .. 51 263.82 I 47 Coal/Ash/FGD 131.52 210.43 236.73 . I 48-60 Other Mechanical 53.04 84.86 95.47 70-80 Electrical Equipment 36.05 57.68 r. 64.89 I Construction Cost Total 439.84 703.74 791.70 I Contingency (16 %) Subtota 1 510.21 816.33 918 .. 37 I Construction/Fac1lities/ Uti 1 ities (~0%) Subtotal 561.23 897.97 1010.20 I Engineering & Administration (12 %) Subtotal 628.54 1005.73 1131.43 I Interest During Construction I . (6 years) 58.63 93.73 105.45 Total Plant Cost 637.17 1099.46 1236.88 I $/kw 1374.00 $ 2199/kw $ 2473/kw I :1 I , . \. , I ·-;t: I G TABLE 7.3.13 I 250 MW COAL-FIRED STEAM COST ESTIMATES I $ MILLIONS (1980) I ACCOUNT/ITEM LOWER 48 ANCHORAGE BELUGA FAIRBANKS (1.6) (1.8) (2.2) I 10-20 Civil/Structural/ Architectural 39.23 62.77 70.61' 86.30 I 30-~6 Mechanical Equipment 79.15 126.64 142.47 174.13 I 47 Coal/Ash/FGD 77.52 124.03 139.53 170.54 48-60 Other Mechanical 28,.65 -45.84 51.57 63.03 I 70-80 Electrical Equipment 19.46 31.13 35.02 42.81 --I Construction Cost Total 244.01 390.41 439.20 536 .. 81 I Contingency {16%) Subtotal 283.05 452.87 509.47 622.69 I Construction/Facilities/ Utilities (10%) Subtota 1 311 .. 35 498.16 560.41 684.96 I Engineer-Ing & Administration (12%) I Subtotal 348 . .71 557.94 627.65 767.16 Interest I During Construction (6 years) 32.51 52.00 58.50 71.50 Tutal Plant Cost 381.22 609.94 686.15 838.66 I $/kw 1524.00 $ 2440/kw $2744/kw $3354/kw .. I I I I I ~ '. -"') "I TABLE 7.3 .. 14 I 100 MW COAL-FIRED STEAM COST ESTIMATES I $ MILLIONS (1980) I ACCOUNT/ITEM LOWER 48 ANCHORAGE BELUGA FAIRBANKS (1.6) (1.8) (2.2) I 10-20 Civil/Structural/ Arch itectura 1 21.19 33.90 38.14 46.62. I ·' 30-46 Mechanical Equipment 42.74 68~38 76.93 94.03 I 47 Coal/Ash/FGD 22.08 35.21 39.74 48.'5:7 48-60 Other Mechanical 15.47 24.75 27.85 34.03 I" 70-80 Electrical Equipment · 10.50 16.80 18.90 23.10 I I Construction Cost Total 111.98 179.04 201.56 246.35 Contingency (16%) Subtota 1 129.89 207.68 233.($0 285.76 I Construction/Facilities/ Uti 1 it ies (10%) I Subtotal 14?..88 228.45 257.19 314.34 Engineering & Administration (12%) I Subtotal 160.03 255.86 288.05 352.06 Interest I During Construction (5 years) 12.32 19.71 22.18 27.11 Total Plant Cost 172.35 275.57 310.23 379.17 I 0 $/~:w 723.00 $2755/kw $3102/kw $3791./kw I I •• I I TABLE 7.3.15 II 250 MW COMBINED-CYCLE PLANT COST ESTIMATES . 1· I I I I I I I I I I I I I I I ACCOUNT/ITEM 20 C iv i 1 /Structural I Architectura 1 21,22,23 Buildings/Struct. 26,28 Foundations Site Work 40 Mechanical 41-47 Generating Units 45 Fuel Handling 48 Other Mechanical 70/80 Electrical Equipment 100 Transportation Construction Cost Total Contingency (16%) Subtotal Construction/Facilities/ Utilities (10%) Subtota 1 Engineering & Administration (12%) Subtotal Interest During Construction (3 years) TotaJ Plant Cost $/kw .. LO~JER 48 2.83 5.63 37.50 1.40 5o28 11.79 (25%) 9.38 73.81 85.61 94.17 105.47 4.79 110.26 $442/kw $ MILLIOMS (1980) ANCHORAGE (1. 6) 4.53 9.00 60.00 2.24 18.45 18.86 FAIRBANKS (2.2) 6.23 12.39 82.50 3.08 11.62 25.94 (50%) 18.76 j (75%) 28.14 121.84 141.34 155.47 174.13 7.91 182.04 $728/kw 169.90 197.08 216.78 242.79 11.02 253.81 $1015/kw I I TABLE 7.3.16 I 75 M\~ GAS TURBINE PLANT COST ESTIMATES From Gas Turbine World Handbnok (Reference 19) Turnkey Anchorage 6Bids 1978 $ X 10 13.95 18.10 18.80 . 14.3 MW 63 75 77 78 $18.10 X 10 6 ~~~ = $20.58 X 10 6 I I I I I I I I I I I $ MILLIONS (1980) I I I I~ ~. ITEr4 Turnkey Cost Construct ion/F aci 1 it ies/ Uti 1 it i es ~10%) Subtotal Engineering & Administration (14%) Subtota 1 Interest During Construction (2 years) Total Plant Cost $/kw ANCHORAGE 20.58 22.63 25.80 0.52 26.32 $350/kw FAIRBANKS (2.2 -1.6}, 32.85 0 36.13 41.19 0.82 42.01 $560/kw . ' I ~ . I TABLE 7.3.17 I 10 MW DIESEL PLANT COST ESTIMATES I COHPANY BID $ MILLIONS (1980) I REFERE;!CE SUPERIOR PRODS. BELYEA CO. CUMMINS INT. ACCOUNT/ITEM (47) (48) DIESEL (49) I 20 Civil/Structural/Architectural 21-23 Buildings $ 0.72 $ 0.72 $ 0. 72 28 Found at ions 0.72 0.72 0.72 I 40 Mechanical 41 Generating Units 5.05 3,00 1.80 I 45-80 Auxillary Mechanical and Electrical Equipment 0.30 0.30 0.45 I 100 Transeortation 0.50 0.04 0.06 I Construction Cost Totals I in Alaska $ 7.29 $ 4.78 $ 3.75 Contingency (16%) I Subtotal 8.46 5.54 4.35 Construction/Facilities/ I Utilities (10%) Subtotal 9.31 6.09 4.78 I En~ eering & Administration (14%) I Subtotal 10 .. 61 6.94 5.45 Interest During Construction I (1 year) 0.16 .10 .08 Total Plant Cost 10.77 7.04 5.53 I $/kw $1077.00/kw $704.00/kw $553.00/kw Average One Cost = $778/kw @ 1.5 A 1 ask a Factor I I . , t . . ~ .. ' . . ·.• . . . . . . " . . .. . . . . .. . . t, ' ' • • ' • • • I --, .. -,..--... ------------- TABLE 7.3.18 SUMMARY OF THERMAL GENERATING RESOURl PLJ\NT PARAMETERS PLANT TYPE PARAMETER COAL-fiRED STEAM COMBINED-GAS-D!E~U CYCLE TURBINE Plant Size Considered: 500 MH 250 MW 100 MW 250 MW 75 MW 10 iMW Heat Rate (Btu/kwh) 10,500 10,500 10,500 8,500 12,000 11~500 O&M Costs Fixed O&M {$/yr/kw) 0.50 1.05 1.30 2.75 2.75 {},.50 Variable O&M {$/MWH) 1.40 1.80 2.20 0.30 0.30 s,oo Out ages P 1 anned Outages (%) 11 11 11 14 11 1 Forced Outages (%) 5 5 .5 6 3.8 5 Construction Period (yrs) 6 6 5 3 2 1 Start-up Time (years) 6 6 6 4 4 1 Economic Life {years) 30 30 30 30 gas-fired 30 30 oil-fired 20 Capital Cost ($/kw) Anchorage $2199/kw $2440/kw $2755/kw $728/kw $350/kw 0 Beluga $2473/kw $2744/kw $3102/kw Fairbanks $3354/kw $3791/kw $1015/kw $560/kw Rail belt $778/kw ""'"\ --~ --... --------------·J --· I TABLE 7. 3.16 -Cost Est ·•mate Surrmary, $ Mi 11 ion ·Ace. Item Snow L Bruskasha Keetna Cache Browne Talkeetna Hicks $trandl ine L ! Chaka Allison Cr. Plant Factor 29% 48% 27% 20% 34% 11% 46% 55% Cap. Installed 120MW 70MW llOMW 75MW 210MW 83MW 265MW 485MW 7.3MW Product Cost (mills/kwh) 54.5 164 62.2 · 169 160 103 160 39.5 119 ll4 ~--~~--------------------------~~--~--~~~--- 01 -.Land & D~iiages 1.095 4.509 1.858 2.125 5.174 0 .. 538 1. 967 0.500 0.500 --03 Reservo1r 5.236 33.66 15.334 17.578 35.53 4.114 18.7 0.0688 ------------~----~------------~~--------~~~--~~~--~~---------------------~----~---- 041 Dam 46.765 · 38 .. 93 105.58 136.605 256.945 119.537 118.609 0.955 3.711 \ 042 Sp1]lwax 043 Diversion + 11 Outlet 044 Power Intake 071 Powerhouse - Civil 072,3,4 Powerhouse Mec & El 075 Tailrace 076,7 Switchyard (17%) (14%) (23%) (30%) (29%) (31%) (20%) . (7%) 26.038 15.70 28.923 26.937 82.958 14.949 23.784 1.27 17.497 18.300 (6.7%) 32.460 .35. 640 1.360 34.692 11.559 (4.1%) 24.810 25.640 1.373 71.583 11.237 (2.4%) 32.387 33.88 3.315 54.783 9.679 (2.1%) 26.160 27.390 2.368 32.841 25.742 (2.9%) 60.692 87.108 12.173 48-.449 9.17P (2.4%) 23.835 31.415 2.491 31.88 (5.3%) 54.53 77.47 6.317 _... 1.727 487.633 8.42 {41%). (15.6%) 115.08 4.308 165.92 1.525 16.009 2.076 Transmission 4.686 2.075 4.725 3.3 3.875 3.337 4.738 15.488 0.454 rn • .-637 -- -- S .. 364 7.869 4.247 6.607 8 • 2 46 . 56 . 2 888 .. 38 . 6 . 5 . 9 .. --~~~----~--~~---4~0~20~-----4~2~1C __ ~~60~8~0~-~4~2~30~---a~.6~65~--~2~2~90~--~24~8~0~~7~3~80~-----4~4~9~0--__ __ li 'I /, I I I I I I I I I I I I I I I I I I I -,:1 ~ -Planning Procedure (:(. \ 1~:t=-Introduction The objectives of generation planning are to determine the roost suitable size of development and scheduling for the Susitna Basin hydro schemes and to evaluate the sensitivity of these schemes to the assumptions made for the planning studies. Generation planning analyses was done by making a comparison of alternatives with the aid of a production cost model to address the system cost of power under various developments and the direct comparison of alternatives using standard numerical evaluation techniques. Since it is recognized that the selection of a generation plan may be sensitive to the underlying assumptions of load projection, interest and escalation rates and fuel costs the planning procedure attempted to deal with these uncertainties. Initially, a set of variabies was established for use in identifying base plans in the first phase of stu ·. These plans would consider basin development with and without a hydroelectric development in ~he Susitna River Basin. In the first phase of generation planning, the study focused on the mid-load forecast to identify a base plan without the Susitna project and with alternative Susitna developments added to the system ... I I I I I I I I I I I I I I I I I -> w a: I N U) -0 z ~ I a: 0 u.. Calculations SUBJECT: 'St..>~ 1 T1V A 16 MJ ~ tlhiVS.t.oPM ~ \ 01710t-.lS L------..J 11 L-Tt-12 N 1'\:nv ;:: j k'-l:Dao n:t..t::c.:nz tC 1 ,__'"""ooi D sur.:to~ tt S.t--1 T O?Tta~S 11-t r.rz r--t £1t... ut:.vS LO~f'l F:f..J~ 0\'TLCA--l$ r----------~"':'· iz-Co NO nt l c_ r2A tJVvti\JG 0~ G F ...N E:.fZ. ~ll.,r...J p~~s..*-" lf\J f'"ot2 h t4 'Po~ l OtJ t::t-J \J t !2.otJnf"t.,if G ~ fi:..iAA-11. o~ 1'vth-J t-----~ \1-'l~f'"~ £~~to~ l' {G~ P12 b.~r ct1o,J CiF PL-\,.h.J s t..Lr c ... :rtok.l JOB NUMBER fJ (160 .. ~6 FILE :'.:UMBER ------ SHEET '?.. OF_2 __ _ BY 7ef6y( _ DATE 2(2/Jt APP DATE I I I I I I I I I I I I I I I ~I -I I I The second phctse of planning assessed the impact of varying the load forecast for planning purposes. This was done in two manners. Initially~ generation plans with and without the Susitna project were identified for the high and low forecasts. A plan was also made for the low forecast considering an additional load effort at conservation and load management. U~der this phase, a plan was developed considering a-probablistic forecast. The third phase of planning assessed the impacts of variable planning parameters including variable fuel escaliition. Finally, a sensitivity analysis was performed combining variable forecasts and planning parameters. 7.4.2 -Generation Planning Model A major tool used in the generation planning study is a computer simulation program for system studies. There are a number of generation planning models avail able conmercially and accepted for use in the utility ·hi~IJStr y. These models include the following: WASP (Wien Automated System Planning) GENOP OGP (Optimized Generation Planning} PROMOD by Tennessee Valley Authority by Westinghouse by General Electric by Energy Management Associates I I I I I I I I I I I I I I I I I I 10 " The WASP program was not available for use in this study due to limitations on availability to private engineering firms. Therefore, it was not given further consideration for use in generation planning. As of September 30, 1980, this program was made available to the general industry. Key considerations for use in _selection of a model for this study are data processing costs, method of production cost model~ng, treatment of system reliability, selection of new capacity, dispatching of hydroelectric capa~·-'-y to meet load projections and ability of th~'model to address load uncertatinty. Although some of these items are handled differentry in each of these programs, common threads of operation exist between the three programs. Some of the salient featues of each model are shown on Table 7.4.1. One major area of difference in comparing the models is the method of determining forced outages in the production cost algorithm. The three methods used are: -Deterministic methods which devote unit capacity by a multiplier or by ,...... extending planned maintenance schedules. -Stochastic methods which can be reduced to deterministic methods. Strictly speaking stochastic repre~·~ntations of outages is a random selection of some units in each commitment zone to be· put out of service. The load previously served will bE: transferred to higher cost units. I I I I I I I I I I I I I I I I I I I <! :>robabilistic methods, which are described by the modified Booth - Baleriaux method of production simulation which allows for probability distribution of generation unit outages. While the selection of one of these method$ may be critical in the use of a model for short-term outage scheduling, it becomes less import,nt for the purposes of this planning study. There would be virtually no difference in planning results over the long term of study for our planning purposes regardless of which method is adopted. Another consideration of program features is the method of dispatching hydropower resources to meet 1 oad demands.. The GENOP program dispatches hydroelectric units first with the run-of-river units meeting load demand and the units with storage capability used to shave peak demands. The OGP program uses a similar method, utilizing hydroelectric energy as much as possible to minimize system operating costs. Hydropower is scheduled first on a monthly· basis to account for seasonal conditions.. An additional feature of the program is the ability to use dry year or finn energy on a monthly basis to determine system reliability, while usin§ average annnual energy to determine system production costs. The PROMOD program all o~s for three leve 1 s of annual runoff and assQci ated hydroelectric energyo These energy levels can be entered into the program in a probabilistic manner to be used in dete~mi~ing reliability and production costing. Run-of-river and storage units are dispatched as ~n the other programs. I I I I I I ll I I I I •• "· I I I· I I I I" Based upon the considerations of the features and availability of the programs, it was decided to use the OGP ptogram for the planning studies. A primary reason for this decision was the efficiency involved in using a ? program which" the study team has previously used and. has a working knowledge of. A 1 though the PROMOD model does have a few advantages over the OGP mode 1 , switch-over to it is not warranted due to the level of detail of the study and the iPefficiencies involved in starting up and utilizing the program~ There is one other model which warrants consideration. This is the Electric Power Research Institute model, 11 0ver/Under Capacity Planning Model.~ The EPRI modEl was developed in 1978 under the objective of providing a framework for evaluating the consequences of over and under capacity in terms of total costs to consumers. The model calculates long-term total costs of alternative planning reserve margins from an end point energy cost view~ The fundamental purpose of the EPRI model is to measure total cost to consumers of different planning reserve margins. The model is not intended to provide a detailed analysis of technology mix, load forecasting, production costing or corporate finance although many outputs ar·e sunnnaries of these kinds of data. It was cohcluded that although the EPRI model could provide useful information in terms of the levels of capacity needed for' meeting . ..,..." I I I I I I I I •• I I I I I I I I I I uncertain de~and and the consequences of over and under building, the model did not meet the overall needs of the study. The primary tool used for the generation planning studies was the mathematical model developed by the General Electric-Electric Utility Systems Engineering Department, called Optimized Generation Planning (OGP). The following infon-nation is paraphrased from GE literature on the program. .... The OGP program was developed over ten years ago to combine the thr·ee main elements of generation expansion planning (system reliability, operating and investment costs) and automate generation addition decision analysis . OGP wi 11 automatically develop optimum gene rat ion ex pans i•)n patterns in terms of economics, reliability and operation. Many utilities use OGP to study load management, unit size, capital and fuel costs!! energy storage, forced outage rates and forecast uncertainty. The OGP program requires an extensive system of specific and generalized · data to perform its planning function. In developing an optimal plan~ the program cons-iders the existing and committed (planned and under construction) units available to the system and the characteristics of these units including age~ heat Y'L ~t size, and outage rates as the base generation plan. The program .. _ .·:.iders the given load forecast and system design and operation crit~ ... : to determine the need for additional -------~---·-----:--- TABLE 7.4.1 SALIENT FEATURES OF GENERATION PLANNING PROGRAMS Program/ Devel£per GENOP/ Westinghouse PROMOD/EMA OGP/GE Load Modeling Done by two external programs Done by one external program Done by one external program Generation Modeling Done by one external program Done by one external program Done by one external program Optimization Available yes no yes Reliability Criterion LOLP or % reserve LOLP or % reserve LOLP or % reserve Production Avai1abil ity and Simulation Cost/Run Deterministic or $500.00 to Modified Booth -validate Learning Baleri aux Curve Cost $300 -$800/run Modified Booth -$2,500.00 to Baleriaux validate on TYMSHARE Learn ingi Curve Costs $300 "' $500/run Deterministic or AAI validated Stochastic Co 1 umbi a & Buffalo Experienced Personnel $50 -$800/run I I I I I I I II I I I I I I I I I I I "' system capacity based on given reliability criteria. If a need exists during any monthly iteration, the program will consider additions from a list of alternatives and select the available unit fitting the system needs in the optimal fashion. Unit selection is made by computing production costs for the system with each alternative included and comparing the results. The fir·st calculation in selecting the generation capacity to install in a future year is the reliability evaluation, using input corresponding to the desired system characteristics. This will answer the questions of 11 how much" capacity to add ar.d 11 When 11 it should be instc:.. 1ed. A production costing simulation is also done to determine the operating costs for the generation system with given unit additions. Finally, an investment cost analysis of the capital costs help to answer the question of 11 What kind 11 of generation to add to the system. The model is further used then to compare alternative plans for meeting variable electrical demands, based on system reliability and production costs for the study period. ... - I I I I I I I I I I I I I I I I I I I I :1·? ¥ .. 4.3 -Load Representation Besides generation unit data and system reliability criteria, the program uses a model of the system load including month to year peak load ratios, typ~caJ daily load shapes for days and weekends, and projected growth for i) the period of study 1n terms of demand and energy supply. Load forecasts used for generation planning are represented in detail in Section 5. The forecasts to be used for generation planning is based on Acres • analysis of the ISER energy forecast. The energy forecast user' by Acres for establishing the "base" generation plan is the mid-range forecast. Sensitivity analys~s will be carried out using variable loads deveJoped using the !SER scenarios of high and low levels of both economic activity and government spending. The energy and load forec(l.sts developed by I~ER and Woodw~rd Clyde Consultants include energy projections from self-supplied industrial and military generation sectors. It ;~, foreseeable that these markets will be unavailable for the future el2ctrical suppliers to a large extent. By the same token, the capacity owned by these sectors will no+. be available as a supply by the g~neral market. A review of the indust·rial self suppliers indicates that they are ' primarily offshore operations, drilling operations and others which would I I I I I I I . I I I • I I I I I I I I I not 1 ikely add nor draw power from the system. Thus, those amounts have been deleted from the ISER totals. Additionally, a.1though it is considered likely that the military would purchase available cost effective power from a general market, much of thei1 capacity resource is tied to district heating systems, and thus would be expected to continue operation. For tht=se reasons only one-third of the military generation total will be considered as a load on the total system. This amount is about 4 percent of total energy in 1980 and decreases to 2.5 percent in 1990. This method of ~counting for these loads has no real effect on total capacity additions needed to meet projected loads after 1985. Tcble 7.4.2 illustrates the load and energy forecasts at five year intervals throughout the planning period. TABLE 7.4.2 LOAD AND ENERGY FORECASTS* ALASKA RAILBELT AREA Low Forecast Mid Forecast Hi9h Forecast YEAR MW GWh MW GWh MW GWh 1980 BASE 514 2,789 514 Z',789 514 2,789 1985 578 3,158 650 3,565 695 3,859 1990 641 3,503 735 4,032 920 5,085 1995 797 4,351 944 5,171 1,294 7,119 2000 952 5,198 1,173 6,413 1,669 9,153 2005 1,047 5,707 1,379 7,526 2~287 12,?43 2010 1,141 6,215 1,635 8,938 2~209 15,933 * Derived from the Woodward-Clyde Consultants submittal of September 23, 1980, adjusted to eliminate industrial self-supplied and two-·thirds of the military sector. 'I I I I I I I I I I I I I I I I a· I I -, :l·~ ~7 .:; 74 -Impact of Load Uncertainty Obviously, the load forecast used to develop a generation plan will have a significant bearing on the nature of the plan. In order to identify the impact of the uncertain loads, two methods will be used. < The first will be to develop plans using the high and low forecasts on their own. This will identify the upper and lower bounds of development which will be needed in the ra i1 belt. In order to incorporate the variable forecasts .!l}S! uncertainty of the load forec~sts into p~anning, a probability based load model feature of the OGP progral'il will be used. A brief description of this feature follJws. The middle level forecast or ~ost likely forecast, is introduced into the progrcm in detail. Th~s would include daily load shapes, monthly variability and annual growth of peaks a.nd energy. Additional variables are added which introduce forecast uncertainty in terms of higher and lower levels of peak demand and the probability of the occurrence of tltitese for·ecasts. For example: in year 1985 the middle level demand forecast entered is 1000 MW. Variable forecasts are entered for 850, 900, 1100 and 1150 MW, with associated probabilities of occurrence of .10, .20, .20 and .10, leaving the middle level as .40. ,. II II I I I I I I I I I I I I I I I I I The OGP program will use this variable forecast in generating system reliability calculation only. A loss of load probiiJility will be calculated for each projected demand level as compared to the available capacity and a weighted average will be taken. This loss of load probability will then be used for capacity addition decisions. After capacity decisions are made, the program uses the middle level forecast detail for operating the production cost model .. • This method of dealing with uncertainty is directly applicable to the data available fof' 6 .. 36 studies. There are five forecasts \'klich could be plugged in to the r·2liabi1ity calculations, the three by ISER and the two extremes calculated by Acres represented in Table 7.4.2. Subjectivity is reduced to the decision of placing pr,obabilities on the load forecasts. Two alternative probabilities will be introduced. T~1e initial set will be the same as those introduced in the example. This is based on the assumption that each outside forecast is half as likely to happen as the adjacent forecast towards the middle. As an alternative, the system will be analyzed under the assumption that all forecasts have an equal chance of happening. The loads and jJrobabilities will be analyzed as: FORECAST LES-LG* LES-MG MES-·MG HES .. ·MG HES··HG Probability Set 1 .10 .20 .40 .20 .10 * ES -Economic activ'ity G -Government L, M, H -Low~ Medium~ High Probability Set 2 .20 .20 .20 .20 .20 I I I I I I I I I I I I I I I I I ' • I "' An inquiry has been made to ISER to gain their opinions of these probability sets and invite n. probability set of their own. . -j .l·S' 7.~.5) -Target Generation Plant Reliability In order to perform this system study, a criterion for generating plant .,. ., and system reliability is necessary. This criterion is important to determine the adequacy of the available generating capacity as well as the sizing and timing of additional units. Plant reliability is expressed in the form of forced and p 1 armed Gut age· rates which have been presented within the.individual resource description in Section 7.3. System reliability is expressed as the 11 loss of load probability11 (LOLP). A LOLP for a system is calculated probability based on the characteristics of capacity, forced and schedulerl·cutage and cycling ability of individual units in the generating system. The probability defines the likelihood of net meeting the full demand within a one year period. For example, a LOLP of 1 relates to the probability of not meeting demand one day in one year; a LOLP of 0.1 is one day in ten years. For this study, LOLP of 0.1 will be adopted. This value is widely used by utility planners in the c.ount~,.Y as a target for independent systems. This target value will be used both for the base plan and for sensitivity analyses dealing with the effects of over/under capacity availability .. I I I I I I I I I I I I I I I I I I I ......:...-·· -, -:I·LP ~.;ss -Interconnection Caeability Early in the study process, it was determined that some judgement was needed to determine whether it would be appropriate to assume the existence of an interconnected system or isolated load center. Initially, it. was determined that a 138 kV 1 ine would connect the Anchorage and Fairbanks load centers and would provide the capability of transferring 50 MW of capacity at any point in time. The next logical consideration was, in further capacity addition studies, whether to assume a full flow interconnect ion. or to 11m it the interconnection to the 138 kV line. In order to address this question, a simplified analysis was performed, comparing the costs of thermal expansion in each load center with the costs of adding intert;e capability as needed and gene rat ion capability in the least expensive mannel'. Thus, one scenario was developed with the 138 kV line in place in 1984 and additional transmission added if needed with ex pans ion in the most economic area. A second scenario was developed a~lowing only the 138 ~V 1 ine in 1984 and individual load center capacity add it ions past that point in time. The ISER mid-level load forecast was used. ., I I -I I I I I I I I I I I I I I "' I I •• Under the intertie scenari _,, it was found necessary to add a 230 kV uprate of the 138 kV 1 i 1.1e in 1986 and the currently committed capacity additions of CEA and Bradley Lake. No oth~i ... capacity additions were needed unti 1 1993 when additional capacity was needed. Under the limited intertie scenario, capacity was necessary to ensure reliability in both systems in the 1986-1988 ti.neframe, in addition to that capacity already committed. Capacity would again be needed in 1993 in both Anchorage and Fairbanks systems. Assumptions for the assessment were considered to be conservative on the side of the non-intertied system. These assumptions af'ld additional detail on the assessment are included in Appendix C. It was clearly seen from this brief study, that an intertied system is the most cost effective position for both Fairbanks and Anchorage, by an overall cost ratio of greater than 10 to 1, (non-intertie to intertie)~ From the assessment, it was considered that the best way to proceed with the initial generation planning analysis was to ,Jssure up to 230 kV of inte.rtie line as existing in the system in 1986. Any additional generating facilities which wou·ld be nt::eded to carry power to either load center would be included in the cost of the alternative. I I I I •• I I I I I I I I I I • I I I (l·l ¥.4.~-Economic and Financial Parameters As a pub 1 ic investment, it was detennined that the Susitna project should be evaluated initially from a public or economic perspective, using economic parameters .. Initial analysis and screening of Susitna candidates employed a numerical economic analysis and the general aid of the OGP generation planning model. A financial or cost of power study will then be undertaken for those alternative candidates that were judged most favorable fran the economic eva1 uat ion. That is the economically vi ab 1 e proposals will be simulated using the same generation planning model to determine the cost of power with and without Susitna proposal. The differences between economic and financial perspectives pertain to the following parameters. (, ~-Project Life In economic ev~luations, an economic life is used without regard to the terms (repayment period) of debt capital employed to finance the project. Cost of power (or fi nanc i a 1 } perspective uses an amortization period that is tied to the tenns of financing. Retirement period (policy) should be equivalent to project life in economic evaluations; cost of power analysis may use a retirement period that differs from project life. I I I I I I I I I I I I I I I I I I I ~e{ ·-Denomination of Cash Flows and Discount Rates ' The economic evaluation will use real dollars and real discount rates that exc ... ·.Je the effects of general price inflation with tl1e exception of fuel es:alation. Cost of pow~r analysis is in nominal or escalated dollar terms; that is~ it uses escalated cash flows and nominal interest rates. ~-Taxes and Subsidies Th·ese intra-state transfer payments are excluded from the economic analyses and considering the cu~rent status of taxation needs in Alaska, taxes will be considered as zero.for the cost of power ana lysis. ~~Market or Shadow Prices Whenever market and shadow prices diverge, economic evaluations use shadow prices (opportunity costs or values). Cost of power analysis uses market prices projected as applicanle based on Subtask 6.32 0 output. It is important to note that .3pplication of the various parameters contained herein win not necessarily provide an accurate reflection of the true life cycle cost of any single generating resource of the system. I I I I I I I I I I I I I 10 I I I •• From the public (State of Alaska) perspective# the re.l~vant project rosts are based on opportunity values ~nd exclude transfer payments such as taxes and subsidies. This comparative analysis of project economics and state net economic benefits wi 11 be addressed under Task l1. -Interest Rates and Annual Carrying Charges Generation planning based on economic parameters and cr'iteria wi11 use a 3 percent real discount rate in the base case ana?ysis. This figure corresponds to the historical and expe~ted reul cost of debt capital. Sensitivity analysis \'Jill examine in 1981 the effects of low and high real discount rates, using a range of 1.5 percent (recent real return on Alaska Permanent Fund investments) to 5 percent. The ic;sue of tax-exempt. financing does not impinge on these economic evaluations. Financial or cost of power analyses requires a nominal or market rate of interest for discounted cash flow analysis. This rate ~Jill depend on~ among others, general price inflation\): capital structure {debt-equity ratios) and tax-exempt status. In the base case, a general rate. of price inflation of 7 percent is assumed fer the period 1980 to 2010. Given a 100 percent debt capitalization and a 3 percent real discount rate, the appropriate nominal im:erest rate is approximately 10 percent in the base case.lf 1/ The nominal interest rate is computed as (1 + inflation rate) X (1 + real 1nterest rate), or 1 o07 X 1.03. i I I 1 I I I I I I I I I I I I I I I To calculate annual carrying charges, the fo 11owing assumptions were made regarding the economic 1 ife of various power· projects, fat .. consistency, these 1 i ves were also used as the p 1 ant 1 i ves. ~ Large steam plant -30 y~ars ~ Small steam plant -35 years "~ Hydroelectric project -50 years .. ~~ Gas turbine, oi 1-fired -20 years 4\..._sJ Gas turbine, gas-fired -30 years ID~) Diesel -30 years It should be noted that the 50-year 1 ife for hycto projects was selected as a conservative estimate and does not include replacement investment expenditures. The factors for insurance costs (0.10 percent for hydro projects and 0. 25 percent for a 11 others) are based on FERC guidelines.Y State and federal .taxes were assumed to b:J zero for all types of power projects. This assumption is va1id for plarming based on economic criteria since all intra-state taxes shou1rl be excluded as tra,.~sfer payments from Alaska's perspective. The: subsequent financial . analyses may relax this assumption if non-zero state and/or local taxes or payments in lieu dre identified. Table 7 ,.lL3 summarizes the annual fixed carrying charges relevant to the generatiun planning analysis ba.sed on economic and financial para~eters~ 2/ Federal Energy Regulatory Commission, Hydroelectric Power _Evaluat~,9.!!., Washington, August 1979. I '~ ·I I I :1 I I I I I 'I I I I I I I I ;I ~ 7~4.7.2 -Cost Escalation Rates In the initial set of generation planning parameters, it is assumed that all cost items except energy escalate at the rate of general price escalation (7 percent per year). This results in real growth rat~s of zero percent for non-energy costs in the set of economic parameters used in real dollar generation planning and nominal growth rates of 7 percent for the subsequent escalated dollar cost of power (financial) analysis. Base period (January 1980) energy prices will be estima.ted based on both market and shadow (opportunity) values. The initial set of generation planntng parameters will use base period costs (market and shadow prices) of $1.15/106 Btu and $4.00/106 Btu for coal and distillate respectively. For natural gas 1 the curr-ent actual market pr-ice is about $1.05/106 Btu and the sh4 .. :~ow pr'ice is ~stimated to be $2.00/106 Btu~ The shadow price for gas represents the expected market value assuming an export market were developed. This assumption and value is to be used for both the economic and cost of power an a 1 ys is. Real growth rates in energy costs (excluding general price inflation) are shown in Table 7 .4.4. These are based on fuel escalation rates fron the Department of Energy (DOE) mid-term Energy Forecasting System for DOE Region 10 (including the States of Alaska, Washington, Oregon and Idaho) .Y Price escalators pertaining to the industrial sector were selected over those available for the commercial and residential sectors I!. I I I I I I I I I I I I I I I to reflect ui:ilities' bulk ~urchasing advantage. A.composite escalation rate has been computed for the period 1980 to 1995 reflecting average compound growth rate per year. As DOE ha: suggested that the forecasts to 1995 may be extenrled to 2005, the composite escalation rates are assumed to prevail in the period 1996 to 2005. Beyond 2005, zero real growth in energy prices is assumed. For cost of power analyses, the nominal (inflation-r;nclusive) rates of energy price escalation will be used. These al"e· defined as (1 +general price inflation rate) x (1 +energy price escalator). For example, using 7 percent and 3 percent values for the rates of general price inflation and fJel prices:~ the nominal escalator for fuel would be 1.07 x 1.03 = 1.102, or 10.2 percent. Table 7 .4.5 summc;"'izes the sets of economic and financial parameters for generation planning. 3 1 Departmen'" of Energy, Office of Conservation and Solar Energy, Methodology and Procedures for Life Cycle Cost Analysi_~, Federal Register, October 7, l980. I I I I I I I I I I I I I I I I I I •• TABLE 7.4.3 ANNUAL FIX~D CARRYING CHARGES UStD IN GtNtRATION PLANNING MODEL 30-Year Thermal (%) ECONOMIC PARAMETERS Cost of·Money 3 .. 00 Amortization 2.10 Insurance 0.25 TOTALS 5.35 FINANCIAL PARAMETERS ~QE.-exempt ~ost of Money 10.00 Amortization 0.61 Insurance 0 .. 25 TOTALS 10.86 }ax-exempt, Cost of Money 8.00 Amortization 0,88 Insurance 0.25 TOTALS 9.13 Project Life/T~pe 35-Year SO-Year 20-Year Thermal Hydro Thermal (%) (%) (%) 3.0(\ 3.00 3.00 1.6o 0 .. 89 3.72 0.25 0.10 0 .. 25 4.90 3 .. 99 6 .9T 10 .. 00 10.00 10.00 0.37 0.09 1.75 0 .. 25 0.10 0.25 I0:62 1o.I9 I2.oo 8.00 8.GO 8.00 0.58 0.17 2.1.9 0.25 0_..10 0.25 8 .. 8J ·tr:zr 10.44 :1 I I I I I I I I I I I I I I I I I •• TABLE 7.4.4 FUEL PRICES AND ESCALATION RATES Base Period {January 1980) Prices ($/million Btu) Market Prices Shadow (Opportunity) Values Real Escalation Rates (Percentage Change ComEounded Annually) 1980 -1985 1986 -1990 1991 -1995 Composite (average) 1980 -1995 1996 -2005 2006 -2010 Natural Gas ~oal Distillate $1.05 $1~15 $4.00 2.00 1.15 4.00 1.79% 9o56% 3.38% 6.20 2.39 3.09 3.99 -2.87 4.27 3.98 2.93 3.58 3.98 2.93 3.58 0 0 0 I I I I I I I I I I I I I I I I I I I * ~~o~~~ th~t economic ~nd financial parameters apply to real dollar and esc:1~ ·~:cd dollar c:nalyses respectively. I I I I I I I I I I I I I ~ I I I I' I •• ~ • • • • • • c:;::ao. ~ ' • .. '. .: • ·.. • •. • I . . . I ' , . -.. · . · · . I ~ .. : o . . .. . . • .• • • , ~ • • . : • • • • • 4 ' • • . • • • ' • : •• • • •• .. ' ' ' '·: ' •• 0 ' : ., > -· ....... ·_. . ;. : :~~-~ . ·•. . . . ~ ... 7.5-Base Generation Plan-Mid level Load Fov-ecast This section describes the efforts conducted under the fir·~.;t phase of the generation planning procedure de.scribed in Section 7.4.1, which concentrates on the mid level load forecast _and the economic parcmeters. Three subsections describe the all therm?J generation plan (with input from Section 7.3.3), the thermal and competitiv~ hydro plan (with input from Section 7.3.2) and the ~ Susitna Alternative schemes (input from Section 6). The OGP-5 p;ogram is the main engineering tool used throughout this generation plan analysis. Appendices A and B contain the summary outputs of selected runs as viell as a description of 11 How to Interpret An OGP-5 Surrmary Output... It should be noted that the maximum number cf years that can be analysed in our OGP-5 run is 20 and since our study period is thirty years (1980-2010), a ten-year run representing the 1980 to 1990 time frame was made and is common to all mid level forecast generation planning sequences. This ten year model is surrmarized in Table 7.5.1, which shows the 1982 and 1988 committed units and retirements that occur during this period. The results of this 10 year run are transferred to the 1990-2010 runs in order to get the 30 year representation of system characteristics. A summary of all runs completed in this phase is presented in Table 7.5.2. ; • ' I t ;. ' d ' . . . . I I I I I I I I I I I I I I I I I I ,.~. ; ... " ' 7.5.1-Thermal Generation P1an Two all-thermal generating futures were considered; one which allowed the renewal of existing natural gas gas turbines which are due to be retired during the study period and one which merely retired the units at the end of the.ir economic 1 ives. The purpose for the renewal pol icy follows from the Fuel Use Act limitations on new electric generating stations using natural gas and on the potential exemption allowed for renewed units. This case appears to be the clos~st to the real life simulation of operating natural gas turbines in Alaska in the future. Of the 943 MW of existing capacity, 734 MW were due to retire in the next 20 years. Of these 456 MW were natural gas gas turbines. These units were input at 100% of the capital cost in the year they were to retire and allowed to cant inue operating. The non-renewed scenario would represent the extreme case for natural gas gas turbines operating on1y in the peaking condition IJ and therefore was used in comparisons, In both cases, base-loaded nateral gas combined cycle units were n0t considered due to the limitations of the Fuel Use Act. Tc1ble 7.5.2 sunmarizes the results of these two all-thermal runs. The Thermal Plans iare similar in composition, adding 900 MW of coal unit~ in 100 MW increments) and similar amounts of diesei capacity (40 r4W in the renew case and 50 MW in the no renew case). The natural gas gas turbines are almost exactly motched with new gas turbir~es in the selected no rene'" case adding 600 MW to the system. The add it ion of these units represents approximately an $11 million PW variation between th~ renew and no renew case. I I i I I I I I I I I I I I I I I I I 7.5.2 -Thermal and Competitive Hydropowe~ Generation Plan Based on the results of the competitive hydropower screening described in Section 7.3.2, three of the ten sites were chosen to be the most economically sound projects, compared to their thermal alternatives and were applied to the generation planning procedure. These sites were chaka-chamna, Keetna and Snow and were assumed to be installed during 1993, 1997 and 2002. The results of this generation plan are presented in Table 7.5.2 and graphically depicted in Figure 7.5.1 as compared to the all thermal case. 7.5.3 -Susitna Generation Plans Essentially five Susitna "a1ternatives 11 evolved from the Sustitna Basir Studies described in Section 6. These five Susitn~ p1ans were tested in the OGP-5 model and compared to the three runs described in the previous section;;;. Table 7.5.2 sumnarizes the results of all eight runs. Tne five simplified Susitna plans are as follows: ---..---:w:m~'--__::_.2.....:-...!_ ___ _ -··--.. -... - - - - - -.. - - --- - December ON-LINE TOTAL COST Installed Firm Plan Stage Description Month/Year Million 1980$ Capacit:l{ ., _Capacity 2A 1 Watana Low Oan 1/92 1774 400 MW 206 MW ') Raise Watana Dam 1/95 376 194 MW c. 3 Add Capacity 1/97 136 400 MW 400 MW 4 Devil Canyon P-am 1/02 999 400 MW 352 ~1W TOTAL T21J()~ 1152 MW 3AE 1 High Watana Dam 6/93 1984 400 MW 400 MW 2 Add powerhouse capacity 1/96 157 400 MW 400 MW 3 Dev i1 Canyon Dam 1/00 999 400 r~w 352 MW TOTAL !200 MW 1152 MW 3A2 1 Watana High Dam 6/93 1984 400 MW 400 f~r1W 2 Devil Canyon Dam 1/00 999 400 MW 337 MW TOTAL BOO MW 737 MW 6A 1 High Devil Canyon Dam 1/94 1570 400 MW 351 MW 2· Vee Dam 1/00 1177 400 MW 315 MW TOTAL 800 MW 666 t~ 7A 1 Watana High Dam 6/93 1984 400 MW 400 M~J 2 Add powerhouse capacity 1/96 157 400 MW 400 MW 3 Add tunnel capa.c ity 1/00 1314 380 MW 179 MW TOTAL 1180 MW 979 MW I I I I I I I ~ ~ I I i I I I I I· I I - I 0 Despite the short t~~~ competitiveness of the 3A2 altern~ive, the 3AE plan was selected as the proposec Susitna alternative to complete the Phase II and Phase III generation planning procedures. I I ••• I I I I I I I I I I I I I I I I TABL~ 7.5.1 TEN YEAR BASE GENERATION PLAN MID LOAD FORECAST ----------------·~------------------------------------------- YEAR 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 MW Committed 60 cc+ 95 HY+ SYSTEM (MW) MW NG OIL OIL Ret ired COAL GT GT DIESEL CC 54 470 168 65 141 54 ·,. 470 168 65 141 54 470 168 65 201 49 54 470 168 65 201 54 470 168 65 201 14 {NGGT) 54 456 168 65 201 50 456 168 65 201 4 (Coal) 50 456 168 65 201 50 456 168 65 201 141l 5 (Coal) 45 456 168 65 201 45 456 168 65 201 *This figures varies slightly from the 943.6 MW reported due to internal computer rounding. HY 49 49 49 49 49 49 49 144 144 TOTAL CAPABILITY (MW) 947* 947 1007 1007 1007 993 993 989 1J84 1~79 1079 ·----------.. -----:--1 •• - TABLE 7.5.2 SUMMARY OF BASE GENERATION PLANS-MID LOAD FORECAST ALL THERMAL THERMAL SUSITNA ALTERNATIVES THERMAL THERMAL AND STAGED W HW I. QC W400/DC400 HOC/VEE W/ TUNNEL +RENEWS NO RENEWS OTHER HYDRO 2A 3AEEJ 3A2 6A 7 JOB 4i I.D. LME3 LME1 L5Y9 L8Jg LCK5 LB25 LAZ7 1990 MW 1079 1079 MW 1079 MW 1079 MW ln79 MW 1079 MW 1079 MW 1990-2010 THERMAL ADDS: 456 RN Coal (MW) 900 900 200 300 200 400 400 NGGT (MW} 150 600 300 225 525 450 300 .Diesels (MW) 40 50 0 0 50 60 10 TOTAL 1546 ~lW 1550 MW 500 MW 525 MW 755 MW 910 t"lW 710 MW TOTAL RETIREMENTS {734) (734 MW) (734 MW) ( 734 MW) ( 734 MW) ( 734 MW) ( 734 t~JW) HYDRO ADDS: 1/92 W400 Mit NAME MW 1/95 + Dam 6/93 W400 6/93 W400 1/94 HOC 400 6/93 W400 1/97 N400 ~ 1/96 W400 1/00 OC400 1/00 VEE 400 1/96 W400 1/02 DC400 1/00 DC400 1/00 T380 TOTAL FIRM* MW 2010 1891 MW 1895M~~ 1997 ~1W 2023 MW 1858 MW 1921 MW 1689 MW $X 10'· 6 {80$) lO Year PW 813.7 873.7 873.7 873.7 873.7 873.7 873.7 20 Year PW 3308.3 3319.4 2509.4 2360.6 2349.6 2624.5 2584.6 TOTAL 4182.0 4193.1 3382.1 3234.3 3222.3 3497.2 3458.3 PROJECT LIFE PW * In Peak Month {December) I I I I I I I I I I I I I I I I I I I 7.6 -Generation Planning_;:-Load Sensitivity As discussed in Secion. 5, the many uncertainties of load forecasting provide a wide rar1ge of possibilities for future generation planning. This section provides a detailed look at .the generation planning procedure as applied to varying load situations. The four load mode'ls evaluated in this sensitivity are shown graphically in Figure 7.6.1. They ar~ the High Government-High Economic Scenario HG-HES, the Low Government-Low Economic Scenario LG-LES, the Load Management and Conservation Scenario (LMLCS), a.nd the Proba.bil istic Scenario (PS). Also shown on this figure is the ~~.ediumGovernment-Medium Economic Scenario (MG-MES) used in the previous analysis and the ISER high and l0\'1 forecasts (MG-HES and MG-LES). Planning under the four previously mentioned load forecasts is described below. 7.6.1 -High §overnme,t -High Economic Scenario (HG-HES) a A similar methodology wa.s applied to the high load forecast as the medium load analysis described in Section 7 .5. This analysis involved a c<>mmon 1980-1990 ten year run, two 20 year 1990-2010 all thermal runs (with and without renewed gas turb ·ines) and a 20-year 1990-2010 Sui stna alternative run. For this analysis, the Sm:.ttna alternative 3AE was chosen as the onl.t ·. igh load model altarnative which installs Watana High Dam (800 M\~) and Devil Canyon Dam (400 MW) during the study period. Table 7.6.1 :1 I I I I I I I I I I I I I I I I I I summarizes the results of this analysis. Figure 7 .6.1 depicts the all thermal generation plan and thecSusitna generation plan 3AE. Of particular note in the high forecast is the installation of a 100 MW coal unit in 1990 to meet demand unt i 1 Sus i tna· comes on line. It can be seen that the total difference in 1980 present worth is of the two systems is in excess of $200 mill ion in 1980 dollars indicating the benefit of planning under the high load forecast with the Susitna plan. /.CJ .~ ~2 -Low Government -Low Economic Scenario The low range load forecast poses .a di~ferent situation with respect to the generation planning procedure. The installation of Susitna 3AE would be staged as Watana 400 MW in June of 1993 and Dev i 1 Canyon 400 M~~ delayed to 2002. This configuration results in almost a $700 million (1980 dollars) difference between the aJl ... thermal case for the low load forecast. These results are sLmmariz.ed in Table 7 .6.2 and Figure 7~6.3. ,.q-3 ~jr-Load Management and Conservation Scenario (To be written) • • > • • ' ~ .,. • . • • ..... : • : • • • i . . . . . . . . . 0 :, . . . ' - ~· I I I I I I I I :I I I I I I I ~I I I -,.q.+ 7-.6.4 -Probabllistic Generation Planning {To be written) 1-Cf· ~- 7.8"?5 -Summarv of Load Sensitivity Analysis (To be written) I 'I I I I I I I I I I I I I I I I I I TABLE 7.6.1 SUMMARY OF GENERATION PLANS -HIGH LOAD FORECAST ALL THERMAL SUSITNA ALTERNATIVES RENEWS NO RENEWS 3AE PARAMETER/JOB I.D.# L2E9 L7F7 LA73 1990 MW (+100 MW COAL) 1179 1179 1179 1990-2010 Thermal adds 456 Coal (MW) 1900 1900 ~900 NGGT {MW) 375 975 750 Diesels (MW} 130 50 {) TOTAL 2861 MW 2925 MW 1650Mw- (RETIREMENTS) MW (734) {734) (734) HYDO 6/93 W400 Month/Year Name MW 1/96 W400 1/00 DC400 2010 TOTAL FIRM* CAPACITY MW 3306MW 3370MW 3248MW $ X 106 (80$) 10 year PW $1060.5 $1060.5 $1060.5 20 year PW 5306.8 5307.4 4094.6 TOTAL $6367.3 $6367.9 $6155.1 * In peak month -December ,l . e.. • • ~ -• ~ • • , ~ ~:. ""' ~ • ' . • • • .... -·:-. . 9 . . . . . . ~ . I I I I I TABLE 7.6 .2 . SUM~·'\RY OF GENERATION PLANS -LOW LOAD FORECAST il I I I I I I I •• I I I I I PARAMETER/JOB I.O.# 1990 MW 1990-2010 Thermal adc's Coal (MW) NGGT (~1W) Diesels (M~J) TOTAL (RETIREMENTS) MW HYDO Month/Year Name MW 2010 TOTAL FIRM* CAPACITY $ X 106 (80$} 10 year PW 20 year PW TOTAL * In peak month -December ALL THERMAL RENEWS L2C7 1079 456'. 600 30 1086 MW (734) 1431~1W $ 744.1 2502.2 $3246.3 NO RENEWS L7E1 1079 700 300 40 1040 MW (734) 1385MW $ 744.1 2519 .. 8 $3263.9 SUSITNA ALTERNATIVES 3A2 LC07 1079 , 150 40 290 MW (734) 6/93 W400 1/02 0400 1272MW $ 744.1 1835.8 $2579.9 I I I I ·I I -1 I I I I I I I I I .,.~. ... I I r;.·" 7. 7 -Variable Parameters and Sensitivity Analysis This section describes the Phase III work accomplished to assess the impact of variable parameters and ~;ensitivity of the parameters on the results of the prugr an. As the \oJOrk descr ib.ed in the previous section performed a sensitivity analysis of load forf~casts, this section provides a sensitivity analysis of thermal and Susitna costs, cost of money (i.e., interest rates), fuel cost and differential fuel cost escalation. and plant be sensitivity. All these analyses are based or the mid lev-el load forecast and the Susitna alternative 3AE. 7. 7.1 -~ange of. C <~ita1 Cost Estimates thermal Capital Cost ' (to be written) Sus itna Costs (to be written) I I I ,. ,I 1 .. I I I I I I ••• I, I I I I I I ~· . -: . ' . . . ·. ~ :. .. . . ' : . Susitna C~pii~.al Costs The pr·imary concern vlit:h respect to Susitna costs is the variability due to seismic dE:sfgn which could signific1antly increase the cost of the project. In order to atssess this concern, three runs of the OGPS model varying only the cost of the Susitna alternatives were made. The range of costs were as fo 11 ows: Base Case Sensitivity I I I I I I I I :I I I I I I I I I I I 7. 7.2 or .3 -Range of Interest Rates Another concern with respect to the economics of the study is the impact of a variable cost of money. Holding all other parameters constant as was done in the 0 percent inflation-3 percent cost of money runs, a range of interest rates were looked at from 3 to 9 percent. under both the thermal .and Susitna cases. The results of these runs are shown in ~igure 7.7.2. / .. 7.7.4-Sensitivity of. the Cost of Money Parameter {to be completed) . I I ,. I I 'I I I I I ~· I I I I I :I I. I 7.7.5 -Range of Fuel Costs and Fuel Cost Escalation V ari ab 1 e Fuel Costs The base run made using the developed opportunity fuel costs and DOE fuel cost escalation parameters for both thermal and Susitna options were tested using a 20 percent 1 ess base cost and a 11 owed to esc a l ate at the DOE rates these parameters are presented in Table 7. 7 .2. Variable Fuel Cost Escalation The DOE escalation rates of 3. 98% for coal, 2. 93% for natural gas and 3.58% for oil were. used in the base case runs. A" run was made using a constant 0% escalation rate for all fuels and the base case fuel cost. These parameters were used in both the thermal and Susitna opt ion 7.7.6-Sensitivity of Fuel Cost and Differential Fuel Escalation Rates (to be written) .,_ ~I • "I I ·I •• I I I I I I I I I I ,, •. I I LIST OF REFERENCES (1) Abegg, F. · "Burning Coal in Alaska-A Winter Experience", ASME, 1980. {2) Alaskan Department of Commerce and Economic Development, Alaska Coal and the Pacific, Juneau, Alaska, September, 1977. (3) Battelle Pacific Northwest Laboratories, Alaskan Electric Power; An Analysis of Future Requirements and Supply Alternatives ,for the . Rai lbe lUegion, March, 1978. · (4) Engineering News Record, 11 Construct ion is Underway on A1 ask a-Canada Gasline" August 21, 1980s p. 18. (5) (6) (7) (8) {9) (10) ( l 1 ) (12) {13) (14) (15} Erickson, Gregg and Boness, Frederick.. Alaska Coal and Alaska Power Alternatives for the Railbelt, ~1a,x 1980. Executive Office of the President, Energy Policy and Planning, Decision and Report to Concl!'ess on the Alaska Natural Gas Transportation System, September, 1977 ... ICF Incorporated. A Re.view of Alaska Natural Ga~ Transportation System Issues; FERC, EJ-78-C-Ol-6395, May, 1979. - Jensen Associates Inc. " The Market Outlook for Alaskan Natural Gas!$*t September~ 1979 .. U.S. Department of Energy, Cost and Quality of Fuels for Electric Uti.litX Plants. FPC Form No. 423, DOE/EIA-0075 (80/04), June 1, 1980. - U.S. Department of Energ_y, nRecorrmendation to the President on ANGTS~*' May 1, 1977. The Alaska Economy Year-End Performance Report, Alaska Department of Commerce and Eocnomic Development, 1979. Alaska Oi1 and Gas Conservation CommissionStatistical Report, 1978. State of Alaska, Department of Natural Resources, Division of Minerals and Energy Management, "Historic and Projected Demand for Oi 1 and Gas in Alaska 1972-1995," April, 1977. I.be Energy Report, Vol. f'.Jo .. 3, Fairbanks North Star Borough, Corm1unity Information Center, September, 1980. Rao, P. D. and Wolff, Ernest N. "Characterization and Evaluation of Washabi 1 ity of Alaskan Coals." University of Fairbanks for DOE Grant No. G0166212, May, 1978. 'I I I I I I I I I I I I I I I I I I I REFERENCES (Cont.) (16) U.S. Department of Energy, Office of Environmental Assessments, Division of Energy and Power. A 1 ask a Re:gional Energy Resources. Plannin Project, Phase 2, Coal, H droelectric and Ener y Alternatives; Volume Be uga oa 1strict na ysis. . repared ty A aska epartment of CofTJT1erce and Economic Development 1980 (17) Coal-Fired Power Plant Capital Cost Estimates -EPRI AF-342 (SOA 76-329} Final Report, Dec., 1977 (18) Combined Cycle Power Plant Capital Cost Estimates -EPRI AF-610 (SOA 77-402) Final Report, Dec., 1977 (19) Gas Turbine World Handbook -1978, Peq~ot Pub. Vol. 4, 1979-80. {20) 1978 Fair:-banks Energy Inventory -Community Information Center Special Report No. 4~ Fairbanks North Star Borough, July, 1979. (21) U.S. Department of Energy, Steam-Electric Plant Construction Cost and Annual Production Expenses l976t A~gust, 1978 (22) U.S. Department of Energy, Gas Turbine Electric Plant Construction Cost and Annual Production Expenses-1976, EIA-0180, April, 1979. (23) (24) Electrical Wqrld Directory of Electric Utilities -1979-80 87th Edition (25) Hydro ower Cost Estimatin Manual -U.S. Army Corp of Engineers, Portland, Oregon, P~ 40, C-3 , May, 1979. (26) Personal corrmunication re: Susitna Hydroelectric Project -Task 6, Cost Estimating·. September, 1980. (27) Bechtel Cot"poration, Executive Summary, Preliminary Feasibility Stud\ Coal Ex ort Pro ram, Bass-Hunt-Wilson Coal Leases, Chuitna River Fie d A aska. Apri 980. (28) . Hennigan, Brian D., Cook Inlet Coal: Economics of Mining and Marine Slurry Transport Masters Thesis, University of Washington, Seattle, \~A, 1977. . (29) Olsen, Marvin, et al., 1979. Beluga Coal Field Development: Social Effects and Management Alternatives. Prepared for Alaska Oivis·ion of Energy and Power Development, Department of Conmerce and Economic Development, Ancho~age, AK and the U.S. Department of Energy, Office of Technology Impacts, Regional Assessment Division, Washington, D.C. by Pacific Northwest. Laboratroy, Richland, WA, Battelle Human Affa.irs Research Cen~ers~ Seattle, WA and CH2M Hi 11 't Anchorage, AK. PNL-RAP-29 UC-11. · .. . I - I I I I I I I ·I I I I I I I I I =• I REFERENCES (Cont.) {30) Battelle Pacific Northwest Laboratory, Draft Final Report Beluga Coal r~arket Studies for the State of Alaska, Office of the Governor, Division of Policy Development and Planning, September· 1980. (31) Federal Energy Regulatory Commission (FERC) Form No. 12 Power System Statements for (a) Anchorage Municipal Light and Power Department (Afr1LD), (b) Chugach Electric Association (CEA), (c) Fairbanks Municipal Uti 1 ity System (FMUS), {d) Homer Electric Association (HEA), and (e) Golden Valley Electric Association (GVEA), December 31, 1979. (32) Wi 11 iam Brothers Engineering Company Report on FMUS and GVEA Systems, 1978. . - (33) Alaska. Department of Revenue, Petroleum Revenue Division. Petroleum Productio.n Revenue Forecast, Quarterly Report, March 1980. {34~) Alcan Pipeline Company, Alcan Pipeline Project 48-inch Alternative Proposal, March 1977. (35) Markle, Donald~ ot OTT Geo-Heat Utilization Center, Geothermal Energy in Alaska: Site Data Base and Development Status, for the U.S. Department of Energy, April 1979. (36) (37) (38) (39) (40) (41) (42) (43) The Bureau of National Affairs (BNA), Incorporated, BNA Policy and Practice Series; Air Pollution Control, Section 101; Ambient Air Quality Standards, Section 111; State Policies, Section 121 New Source Performance Standards, copyright 1980. State of Alaska, Alaska Administrative Code, Title 19, Chapter 50.050 (d)" State of Alaska, Alaskan Administrative Code, Title 18, Chapter 50.090, Ice Fog Limitations. · State of l\laska, Alaska Admi.nistrative Code, Title 18, Chapter 50,020~ Ambient Air Quality Standards. State of Alaska, A'laska Administrative Code. Title 1H, Chapter 50.021., State Air Quality Classifications. Edison Electric Institute (EEl), ••Report on Equipment Availability for the 10-year period 1968-l978 11 , 1979. Personal comnunication with Mr. Hank Nichols of Anchor·c-..,. · :·1icipal light and Power Department, September 1980. Personal comnunication with Mr. larry Colp of Fairbanks Municipal Utilities System, September 1980. .. ,.. I I I I I I I I I I I I I I I I I I I I I I I r:~ -· REFERENCES (Cont.) {44) Personal communication with Mr. Woody Baker, Golden Valley Electric Association Production Superintendant, September 1980. (45) U.S. Department of Energy, Office of Conservation and Solar Federal Ener Mana ement and Plannin Pro rams; Methodolo Register~ Tuesday, October .7, 1980. (46) Personal communication with Dr. Charles Logsdan, Alaska State Department of Revenue, December 1980. (47) Personal communication with Mr. Schandler of Superior Products, Springfield, Ohio, September 1980. (48} Personal communication with Belyea Company, Jersey City, New Jersey, September 1980 ~ (49) Personal communication \vith Mr. Marshall of Cummins International Diesel., Baltimore, ~taryland, September 1980. (50} Battelle Pacific Northwest Laboratory, Beluga Coal Market Study for the State of Alaska, Office of the Governor-;' _December 1980. '·'.• ,;.;. , •. 8' -ENGINEERING· 'STUDIES ••••• " I -'- ~. I I I I I I ·I I I I I I I I I I I I 8 -ENGINEERING STUDIES (NOTE: The material presented here is a preliminary sketch of what is to appear in the final version of the report. It wi 11 be expanded as current office work is coinpl eted. More text wi 11 be added as we 11 as sets of engineering drawings of project layouts and figures showing results of concrete dan stress and cost summary tab 1 es). As the project planning studies outlined in s~ections 6 and 7 were completed, a star·t was made with more detailed engineering studies for the selected Watana ~nd Devil Canyon sites. The major thrust of these studies is twofold: (a) To select the appropriate dam type for the t~Q sites; (b) To undertake some preliminary design of the selected dam types .. This section briefly outlines the results of the studies to date. 8. 1 - D ev i 1 C anyo n S it e 8.1.1 -Dam Type Studies A major cost advantage of an arch dam relative to a comparable rock/earth- fil1 dam is in the generally reduced cost of the auxiliary structures and hence in order to study the relative economics of different dam types it was necessary to develop complete general arrangements. A representative 1 ayout has been studied for each of three d&'Tl types at the Devil Canyon site: (a) A thick concrete arch dam; (b) A thin concrete arch dam; and (c) A rockfi11 dam. None of these 1 ayouts are intended as the final site arrangement, but each will be sufficiently representative of the preferred scheme for each dam type as to provide an adequate basis for technical and economic comparison. All dams are located just downstream of where the river enters Devil Canyon close to its narrowest point and the optimum location for all types of dam. (a) Thick Arch Dam As shown on Drawing No. , the main concrete dam is a si;,g1E'~ center arched structure with a vertical clyindrical upstrean face and a sloping downstream face inclined at 1V:0.4H. Toe maximum height of the dam is 635 feet with a unifonn crest \'lidth of 30 feet, a crest length of approximately 1,400 feet and a maximum foundation width of 225 feet. The crest elevation is 1,460-'feet. The center portion of the dam is founded ·on a massive mass concrete pad constructed in the excavated river bed. This centr-al section incorpor·ates a service spillway with gated orifice spillways discharging down the steeply inclined downstrean face of the dan into a single large dissipating basin set below river level and spanning the valley with sidewalls anchored into the solid bedrock. .... 71 • 'I I I ·I I I I I I I I I I The main dam terminates. in thrust blocks high on the abutments. The 1 eft abutment thrust b 1 ock i ncorpor·ates an emergency gated centra 1 structure which discharges into a rock channel running well downstre~m and terminating at a high level in the river valley. Beyond the control structure and thrust block is a rockfill dike sitting on a low lying saddle and founded on bedrock. The powerhouse houses 4 x 150 MW units and is located underground within the right abutment .. The multi-level intake is ccnstructed·integral to the dam and connected by vert i ca 1 stee 1-1 i ned penstocks. The service spillway is designed to pass approximately the 1:500 year routed flood with larger floods discharged downstream via the emergency spillway. (b) Thin Arch Dam -. ~ .. As shown on Drawing No. the main dam is a two center double -curved arch structure of similar height to the thick arch dam, but with a 20 foot un·i form crest width and a maximum base width of 90 feet~ The crest elevation is 1455 feet~ The center section is founded on a concrete pad and· the extr1:me upper portion of the dam terminates in concrete thrust blocks located on the abutments. The main service spi~lway is located on the right abutment and consists of a conventional gated control structure discharging down a concrete-lined chute terminating in a flip bucket. The bucket discharges into an unlined plunge pool ·excavated in the riverbed aluvium and located sufficiently far downstream to prevent undermining of the dam and associated structures. The main spillway is supplemented by orifice type. spillways located high in the center portion of the dam and discharging into a concrete~ lined plunge pool immediately downstream of the dam. An emerg,ency spillway consisting of f..'ither a fuse plug or a simple gated structure discharging into an unlined rock chute, terminating well downstream is located beyond the saddle dam on the left abutment. The concrete dam terminates in massive thrust blocks and is continued on the left abutment by the already vertical saddle dam. The right bank and supplementary central spillways will discharge the 1:10,000 year flood and exce~s flows for storms with a reduced frequency wi 11 be discharge(~ through the emergency 1 eft abutment spillway. (c) Rockfill Dam As shown on Drawing No. , the rockfill dam is approximately 670 feet high. It has a crest width of 50 feet, upstream and downstream slgpes of 1:2.25 and 1:2~ respectively and contains approximately 20 x 10 cubic yards of material. The central impervious core is supported by a downstr-eam semi -pervious zone and these two zones are · protected upstream and downstream by filter and transition materials. I ·I I I I I I I I I I I I I" I I ·I I 'I }i The shell sections are constructed from blasted rock and the whole of the dam is founded on sound bedrock. External cofferdams are founded on the riverbed aluvium. A single spillway consisting of a gated control structure, chute and downstream unlined plunge pool is located on the right abutment. This is designed for the 1:10,000 year routed flood with excess capacity to allo\-1 dis.charge of the probable maximum flood with no damage to the main dam. 8.1.2 -Construction Materials Sand and gravel for concrete aggregates are found in sufficient quantities immediately upstream in the Cheechako fan and terraces. The gravel and sands are formed from the granitic and metamorphic rocks of the area, and at this time it is anticipated that they will be suitable for the production of aggregates after a moderate amount of screening and washing. Material for the rockfill dam shell would be blasted rock, some of it coming from the site.axcavations. , It is anticipated that some impervious material for the cor~~ is available from the till deposits forming the flat elevated areas on the left abutment and that other suitable borrow materials will be available in high lying areas within the three mile upstream reach of the river, however, none of these deposits have yet been proven. 8.1.3 -Remarks The geology of the site is as discussed in Section 6.3 and it appears at this stage that there are no geological or geotechnical aspects that would preclude any of the dam types from consideration. A rockfill dam would be more adaptable than a concrete arch dam to poorer foundation conditions~ a 1 though at present, foundation and abutment 1 cadi ngs from tho . ·"ch dams appear well within acceptable limits. The thick arch dam allows for the incorporation of a main service spillway within the crown of the dam and discharging straight down the river. For the thin arch and rockfill alternatives the equivalent discharge capacity has to be provided at additional cost through the abutments. Under hydrostatic temperature and seismic loadings, stresses within the thick arch dam are generally 1 ower than for the thin arch a 1 tern at i ve. Where, at a particular section, the surface stresses approach the maximum allowable, the remaining understressed area of Goncrete is greater for the thick arch and the factor of safety for the dam is correspondingly higher. The thin arch is, however, a more efficient design and better utilizes the inherent properties of the concrete. rt~is designed around acceptable perdetermined factors of safety and requires a smaller volume of concrete for the actual dam structure. The costs of the alternative dam layouts including all associated ·structures and transmission to Go1 d Creek are as given belo\'1: , 0 'I I I I I I I I I I I I I I I I •• I I Capital Cost in $ 1980 x 1000* Thick Arch Thin Arch RockJi 11 *Costs include all engineering and administrative costs and contingencies but not escalation or AFDC. 8.1.4-Preliminary Arch Dam Design Both thin and thick arch dam designs were originally analyzed by means·· of a finite element computer program. Results from these analyses indicated substantially lower stresses for the thick arch under hydrostatic and temperature loadings as would be anticipated with extremely high tensile = stresses for both types of dams under high seismic loading. Stresses close to the foundations and abutments were distorted because of the coarse mesh spacing of the selected nodes. In accordance with curT·ent American practice, to reduce the cost of computer time and in order to produce results which could more readily be interpreted, it was decided to use the trial 1 oad method .:1nd the. associ a ted program Arch Dam Stress Analysis System (ADSAS) developed by the USI?R. A thin two center arch dam is located approximately normal to the valley. There is a gradual thickening of the dam towards the abutments, but the two center configuration produces similar thickness and contact pressures at equivalent rock/concrete contact elevations and a symmetrical distribution of pressures across the dam. Under hydrostatic loads no tension is evident at the dam faces. Under extreme temperature distribution as determined by the USSR program HEATFLOW, for full reservoir conditions there are low tension stresses on both faces across the crest of the dam. These approach the allowable tensile stress of 150 psi. · Although analysis has still to be completed for s~ismic loadings, indications are that the concrete thin arch dam at Devil Canyon will be structurally feasible. - I I I I I I ·I I I I I I I I I I I I I . . .. • ..... • .... • .... '•'f'( • • . 8. 2 -Watana Site 8. 2.1 -Dam Type Studies A rockfill dam layout has been studied at Watana with the dam sited betwe.en the nor-thwest trending shear zones of the 11 Fins" and the 11 Fingerbuster 11 • The· dam is close to the alignment proposed by the· Corps of .Engineers and is skewed slightly to the valley in a north-northwest direction. The approximate height of the dam is 900 feet, and the volume is approximately 62 x 106 in yards. The crest elevation of the dam is 2,225 feet. The spillway discharges down the right abutment with an intermediate stilling basin and a down~tream stilling basin below river level. An 800 MW underground power stat ~H;n is 1 ocated on the 1 eft abutment. 8.2.2 -Construction Materials At this time it is assumed that some of the shell material for the dam will be obtained from site excavations and the remainder, which will be the large majority, will consist of blasted rock from borrow areas. Gravels for filler zones is avail able from alluvial deposits in Tsusena Creek. Core material is available from glacial tills located approximately three miles upstream above the right side of the river valley. This material will require very little processing. 8. 2.3 -Remarks As an alternative to the rockfill dam, a three center concrete thin arch has been considered, and layouts are shown on Drawings and The cost of the con rete for such a dam is prohibitive when compared to a rockfill and no further consideration has been given to this alternative .. The tentative cost of a rockfill dam scheme at Watana is $1,860 x 103 including all engineering and administrative costs and contingencies but not escalation or AFDC. 8.2.4 .., Preliminary Dam Design A section has been tentatively established for a rockfiii dam with a near vertical impervious core. At this time, no stability analyses have been conducted on the dam, but the section is based on Acres past experience and on general experience throughout the world on similar sizes of dam and locations of similar seismic activity. 0 . The crest width of the dan is 50 feet, the upstream slope is 1V:2 .. 25H and the downstream slope is 1V:2H. The core is composed of materials from the fine till deposits and the shell is presently considered to be constructed from blasted rock from site excavations and from borrow. - .. 9 -· SUSJTNA, HYDROElECTRIC DEVELOPMENT ,. -' . ' . . .. . . . . :<~ ~ {j '. ': .II I I I I I I I I I I I I I· I I I 9 -SUSITNA HYDROELECTRIC DEVELOPMENT 9.1 -Introduction It is anticipated at this stage that the final scheme will be a Watana rockfi11 dan developnent in conjunction with a thin concrete dam development downstream. The heights of the dams will be approximately 900 feet at Watana and 635 feet at Devil Canyon developing maximi.JTl heads of 760 feet and 585 feet respP .... tively at the turbines producing maximum outputs of 800 and 400 MW. The total storage at each of the Watana and Devil Canyon reservoirs will be 10 x 106 and 1.1 x 106 !?-;re feet respectively with live storage of 4.6 x 106 and 0.75 x 106 acre feet. Project configurations are conceptual and the upcoming stages of the study in 1981 will determine more accurately the layouts, dam heights, and installed capacities. 9.2 -Project Description When completed the two sites will be operated in conjunction-with one another with routed flows from Watana supplying the much smaller capacity Devil Canyon reservoir. The 1 arge storage at Watana and associated high degree of regulation substantially raises th firm energy potential of both Watana and Devil Canyon, For this reason, together with the resulting reduced floods during construction and lower design floods at Devil Canyon, it is economic to construct Watana as ~ th1: initial development. Watana would be staged with an initial capacity of 400 MW and an additional 400 MW added later. ·After complete development at the site, Devil Canyon would be brought on line to meet increased system demand ... 9.2.1-Watana Developmen_! Tentative development of this site will be as described in Section 8. Initially, the dam \Yill be constructed to its full height with a reduced power installation. Excavation of penstock and tailrace tunnels associated with additional future generating units will be completed at the time of install at ion of these units. 9.2.2 -Devil Canyon Development The development of this site wi 11 be as described in Section 8. The dam wi 11 be constructed to its full height and the full capacity of 400 MW wi 11 be in st a 11 ed . 9.2.3 -Construction Schedules At this stage of the. study a pre 1 im in ary assessment of the construction schedules for the Watana and Devil Canyon dams have been made~ The. main objective being to provide a reasonable estimate of on-line dates for the generating planning studies described in Chapter 7. More detailed construc~ion schedules will be developed during the 1981 studies. ·a I I I I I I 10 I I I I I I I I I I I 0 0 ;' 0 : • 0 0 0 0 00 ~ : \\ • 0 -'0 0 In developing the~e preliminary schedules, roughly 70 major construction activities were identified and the applicable quantities such as excavation and borrow volumes and volume of concrete were determined. Construction durations were then estimated using historical reco\"'ds as backup and the exper"'tise of senior scheduler-planners, estimators and design staff. A critical path logic diagram (CPM) was then developed from those activities and the project duration was manually determined. The critical' ·or near critical activity durations were further reviewed and refined as needed. These construction logic diagrams are coded so that they may be incorporated into a computerized system for the more detailed studies to be conducted during 1981. The schedules developed are as follows: (a) Watana Rockfi 11 0 am As shown in Figure , it is expected to take approximately 11 years to complete construction of the Watana dan fron the start of an access road at Highway 3 to the testing and commissioning of all the generating units. Principal components of the schedule include approximately 2-1/2 years for site and 1oca1 access, 1-1/2 years for river diversion and most of the remaining time for foundation preparation and embankment placement. This period compares to the 10 years estimated in the COE 1979 report. Only about six months per year can be used for fill placement due to snow and temperature conditions. Fill placement is estimated at approximately 2. 3 mill ion cubic yards per month with a tota1 voruome placement of 61 million cubic yards. This is in general agreement with the 1979 COE report which estimates approximately 2. 4 mill ion cubic yards per month placement over a five month annual placement period. It is expected that the river can be impounded as construct ion proceeds so as to minimize the time 1 ag between the completion of the dam embankment and the testing and commissioning of the first power unit. The schedule shows the date of earliest power production from Watana would be in 1993. This is based on starting construction of the access road in 1983 with start of construction at the site early in 1985 as soon as the FERC license is received. Should it not be possible to start construction of the access road prior to receipt of the FERC 1 icense, alternate methods of site access caul d be developed. One such method would be to bring in equipment required for initial site access and diversion tunnel construction overland from the Denali highway during the winter· months. An alternative method would involve constructing an airstrip and flying the necessary equipment and camp facilities in--Thi.s would allow paralleling the permanent access road construction period with the initial on-site construction and 5 although more costly, could reduce the total construction period byoup to 2-1/2 years. ~ ... ,. 'I I I, I I 'I I I I I :I I I I I I I I (b)· Devil Canyon Gravity Arch Dam As shown in .Figure 9.4, it will take approximately 6-1/2 years to comp 1 ete the dan fr011 the time of access to the site to :-he testing and commissioning of the power !'tlits. This is slightly shorter than the schedule in the COE 1979 Re~ which indicates an eight year schedule. The key elements in d~t rmin ing the entire project duration are the construction of diversion tunnels, cofferdams, the excavation and preparation of the foundation and the placement of the concrete dam. For purposes of estimating activity durations, it is assumed that embankment and curtain grouting wi 11 be done through vertical access shafts on each embankment with several horizontal tunnels being provided through the dam. It is assumed that access to the Devil Canyon site can easily be made avail able due to the proximity of the road to the Watana site. If this were the case, at 1 east 15 months waul d be added to the front end of the De\!'il Canyon schedule in order to construct a road from Highway 3. The attached figures represent an "early start" schedule and the majority of effort was expended in determining the 11 Critica1 path" which controls project duration. The 11non-critica1 11 items should be scheduled not merely to minimize construction period, but also to take into account resource availability and financial and climatic aspects. The "optimization" of the schedule will be performed during 1981. It is expected that -the project schedules wi 11 be refined as the following aspects are developed:. (a) Reconcil at ion and refinement of major construction activity quantities; (b) Detailing and refinement of foundation preparation and grouting requirements; (c) Refinement of reservoir filling rates; (d) Detailing of major structural components; (e) Incorporation of additional information based upon ongoing field studies and development of client and project requirements. 9.2.4 -Cost Estimates Cost estimates for Dev i1 Canyon and Watana are presently based on costs as established for the comparison of alternative site developments and as described under Section 6.6 .. A prel iminarycontractor' s type estimate is presently being prepared and this will _~p.rovid.e_amore_accurate .. _level of cos_ttng~ fitting to comparison of schemes at a particular ~ite and selection of an optimum site dev.elopment. ·a I I I I I I I I I I I I I I I I Costs will be based on the assembly of a typical construction fleet and labor force and the determination of applicable plant$ ... .Jterial and labor costs. Escalation and interest during construction will be based on a typical curve representative of the pattern of annual expenditures as experienced on previ1 us similar P}"'Ojects. •• I I I I -I I I I I REFERENCES I I I I I I I I I I I I I ·I I I I I I·· I DRAWINGS I I I I I I I 0 I :I I I I I I I 'I I I I I APPENDICES I 'I I I . • , I I I I I I I I I I I I I I I I I,. I I ·I I I I •) . B -HYDROPOWER SIMULATION ~10DEL RESULTS I I I I I- I I I I I I I I I I I I I TABLE 1 STAGE 1 MONTH Watana (2200) 800 MW EA EF (GWH) ( G\-JH) JANUARY 264 263 FEBRUARY 250 249 I MARCH 224 224 APRIL 201 201 MAY 186 186 JUNE 187 183 JULY 285 183 AUGUST 499 190 SEPTEMBER 370 204 OCTOBER 233 233 NOVEMBER 266 266 DECEMBER 287 287 TOTAL ANNUAL 3252 2669 EA: Average Monthly Energy EF: Monthly Firm Energy STAC1E 2 Devil Cany_on (1450) (Total 1400 MW)•• Af 600 M~l EA EF (GWH) (GWH) - 523 519 496 494 443 442 381 392 406 392 424 371 474 361 738 381 671 407 472 462 526 522 571 566 6125 5309 ' ' ~, I I ·- 1 I I I I I I I I I I .I· I. I· I STAGE·1 MONTH Watana (2l00} 400 MW 0 EA EF (GWH) (GWH) JANUARY 138 (' 137 FEBRUARY 130 129 MARCH 117 116 APRIL 103 56.6 MAY 100 100 JUNE 154 102 JULY 322 103 AUGUST 355 365 SEPTE~lBER 269 "188 OCTOBER 131 " 123 NOVEMBER 140 139 DECEf(BER 150 149 l TOTAL ANNUAL 2109 1708 EA: Average ~1onthly Energy EF: Monthly Firm Energy TABLE 2 STAGE 2 STAGE 3 Add 400 MW to ~\etd Devil Canyon Watana ·-: · · (1450} 400 MW EA EF EA EF (GWH) (GWH) (GWH) _ •-{GWH) 264 263 523 519 250 249 496 494 224 224 443 442 201 201 381 392 186 186 406 392 187 183 424 371 285 183 474 361 499 190 738 381 370 204 671 407 <- 233 233 472 462 266 266 526 522 287 287 571 566 3252 2669 L 6125 5309 I; •• I I. I I I I I I I I I I I I I I ·I STAGE 1 Watana {2200) MONTH 400 MW ~-EA EF (GWH) {G\~H) - JANUARY 263 263 FEBRUARY 250 249 fvlARCH 224 224 APRIL 201 201. MAY 186 186 JUNE 187 184 JULY 245 183 AUGUST 333 190 SEPTEMBER 315 204 OCTOBER . 233 233 NOVEMBER 266 265 DECEMBER 287 287 TOTAL ANNUAL 2990 2669 EA: Average Monthly Energy EF: Monthly Firm Energy TABLE 3 STAGE 2 STAGE 3 Add 400 MW to ...AEkr Devil Canyon Watana (1450} 400 MW EA EF EA EF (GWH) (GWH) (GWH) (GWH) ., 264 . 263 523 519 250 249 496 494 224 224 443 442 . 201 201 381 392· 186 186 I 406 392 187 183 424 371 285 183 474 361 499 190 738 381 370 204 671 407 233 233 472 . 462 266 266 526 522 287 287 571 566 3252 2669 6125 5309 ,. I I· I I I I I I I I I I I I I I I I STAGE 1 Watana (2200} MONTH 400 MW EA EF (GWH) (GWH) JANUARY 263 263 FEBRUARY 250 249 MARCH 224 224 APRIL 201 201 MAY 186 186 JUNE 187 184 JULY 245 183 AUGUST 3:33 190 SEPTEMBER 315 204 OCTOBER 233 233 NOVEMBER 266 265 DECEMBER 287 287 TOTAL ANNUAL 2990 2669 EA: Average Monthly Energy EF: Monthly Firm Energy TABLE 3A STAGE 2 STAGE 3 Add 400 MW to ~Devil Canyon Watana (1450) 400 MW EA EF EA EF (GWH) (GWH) JGWH_)_ (GWH) 264 263 523 519 250 249 496 494 224 224 443 . 442 201 201 381 392 186 186 431 392 187 183 458 371 285 183 576 361 499 190 688 381 l 370 204 636 407 233 233 498 462 266 266 526 ·511 ; 287 287 571 567 3252 2669 6227 5310 " I I I I I I I I I I I I I I I I I I TABLEY4 STAGE 1 MONTH High Devil Canyon (1750) 800 MW EA EF (GvJH) (GWH) JANUARY 250 249 FEBRUARY 232 234 MARCH 205 210 APRIL 184 189 MAY 180 179 JUNE 218 182 JULY 497 171 AUGUST 643 186 SEPTEMBER 446 197 OCTOBER 230 223 NOVEMBER 255 253 DECEMBER 273 272 TOTAL ANNUAL 3613 2545 EA: Average Monthly Energy EF: Monthly Firm Energy STAGE 2 Vee (2355) \' ' : (Total 1200 MW) , +-4{}0-MW EA EF (GWH)_ (GWH) 368 368 349 350 303 313 268 276 254 258 290 247 526 319 752 298 575 280 394 366 404 395 425 401 4908 3871 , I I I I I I I I I I I I •• ~- 1 .: I I I Ht&..-oe~··'-a~'IIJ~t>). (lit to) 4oo M.W STAGE 1 1.1-.:.... ~ ....... '"" \'--~~! MONTH 4QQ · UW;: EA EF (GWH) (GWH) JANUARY 114 113 FEBRUARY 107 106 MARCH 96 791 APRIL 79 252 MAY 92 857 JUNE 300 215 JULY 319 319 AUGUST 317 319 SEPTEMBER 289 245 OCTOBER 152 102 NOVEMBER 117 116 DECEMBER 125 124 TOTAL ANNUAL 2107 3559 EA: Average Monthly Energy EF: Monthly Firm Energy TABLE 5 HIGtfrf . Jle.ui~. CAA"lOAl (l1'5"D) A·DO 4oo iA"" STAGE 2 ·Aee-400 MW te- -... trJaLaua -· EA EF (GWH) (GWH) 250 249 232 234 205 210 184 189 , 180 179 218 182 497 171 643 186 446 197 230 223 255 253 273 272 2107 2545 ' VEe· (Z;it") . ..r:(ooMW to TAt,. t 2.0o M w STAGE 3 Add=Devtr·~ca·nyo11 ·c··-.. ,... ,.. " . "'.nn ........... J. 't;JV J 'TVV 1'1~ EA EF (G~JH) (GWH) 368 368 349 350 303 313 268 276 254 258 290 247 526 319 752 298 575 280 394 366 404 395 425 401 4908 3871 ~a I I I I I ••• I I "' I I I I I I I I I I 1..: G.~+ ~· •Jil... ,·..:,.r..J"f·: ,, ( \i ·:a) 4 ..... ~. "'' '~•' STAGE 1 MONTH Wat:ana \~206) ----4atJ-MW EA EF (GWH) (GWH) JANUARY 234 232 FEBRUARY 217 219 MARCH 192 197 APRIL 173 177 MAY 169 168 JUNE 196 171 JULY 266 171 AUGUST 288 ' 175 SEPTEMBER 284 185 OCTOBER 218 209 NOVEMBER 239 238 DECEMBER 25.6 255 TOTAL ANNUAL 2732 2397 EA: Average Monthly Energy EF: Monthly Firm Energy TABLE 6 l \-4 I bl-l t,: v! ~ <: Ar....; 'f o ......,, : '1 S-1 .,-\.:;~ 4<->.~ M'-v STAGE 2 -Adtf--4 eo-r~w to-- . Wa.tana-- EA EF (GWH) _(GWH) 250 249 232 234 205 210 184 189 180 179 218 182 497 171 643 186 446 197 ' 230 223 255 253 273 272 2107 2545 STAGE 3 Ad-d-Sevt+-€an~ n (1·4t::".n..\. _A/"1.1"\. MW ·~V) "tUU 1 EA EF (GWH) {GWH} 368 368 349 350 303 313 268 276 254 258 290 247 526 319 752 298 575 280 394 366 404 395 425 401 I 4908 3871 I I I I I I I I ,~ I I I I I I I I I I MONTH JANUARY . FEBRUARY MARCH APRIL . MAY JUNE JULY AUGUST SEPTEMBER OCTOBER . NOVEMBER DECEMBER TOTAL ANNUAL • , -,.J\r; 'fl.> hJ 4--o.::M'N STAGE 1 ~t2~0&}- · ---40&---MW ·· EA · EF _(GWH_l (GWH) 234 232 217 219 192 197 173 177 169 168 196 171 266 171 288 175 284 185 218 209 239 238 256 255 2732 2397 EA: Average Monthly Energy EF: Monthly Firm Energy TABLE 6A tt i6~ C<';\f; \.... C .AIV .. f'~•-J (11~.) ,t\1))) 4 ~.; M"' P_;·~;•,:'>:.': Citf<:*3.' 1$' M¥.j, STAGE 2 --Amr41Jo~·Mtor to ·-watana· .. - EA EF (GWH) (GWH} 167 167 158 158 142 142 ~ 125 125 133 117 476 251 493 494 515 522 461 349 • 222 145 167 167 182 182 3241 2819 'It:=_ \2"$:::.:. ... ) 4-UDiA1\J/ ( T(.}e .. f\1_ I -:1. : ..... MVIf) STAGE 3 Add-Bevtt -canyon .l.Lt+"SCT}~ EA EF (GWH) ( G~-~· ~ ~ ·• ' . 432 435 411 415 360 372 318 328 287 290 321 277 564 349 820 332 646 315 447 415 457 446 " 480 456 5543 4430 --.,..---..,..-,.....-~~-----------. -------=- t-hC..t-\ i:;c..,;: 'J l (.. ~ ol\)o.J 'f~r..J Or·;-;.;:.) l?t-'--;.i M 'N . STAGE 1 wata-na~-( 2200J MONTH ·-"'--·¢ao-Mtaf' ~ EA EF (GWH) (GWH) JANUARY 250 249 . FEBRUARY 232 234 - MARCH 205 210 APRIL 184 189 ~1AY 180 179 JUNE 218 182 . JULY 497 171 AUGUST 643 186 SEPTEMBER 446 197 OCTOBER 230 223 NOVEMBER· 255 253 DECEMBER 273 272 TOTAL ANNUAL 2107 2545 ~ EA: Average Monthly Energy EF: Monthly Firm Energy TABLE 7 VEE' ( 7. ?:; S :, ) 4o~ MW ( 'f':lir-,\.. !,';;.~ M W} STAGE 2 STAGE 3 -~{}9~--Mw..-.. t o--Add-fie-v-t+·--eanycrn ~itrwa--·· (14-5Q-r413&-MW EA EF EA EF {GWH) (GWH) _(G~JH) {GWH) 167 167 432 435 158 158 411 415 142 142 360 372 125 125 318 328 133 117 287 290 476 251 321 277 493 494 564 349 515 522 820 332 461 349 646 315 222 145 447•. 415 167 167 457 446 ·182 182 480 456 ... 3241 2819 5543 4430 , ,I I ·I I I I I I I I I I I I I I I I I ' ··- •' ' . ' " . . ., -_, ... " . . . . ' . . . . . . . . . . : ~ . -' . - C -GENERATION PLANNING MODEL RESULTS ' I I I I I I I I I 'I I ~· APPENDIX c, HOW TO INTERPRET AN OGP-5 GENERATION PLANNING PROGRAM {. The Genera(Jf,.ectric OGP-5 program "¢ :Jsed in the~neration planning study provides the operator with a large quantity of useful system characteristics including fuel consumption by type and by year, hourly dispatch of operating units, production costs for each unit type by year and decision making calculations for years when additions are contemplated by the system. This output, which also includes detailed description of the input parameters, was used in the study to recommend the various plans and analyse the results. An abbreviated summary .of the salient output results is also printed by the program for those who are interested in the results of a variety of program runs. Included in +:11~ Append~re the summary outputs of the key runs made during - the generation planning procedure. The following describes the type of output I received in these pages and how to interpret the results in a manner consistent 1 with the generation planning results discussed in Sections 7.5 to 7 .8. I I I I Each summary has three {3) pages: -~~svsl~- Yearly Cost and Cumulative Present Worth Yearly $/MWh I I I I ,I I ·I I I I •• I I I I I I I Some information is repeated on the summaries (i.e., load, total capabilities and yearly cost) but essentially each table contains a particular set of information useful to the generation planner. R_efer to Page 1 -Generation System 5~ L.C. 1. JOB NUMBER f_EFERS TO. THE ID CODE FOR EACH RUN .AND ACTS AS A CROSS REFERENCE IN THE TEXT] . 2. The types of generation available to the Alaska Railbelt include coal, natural gas, gas turbines, NGASGT), oil gas turbines (OIL G'r), diesels, combined cycle units (COMCYC) and Hydro (Types 7-10 on the summary). NUKE referring to Nuclear units is not available to the Railbelt however is required input to the program. 3. Since the OGP-5 program can only be run in 20 year intervals and the study period was 30 years, it was necessary to make a 10 year run and carry the results forward to the 20 year (1990-2010) run. This line surrrnarizes the 1990 systan by the number of MW per unit type. I I I I I I I I I I I I I I I I -I •• 4. This matrix indicates the year and number of each type of unit added to the operating system based on need or committed (flagged by an asterick *) Hydro MW additions are somewhat misleading. The program rates the Hydro station based on the MW capacity available in the peak month of demand {i.e.~ December) rather than the total installed capacity of the units. This does not affect the product ion costing routine since the energy is computed over a year of generation. 5. The bottom port ion of the matrix indicated the total cmount of add it ions and retil"ements during the 20 year period and the percentage mix totals for the last year of the study and for all automatic additions. Referring to page 2 of the summary-Yearly·cast and Cumu1ative Present \~orth: 1. Load and MW capability are used to compute the percent reserve available by year. 2.. .The Loss of Load Probability (described in Section 7 .4.5) is listed ·;n. days per year· which is the planning criteria outlined0 as 1 day in 10 years = l<.. 0.01. You can also plan for LOLP in hours/year however this option was not exercised. 3. Yearly cost refers to the total yearly cost (in mill ions of that year• s dollars) for operating the system • cr I I I "I 4 .. Correspondingly the Cnmulative Present Worth Total column brings this ~ yearly cost back by the cost of rr.oney (3% in our study) to 1980 dollars (our c.... . base). Thejumulative present worth figure does not include pre-1980 sunk ,... costs of the existing system. ·J Referring to page 3 of the Sl111111ary, the yearly $/MWh table: I I I I •• I ,I I I I I I I 1. peak demand and annual energy (GWh) is listed as input fran the load model 2. The total costs are broken up into investment costs, fuel costs and O&M costs (N.I. refers to nuclear inventory costs which are not a part of this study). The costs are quoted in $/MWh (=mills/KWh) in the year they occur. The tot a f $/MWh is not a represent at ion of the cost paid by consumers for -- electricity. It is a production cost for an oper~ting system neglecti.ng metering, distribution losses and most importantly the sunk investment costs of the existing 1980 syst2m. It is, hO\'Iever, a tool to judge the various thermal alternative hydro and Susitna projects since the logic is the same for all cases. tt prfP I I I I I I I. 1. I I I I I I I I I :1 JOB NUMBER I.O. LME3 LME1 L5Y9 L8J9 LCKS LB25 LAZ7 l2E9 L~F7 LA73 L2C7 L7El LC07 APPENDIX B SELECTED OGP-5 GENERATION PLANNING SUMMARY OUTPUTS LOAD MODEL MID MID MID MID MID MID MID MID HIGH HIGH HIGH LOW LOW LOW DESCRIPTION {1990-2010) all thermal with renews { 1990-2010) . all thennal .without renews " (1990-2010) thennal and competitive hydropower (1990-2010) Susitna 2A staged Watana darn/DC (1990-2010) Susitna 3AE-High Watana/DC (1990-2010) Susitna 3A2 - Watana 400/DC 400 (1990-2010) Susitna 6A -High Devil Canyon/Vee.,_· (1990-2010) Susitna 7A-Watana 800 + Tunnel ( 1990-2010) a 11 thennal \'lith renews (1990-2010) all thennal without renews (1990-2010) Susitna 3AE (1990-2010) all thennal with renews {1990-2010) all thermal without renews '- (1990-2010) Susitna 3A2 -I I I 0 1 I I I I I I I I I I I I I .I •• D -TASK 2 -STATUS REPORT ~ I I I •• I I I ·I I :1 I I I •• I I I I D. J COMPLETION REPORT SU.M!1ARY LAND STATUS RESEARCH SUBTASK 2.04 .. --·-···~"',;;,.,··-:.:: --~--~ . ' ~· .. .:.-.. ~ --~~-·--.· : ______ -'--"- f .. ' ·- I_ I I I I I I I I ; I I I I -· I. I I I INTRODUCTION The purpose of this report is to prqvide an overview of the results obtained through the identification of the general land ownership status within the Upper Susitna River Basin and the Anchorage~Fairbanks Intertie Corridor-(Figure 1) • SIGNIFICANT L&~D POLICIES AFFECTING THE STUDY AREA The Federal government remains the largest land owner in Alaska. . Ho~.;ever, this domination of ownership has been eroded with the passage of the Alaska Statehood Act in 1959 and the Alaska Native Claims Settlement Act in 1971. These Acts have placed in question the ultimate land ownership patterns of the State with competition for the land divided among the Federal government, the State of Alaska, and private Native regional and village corporations. . With the enactment of the Statehood Act, the State of Alaska became entitled to a total of 10 4. 5 million acres. Sect_ion 6·(b) of the Act included 102.5 million acres of general g:rant lands to be used at the discretion of the State. ·In addition, certain federar lands were to be held in trust for both public schools and for the University of Alaska." Public Law 84-830, passed in 1956, provided for one million acres of mental health grant lands. In 1978r the State legislature passed a lat·r designed to convert · the 1.2 million acres of land held as snecial trust~ for ~ -funding public schools, mental health programs, and the University of Alaska into general grant lands to be_treated in the same manner as other State-held land.. The plan was to replace the land with an annual income, a percentage of t..~e total receipts from the management of State land, including oil royalties. However, tl'l.e University of Alaska e:.~ercised· its option and turned do~vn this trust fund and retains management over the lands it holds title to. The State of Alas.ka has granted land entitlements to the organized Boroughs and Municipalities.. As a result of thi~ entitlement, both the Matanuska-Susitna and North Star Boroughs have extensive land holdings. The t1.unicipality of Anchorage has received its entitlement, which is considerably less than that received by the boroughs. In response. to increasing public pressure and changing la"t·ls, the State legislature passed HB66 in 1979, charging the Department of Natural Resources vlith the responsibility of disposing 100,000 acres of land annually to p_rivate ownership. /I • I I I I -1 0 I I I I ... I I :I I I I I I I Map Index " 4 12 1 i 7 6 1 ..... ... C· DOYON 1 24 I 19· 20 21 22 I t 23t r C.LR.L I I t I l~~TNA ~ I I I LAND STATUS RESEARCH STUDY AREA ANCHORAGE -FAIRBANKS TRANSMISSION CORRIDOR & UPPER SUSJTNA RIVER BASIN FIGURE 1 t .. I I I I· ·I I I I I .; I I I. I I I I I . I C9 This land is disposed through four methods: direct sale, homesites, remote parcels, and agricultural rights.. It is apparent from recent discussions betw·een the Alaska Power Authority and the State Division of Lands that the State Division of Lands is severely encumbered by its requirement to an11ually dispose of 100,000 acres of land to the public. Consequently, necessary regional and site considerations, e.g. proposed Intertie Corridor, relating to the disposal of these lands are frequently omitted from the State's land disposal selection process. · With the passage of the Alaska Native Claims Settlement Act (ANCSA) in 1971, the State of Ala~ska y;as no longer the sole entity selecting federal lands.. Onder the Act, private Native regional and village corporations were entitled to select lands from the Federal go"'..rernment holdings and from those lands previously selected, but not patented to the State of Alaska. To date, neither the State nor the Native Corporations has received its full. entitlement under the Statehood Act and the Alaska Native Claims Settlement Act. PRESENT LAND O~~ERSHIP TRENDS Anchora9:e-WilloY1 This section contains a complex mixture of land ownership with the extensive private O\'ltlership interspersed ~1ith large blocks of State and Borough lands. The State has res~rved several areas lor public recreational use (Nancy Lake State Recreation area, ·Goose Bay and Susitna Flats Game. Refuge, and Chugach State Park) . The only large State . land disposal within this area is the Pt. ~'lacKenzie Agricultural Project scheduled for spring 1981. The holdings by the Federal government are dominated by military reserves in the Anchorage area. ~·7illow-Talkeetna Thia area is characterized by nw.-nerous private holdings along the Parks Highway. · Large blocks of State,· Native, and Borough lands dominate the remainder of the land in this area. Numerous State land disposals hav:e taken place and are projected for this area. Talkeetna-Fairbanks This section represents an area of large blocks of State Oi.'lned land.. Numerous private holdings are concentrated in scattered communities located along the Parks High-;·1ay. The most notable of these are Cant~1ell r Healy, Clear and Nenana. Canttvell and Neriana are both surrounded by large blocks of Native lands. : I· • I. I I I I I I I 'I I. I I I I I I I I .c -Both the Denali State Park and the !-1t. McKinley National Park are located in this section~ Upper Susitna River B·asin The land status in this area is relatively simple, due j:o the large amount. of public land managed by the Bureau of Land Management. There are large blocks of private Native Village corporation lands along the Susitna Ri',.rer. Other private holdings consist of widely scattered remote parcels ... · The State has selected much of the Federal land in this area and is expected to receive patent. LAND STATUSC METHODOLOGY The CIRI Land Department utilized the following sources to identi£y the· ownership and other interests within the Anchorage- Fairbanks Transmission Line Corridor and Up~er Susitna River Basin: Alaska Department of Natural Resources Alaska Department of Transportation Bureau of Land 1.fanagement Cook Inlet Region, Inc., Land Records Matanuska-Susitna Borough Tax Assessor Records l-1unicipality of Anchorage Tax Assessor Records North Star Borough Land M~nagement Records Land information compiled from the above agencies \-las trans- cribed onto diazo worksheets. Mvlars were made from these -~ _worksheets and used to prodice finished maps and additional diazo reproducibles. ., ,~ I I I I I I I I I I I I I I I I I I ;j) miscS/bb 0.2 AERIAL PHOTOGRAPHY AND PHOTOGRAMMETRIC MAPPif\I.Q Prior to 1980, the only low level aerial photography that was available covering the ··study area consisted of photos obtained for the. Army Corps of· Engineers in the Vicinity of the Proposed Devils Canyon and Watana Damsites. Thm photography was C.lf mapping quality at the photo scale of 1 11 = 2, 0001 and was photo-. graphed in black and white format. The attached map delineates the limits of this photography .. Some fragmentary low level photography existed along portions of the alternative transmission corridors. These photographs were obtained by several agencies and were produced at various photo scales. High altitude photography obtained in past years existed ov·er the entire project area.. The National Aeronautical and Space .Adminis- tration (N .A.S. A.) obtained both black and white, and color infrared photography from an altitude of approximately 60 1 000 feet ... LANDSAT satellite photography existed prior to 19$0 and was photographed from several hundred miles altitude. Subsequent to commencement of the 1980 field season 1 the following areas have been aerial photographed: 0 0 Area I 1 Devils Canyon Reservoir Sca!ei 1" = 2 1 000' Format; Focal Length = Area I I, Watana Reservoir 1 11 = 20001 6", Color gu X 9 11 Scale; Format; Focal Length = £" 1 Color"" 9 11 x 9 11 -1. - I· I I I I I I I I I I miscS/bb 0 Area 3 1 Lower Susitna River from Cook Inlet to Devils Canyon scale; 1" = 4,ooo• Format; Focal Length -6 11 1 Black & White 9 11 x gn 0 Area 4 1 Alternative Access Corridors including HBiock 11 Scale; 1 11 = 2 1 000' Format; Focal Length -6 11 1 Color 9 11 x 9 11 0 Area 5 1 Alternative Transmission Corridors (Partial) Scaie; 1 11 = 2,000• Format; Focal Length -6" 1 Color 9 11 x 9 11 The limits of the above listed photography are shown on the attached map. The photography coverage in Areas and 11 were pre-marked with flight panels (white crossas) on the ground which have been field surveyed and wilf serve as mapping control for future contour mapping of both Devils Canyon and Watana Reservoirs. •• I· I ·I I I I ·I I I I I I ,, ·I I I I misc5/y1 0.3 CONTROL NETWORK SURVEYS R&M has completed the horizontal and vertical controi field surveys and is currently involved in the data reductions and network adjustments. Pr'I.~liminary horizontal and vertical coordinates have been generated, and the full final network adjustment will be completed by Feb1~uary 2, 1981. The horizontal control is broken into three schemes: _, 1. Primary control: Second order, Class I Stations. Rela- tive positional accuracy exceeds 1 in 50,000. - 2. Secondary Control: Second Order, Class I I Stations .. Relative positional accuracy exceeds 1 in 20,000. 3. Additionai Control: Third Order 1 Class Stations .. Relative positional accuracy exceeds 1 in 10 1 000. The actual horizontal fiefd closures analyzed have been well above these minimums. A full positional analysis for each station will accompany the final documentation. The vertical control consists of a first order level line running through the project area. This line was tied to the horizontal network. The result is first order benchmarks at periodic spacing and third order elevations throughout the horizontal network. The attached map shows the horizontal and vertical control station > positions and the horizontal network configuration. The final data will be stored at R&M Consultantst Anchorage office. · . I • I I I I I I I. I I· I I I I I I I susiS/11 . . 0 .. 4 ACCEss· ROAD Subtask 2.10 of the plan of study is the location study necessary to determine the most desirable location for an access route ·and the most ecomonmical transportation mode or modal split~ There are three general corridors being analyzed for access to potential damsites, tunnel sites, and other anciiJiary features of the proposed project. tn addition consideration is given to using road r railroad or a combinatio.n of both to serve the project. The: work to date has been held to definition of well defined gen- eral corridors and which still satisfy the requirements of the plan of study with regard to location. Alignment design criteria being utilized for this study consists of the following: " APPROVED ROADWAY DESIGN PARAMETERS 60 mph 6% so Design Speed Maximum Grade Max2mum Curvature Design Loading ao· Kip Axle & 200 Kip total (Construction Period) Design Loading (After Construction) APPROVED RAILROAD DESIGN PARAMEI'ERS Maximum Grade Maximum Curvature Loading HS-20 2.5% 10° E-SO I I I I I I I I I I I I I I susiS/12 This criteria was applied to a number of possible alignments arid each alignment was sketched on one-inch to the mile contour maps. All alternatives were designed to serve both the Devils Canyon and the Watana Damsites. Other potential dam sites could be served with only minor changes if other sites should prove to be desirable. All alternatives were compared and the three· routes showing the most advantageous gr·ade, alignment and length characteristics were recommended for photography. As an additional check the three most promising corridors were flown by helicopter to provide the project team with a close look at actual ~;;round conditions. The three most oromisinc corridors shown 1n Exhibit , allow . ... --- consideration of a nL~mber of transportation alternative pi12.fiS including certain attractive stage con~truction and modal split options. These options will be examined in detail during latet" phases of the access study. The proposeci railroai alignment is near•fy coincident with the proposed road a.lignment on the south side of the Susitna River and must be considered as a viable alternative at this time. •' I I I I I I I I I I I I I I I I I I mfsc5/t1 0.5 AIRSTRIP LOCATION STUDY An airstrit-location study and site survey was done under Subtask 2.03 in September and October of 1980. The work was undertaken persuant to specific instructions from Ac.res American 1 Inc. Wind data from the weather recording station at Watana Camp was used to· generate a Wind Rose for use in determining the preferred orientation of the runway. Two possible runway locations were laid out on large scale contour mapping pursuant to FAA criteria for general transport class faci Jity. The two alignments were reviewed in the field and the more suitable alignment. was surveyed and reviewed by the archeological team. The proposed runway lay adjacent to an identified borrow area that was identified as having sufficient material for construction. A peat probe was used to determine the amount of unsuitable material on the surface .. The proposed alignment was laid out such that initial construction of 2500 feet was possible without encroaching on areas requiring drainage structures. This atignment is expandable to serve C-130 aircraft. Cost estimates were prepared and a Jocation study report SUb!llitted. I I I I I I I I I I I I I I I I I I susi1/u _ 0.6 HYDROGRAPHIC SURVEYS Hydrographic surveys extend from Portage Creek confluence· down- stream to the village of Talkeetna; a distance of ab1Jut 60 miles. During September and October of 1980 1 there were 62 cross sections of the Susitna River floodplain surveyed and a longitudinal profile of the rivers thalweg sounded. Hydrographic survey data wiH be used for hydraulic modeling 1 ice process modeling, sedimentation studies, river morphology studies 1 in stream flow studies and fisheries studies. River cross sections define the floodplain geometry -for the determination of tne pre and post project flow regimei formation 1 stability and decay of an ice cover; river morphological characteristics and will provide input for riverene aquatic habitat definition. ln addition to horizontal and vertical coordinates, each cross section documents vegetation limits and types, bed and bank materials, unique morpho~ogical fea'tures such as scour, erosion~ deposition, ice scars 1 • bar formation. and flow regime at the time of survey. Cross sections are plotted on air photo mosaics (scale 1 inch = 500 ft.) which enables tying each cross section together longitudinally along the river. Key cultural and environmental features can also be identified on the mosaics allowing positive location for special attention during the above listed analyses. Each cross section has a benchmar-k established in the field with a vertical and horizontal datum so that they can be resurveyed in the future to. determine changes with time in floodplain geometry. The vertical dnd ho.rizontal coordinates are entered on the computer in HEC-2 format and are available "in computer listing or punched card form.. A report including pic~ures with descriptions of morphological features wiU be utilized by the office analyzer to ensure proper interpretation of field data. ' ,, I I I I •~ I I I I I I I I I I I I I. E -TASK 3 -STATUS REPORT I I I I I I I I I I I I I .... I I I I APPENDIX E E.l fiaJd Data Collection and Processing The objective of the Field Data Index and Distribution System is to establish a formal system of conveying information concerning hydrologic and climatologic data avai 1 abi 1 ity to each member of the study team. The project data base consists of (a) Historical recorded data up to January 1, 1980; (b) 1980 data co·; lected by government agencies ~nd study tean members. Historic a 1 fi 1 es have been researched and ava i 1 ab 1 e data are docume-nteo in the Field Data Indexes prepared by R & M Consultants and updated every six months. Records which could be retrieved or copied exist in·R&M Consultants files. Records which are unavailable at this time, are identified as to location of files, data type, and period of record. There are 15 major data categories assigned to the Susitna Basin. With each major category, each data station is assigned a unique number which identifies the index file containing the data<> A convention of upstream to downstrea&1l order is used to number each data station. For example, if it is desired to review hydrological data availability in the Susitna River a.t Gold Creek~ the fnllowing index numbers would be referenced: 0140 Streamflow Continuous Gaging 0340 Water Quality 0440 Water Temperature 0540 Sediment Discharge All new data collected by R&M C()nsultants or other organizations will be added to the index system. Typical log of field observation carried out by R&~ Consultants is presented in Table E.l. Hard copy of the data wi 11 be stored in the R&M Consultants and Acres American offices. The data is made ava.i 1 able to project team members and other concerned parties. , .• I I I I ••• I I I I I I I I I I I I I E.2 -Hater Resources Studies E.2.1 -Streamflow Extension Historical streamflow data is available for several gaging stations on the Susitna River and its tributaries.· The longest period of record is avai 1 ab 1 e for the station at Go 1 d Creek ( 30 years from September 1949) . At other stations, the record length varies from 6 to 23 ·years. The Acres FILLIN computer program has been used for filling in'·'the incomplete streamflow data sets. It is based on the pragran developed by the Texas Water Development ~oard (December 1970) l1}.. The procedure adopted is a multisite regression technique which analyzes monthly time series data (streamflow, rainfall or evaporation data) and fills in missing portions in the incomplete records. The program evaluates statistical paramet.ers which characterizes the data set (i.e. seasonal means,· sea.sonal standard deviations, lag-one autocorrelation coefficients and multisite spatial correlation coefficients) ana creates. a fi.lled-in da~a set in which these stqtistical parameters are pr·eserved. A brief description of the steps involved in the program is presented in the following sections. I I I I I I I I I I I I I I I I I I I ••• E.2.2 -Program Description The fill in procedure comprises· the following steps: 1. The data se!ts pertain.ing to individual sites are arranged in descending order of the length of record in each set. 2. Sample skewness is removed by a Gaussian transformation. The procedure chosen is a logastitimic trans format ion of each data item. 3. The mean and standard deviation of the transformed data sets are computed. 4. Each value of the transformed data is normalized by subtracting the monthly mean and dividing· the remainder by the monthly standard deviation. This transformation renders the time series data stationa·ry , to the second order. 5. The linear predictor equations for each site are estimated. The dependent variable at time step i at site s is a function of time step i, and variables at several other sites. The general form of the Pl'edictor equation i is: s .. Ys,i = as, YK, + s -l K . + 1 b + K = 1 1 k = 1 k Yk, i es .. s, ' 1 where as,k and· bs,k are the regression coefficients and es, i is a random Gaussian process with the covariance function equal to the multiple, correlation coefficient matrix. 6. The predictor equations are used to synthesize data for the gaps. The voids are filled in a reverse direction going fr·cm the denser tu the sparser data. 7. The synthesized values are aJjusted in or.der to avoid abrupt transitions which sometimes occur at the interfaces of the synthesized and available data. This smoothing procedure uses the left-hand edge of the gap to set up a 1 i near· corrector which introduces it into the analysis as a maximum probable upper (or lower) bound of the process. 8. The inverse transforms are carried out on the data to convert it back to the original units. ' The fill-in procedurE pr"eserves the statistical parameters of the original time series: mean, variance, autocorrelation and cross carrel t ion coefficients tt · ,I •• ;I I I I :1 I I I •• I I I I I I I I E.2.3 -Data and Computer Runs Mean monthly flow data obtained from the USGS was used as input. A subroutine which intsrfaces the FILLIN program with the USGS data fornHit was set up by Acres. Table E2· shows the available historical data at the ~1aging stations. Tables E.3 to E.9 summarize the i-nput data. All the missing data are identified as -1 for computation reason. Records of all seven gaging sites were used in the first model run. Lack of overlapping data between Cantwell, Chulitna and Susitna stations resulted in a zero correlation which aborted the fill-in procedure. The extension of data for the Susitna station was therefore~ carried out without the Cantwell and Chulitna station records. The mean and standard deviation of the filled data sets (Table E.lO} are within the limits of the confidence interval of 5%. The lag-one correlation coefficients show similar limits (Table E.ll) for the un-filled oata st:ts. The spatial correlation matrix shows a good correspondence of the·values in winter and fall and a fair correspondence in spring and summer .. Spatial corre 1 at ion coefficients for uti 1 i zed and fi 11 ed data sets are given in Tab'les E.l2 and E.l3, respectively. Filled-in data. sets for the seven gaging sites are presented in Tables E-14 to E-20. The fill-in procedure used appears superior to other existing regression procedures which have difficulties in preserving autocorrelation and spatia·! correlation. Probably the smoothing procedure used in this program has an important contribution to the fitness of the model~ E.2.3 Estimate of Streamflow at Dam Sites Estimate of mean monthly flows at the sites was made adopting a linear drainage area relationship between the gaging stations and the dam sites~ For Denali site, such a relation could not be used due to lower unit run off from the Lake Louise area. Si nee the loca1 area at the dam site is simi 1 ai"' to that below Cqntwell station, the streamflow was directly related to the unit .flows measured at Gold Creek, Cantwell and Denali gages. The following, relationships were used to calculate streamflows at the dam sites: I II I I I I ~· I 'I I I J. I I I I I I I 1. 2. 3. 4. 5. 6. 7. Qoc = 0.827 (Qg _Qc) + Qc QHDC = 0.802 (Og _Qc) + Qc Qw = 0.515 (Qg _Qc) + Qc Qsrrr = 0.042 (Qg _Qc) + Qc Qv = Oc Qo = 0.153 (Q 9 -Qc) + Qd ' OM = 0.429 {Qc -Qd) + Q ' Where Q =Streamflow in ft3/set· A = Drainage area in mi2 ,;; Subscript DC, HDCt: W~ SIII, V, D and M stand for dam sites at Devil Canyon~ High Devi 1 Canyon, Watana, Susitna III, Vee, Denali and Maclaren respectively. Subscripts g, c, and d stand for gaging stations at Gold Creek, Cantwell and Denali respectively. The computed mean monthly flows for the 30 year period at each dam site are given in Tables E.21 to E.27. I I I I I I I I I I ·I I I I I I I I I E-3 -Flood and PMF Studies E.3.1 -Flood Studies Historical flood records of stat·ions along the Susitna River and its tributaries indicated~that the ma..iority of flood peaks occur in the months of June and August3 Figure El. Generally, the annual flood peak is a result of sno\\me1t or a combination of snov.melt and rainfall over an extensive area of the basin~ To date, 55 percent of the annual maximum flood peaks of the Susitna River recorded at Gold Creek have occurred in June. The summer flood peaks generally occur in August and are a result of heavy widespread rain augumented by significant sno~elt from hfgher elevations and glaciers. · The 1 argest flood peaks observed and the mean annual peak at the stations on the Susitna River and its tributaries are given in Table £.28. TABLE E.28 -Largest Observed Peak Discharg~ Mean. Maximum Annual Observed IJate USGS Drainage Flood Flood Maximum Gage.· Area-Near Near Peak Station No. Mile 2 cfs cfs Observed Maclaren River near Paxson (15291200) 280 6,000 9,260 8-11-71 Susitna River near Denali · (15291000) 950 17,000 38,200 . 8-l0-71 Susitna River near Cantwell (15291500) 4,140 33,700 55,000 8-10-71 Susitna River at Gold Creek (15292000) 6,160 53,000 90,700 6-7-64 --,~~~--~--------~-------~~--·-; r----,----,-~-~~---, --: I I ··- ! I I I I I I I I I I I I 'I I "el I R&M Consultants have conducted frequency analyses of streamflo~tt to ·determine up to the 1:10,000 year flood peak in the ba5in.. In addition, they have performed other statistical analYses to. determine relationships bet\veen the twenty ( 02o> and two year_ (Q2) flood peaks for a check of the homogeneity of floods at the stations selected for inclusion into a regional flood frequency analysis. The statistical frequency distribution found to give the best fit to available data was the three-parameter log normal distributi6n in the basin. · The ratio Q2o/Q2-was developed for both the annual and October-May peak dis~harges. The ratios for these two series are given in Tahles E.29 and E.30 and indicate that the stations selected in both cases for the regional flood peak frequency analysis are homogenous at the 95 percent confidence level. The Multiple Linea-r Regression analysis conducted by R&M Consultants related mean annual instantaneous peak flow to basin characteristics. Twelve wat~rshed parameters were considered, including: drainage area, main channel slope, stream length, mean basi.n levation, area of lakes and ponds, area of forests, area of glaciers, mean annual precipitation, precipitatinn intensity, mean annual snowfall, and mean minimum January temperature. A forward stepping multiple linear regression computer program was utilized for this analysis. It was found that drainage area, stream length, area of glaciers, mean annual precipitation and mean annual snowfall were the most influential parameters in predicting mean annual instantaneous peak flow .. For October -May instantaneous peak flows, drainage area and stream length ware found to be the most influential .. The equations developed from the linear regression analysis are: . ( 1) Mean Annua 1 Instantaneous Peak Q = 7.06{DA) + 46.36{L) + 697.14(G) + 200.15(MAP) -49.55(MAS) -2594.44 (2) Mean October -May Instantaneous Peak 0 Q c 1.56(DA) + 143.35(L) -2893.83 where Q = Peak Flows. stet DA = Drainage Area, mi2 L = Ma·!n Channe 1 Length, mi MAP ~ Mean Annual Precipitati0n, in MAS ~Mean Annual Snowfall, tn G =· Area of Hlaciers!l· percent . I •. I I I I I I I I I I I I I I I I I I mean October-May peak are 0.99 and 0.97, respectively. The standard error of the estimates are 1464 .. 9 cfs and 3081.1 cfs, respectively. Continuing studies include using log transforms of flows and basin parameters to determine if better regression equations can be obtained. Dimensionless flood frequency curves have been developed for both the annual instantaneous peak and the October -May instantaneous peak for the basin and are shown in Figures E2 and E3. The curves relate the ratio of a fl·aod peak with a given return period to the two year flood peak. The two year flood peak can be represented by the mean annual instantaneous flood peak given by the regression equations above. Therefore, a flood peak for a given return period in engaged areas can be obtained from Figure E2 or E3 if watershed characteristics are given. E.3.2 -Probable Maximum flood Studies Probable maximum flood (~MF) determination is being carried out by using the SSARR computer program developed by the Corps of Engineers for mathematical hydrologi-cal simulations~ operational river forecasting~ and river management activities. The SSARR program now being used is the same as used by the Corps of Engineers in the previous (1975) PMF studies. Present studies consist of a review of previous PMF studies on the Susitna River .. ' . ' The acceptability of the SSARR computer program for streamflow forecasting has been demonstrated on numerous occasions. Therefore, present analysis consist of only sensitivity runs to determine the changes to peak flows due to variations in critical parameters. Basically, the pre 1 iminary sensitivity runs w-ill attempt to show the change in peak flow estimates due to changes in input parameters such as temperature and precipitation rather than the physical parameters which describe the response of the watershed. The first sensitivity run consisted of delaying spring melt by inputting a cool temperature sequency in May followed by a sharp temperature rise in early June, with the maximum temperature occurring on the first day .of the recorrmended probable maximum precipitation (PMP) storm.. The t~mperature sequence ensures that very 1 imited melt occurs within the watershed prior to the PMP resulting in large quantities of snowpack available for melting 'in 1 ate May and .early June. The aim is to try and ensure that the sno\'t!ile1t peak flow occurs within a reasonable time of the rainfall peak. The temperature sequence assumed, 32°~ is not below the minimum monthly mean temperature for May that has been recorded at the representative station. The result of this run is an increase in the spring PMF peak inflow to Watana Reservoir from 233,000 cfs to 243,000 cfs, an increase ·of four percent. Other sensitivity runs will cons·ist of precipitation increases in amounts of snow on ground at the start of simulations and rainfall amounts, particularly for storms antecedent to the PMF storm.. Final runs will refine basin parameters to attempt to model the watershed more accurately, provided I I I I I •• I I I ·:1 I ·I I ·~· I I I ·0 I I .I , _ _.' -:. that the sensitivity of the model to increases in precipitation and manipulation of temperature sequences prove significant. l<uns made: increase snowpack 4% change full PMP storm 47% change temperature sequence increase 9% F E.4 -Climate Studies for Transmission Lines The objective of the studies is to provide climatological criteria for ice and wind loadings for of transmission 1 ine design . E.4~1 -Wind Loads Historical records of \'lind data collected by the National Oceanic Atmospheric Administration (NOAA -formerly National Weather Service) for the stations at Anchorage, Fairban.ks, Ta1keetna, Summit, Big Delta and Gulkana were obtained and reviewed. Data for the Healy Power Station sites were obtained from the Artie Environmental Information ana Data Center (AEIDC). The length of record varies from over 25 years at Fairbanks to ·less than two years at Healy. The records provide the fastest mile wind which is the fastest observed1-minute value. Gust speed are not reported by NOAA. Discussions were held with the Corps of Engineers on the design criteria used for the Snett~sham transmission lines.. It wa-s, however" apparent that the conditions in the Susitna tranmission cor-ridors will be far less severe than the Snettisham values. Further discussions with the utilities in the Susitna area are in progress. For preliminary design, the data collected from the stations listed ab~?ve were analyzed. A summary of the peak wind speeds are presented. in Table E.32. The highest wind speed of 74 mph was observE.~"' at Big De-y· ·;. Since the Healy record is short, hourly reported wind spes ~. were eJ 1ned for occurrence of speeds over 50 mph. In addition to the 70 mph 't> td recorded in Ja.nuary 1979, speeds of 50 to 60 mph were recorded severa~' . :mes in 1979. During the first half of 19~0, a peak value of 65 mph was recorded. Based on the above and experience on otheY' projects in northern c 1 tmates, conservative estimates of 100 mph for the highest wind speed {1 minute du·ration) and a 150 mph for a few second gust have been made for preliminary designs. These represent approximately 1:30 year events. TABLE E.32 Period of Record Maximum Observed _s_t_at_i~a~n~-~------------~----------~Y~ea~r~s~----~W~i~n~d_S~p~e~e~d~·-m~p~h~·----- Anchorage Big Delta Fairbanks Gulkana Healy Summit Talkeetna 24 23 26 15 1-1/2 15 10 61 74 40 52 70 48 38 I I :I I I .. I I I I I :1 I I I I. I I I I E.4 .• 2 -Ice Loads Ice loads on transmission lines usuc.,lly resu'lt from freezing precipitation and/or_ in-cloud icing. (a) Freezing Prec]Ritation Long term data on freezing precipitation is available only for Anchorage and Fairbanks stations (lO years). For 6u1kana, Big Delta, and Talkeetna only 3 years (1969 -72) -record could be obtained. Three hourly data obtained from the NOAA ~~ere analyzed and a plot of occurrence frequency for Anchorage ·a.nd Fairbanks has been prepared, Figure E.4 .. 1. This indicates that a potential 2u ice accumulation has an occurrenc~;~ frequency of 1 in· 30 years. (b) In-cloud Icinq With the avail' able information on cloud cover~,· temperature and wind, it has not been p1ossible to estimate in-cloud icing •. Field observations of actual ice-accretions· during individual in-cloud icing events are being made during the winter of 1980. With this and other climati,c data collected it is proposed to calibrate an Acres mathematical model that calculate~) in-cloud ice accretion as a function of super cooling, cloud drop size distribution (cloud type) and wind speed and estimate potential ice accretion for design conditions. E.4~3 -Combined Wind/Ice Loads For design of the transmission lines a combination of wind and one of the two types of ice load~; is expected to be'critical. In th~~ absence of estimates for in-cloud icing loads, it is proposed that pr·eliminary designs be based on wind loads due to 100 mph sustained wind and/or 150 mph gusts in combination with 2u icE.~ accumulation due to freezing rain since this i,ce may remain on the lines for some time after its accumulation. A detailed evaluation of the combined ice/wind loads is proposed to bE.~ made ~fter this winter field data is analyzed taking account of the economic impact of the design loads on tower designs, SUSITNA HYDROELECTRIC PROJECT Table E.l -Hydrology Field Obser·vation Log --------~---~------ Parameter Measured (4) River Stage (Sus itna Riv.er) (5) Water Quality(l,2) (6) Sediment SUSITNA HYDROELECTRIC PROJECT Table E.1 -Hydr:ology Fiel~ Observation Log (Cont•d) Station location ( i) Deadman Creek (a) Devil Canyon ·(a) Susitna River near Watana Dam site (b) Susitna River near Cant we 11 (Vee Canyon Site) (c) Susitna River ... , Go 1 d Creek {a) Susi~na River near Cantwell (Vee Canyon Site) (b) Susitna River at Gold Creek Type of Instrument Used Crest-stage recorder Staff Gage Martek Water Quality Data Logger VWR pH Meter YSI DO Meter YSI S-C-T Meter Van Darn ~ampler Imhoff Cones Same as at Vee Canyon Point-integrating Suspended Sediment Sampler Same as at Vt~e Canyon , Date of Installation (1980) 7/30 4/81 10/23 N/A N/A N/A N/A Date or Observation ObservatiOlll' Freguency (1980) Unscheduled Unscheduled Conti rn:ous Sum: monthly 6/19 Win: 2-3 months 8/8 9/5 9/17 10/17 Sum: monthly 8/8 win: 2-3 months 10/14 Sum: monthly 9/5 Win: 2-3 months 9/17 10/18 Sum: monthly .. 10/16 // Tjrpe of Observation Event Event Schedtuled Schedtllled· Scheduled Scheduled Sched/Event Scheduled Scheduled Scheduled Scheduled SchedlEvent Schedule~d ... Scheduled - ---··-·-- - -,_ - - -... - - -·-- Parameter t~easured (7) Climate (3) (8) Snow Densi.ty and Depth SUSITNA HYUROELECTRIC PROJECT Table E.l -Hydrology f·ie1d Observation Log (Cont'd) Station location (b) Devil Canyon (c) Kosina Creek (d) Tyone River (e.) Denali (Sus itna lodge} (f) Susitna Glacier (a) West Fork G·lacier Snow Course (b) Susitna Glaciar Snow Course Type of Instr·ument Used MRI Weathetr Wizard (IWW) MRI Weather· Wt zard MRI Weather Wizard MRI Weather Wiz.ard MRI Weather Wizard MRI Weather _Wizard Carpenter Machine Works Snow Sampling Kit Aerial Snow Markers Same as at West Fork Date of Installation (1980) 3/13 7/17 8/25 'd/21 7/18 7/20 8/26 (4) 8/28 9/4 {4) Observation ·Frequency Continuous Continuous Continuous Continuous Cvntinuous Continuous Date of Observ atio:m Type of (i980} Observation 4/8 -6/lrn Scheduled 6/19 -7il1JJj 8/14 -lOl~ 10/17 p 7/17 ... 8/2.$ Scheduled 10/16 -p 8/25 -P Scheduled 8/27 ..: 8/l@ Scheduled 10/17 -12#1 7/18 :_ 8/28 Scheduled 8/28 -1 7/20 -8/Jl Scheduled 8/7 -:8/14 8/28 -p Win: monthly l/1/81 Scheduled Win: monthly 1/l/81 Scheduled --·-----------------}'-- SUSITNA HYDROELECTRIC PROJECT '$> Table E.1 -Hydrology Field Observation Log (Cont'd} Date of Date of Type of Installation Observation ObservatioJll Type of Parameter Measured Station Location Instrument Used (1980) Fre~ency (1980) Observation (c) East Forst en acier Same as at West 9/4 (4) Win~ monthly 1/1/81 Scheduled Snow Course Fork (d) Butte Creek Pass Same as at West 9/11 (4} Win: monthly 1/1/81 Scheduled Snow Course Fork (9) Ice Buildup (a) Watana Camp Steel Plate 11/12 Unscheduled Event During Precipitation (b' } Denali Steel Plate 11/12 Unscheduled Event {Susitna Lodge) (c) Healy Steel Plate 11/81 /Unscheduled Event (proposed) (10) In-cloud Icing (a) Watana Camp Short Section of 9/10 Unscheduled Event (ice buildup on Transmission Line 10/16 transmission 1 ine) "" .. (b) Denali Short Section of 9/11 Unscheduled Event (Sus itn a Lodge) Transmission Line 10/20 (c) Healy Short Section of 1981 Un sched u 1 ed Event Transmission Line ~proposed) (11) Snow Creep (a) Watana Camp 12/80 (proposed) Win: monthly 1/1/81 Scheduled (o) Devil Canyon 12/80 ( proposf~d) Win: monthly 1/1/81 Scheduled ----------------·--- SUSITNA HYDROELECTRIC PROJECT Table E.l -Hydrology Field Observation LQB_ (Cont'd) Date of Date of .Jype of Installation Observation Observ at i QtSI Type of Parameter Measured Station Location Instrument Used (1980) •> Frequency (1980) Observation (c) Healy 12/80 {proposed) Win: monthly 1/1/81 Scheduled (12) Ice Thickness Susitna River and Ice Auger N/A Win: monthly 12/1 Scheduled and Competence Tributaries (5) Measuring Tape Ice Penetrometer ' (13) Extent of Ice Susitna River SLR Camera N/A Daily or weekly 10/80, Event Cover, Locations Survey Equipment During f.reeze-11/80, 1~/80 of Ice Jams up & Bt .. eak-up 4/81, 5l'$1 (14) Glacial Sus itn a Glacier Survey Equipment 6/81 Monthly or Scheduled Composition SLR Camera (proposed) Bimonthly and Movement Aerial Photography ----------------sa--- SUSITNA HYDROELECTRIC PROJECT Table E.l -Hydrology Field Observation Log (Cont'd) NOTES: (1) WQ parameters measured by the continuous water quality monitor: water temperature, dissolved oxygen, condoci:ivity~ pH, and oxidation -reduction potential. {2) WQ parameters m~.J"Jured in the field: dissolved oxygen, water temperatures conductivity, pH, alkalinity, settleable solids, and free carbon dioxide. (3) Clima~e parameters measured at each station: air temperature, average wind speed, wind direction, peak wind gust, relative humidity, precipitation, and solar radiation9 Snowfall amounts will be measured in heated precipit<ation bucket ;:.~ Wanata only .. Data are recorded at thirty (30) minute intervals at the Susitna Glacier station and at fifteer. (15) minute intervals at ali the other stations. (4} Dates refer to dates of installation of aerial snow survey markers. The actual snow courses are located at (}ne of the markers at each of the three glaciers. (5) Several sites along the main stem of the Susitna and a few sites on the larger ~ributaries are to be observed ... ___________ .. _____ ; __ _ TABLE E.2-Available t/~an Mo'nthly Streamflow Data Sites (USGS Gage No.) Years 1950 1955 1960 1965 1970 1975 1918":9 Gold Creek (15292000) 1950 1g!u:9 Denali (15291000) 1957 1~9~ - Maclaren (15291200) 1958 19JU9 Skwentna (15294300) 1960 19:?9 Talkeetna (15292800} 1964 191:9 Cantwell (15291500) 1961 1972 Chulitna (15292400) 1958 1972 Susitna (15294350) 1973 1919 -- -- - -------------- TABLE-E..3 MAC.kAREJ~ UNFlLLE.D DAl'A SE \ SllE tiD. t HC LAREU ----·------------------·-------------...,....,=o:>.--.... ... '·"' YEAR OCT tmv ItEC JAN FEB HAR: UAY JUN JUL AUG SEP CAl:, ~·Q"\ 1 -t.o -t.o -t.o -I'7o -1;o -1..0 -r.u -I.o -I.o ·-t.o -I.o -t.o ~~-u- 2 -1 • 0 -1 • 0 -1 • o -1 , 0 -1 • o -1 • 0 -1 • 0 -1 • 0 -1 • 0 -1 c 0 -1 • 0 -1 o o 12'S1 -1 t 0 -1 t 0 -1 t 0 -1" t 0 -1 t 0 -1 t 0 "'"1 t 0 - 1 t 0 -1 t 0 -1 t 0 -1 t 0 -1 I 0 15!'S!'! I -.t.o -Lo -t.o -l.o -t.o -l.o -t. o -1.6 -1. o -t.o -I.o -I.o r~-sr- -t.o -t.o -t.o -t.o -t.o -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.~ ttS~ -1.0 -t.o -t.o -t.o ..;.t.o -1.0 -1.0 -1.0 .. t.o -t.o -1.0 -t.o 1~s~ -1. 0 -1 • 0 -1 • 0 -1 • 0 -1 • 0 -1 • 0 -1 • 0 -i • 0 .:.i • 0 -1 • 0 -1 • 0 -1 • 0 1 ?!25---~ - -1.0 -t.o -1.0 -t.o -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.o -1.0 t~~~ -1.0 -t.o -1.0 -t.o -1.0 -1.0 -1.0 -t.o 3532.o 3525.o 2699.o 784.o 1~sn 3 .o 1 .o 23.0 129.0 95.4 6.2.5 77.5 587.0 2B79;o 2680.0 2083.0 056.0 19'S~ 549.o 25o.o t9o.o 1so.<> 11o.o 94,3 91.5 t742.o 2t24.o 3359.0 304s.o 2439.0 t9&a 12 687.~ 195.0 149.0 110.0 93.9 96.0 145.0 1237.0 2678.0 3369.0 3299,0 1160.0 19&1 ---,3 3Eir.o 2·nr.o 17\i~-o t2<r:o--rr;o.-o---· 9:r.-o--I!:!o~·o---eJ2-;-6""-29l~.o 326s;o-~lf'27.o-'"""1II"'"TI"#27.o-f~H'-- 14 383.0 210.0 130.0 100,0 91.0 80,0 BJ.O 2131.0 3110.0 ~649.0 3136.0 12)3.0 1943 ts 416.o 14o.o 98.0 e5.o ae.o 11.0 12.0 3B6.o 4297.0 2764.0 2?24.0 871.0 194~. 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"" ·--·-~ ·--· __ ,_,.. .... ·-.... ~--... -----·----'""""~ ........ --------------------------------------------~---~· --- -.. ----- - -------- •·-•' ,;,..-,_. _', •·• • w' --- - ------ -- -- --- ·--~- SITE NO. 6 SKWEtHNA YEAr~ OCT uov [IEC JAN FEB MAR Af'~ MAY JUH JUL AUG SEP · CAl(':j~·-- 1 -1.0 -1.0 -t.o -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 19i5b ~-2 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 --1.0 -1.0 -1.0 t~1· 3 -1.0 -1.0 -t.o -t.o -1.0 -1.0 -1.0 -LO -1.0 -1.0 -.! .o -1.0 1~$~ 4 -t.o -t.o -1o0 -t.o -1.0 -1.0 -1.0 ::..L..Q. -t.t2 -1.0 -1.0 -1.0 t'iY~L--. 5 -1.0 -1.0 -1.0 -1.0 -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 1~~ 6 -1.0 -.1· 0 -1.0 -1.0 -1.0 -1.0 -1.0 -!.0 -t.o -t.o -1.0 -1.0 t~s 7 -1.0 -1.0 -1.0 -1.0 -1.0 -t.o -1.0 -t.o -1.0 -1.0 -t~o -1.0 1~6 A -t.o -Lo :..I.o -.i.o -1.0 -1.0 -1.0 -1.0 -t.o -1.0 -1.0 -t.o 1~51' 9 -1.0 -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.0 -t.o -1 .o -t,o -1.0 1:~5& 10 ·-1. 0 -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.0 -1.0 ~t.o -1.0 -1.0 1~5'9 il--:!5:32.0 ·Hiso.o 140090 1097.0 96i.o 843.0 835.0 104BO.o 13440.0 16690.0 15990.0. 9171.0 tiio- 12 3889,0 .1600.0 1597.0 1403.0 115<\.0 1155.0 1700.0 11210.0 20570.0 16480.0 13910. o: 12020.0 l~O.t 1l 4605.0 2200.0 1400.0 1200.0 860.0 760.0 1000.0 6613.0 15630.0 14930.0 12080.0 6723.0 1~~~ 14 2901.0 1250.0 1100.0 1900.0 eto.o 700.0 650.0 7/65.0 . 14050.0 20430.0 12020.0 7180.0 1iJ~3 15 5:155.0 1sso.o 940.0 970.0 750.0 600.0 840.0 1635.0 2725().0 16480.0 12680.0 6224·0 1?~" 16 4425.0 1 z.~o. o 130~0 92Q..O BOQ..!.O /40.0 !?.Q.&_-1~ HL_Q__JlJ§O • o 1937(!. 0 140.!0.0 13090.0 tS\~S --·-17 4122.0 1575.0 1150.0 1100.0 uoo.o 1J 00 I 0 1300.0 4502.0 19550t0 14180.0 17320.0 9812.0 1~&~ 10 5576.0 1400.0 900.0 720.0 t£.50.0 650.0 780.0 1794.0 1-\430.0 ·-14740.0 15760.0 9517.0 1967 19 3832.0 1560.0 1181.0 1Q.~~01. 1000~0 950.0 1293..L.Q_1_3460. 0 20'770 .o 174§0.0 l0560.0 3.855 .o l.2!1L_ __ 20 1929 .. 0 679.0 624.0 600.0 600.0 626.0 1·197.0 11070.0 19590.0 !3650.0 7471.0 3793.0 19.&9· 21 56.54. () 1607.0 832.0 766.0 700.0 650.0 728.0 11710e0 22980.0 21120.0 13030 ;() 6665.0 19?0 22 2919~0 2023.0 1l 94.0 B65.o 72t.o 613.0 607.0 5963.0 25400.0 20600.0 15920.0 6024.0 1)\71 2J.~-J020. o---"I327 e·o-!103. 0 9a9:o-a9a . o -aii: o ·---~._._. -·· ---------·--------9 2"5I:"o-i 972--··-742.0 8045.0 1533.0.0 16840.0 13370 .o 24 4551.0 2~'4o~o 1316.0 910.0 702.0 606.0 727.0 6349.0 15200.0 13850.0 9874.0 6164.0 1973 25 35•l0. 0 1iOO.O 1265.0 1023.0 902.0 8!.1.0 !005.0 6765.0 10650.0 11670.0 10480.0 11800 .o 19?-t 26 4557 .. 0 23l'S • 0 919.0 aoo.o 750.0 750.0 767.0 7352.0 19060.0 19520.0 117H>.o 8471.0 1Stl5 27 4704.0 197~ .• 0 1258.0 971.0 897 .. 0 eoo,o 12.70.0 Sfj0"6 • 0 H.i120. 0 11580.0 11120 ~o Bl65.() 197& 29 6196.0 289()&0 2871.0 2829.0 1821.0 1200.0 1200 d) 9906.0 ·36670 t 0 25270.0 20160.0 10290.0 1977 29-5799.0 2373":0--1548. 0 -·-----~----------_,.,. ___ ... -.,-..... ---·--·--------·---1J7•\0.0 ~'-'"-1213.0 944.0 8•U • 0 1023.0 9006 d) 1 :l84(). () 18100.0 7335.0 197B JO 4936.0 1580.0 ' 1555 ~0 1165d) 103-S,O 991 .. 0 1597.0" 11660.0 14980.0 15830 .. 0 16210.0 7448.0 1979 ______________ , _____ _ SITE ~0. 7 DENALI --~~~==~~~--~~==-------------------------------------------------------------------~~----------------~--=--- YEAR OCT tfOV DEC JAN FEB t\AY • Jun. JUL AUB 1 -t.o -1.o -t.o -t.o -t.o -t.o -td> -t.o -t.o -t.c -t.o· -1.0 1Ysij:=-·· 2 -1~o -t.o -1.0 -1.0 -i.o -1.0 -1.0 -1.0 -1.0 -1.0 -t.o -1~o 1951 J .:.f.o -1,0 -1.0 -J.O -1 1 0 -LO -1·2 -hO -ltO -1.0 -loO -1.0 1952: 4 --t.o -1.0 --t.o -t.o -t.o -t~o -1.0 -t.o -t.o -t.o --t.o -1.0 t95.l. 5 -t.o -1.0 -1.0 -t.o -t.o -1.0 -1~0 -t.o -t.o -1.0 -1.0 -1.0 1954 -·--L -1. •. 0 .--1 •. 0 -1 • .0 -.L.O -.t.~o -L •. (L -:.1.0 -1.0 -1.0 -1_.0 -1.~ -1.0 t9~~t ...... _ z -t.o -1.0 -t.o -1.0 -1.0 -1.0 -1.0 -1.0 -1.o -t.o -t.o -t.o 1i5A fl -t.o -1.0 -t.o -1.0 -1.0 -1.0 -1.o -1.0 12210.o 11170.6 97&9.o 40tz.o 1957 9 1277.0 41Q 1 0 268.0 21!a0 150t0 12~.Q 210·0 1163.0 8367,0 9150.0 6536.0 1879.0 195a to 939,0 399.0 tzo.o 112.0 at.o 41.7 ~J.o 11a2.o 8S9t.o B333.o 7B82.o 249s.o 1959 11 1577.0 760.0 575.0 444.0 321~0 275~0 265.0 3349.0 5237.0 9039.0 7910.0 4817.0 196Q 12 1781.0 660.0 493.0 331.0 271.0 281.0 415.0 2959.0 6412.0 8078.0 7253.0 2695.0. 1961 13 1211n.o 6ntr;o :tt-;m.o 2e.o.o 2~15;<> 22~-2err;-o-~I97.0 9l59?.o flf220'"';1i--v:.l5il;o 3649.o Ili'o-n"-··- 14 1079.0 5!0.0 310.0 250.0 230.0 200.0 210.0 3253.0 6763.0 10500,0 10210,0 3949.0 190.3 15 925.0 29o.o 18s.o 140.o t4o~o tto.o tJo.o 9to.o tl63o.o 7~77,0 6552.0 2633.0 1964 Ili t4!a.o 7o2.o 279.o 22o.o 2oo.o 2oa.o 32<>.o 2464.o 4o47.o 67SF.O 576:/l.o o9s-s.o I96ti 17 920,0 300,0 2iO.O 210,0 200.0 200,0 2BOtO 1629.0 6850.0 8287.0 6432.0 3200.0 1966 1B 920.0 300.0 240,0 210.0 200.0 200,0 280.0 1629.0 6850.0 8~87.0 6432.0 3200.0 1967 --~9 -I.o -r-;tr -L<r----=I.o -r.o -1.0 -r-;-u---=r;o -=1.u r1n~o.o 9S2t~.o -zrv:r:cr-"19lia- 20 700.0 304.0 172.0 145.0 140.0 145.0 229.0 1768.0 8146.0 9445.0 3919.0 2213.0 1969 21 1002.0 501.0 339.0 265.0 221.0 193.0 319.0 2210.0 5013.0 8454.0 6216.0 1946.0 1970 ~2 528.0 395,0 276.0 170.0 125.0 120.0 135.0 629o0 8099.0 10~10.0 16400.0 3298.0 197{-· 2J 1039.0 478.0 380.0 339.0 307.0 286.0 270.0 3468.0 65~2.0 10450.0 8664.0 2778.0 1972 . __ 24 667.0 323 •. 0 211.0 17Ba0 1&4.0 153,() 153.0 104~t<> 5741.0 8346~0 7268.0 2445.0 197"3 2r--e76. o 4 62. o 366 ~0--· :.u·o:·o-·-27 r:·o--!tis: o--262·: o -2 s:rr: '0~561.2:-o -9547";-o----929 .;,;_2 --. o'--__,5,..,.-t 52. o . i974 __ _ ~6 2135.0 673.0 381.0 300.0 200.0 200.0 200.0 1640.0 7040.0 12110,0 7295.0 3S7l.O 1975 27 1539.0 375.0 169.~ 112.0 97.0 90.0 123.0 1805.~ 5939.0 8558.0 10080·0 1822.0 1976 --__,...2a e94oo U7.o 3:n.o :!66.o. 2~070-23170 24~.o r.~9sd> a's3.o Iooi~.o rorao.o 3i5?.o 19,- 29 1148,0 652.0 439t0w J4Bo0 300.0 24b,~ 26Je0 2031~0 5250.0 8993,0 8614o0 J622o0 1970 30 965.0 463~0 312.0 263.0 229.0 203.0 250.0 2791,0 7650.0 9504~0 9178.0 4512.0 1979 ~----·-------~ ....... ____ _,__ .... -""\. ,..._, ____ ,._, ... -... ·~···~---~-•" --·---~ ., ... '"''~"" .,.-.,F .,._ _,, -•. _....,,. -· _,._. ... -...... _,.., .. .-..-----------""!---.. --... -. ... --.----·l'f!'-!11·----"' -----~------------- TABLE E .. lO Mean and Standard Deviation Before and After Fi 11 ing-in MONTH Site Statistica.l Before (No.of Data) Parameter or After 10 11 12 1 2 3 4 5 6 7 8 9 B 31,250 13,246 9,070 8!204 7,409 6,262 7,213 60,822 122,506 130,980 109~362 68,060 Go-ld Creek · Mean 11 30,054 12,658 8,214 7,905 7~037 6,320 6,978 60,462 123,697 131,931 11021840 65,963 f'\• (360) B 6,611 3~091 2,375 1,300 1,125 621 809 13,086 25,167 12,247 14·~140 13,458 so A 8,302 3~645 2,796 1,668 1,472 955 1,031 15,009 30,175 ~4,056 17 360 17,258 ~· B 1_~122 490 313 243 206 l88 232 2,036 . 7,285: 9,350 a~oso 3 349 , . Denali Mean A 1,106 475 308 252 210 187 237 2,072 7,195 9,277 1~¥98 3,1~0 (259) B 384 149 107 83 66 63 80 790 1,930 1,311 1~116 1,216 so A 340 149 107 112 79 69 73 834 1,797' 1,219 1 )49 1,132 .. lt B 409 177 118 96 84 76 87 802 2,912 3,180 2~572 1~148 Maclaren Mean A 409 173 110 93 82 72 85 824 .2,893 3-,179 2~SU6 1,194 (256) B 110 50 40 31 26 22 26 462 611 496 609 460 so A 106 48 39 30 25 22 24 488 562 437 581 474 B 4,297 1,779 1,267 1,078 903 809 1,016 . 7,920 18,578 17,090 13~370 8,149 Skwentna Mean A 4,237 1,731 1,195 1,057 861 787 1,004 8,651 19,860 17,277 13~566 7,997 (240) B 1,110 477 447 441 256 179 321 3»139 5,854 3,147 2~871 2,452 so A 1,084 586 442 437 241 174 288 3,460 7,261 3,332 2,976 2,564 B 2,505 1,146 8l~2 674 565 497 569 4,290 11,498 10~513 9.272 5,429 Talkeetna Mean A 2li698 1,195 851 673 560 480 551 4,071 11,572 10ll751 () 10~405 6,015 (184) B 825 273 176 102 92 87 129 1,776 3,801 1,954 2~879 2,180 so A 726 308 191 114 104 81 121 1,489 3,643 1,741 3~015 2,004 B 3,033 1,449 998 823 . 722 691 853 7,701 19,326 16,891 14$658 7,800 Cantwell Mean A 3,073 1,438 981 822 703 657 82B 7,165 17,642 16,446 16~037 7,729 (137) B 802 476 314 272 230 228 257 2,911 6,462 2,906 4,126 2,668 so A 776 430 263 219 193 225 275 2,798 5,397 2!1662 3!163 2,673 B 4,858 1,993 1,456 1,275 1,094 975 1,158 8,510 22,536 26,332 22,184 11,736 Chu1 itna Mean A 5,282 2.,094 1,493 1,311 1,089 973 1,184 9,658 23,267 26,982 22,444 11,876 (176) B 1,276 389 261 198 . 147 147 249 3,159 5,648 3,362 4;674 3,671 SO. A 1,351 471 290 194 133 129 195 4,257 5,383 3,636 4;388 3,666 B -Before A -After _.', I Ia I TABLE E.ll Lag-One Correlation Coefficients •• Before After Filling Filling I Gold Creek .61 .61 I Denali Maclaren .56 .559 .59 .575 I Skwentna .60 .608 Talkeetna I Cantwell .66 .628 .. 64 .628 ., I Chulitna .41 .499 Susitna .574 .715 I I I I I I I I I I - - - - - ----- - - - - - - - - - - TABLE E.l2 SPATIAL CORRELATION MATRIX UNFILLED DATE SET Gold Creek i . 1.0 .588 .628 .480 .346 .530 .525 .552 .395 .456 .257 .166 .233 .333 Denali i 1.0 .728 .415 .732 .583 .863 .198 .611 .443 .211 .442 .242 .529 Maclaren i 1.0 .482 .592 .308 .730 .377 .524 .694 .346 .367 .154 .499 Skwentna i 1.0 .368 .3b4 .673 .191 .248 .346 e544 .157 .213 .2..77 Talkeetna i 1.0 .480 .724 .019 .386 .. 402 .172 .586 .112 .408 Cantwell i 1.0 .4tl8 .154 .280 .113 .033 .!66 .392 .204 ? Chulitna i 1.0 w208 .558 .479 .276 .492 .225 .666 Gold Creek i 1.0 .553 .615 .452 .290 .486 .490 Denali i-1 1.0 .730 .399 .722 .550 .853 Mclaren i-1 1.0 .478 .593 .276 .721 Skwentna i-1 1.0 .350 .351 .453 Talkeetna i-1 1.0 .429 .706 Cantwell i-1 1.0 .453 Chulit11a i-1 1.0 -~ ------ ----·-.. ----- TABLE E.13 SPATIAL CORRELATION MATRIX FILLED DATE SET Gold Creek i 1.000 0.487 0.554 0 • .527 0.322 0.513 0 .. 489 0.502 0.257 0.328 0.296 0.116 fj,.277 0.243 Denali i 1.000 0.710 0.379 0.664 0.557 0.833 0.171 0.628 0.408 0 .. 194 0.375 0-.308 0.490 . MacLaren i 1.000 <.'~441 0.474 0.350 0.742 0.313 0.463 0.629 0.282 0.269 04233 0.461 Skwentna i 1.000 0.422 0.448 0.454 0.276 0.277 0.290 0 .. 607 0.231 0,.307 0.279 Talkeetna i 1.000 0.485 0.645 0.066 0.373 0.270 0.220 0.574 0 .. 221 0.356 ca·ntwell i 1.000 0.468 0.238 0.325 0.185 0.246 0.253 0.559 0.246 Chulitna i 1.000 0.187 0.514 0.437 0.231 0.386 0,.243 0.611 Gold Creek i 1.000 0.483 0.550 0.532 0.319 0 .. 512 0.489 Denali i-1 1.000 0.707 0.381 0.663 0.555 0.834 MacLaren i-1 1.000 0.443 0.471 0.345 0.742 > Skwentna i-1 1.000 0.423 0.477 0.455 Talkeetna 'i-1 1.000 0.483 0.644 Cantwell i-1 1.000 0.464 Chulitna i-1 1.000 -------------- SITE NO.= 1 RUNF GOLD CREEK YEAR OCT uov DEC JAN FEB APR HAY JON JUL AUG SEP SUHYR CAll,,'~~ t 4335.0 2583.0 1439.0 1027.0 7BB.o 726.0 870.0 t15T0.0-19600.0-22600.o 19iieo.o 830t.o 95659.1 t~(b_..._ 2 3848.0 1300.0 1100.0 960.0 820.0 740.0 1617.0 14090)0 20790.0 22570.0 19670.0 21.240.0 108745.1 19~· 3 ss11.o 2744.o t9oo.o t600.<J tooo.o a~o.o 92o.o 5-119.0 32370.t 2&39o.o 2o92o.o 1448o.o 11419-t.t t9~ 4 8202.0 3497.0 1700,0 1100.0 820e0 820,0 1615t0 19270o0 27J:!Oo1 20200.0 20610.0 15270.0 120424.1 1~~:) 5 5604.0 2100.0 1500.0 1.300.0 1.000.0 790 .• 0 1235.0 17280.0 25250.0 20360.0 26100.0 12920.0 .115429.1 19S.'\ 6 5370.0 2760,0 2.Q.!§..O 1794.0 t~Q~O 11~0~0 1.200.0 9319.0 29960.0 27~60~0 25750.0 14290::...•:::...;0:;._....::1::.:::2:..:2:..:4~4~B ... :•:,..:::1_.;.1~~·.;5iS 1 495t.o i9oo.o t3oo.o 9ao.o 97o.o 94o.o 95o:017660:033J4o.o 3to9ott 245Jo.-o1933o.o 136941~2 ~~~-~·· a 5Bo6.o 305(hO 21-t2.o 11oo.o 15oo.o t2oo.o· 12oo.o 137so.o 3016o.o 2JJto.o 2054o.o 1990o.o t2415A.t tCJ.S'¥ 9 ft2li:,Q. 3951.0 3264.0 1965.0 1307.0 114B.i) 1533.0 12900.0 25700.0 2?980.0 2::!540.0 7550,o0 112953.1 19:SQ to 4B11.o 2t50.o t51J.o 1-448.<> tJo7.o 980.<> 12so.o t599o.o 2332o.o 25ooo.o :nteo.o t692o.o 125869.1 t~s~ 11 65ss~o 2aso~o 2200aO 1845.0 1-452.0 1197.0 tJoo.o t57ao,o l553o.o 22980.0 23590.0 ~05to.o 115792.1 ttAO r 12 779~.o Jooo.o 2694.o 2452.o t754.o tetc.o 265o.o 1736o.o 2945o.o 2457o~o 221oo.o t337o.o 129004.1 t9lt -~tJ 59t6:0-27'oo.o 21oo.o mo;o·---rsoo:014oO::o17oo.o t259o.....-o--4327o.·o2595o.o 2Jsso.o tsa9o.o t38366.o 1945- 14 6723.0 2800.0 2000.0 1600.0 15.00.0 1000.0 BJO.O 19030.0 26000.0 34400.0 23670.0 12320.0 ·131873.0 194~ 15 6~49.0 2250.0 1494~0 1048.0 966.0 713.0 745.0 4307.0 50580.0 22950.0 16440.0 9571.0 117513.1 19&~ 16 6291.0 2799.0 i211.o 960.0 860.0 900.0 1J60e0 12990.0 2S720 .. 0 279-\0.0 21120.0 1935().0 12!401.1 194\Sp_, __ 17 7205 •. () 2099.0 1631 .• "0 1400.0 1300.0 1300.0 1775.0 9645.0 32950.0 19860.0 21830.0. 11750.0 112744.1 194~ ta 412~<> H.oo.o 1sou.o 15oo.o t4oo.o 12oo.o t.i67.o t54ao.o 2951(}.0 26eoo.o 32&2o.o 16S7o;..;.o~~~""='J3Bl=0.:;..;.1~~~~94') ---r9 ..t9oo.o 2353.o 2o5s.o t9ef:O-t9o&.o-r9oo:·o--r9io:o··T&ieo:o-it5s·o:-o2642o.o t7tio.o-9at6.o tt7t3s.t t96r-··- 2o JB2.2.o 163o.o se2.o 72-t.o 723.0 9t6.o tsto.o 11oso.o t55oo.o t6too.o ae79.o 5093.o &6729,0 196\\ 21 3124,0 1215.0 .B66.0 824.0 769.0 7!6•0 10~0.0 1J39p.o HMJO.O 222{!0,0 19980.0 9121.0 90124t1 1~!9 22 52BQ.O 3407~0 2290.0 1~42.0 1036.0 950.0 1082.0 3745~0 32930.0 23950.0 31910.0 14440.0 122470.1 1971 23 5847.0 3093.0 251().0 223~.0 2028.0 1823.0 1710.0 21890.0 34430.0 22770.0 19290~0 1240090 130030.1 1972 24 4B26.o 2253.0 1465.0 1200.0 12oo.o tooo.o t027.o U23s.o 2790o.o t825o.o 2029o.o 9074.0 96620.1 19?3 --·-2s 3'7337o1523.o Io3~r:o-s74.-o-·777:o·-7:rr:o-99-~:o--r6Iao-:o17a7o.o taeoo.o1622o;o t22so:=o-~9..,..o97,;..7;:..:.t~~~974- 26 J.739.o t7oo.o t6o3.o t516 .• o 1471.0 t4oo.o 159J.o .t53so.o J23to.o 2772o.o· 1809o.o 16Jto.o 122202.1 1975 27 7739.0' 1993o0 1081.0 974.0 950.0 900.0 1373.0 12&20.0 243BO.O 18940.0 19800.0 6BS1.0 97631.1 1976 2B 3B74.o 265o.o 2t\03.o t829.o t6ta7015oo.o t6ao.o t2&eo.o J797o.o 22B7o.o 192.oto.o 12640 .. o . 120954.1 1977 29 7571.0 3525.() 2589.0 2029.0 1668.0 1605.0 1702.0 11950.0 190$0.0 21020.0 16390.0 8607.0 97706tl 1970 L , _____ Jo_.~9o~.!l> 2~~.§.!L-!e!!.!..!.Q __ !3~?<cd> .. __!_~~~!~o ~,._l2~HhQ..._~ t!@..!.9_t~~7.~.!.L~i2.?JbJL ?.~~~o .1.-~.1.60.dL!.9?29· o tt3t26 t t 1!22.~ ... ---.. ------------·- ·SITE tW,= 2 fWNF raEUALI YEAR OCT uov [IEC JAil FEIC HAR APR UAY JU1'1 JUL AUG SEF· SUMYR c~~~-~ 1 1272.9 591.5 321.0 382.5 251.2 2~0.7 2SB.B 2152.1 6977.(1 9.18~;. 2 7934.9 1794.5 31352.3 ttS~ 2 711.1 242.1 152.4 122.9 113.9 1ot.s 315.8 1;!~0.0 6155 .. ,s 8022.i 5167.0 29.60.2 25524.6 t9<St 170:9 80327:9 ~-3 1084.4 549.7 336.5 297,5 19Bo9 178.4 1367.4 9411.0 7715.6 :5092.5 32435.7 1~-'S~ 4 1028.2 391.1 232.2 238.7 134,7 . 77.9 216.0 1601.3 6270na 8950.7 6349.5 2255.9 27747.2 t«tS~ 5 914.7 192.2 145.5 84.8 64.3 88.7 217.3 2593.9 5077.0 7864.5 6286.8 2287.0 25816.8 t~ar-6 1120.6 546.9 450.0 299.3 229.t 1 .. 6.6 164.2 . 1380.0 7192.5 10378.4 10047.8 2831.5 34786.8 l~S 7 1455.2 373.7 247.4 196.5 300.4 275.0 21)9.3 4259.3 9754.7 9-4'19.4 5~i06. 8 3242.2 35109.9 t'lS& a 1057.7 475.1 439 .• 7 650.9 .t\22.4 287..1 291.9 3017.3 12210.0 11170.0 9769.0 4G17.0 43908.1 195~. 9 1277.0 610.0 288.0 219.0 tGo.o 120.0 2io.o 1163,0 8367.0 9fso:o 6536.0 1879.0 29969.0 t9sa-· 10 939.0 390.0 170.0 119.0 81.0 ·U .7 43.0 1782.0 8991.0 S33J.o 7982.0 2-198.0 31169'. 7 H'S9 11 1577.0 76(). 0 575 ._o 444.0 3?1.0 275,0 265.0 3349.0 5237.0 9039.0 7910.0 4817.0 34569.0 19'AO 12~---Tiat.o 660.0 483~0 331.0 211.0 281.0 4is.o 2959.0 6412s0 8078.0 7253.0 2695.0 31619.0 196t 13 1290.0 680.0 440.0 280.0 240.0 22o.o 280.0 2197.0 9087.0 10220.0 9454.0 36 .. 9.1} 38037.4} 194~ ~~ 1079.0 510.0 :uo.o 250.0 2Jo.o 200.0 21Q_.O 3253.0 6763.0 1 ~§oo ·~Q_!Q21 o ._o 3949.0 374~_1.0 19A;t_.__ 15 925.0 290.0 185.0 140.0 140.0 1io.o 130.0 9to:o116Jo~o 7577.0 6552 •. o 2633.0 31222.0 l9&q. 16 1468.0 702.0 279.0 220.0 200.0 2oa.o 320.0 2164.0 4647o0 6756.0 576~.0 6955.0 29983.0 1~~s 17 920.0 300.0 240.0 210.0 200.0 200.0 280.0 1629.0 6850.0 8287.0 6432a0 3200.0 28748.0 1~6& BJ 920.0 300~0 240.0 210.0 200.0 200.0 280.0 1629,0 6850,0 8287.0 6432,0 3200.0 28748.0 l'f~7 19 973.5 616.9 323.6 189.0 266.9 2&6.7 3.25.0 1495,3 613Eh 2 11840.0 9825.0 2192,0 34452.1 19QQ 20 700.0 JO'l.O 172.0 145.0 140.0 145.0 229.0 176Bo0 8146t0 9445.0 3919.0 2213.0 27326.0 19a.9 it 1002.0 501.0 339,0 265.0 2~·1. 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I .I I I •• I I I I :1 I I I I I I •• I TABLE E.29 Homogeneity Test Annual Instantaneous Peaks Station Susitna River at Gold Creek Caribou Creek near Sutton Matanuska River at Palmer Susitna River near Denali Maclaren River near Paxson Susitna River near Cantwell Chulitna River near Talkeetna Talkeetna River near Talkeetna Montana Creek near Montana Skwentna River near Skwentna Tonsina River at Tonsina Copper River near Chitina Q2ol~2 = Yzo 1.83 1.82 1.49 1.81 2.02 1.68 1.47 2.33 1.96 1.49 1.72 1.35 Yzo = 1.748 SD = 0.2776 Limits of 95% Confidence Interval (1.11 -2.39) TABLE E.30 Homogeneity Test October -May Instantaneous Peaks Station Susitna River at Gold Creek Caribou Creek near Sutton Matanuska River at Pamer · Susitna River near Denali Maclaren River near Paxson Susitna River near Cantwe 11 Chulitna River near Talkeetna Talkeetna River near Talkeetna Skwentna River near Skwenta Tonsina River at Tonsina Copper River near Chitina L irnits of 95% Confidence. Travel (0.99 -3.41) Q2oiQz = Yzo 1.57 2.63 2.24 2.35 3.32 2 .. 33 1.98 2.12 1.76 2.45 1.50 v20 = z.zos so = o.5175 --------------------U9~ 10 X tO TO ~ INCH 7 X l0c4NCHES n &; l<EUFFEL Be ESSER CO, t.i~DE. lit us" " 46 1320 j·:·~n!;Ltttrr 1:!1 · ·----.· ·------~-i ·f · ·rut~· ------·t ··.. H7 , ; • ~ 1. ; ! : 11 d , 1 i 1 1 1 : t . · · ~ -· -· • t .. · ) t 1 ·r . ( u 11 -. . ---. -... -1 --~-. .. . 1~,r . 1 f -· {·II-t1 J ~ t l' , H i!.L 7 • ::-F i! ! i ~ i j , ! . ; : I ; ; ~~ • }11' . . . I I • . . • . . . . . . . .. • . .. . . . . .. : . . . .. : .. ; .. , . . • • . .. , •. !, , . . • • ". t,. . . 41+ ~m "' . ~ ... . , . ... ' ~ --.. .. --..,. .. . ... .... ,., -· ~....... -·-·-· ..... ~ ~--· .. -.. ·;:: dH II' j' f. · .. ·· :: · ·· ---. ·: ·_ ·· -· I ~~ r ,,.~ Hi liP ... :11! , ·i-ff·.; .. j .... -. .,1 .-~ - : ., t T ' I I I . . . .. t . . I -j t f 11 ~ i I J u 1 f if .• l ... ; ',,. '""' ., . . .. . c. . ... '... . .. .,. ' • .. ~ .. ~ ~ ' ' •• ._ 4 ~ ~ ' ' . .. ~ -. ' .. 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"·---~ ~-" ::::: -:-1=:::·"· -• I·· =: i--· .. :;;::.: : -;t-: -1= ·---:::.. :::. ~ f:-::j:.:-f= .::-':"""':":- r---- -- - 1 0.5 - 8 7 10 7 ·-=-"'"-----5 . ~--- --·--.~" F.,... -1-f':"·t:-.:::· f·-r-1=:: 1---t--+-l·· • --f-· --lH-t-++++lH-+++t--+--+-+-+-1-++1-H-H+HH+H+-li-+l-t-H~H-H-l-t-iH-11-t+ l+t++++t+l-+l+tt-HI-H-H+I-+-t-.-t-+--1 ... -+t-t+t<-t-~-Hr+-t-~-t--11-t----ltttir'f"l·+•"' f,.~ I-'-'~~ : ·-1---I~ f-•--1--1·-f-'t-1-1-H·-HH+·t-'--t-•r-t-1-1-+-t •+++t-HH4·H+H-+I-#+1·+1--I+J+H-f..I-I+H--t++-l+-l++++~l+t+t I+•HHI--1--t-·-+-+l+l+"li++· f+··t-·1--·· -fo---t-1-t--t-t·· -~ ~-<•-"~-~- ~..f·4-1--f..f-H-·l-Hi--H11...J.. .t...-++-t-44-+ +H-·I+l-e'l-ci-HH41+lM-lH-I+-H-+I-+Hrl-t1+H·-H++-I-r-4-.... 1+4+4-H-l+l--1'-<' l-1--'-·.· •· " ·-.t--. ., •.• ,. . 0.01 o.os o.I o.z· 0.5 1-2' 20 30 ... 49 5Q .. 60 ', .10 ..... 80 .. ~-·-.. '90 ... . . ..95 , - - , II ~I I I I I I I I I F--TASK 4 -STATUS REPORT I I I I I I I I I / .... ,!:;._; I I I I 'I I I I I I I I I I I I :1 I I ..... __ <~~ APPENDIX F TASK 4 -SEISMIC STUDIES The studies conducted by Wood"'{ard-Clyde Consultants in 19~0 are summarized in the following Conclusions section from the Interim Report on Seismic Studies for the Susitna Hydroelectric Project. The summary plates and tables showing the relationship~ and data upon which these conclusions are based have been referenced and are included at the end of the Appendix. I I I I I I I I I I I I I I I I I I I CONCLUSIONS Two sets of conclusions have been drawn from the results of the investigation conducted to date. One set, designated technical conclusions, are those conclusions related to scientific data collected. The second set, designated feasibility conclusions, are those conclusions considered important to evaluate the preliminary feasibility of the Project. Both sets of conclusions are discussed below and form the basis for tne proposed 1981 study plan. F.l Feasibility Conclusions (a) No faults with known recent displacement (displacement in the last 100,000 years) pass through or adjacent to the Project sites. (b) tc) (d) (e) (f) The. faults with known recent displacement closest to the Project sites are the Denali and Casile Mountain Faults. These faults and the Benioff Zone associated with the subducting Pacific Plate (at depth below the Project site) are considered to be accepted seismic· sources. Preliminary maximum credible earthquakes for the Denali and Castle Mountain Faults and the Benioff Zone have been estimated as: magnitude (M ) 8.5 earthquake on the Denali Fault occurring 40 miles from the Devil Canyon site and 43 miles from the Watana site; magnitude (M 5 ) 7.4 earthquake on the Castle Mountain Fault occurring 65 miles from the Devil Canyon site and 71 miles from the Watana site; and magnitude (Ms) 8.5 earthquake on the Benioff Zone occurring 37 miles from the Devil t;anyon site and 31 miles from the Watana site. Within the site region, 13 faults and lineaments have been judged to need additional investigation to better define their potential affect on dam design considerations. These 13 faults and lineaments (designated as significant features) were selected on the basis of their seismic source potential and potential for surface rupture through either site. Four of these features are in the vicinity of the \~atana site and nine are in the -vicinity of the Devil Canyon site~ At the present time, the 13 s i gni f·i cant features are not known to be faults with recent d_isplacernent. If additional seismic geology studies show that any of these features is a fault with recent displacement, then the potential for surface rupture through either site, and the ground motions ~ssociated with earthquakes on such a fault, will need to be evaluated. Preliminary estimates of ground motions at the sites were made for the Denali and Castle Mountain Faults and the Benioff Zone (Table F-1). Of these sources, the Benioff Zone is expected to govern the levels of peak horizontal ground acceleration, r·esponse spectra, and duration of strong shaking'!'~·· The ground motion esti.rmates are preliminary in nature and do not ·constitute criteria for design of project facilitieso Finalization of site ground motion estimates and development of design criteria are a part of the next phase of study. ·· oJ~c••••' ,,.-., ",•• .~·,:: •.• ~ "'~~ ·I I F..2 Technical Conclusions I I I I I I I I I I I I I I I lc"··· I (a) The site is located within the Talkeetna Terrain. This tectonic unit has the following boundaries: the Denali Fault to the north and northeast; the Totschunda Fault to the east; the Castle Mountain Fault to the south; a broad zone of deformation and vo 1 canoes to the \'lest; and the Benioff Zone at depth (Figure 6.8). (b) The northern, eastern, and southern boundaries of the Talkeetna Terrain are major fault systems along whit:h displacement occurred during Quaternary time. The Benioff Zone beneath the Talkeetna Terrain l"epresents the upper margin of the Pacific Plate which is being subducted beneath the North American ?1 ate. The western boundary, a broad zone of deformation and volcanoes, does not appear to have brittle 'deformation along a major faulto (c) The Talkeetna Terrain appears to be actin~ as a coherent tectonic unit with the present stress regime. Major strain release occurs along the fault systems bounding the Terrain. Within the Terrain, strain release appears to be randomly occurring at depth within the crust. This strain release is possibly the result of crustal adjustments resulting from perturbation imposed by the Benioff Zone and by stress (associated with plate motion) imposed along the Terrain margin and transmitted throughout the Terrain. (d) The only fault system within the site region (60 miles from either dam· site) which is known to have had displacement in Quaternary time (the last two million years) is the Denali Fault. This fault is approximately 40 miles north of the sites at its closest approach. The Castle Mountain . Fauit system is immediately south of the site region. This fa.ult system also has had displacement·in Quaternary time. {e) Within the site region 48 candidate significant features have been identified. These features are faults and lineaments for which no evidence of recent displacement was observed, but for which evidence of no recent displacement has not been demonstrated. (f) Of the 48 candidate significant features, there are 13 significant features which the results of this study suggest need additional investigation. These 13 features were selected on the basis of their seismic source potential and potential for surface rupture through either dam site. Four of these features are in the vicinity of the Watana site and include the· Talkeetna Thr-ust Fault (KC4-1), the Susitna feature (KD3-3), the Fins feature (KD4-27), and lineament KD3-7. Nine of the features are in the vicinity of the Devil Canyon site and include fault KD5-2 and lineaments KCS-5, KD5-3, KDS-9, KDS-12, KDS-42, KD5-43, KD5-44, and KDS-45 (Figures F-1, F-2). (g) No evidence to support the existence of the Susitna feature has been developed during this study. Reconnaissance level aerial and ground checking has found no evidence of a fault in bedrock and no evidence of deformation in overlying surficial units. I I 'I I I I I I I I I I I I I I I I I Review of aerial gravity and magnetics data show no evidence of a major tectonic dislocation. Earthquakes correlated with the southern portion of the feature of Gedney and Shapiro (1) occurred at depth.s greater than 43 miles. These focal depths suggest that the earthquakes occurred in the Benioff Zone well below the crust and well below the extent of the Susitna feature. The feature may be the result of glaciation of stream drainages whose alignment reflects ·structural control such as joints cir perhaps folding. · (h) The Talkeetna Thrust Fault is a northeast-southwest trending fault which may dip either to the northwest of the southeast. The northeastern continuation of the fault is the Broxson Gulch Thrust Fault resulting in a 167 mile long fault that passes approximately 3.5 miles upstream of the proposed Watana ·site. No evidence of displacement younger than Tertiary {1.8 to 65 m.y.b.pG) in age has been r·eported for either the Talkeetna or Broxson Gulch Thrust Faults. However, anomalous relationships in Tertiary deposits on the north side of the Susitna river were observed during this investigation and may be related to faulting. ( i) (j) (k) ( 1) (m) Seismicity within the Talkeetna Terrain can be clearly delineated as crustal events occurring at depths to approximately 5 to 12 miles and as Benioff Zone events which occur· at greater depths. The depth to the Benioff Zone increases from approximately 25 mi 1 es i.n the southea.stern part of the site region to more than 50 miles in the north\testern part of the microearthquakes area and more than 62 miles in the northwestern site region (Figure F-3). The largest reported historical earthqua~e within the Talkeetna Terrain is the magnitude (Ms) 6.25 event of 1929 which occurred approximately 35 and 45 miles northeast of the Watana and Devil Canyon sites, respectively. Four earthquakes greater than magnitude (Ms) 5 occurred during the period 1904 through August, 1980. Earthquakes as large as magnitude (ML) 5 to 5.5 may possibly occur in the site region without direct association with surface fault rupture. Such events would probably be constrained to rupture p1 anes deeper than 6 mi les1t The 1 argest crust event recorded within the mi croearthquake study. area during 3 months· of monitoring was magnitude (ML) 2.8. It occurred 6.8 miles northeast of t!"e Watana dam site at a depth of 9.3 miles (Figure F-4). Two clusters of microearthquake activity were observed within the mircroearthquake network during the three-month monitoring period. These two clusters occurred in the same general vicinity east of the southern portion of the Talkeetna Thrust Fault. These clusters of seismicity occurred at depths of 9 to 12 miles. One of the clusters gives a composite focal plane mechanism of N23°Elt dipping 50° W, consistent with local geologic trends. The sense of movement is reverse (toward .the southeast} with a dextral component of slip (Figure F-4~. ·., I I I I I I I I I I I I I I I I I I I (n) The clusters of mi croearthquake act·i vity described i"n {m) appear to be related to a ·sma 11 subsurface rupture plane that does not extend to the surface. These clusters do not appear to be related to the Talkeetna Thrust Fault. (o) Seismicity in the vicinity of the site, including the c1usters described above, appears to reflect relatively small-scale crustal adjustments at depth in the crust. These adjustments may be related to stresses imposed by the Benioff Zone. (p) No association of microearthquake activity with candi.d:1te significant or significant features is apparent based on information obtained to date. (q) Hydrologically the two reservoirs are considered as one. This combined Watana-Devil Canyon reservoir would be among the deepest and largest in the world. Primarily,· because water depth has a major appareut theoretical and empirical correiation with the occ:urence of reservoir induced seismicity, it is concluded that the likelihood of a reservoir induced earthquake of any size within the hydrologic regime of the proposed reservoir is high (0.9 on a scale of 0 to 1) (Figure F-5). - (r) Preliminary maximum credible earthquakes (PMCE) have been estimated for crusta.l faults with recent displacement· in and adjacent to the site region and for the Benioff Zone. The PMCE for the Denali Fault is estimated to be a magnitude (Ms) 8.5 event occurring 40 miles from the Watana site. The PMCE for the Castle Mountain Fault 1s estimated to be a magnitude (N 5 ) 7.4 event 65 miles from the Watana site. The PMCE for the Benioff Zone is estimated to be a magnitude {Ms) 8.5 evant occurring 31 miles beneath the Watana dam site and 3! .Jiles km) beneath the Devi 1 Canyon s·ite (Table F-1). ,1· I I I I I I I I I· I I· I I I I I Table F-1 Preliminary Maximum Credible Earthquake- Ground Motions ·-... Mean Peak Horizontal Grouncl Acceleration ..;..;.;;;.;;;;.;.;......-,;;..;;.._.....-..,;.~;...;;..;..-.;;.;.-· ... · . II .;;;.E.;;.;a r;...t;;;.;.h.;.,;;;ai,;;;u.;;;.a.;.;.ke;;;._;;S;.;;;o.;;;u.;..rc.;;.e;;. _______ ..;.;W.;;;.a..;.ta;;;.;n..;..;;a;.....;;;S..;..i ..;.te----_ _,;;;;..0~\? ~] ...... ~ n yon ,?j te . Beni.off Zone Castle Mountain Fault Dena 1 i Fau1 t 0.41 g 0.06 g 0.21 g 0.37 g 0.05 g 0.21 g _! •. ' ,._, : .. I \ ~ . -___ -J.___.r--1 t 1? l I. l 6 .. , - -· -l -.. !..._-I ' CONSUltANTS 14658A December 1980 -~-. . -::::::--~ ,.--.- ·--J ..... ' .. r~ i -~- l \ . -- .. ,-.., -- --... _-~ ...... ~ .. ~-'--~,.. .. . I. -.......___ r-· ---=--_ ..... ~'-----·----------------·-~._-'" 1 ~. .· . .. ~ ,-'·· ~- ! -r ,.a. ~:_---' ,. .... --· -... ~----~----t .. -j 19 .. -~ /~?: c;:::_ • -~ ----r----... · ,...... - / .-,.--- . . . . . -' .......... _ ..... . l ~· r : __ ._. __ _ ,......- LEGEND -~--· -~--- --.--·o~o..-- Indeterminate-A feature Indeterminate - B feature Indeterminate -BL feature !-- .- WATANA SITE SIGNIFICANT FEATURE MAP FIGURE F-1 I . " I I I I I I I I I I I I I I I I I I . . • . t .. .. WOOOWARD-CLYOE CONSUi..'TANTS 14658A December 1980 / : ,. . . :t .... "---.-"" LEGEND . . •. --Indeterminate • A feature -·-Indeterminate -8 feature -o-Indeterminate - B L feature DEVIL CANYON SITE SIGNtftCANT FEATURE MAP FIGURE F-2 I I I I I I I I I II I I I I -. PREPAREo·ay: WOODWARD-CLYDE CONSULTANTS 83.01) (!) C) (!) (!) "C) (!) C) C) C) (!) (!) (!) C) C) (!) (!) .{!) .(!)· • CANTWELL + (!) C) + WA'l" ANA SITE I . I DEVIL CANYON SITE C) " TALKEETNA(!) <D • ~ (!)C) e@ ANCHORAGE • + C) 100 km radius I I l I I DENALI • + LIMIT OF 1964 EARTHQUAKE AFTERSHOCK ZONE LEGEND to/ Depth to Senio.ff zone in kilometers /~-. NOTES C' 1~ Earthquakes of magnitude greater than.4 or intensity greater than V are shown. '-· Magnitude symbol sjzes are shown on a continuoos nonlinear scale. , ' 3. Earthquakes are fisted in Appendix C~ ~ -N- ~ HISTORICAl EARTHQUAKES OF FOCA'L DEPTH GREATER, THAN 35 km. IN THE SITE REGION FROM 1904 THROUGH 1978 0 10 20 30 4o 50 Miles. F E41 ;;tf _ ga :3 0 · 10 20 30 40 . 5iJ Kilometers • • Mt. McKinley + -tso.oo + -149 .. 00 + • "'-'--• _ ____.,.,.. • .,.._-...a s4-" -__ __..,...---,~ fa\l\t "!...--·----oe~:!,.._.....• - .__.-·---· CAN-lWELL -148 .oo .---- -'--·---___ _,_ .. .,.;_,.-.. ~-· 0 .. .,---. -~·.,.,.,-(J / .~-~ ~-r-r~-------------_______ __;,... __________________ . -------~~--, .A.........-· --0 -o o -~/ I __. . .-I / I c:> DENA&I 0 ·-.,..,. -147.00 +63.50 LEGEND. .REPBRTED MAGNITUDE • 4 .. 0 3.0 2.0 1 .. 0 I ·. <9 .. /. .. ,.,.......-I (!) e • / I I 0 0 KDS-3· _ .O_)EP'• ./ ...,~ ..... _ --Microe~rthquake ~ -/ , ~dy~ 1 + -,_ +"-·*" o ~ /. 4 -I +s3.oo I 0 A HUR • e (!).,..-'•~ -· /• • ~ e / -I eJ' /. ··OCR '·-/ I I ,. .. _ . /.. /-. t ,?'. --~ • • 0 . • • - / l -KD5-4~..f'Y' __ KD5-2 0 • SBL. -(!) ;/ 1<04-27 . I f ~ ~~ KD5-12 C) /._A __ -__ -. WAC./ . J· A'V' I I T -A .A,. .&A / . A rn IK~~!!/....:_ . .s:: .. ~05-42. . -_ :/*" w_ -A-i':o/ ___ 7-D-c--~0 . KD3-7 1 t ~----/ __ · ·" K05 '· \ . KC5-5 / . / ,,,--_ "0~0 . I I ;E) .. .. / '{Si ~ 1. --~ • /.. \ • / _/, ~-a.u~~- J // ~ CNL . • \ \ . /. /.--;~~'1. I 1 _ /" (!) KOS-44 • ?~-~---~--ee:(li_ _ . 1 1 I I__ /• 0 6e • /_-7 · --~-----~Ciust~r No~ 1 • -~- • // • -~-GRB I .. .. oP9"" /" tlPG e. . I 1 / -•• e •• . . • A KOS I / / e . t!~~ ~tJster No. 2. : I J C> / _ _ • e -' A• e c, I. / _ ./ TKR.~a 0 80 o e e ·I f /0 / e• 1 I // o i f!J I : : TALKEEJ?, . .. I -----.--/.-----~--------------·--· ------------~--__ o __ -----·---_j ~ •(!) Cl ' -· -o-• -1!) -tso.oo ,_ .& GRB Station location and name used for ~is $tUdy Fault with recent displacement: ---Indeterminate A feature -·-Indeterminate 8 feature ~ -o-Indeterminate BL feature NOTES . -1. Magnltud~ symbol $izes.are shown on continJou~' nonlinear scale. 2. Local events are those inside the dashed lines. Events outside the dashed lines are. considered to be less weU-Ioca;:ed.., -N- ,• . I SHALLOW (FOCAL DEPTH < 30-kn:tl LOCAL· EARTHQUAKt:S LOCATED fROM 28 JUNE THROUGH 28 SEPTEMBER 1980 0 ·10 +s2~oa -147 .. 00 I 20 20 ' : : .. . J I : i l ~' '.'; -~--. _.,_~_...,:,,_<-~- I. I I I I 'I I I I I I I I I I I. 240 220 200 180 160 :§ 140 .s::. -Q. Q) 0 120 100 80 60 . 40 20 I .... ·~ .s ,' .. . Watana • y Combined • • ~- ~21 38~ • 8 21 . . @131 . ,D~il Canyon •· • • : @1160 • •· ... • 39 ... • 0 • J~ -• • • • .. !!)j I . .. .o. ~2···'··. • IE • • : e•• • :,.r •. i •· • • • • . " .. •• 47 -•• • r..;,, • @. • . . . • 1. ". • .Efi4 •• • 0 • . • -~·~62 .u7:l ~ . . .. • • • • ~37 tEill 49. ~o~2B 1R El2o 16 • 8 • :.c.s -· 8 !:!.34 ~:.17 Approximately 11,000 re$ervoirs without reported RIS not plolted ~59 . . ... • • • ~25 @]' • o~~~~~~~~~~~~~~~~~~~--~~~~------~ 10 100 10,000 100,000 Reservoir Capacity in 1 cfm3 (logarithrric. scale) LEGEND D.ep and/or very I art" ~'1Hrvolr l@Jl Accepted .case of RISf maximum magnitude~ 5 ·@: Ac~pted case of R IS~ maximum magnitude 3-5 8 Accepted case of R IS, maximum magnitude S 3 6 Questionable case of RIS •. Not RIS N.-: The foil ewing tnervoinl ~re not platted because of insuffk:ient data: Kinarunl, Sharwathi. *A1 • Nu,.,lc (USSR} dGpth ia in e.xcna of 285 m. PLOT OF WATER DEPTH AND VOLUME. FOR WORLOWID!; RESERVOtRS AND REPORTED CASES OF RIS I . ~IO!)DWARD-CL YOE CONpUl TANTS 14658A December 1980 FIGURE F.-5 -[. " ;:<:-~ -. {j ' .·.;->. ,_, . '."\· ;:;_. '" -_ ,l ,, 0 ·-~ .a .. ·-:;. --~-" 0 ' -~· (:. _0 I I :1 I <; ••• .. I :1 I I G -TASK 5 -STATUS REPORT I I I I I 'I I· -- I I I 'I ·I I I I I I I I I I .I I I :1 I APPENDIX G TASK 5 ~ GEOTECHNICAL EXPLORATION G.l Field Program (a) lntroduction {b) In developing the 1980 exploration program, a review of the available information on the Watana and Devil Canyon sites was conducted. Meetings were held with the Corps .of Engineers to discuss those areas their investigations had identified as requiring additonal studies. These areas of particular concern then were considered in formulating the 1980 program. Howevet", the main theme of this program was to allow for flexibility in the collection of as detailed information as possible on the general conditions present, and any as yet undetected problem areas. This program was inteded to define the feasibility of the dam sites and the quality and availability of construction materials. The investigation included geologic mapping, diamond coie and auger drilling, and geophysical surveys to augment the existing knowledge on the characteristics of the dam site areas. The studies covered the depth, distribution and nature of the of the overburden materials; the type and quality of the bedrock geology including discontinuties and their significance to the foundation competency; and the evaluation of the groundwater regime, the permafrost conditions, and potenttal sources--of-construction materials. Site gelogic mapping was conducted by Acres with the assistance of R&M Consultants and involved measurement and description of the outcrops, aerial and traverse reconnaissance, and air photo interpretation. Devil Canyon Site The pt .. evious work at the Devil Canyon dam site had identified several features that require clarification for an informed evaluation. These include the stress relief joints and shear zones in the left (south) abutment area~ a suspected fault under the proposed saddle dam and a possible fault zone through the Cheechako Creek borrow area {upstream of the dam site) that showed on previous seismic refraction surveys. The. diamond core holes were drilled in the 1980 season to define the geologic structure and rock quality. Two holes (BH-1 and BH-2) in the righ~ abutment and on~ hole {BH-4) in the left abutment, were drilled for correlatjon of the geologic structure encountered in previous drilling and in seismic work in a left abutment shear zone and buried channel area. Two thousand feet of seismic refraction survey were aslo run in the buried channe_l area near B.H-4 to assist in the definition of this shear zone. The holes on the right abutment were drilled to obtain information in the general location of proposed underground structures. The data collected on the left abutment is inconclusive and requires additional work to delineate any left abutment shear zone. I I I I I I I •• I I I I I I I I I I ,. Geophysical logging and permeability determi"nation by watt:r pressure testing wet"'e performed in all three holes. The rock core was logged as the drilling proceeded, noting the rock type and quality. Correlations were made with the testing results and the results of other drilling and mapping. Two auger holes were drilled in the large gravel bar just upstream of the dam to explore the extent of available construction ·materials. These h9les confirmed that extensive gravel and sand deposits are available. Reconnaissance.mapping north of the river also tended to confirm that sufficient glacial till is easily obtainable for use as impervious material in the proposed left abutment saddle dam. Because the program was limited by land access restictions near Cheechako Creek, the objective. was modified in order to gather as much information as possible within the restrictions (Figure G-1). In general, the argillite and graywacke at the Devil Canyon dam site is of good quality. Zones of fracturing or shearing were encountered in all of the exploration work~ and in most cases correlate \'lith the zones of high water take. However, correlation between the holes themselves is difficult at this time. Weathering generally is moderate, affecting the top 40 feet or so of rock. Below this depth rock quality steadily improves with increased distance from v1eatheri ng surfaces. It should be noted that the observations are bas~d on a limited number of borings, and will be revised and updated with subsequent drilling. An instrumentation program was set up to collect static groundwater level and ground temperature data in BH-1 and BH-4. When groundwater and ground temrerature return to ambient 1 eve 1 s, data wi 11 be co 11 ected at monthly intervals. This will provide information on permafrost and the groundwater regime at the site. (c) Watana Site ~ ·The 1980 program at Watana involved geologic mapping, diamond core and auger drilling, and seismic refraction surveys. Several areas previously outlined as potentia'{ problems were investigated. These include the shear zones called uThe Fins 11 , a possible right abutment slide block outlined as a low seismic velocity zone in the 1978 investigations and, "Fingerbuster", a potential fault zone in the river channel (Figure G-2). Three diamond core boreholes \~ere drilled in the dam area to augment the previous data and were orientated to investigate the geologic structures through, the proposed powerhouse on tne 1 eft abutment (BH-8), the possi b 1 ity of a fault in the river channel {BH-6} and the andesite-diorite contact and the possible slide and 11.Finger·bustet"" shear (BH-2) on the right abutment. Permeabi 1 i ty testing and geophys i ca 1 1 oggi ng was· done in these holes -For carrel at ion with the rock core. Approximately 15,000 feet of seismic refraction lines were run throunh the proposed dam site and the relict channel to delineate the overburden thickness and rock quality of the abutments. I I I I I I I I I I I •• I I I I I The foundation conditions within the Watana area are generally sound. Weathering is predominantly mechanical in nature and hc-~s resulted in the. accumulation of talus piles along the canyon. The only intense weathering effects are found in the shear zones• Very little penetrative weathering was observed in the ra~k except at the joints. The rock appears to have a random effect with zones of competent rock separated by poorer qua 1 i ty sheared or fractured zones recurring 15 to 150 feet apart. The permeability values seem to correspond roughly with the rock quality but overall permeability appears very low. These conditions are normal for diorite masses and are readily treated in construction~ A piezometer and thermistor system similar to those at Devil Canyon was installed in BH-6 and the data collected along with that from th-e Corps of Engineers I 1978 system, Will help define the groundwater~ ana permafrost conditions of the area. · G.2 Laboratory Testin~ Representative soil samples obtained by split-spoon and hand sampling from the potential borrow sites of the Watana area were tested to determine. their engineering properties and to verify the field classification. The testing program included determination of moisture contents~ Atterberg limits, grain size distribution and Modified Proctor density. The summary of the testing program is given in Tables G-1 and G-2. The Laboratory testing program results substantiated the previous knowledge of the borr0\'1 areas. Borrow Area E appears to he the most 1 ikl ely source of c 1 ean sands and gravels for filters and concrete ag~regate (Figure G~Z). This alluvial deposit located downstream of the dam is composed of six to ten feet of relatively clean, well graded sandy gravel with cobbles up to four inches ·in diameter, increasing in size with depth. Total depth is estimated at over 50 feet. The material has an average moisture content of 12 percent, ranging from 22 percent in the silty organic material at the top to 1 percent in the gravels at a depth of eight feet. Borrow Area 0 is a likely source of impervious and semi-pervious materials and is bounded by Deadman Creek and the right bank relict channel. This. area appears to be composed of silty sands, probably of glacial origin, interbedded with gravels and till. The fines in this material are non-plastic in the top 10 feet, however, below 10 feet plasticity increases with depth. The economic recoverable depth will depend on permafrost and natural water content conditions. Two other source areas of impervious materials were investigated under this program. Borrow Area Hs located some seven miles downstream of the dam at a bend of the Susitna River is composed of sediments of qlacial origin. The grab sarr.ples collected here show this is a possible source of well graded sand to poorly graded, clayey sands with 40 percent fines. The samples have a maximum dry density of 139 pcf. Another potential borrow area, upstream on Deadman , Greek about three and a half miles from the dam site, was also identified. The material is composed of clayey sands with -a much higher percentage of fines than Borrow Area H. These fines have medium to high plasticity. Only cursory examination was given to these two areas in this program; however, the laboratory results indicate a more in depth investigation is v1arranted. .......,....,. ___ ___,....,~-~--.-. --. --.-. -,,~-.--. --------~--,--~----------------::---- I I I -I I ·~ I I I I I I -I -I I I I ' J' G._3 ...... Pre1 imi nary G_eotechni ca 1 Design Parameters (a} De vi 1 Canayon Sit~ The proposed dam axis at this site is located several hundred feet downstream of the mouth of De vi 1 Canyon Gorge. The valley is generally asymmetrical in shape with rugged outcrops and cliffs forming the abutments. The valley is about 1,000 feet wide at crest elevation. The river through this part of the gorge is very fast and turbulent. The area under consideration for the Devil Canyon site is underlain by a complex series of weathered and altered argillite and graywacke., This rock has been folded and fractured during its tectonic history which has resulted in zones of increased weathering and alteration in the foundation area. Excavation to sound rock wi 11 requh·e the remova 1 of up to 40 feet~ of weat~ered rock. Permafrost has not been detected at the site, but if it does exist, it is not expected to be substantial or widespread. A thawing program can be incorporated with the grout ho·!e installation. Over~urden within the V-shaped valley at the dam site is estimated to be 35 feet of river alluvium and boulders, which will be removed during construction. On the left abutment, hm'lever, a buried channel paralleling the river has been detected crossing the location of the saddle dam.. The overburden in this area exceeds 90 feet in depth and will require constr·:.~ction of a cutoff system. Seepage control wi 11 be effected throvghout the dam.site by a grout curtain. A corresponding drain hole curtain, and drainage adits or galleries excavated into the foundation will be constructed to relieve excess pore pressure and to monitor the effectiveness of the grout curtain. (b) Watana Site The principal structures at the Watana site will be founded predominatly on a dioritic pluton of good engineering quality. Required foundation excavation w·ill include the removal of approximatley 40 feet under the shells. Within the river channel, up to 80 feet of alluvium will be removed under the dam, due to its potential instability during seismic events. On the abutments, there is an average of 15 feet of overburden that will be removed. A 400-foot deep relict channel has been delineated on the right abutmento This area will still require further investigation to ascertain its impact on potential· reservoir leakage. The overall condition of this site is good, and the amount of preparation and remedial work will be comparable to similar large projects. The presence of deep permafrost primarily in the south abutment, may require special construction consideration~ and so further investigation is underway to define the nature and extent of the permafrost data. The permafrost is 11 \'larm" being within approximately one degree (Celsius) of thawing. I I I I ·I I I I I I •• I I I •• I I I I • ' (c) General The information· obtained on the dam sites to date indicates that the construction of the large dams and underground facilities is feasible. The rock type and characteristics at both sites are suitable for large fill or concrete dams.. While permafrost is prevalent at ~latana and may exist sporadically at Devil Canyon, the temperature of the frozen ground is conducive to thawing by convential, proven methods and is not considered likely to be a major problem. Likewise!! indications are that conventional rock support systems· around· underground openings,: in conjunction with installation of grout and drainage systems, will be adequate to ensure stability and safety. From the information obtained to date, it is concluded that adequate amounts of construction materials are available at Devil Canyon for a concrete dam. Adequate sources of material are available at the Watana site for a fiil dam with a rock shell. However, further field investigation and laboratory testing are required to located the most economical sources, and to evaluate whether adequate q~uantities of rounded boulders and cobbles are avaialbe for a proposed alternative gravel shell dam. The plan for the 1981 field program is currently being finalized. It will take into account all available data from previous investigations, on-going geologic studies by Government agencies in the area, and the 1980 program results. The scope of the 1981 field program is aimed at providing sufficient data to firm up the feasibility of constructing the dams and power facilities at the two sites from a geotechnical point of vie~1. The program will incorporate the following speci'fic aspects: (1) Watana Dam Site -Determination of the 1 ocat ion of the most eco.nomi c· construction material sources and the engineering properties of these materials; -Improved definition of possible shear zones within the dam site so that a11 project components such es spillways, diversion tunnels_, powerhouses and penstocks can be located and appropriate foundation treatment and rock support systems designed; -More detailed evaluation of the two major shear zones: "The Fins11 , upstream fr·om the dam and "Fi ngerbuster 10 1 ocated downstream from the dam· . , -Delineation of the geologic contact between the diorite and the andes·rtes adjacent to the dam so that the potential impact of this contact is dealt with in the design of the project, particularly the underground support systems. (2) De vi 1 Canyon Dam. Site -Determination of the engineering properties of the construction materials for both concrete and earth structures which will include testing for freeze-thaw and saturation durability. I I I I I I I I I I I I I I I I I :I I -Additional core drilling in the abutments at lower elevations to determine typical rock conditions, permeabilities and rock strengths; -Additonal drilling across the river to determine if a fault exists down the 1 ength of Devi 1 Canyo·n under the river; - A second angle hole on the left abutment to intersect the suspected fault on the left abutment; -Exploration for' impervious· core and rock fil 1 sources for use in the saddle dam; -Additional field mapping to determine mor·e accurately the-bedding and joint orientation~ in order to produce a structural geologic model of the site. I I I I I I I I I I I I I I I I I I I SAMPLE Borrow Area H W-80-256 Deadman Creek W-80-282 Deadman Creek W-80-300 TABLE G-1 MODIFIED PROCTOR DENSITY RESULTS UNIFIED CLASS. GC-SC CL-CH SM MAX. DRY DENSITV,pcf 139.0 102.5 135 .. 0 OPTIMUM WATER CONTENT 6.2% 22.0% 6.0% I TABLE G-2 I SUMMARY OF LABORATORY TEST DATA I PROJECi NO. 052504 R~M OATE 10-17•80 CLIENT Acrea CONSULT.ANTS, INC, I PAOJECT NAME SII::Ei1iDI PARtY NO. PAGE NO c-01 (Watana ·na. Site) SUMMARY OF LABORATORY TEST DATA ~ .... ' LJnified ua ~d -1. . LO DEPTH 4" 3'" 2" l~" l .. .!/4~ ~/2" 3/8" #4 no 140 i200 • 02 .DOS 002 Moist • Lt. Pr Class. NO. i~ 2Z ~ I OORRCW. H W•8D-256 100 95 es 84 Sl 78 71 64 53 38.2 24 .• 3 13.6 8.6 10.9 21.7 9.2 GC-sc (Grab S418Ple) BORt-iJ if ' H w-so-257 100 97 92 89 84 81 73 66 54 36.0 19.6 8.9 5.2 12.3 17.1 2.5 iGM-SH . I (Grab SUI_ple) ... -. · - DEADMAN w-a0-282 100 99.5 81.3 69.6 ~0.8 42.1 55.9 33.2 r ............. ~ (Grab saaple} -- :I D~ w-ao-3oo 100 95 93 69 87 86 ao 76 58 26.9 9.2 3.0 1.3 6.6 NV ** NP *• SM STRF..Nt (Grab sall{)le) . ~- ALLuviUM w-so-Jo2 100 92 90 82 69 58 45 38 '27 23 14 2.6 GP - (Grab sample) ~· BORI« iW D Ali-Dl IS 00 99 95 9'1 90 84 69 42.3 19.0 6.1 2.6 11.1 NV NP SM (6.0 -7.5 1 ) BOR.Rt ~ D AII-Dl. #6 100 87 87 83 80 75 69 54 28.3 14.4 6.1 3.3 6.7 SM* I (a.o-e.s•) -BORn! w D AH-Dl. .7 Oo 91 91 87 76 62 35.7 18.2 8.2 4.9 6.6 SM* (10.0 -10.3'} I BORR< H All-D2 13 illlO ' D 80 so so 77 73 72 67 61 47 28.5 12.0 3.2 2.9 25.'/ NV Ni> SM ! (1 5 -...l.,.g!l BOR!t< ~ D AH-D2 14 100 94 92 go 89 86 79 62 35.0 21.2 4.1 2.4 11.4 ll.s,\ NP SN -(J,O -4w5f} I REMAftKS: ______ *_Es __ t_;ma ____ t_ed~~-a_lu_e__,_. ______________________________________ ~------- -----*-*-::liV.:-.::a::...:::No~n~V.:::;is:::.::co=u:.s _ _,:.::NP:.....;;:•;_.!,!Non Plastic , NOTE: SIEVE AIIIALYSt$ :t PtftC£Nl PASSlNC - I -·~ -. ., ... .. _ . . .. ·• " w I•IJ/4" \ ~ified LAI ~d _,, . . 3/B Q.O DEPTH 4 .. 3" 2 .. l~" l/2' J4 110 uo 1200 .02 1}05 .D02 ~lst. LL PI: a as. NO. . ~z ~z ., 3~ SH . BORRCW D AH-D2 L'S 100 98 96 92 87 80 59 l0.7 13.8 1.6 ll.2 w NP I (4.5 -6.0~) so~~ D AH-D2 18 100 99 CJ7 93 87 70 44.0 22.5 8.9 4.,0 11.3 lS .. S 2.2 SK (15 .. 0 -16.5' I SORRC~l D AH-02 119 100 96 94 93 91. 85 78 61 38.6 21.3 103 4.2 9.4 11.5 4.2 SK - (20.0 -21.5• ---,~·--· . ' E AH..;El .1.3 100 99 48.0 19.6 SM. I in ,n-1 .s'\ ! BOilRC w E AH-El lt4 100 98 59.5 27.3 MI.· lt2.o -'! .5' l -BOR* ~ E AH-El 16 100 89 c~ 83 80 76 72 62 52 28 6.2 4.4 SP/$M . -I (4.5-6.0') BORRe: ~ ,E AJI-E3 t7. ... lOO 90 76 62 57 40 31 16 3.7 0.7 GW ,(6.5 -a.o•) I BOM.( ~· E AH-E4 t6 100 99 99 92 66 22.2 17.6 5M . cs.o -6.5•) BORR! iW E AU-E7 ft3 100 85 73 56 49 jg 31 12 2.1 2.3 GP ~~.0-3.0') I ~~ ~. B AH-E9 12 (1.5 - 3 0'1 100 .99 28~6 15.7 SM BoRRe ~ R 1Jt-E9 46 {6. s'-.B o•) 00 95 87 79 57 44 33 1.7.0 4.4 G..lof. .,I ** 1-2e Rock Present ln Saap1e REMAIUCS ~ -----:---:--....... -::-------------------------------'-* Esti.mated. Value . HOT.E: su;vE ANALYSIS a PERCENT PASSIN! ·~ I I I I I I I I I I I I I I I I. I I ~-·--. REf6£JIICE: U$$.. TAL.JCEETNA IAOtmAHS (0•5), .AlASKA QIJAI:)RAHLE, . SE'MRD. MERl>I>\N: T32H. RIE. S32 MD 33. DEVIL CANYON LOCATION EXPLO.RATION MAP LEGEND . ,. DH BOREHOL.ES-B~:AU OF RECt.AMA.~ 1960 • BH BOREHOLES-~ 1980 .~ • TP,S. TEST Pits AND"TRENCHES BUREAU OF ~MA.TlON. ~'l G AUGER HOLES-~MER 1980 p·RCX~W SW SEISMIC UNES-· .......,.;;;;.;.;......,..I CORP OF ENGtNEERS, 1978 ~S=L.=-· ...,....SEISMIC UNES- r- 1 SUMMER 1980 !'!ROGRAM • DCJ. I.OCA"TION OF ~NT MEASUREMENT · Zll!) 0 3DO )51;~ ~·~!!Of£ET ~tiED. ctHT'ClJR 25 fEET FIGURE G~l 0 -J I I I I I I I I .I I I I I I I I I ,I @ REF. U~S.,ARMY ~PS OF ENGINEERS SUPPLEMENTAL FEASIBIUTY REPORT 1979. LEGEND •TP TEST PiT •AP AUGER HOLE •DH CORE DRILL HOLE CORP OF ENGfNEERSw 1978 !tOR ROTARY DRILL HOLE •BH BOREHOLE •AH AUGER HOLE J SUMMER 1980 PROGRAM 1-l ---"'""f SEISMIC UNE : OM, SW-CORP OF ENGINEERS, 1978 Sl -SUMME'R l980 PROGRAM ®WJ lOCATION OF JOINT MEASIJREMENTS BORROW AREA .F WATANA LOCATION EXPLORATION 'MAP D m I 2 Q NOTE: AP17 • . TtPOGRAPHIC COHTtu~JRS AR£ APPROXIMATE IIXlD • 0 10110 ~ :mao I 3CEO I FIGURE G-2 .I l ~ ~ ·:J - ~ (; -:· - :~ ~I •• '.J {r' .'<,..· I I I I I I I :I- I I I I I I I I I I I I ~ TES REPORTS ON ENVIRONr1ENTAL IMPACTS Associ'ated wtth the TunneJ _, Watana/Devi·l Canyon and Hi'gh Devtl Canyon/Vee Redevelopment Plans. ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT PRELIMINARY ENVIRONMENTAL ASSESSMENT OF TUNNEL ALTERNATIVES by Terrestrial Environmental Specialists, Inc. Phoenix, New York for Acres l\merican Incorporated B~ffalo, New York December 15, 1980 • .... I 'I I . -· •• I I I I I I I I I I I I I I I . ' 1 TABLE OF CONTENTS Pag~ 1.-INTRODUCTION ••••••••••••.•••••••••..•.•••.••• ~ .•••••••• ~.e 1 • 2 -COMPARISON OF TUNNEL ALTERNATIVES............................ 3 2.1. Scheme l •••••••••••.•. ¥·············~······i•··· 3 2.·z scne·me. 2· .••• o'• ............ e •• e. e •••••••••••••••• a.. 3 2.3 Scheme 3 .••••..•••. ~·····~······················ 3 2·. ·4 Sch erne. 4 .......... "' . . . . . ~ .......•.•.. ,. . . . ... • .. . . . . . • ? 2.5 Location of Devils Canyon Powerhouse •.•.•.•..•• ~ 5 2.6 Disposal of Tunnel Muck •.••••... ~··············· 6 3-CONPARISON OF SCHEME 3 WITH CORPS OF ENGINEERS' SCHEME.... 8 APPENDIX A -DESCRIPTIONS OF TUNNEL SCHEMES APPENDIX 8 -AMENDED DESCRIPTION .OF TUNNEL SCHEME 4 .'.) ·I I I I I ·I I I I I I I I I I I I I 1 "'! INTRODUCTION •) In response to a request by Acres American, Inc .. for input into Subtask 6.02 of the Susitna Hydroelectric Project feasibility study, Terrestrial _Environmental Specialists; Inc. (TES) did a preliminary assessment of tunnel alternatives.. The objectives of this assessment were: • (1) to compare _envi·ronmental aspects of four alternative tunnel I schemes; (2) to compare the b~st tunnel scheme~ as selected by Acres, with the two-dam scheme {Watana and Devils Canyon) proposed by the U.S-. Army Corps of Engineers; (3) to compare two revised locations for the downstream powerhouse; and (4) to comment on alternative methods of disposal of tunnel muck, the rock removed to create a tunnel. The environmental assessment was based on both the project descriptions in a letter dated October 29, 1980, from Acres to TES, as amended by a letter dated December 11, 1980, and on conversations between representatives of these firms. Copies of these letters may be found in the appendices to this report. At the time this assessment was performed complete information was not available on the various tunnel schemes under consideration. Therefore~ TES views this assessment as only a preliminary study. One assumption made by TES, and confirmed by Acres, is that the dam~ pool elevation, and pool level fluctuation!" of Watana are as described by the Corps of Engineers and would not differ among the five schemes10 If, on the contrary, any of the tunnel schemes increase the probability that the pool level at Watana may be lower than that proposed by the Corps or if a particular scheme may moderate the pool fluctuations, then the environmental assessment of the tunnel schemes may, in turn, be affected. 1 'I I I • - I I I I ~. I I I I I I I I I I j' .It is .recognized that an environmental assessment for ranking alternative schemes must include some subjective value judgements. A . . given scheme may be prefert.-:ble from the standpoint of one . environmental discipline {e.g. fisheries) whereas another scheme may be better from another aspect {e.g. terrestrial ecology or aesthetics). To recommend any one scheme over another involves the difficult task of making trade-offs among the environmental' disciplines. Such trade-offs are likely to be controversial. ,c•.:: I I •• I I I I .I I I I •••• I I I ·-·1 I 2 -COMPARISON OF TUNNEL ALTERNATIVES r 2.1 Scheme 1 The environmental ~impacts associated with this tunnel scheme are likely to be greate~r than those of at least one of the other tunnel schemes evaluated (i.e. Scheme 3). The main criterion for 'this assessment is the adverse effects, particularly on fisheries and recreation, of the variable downstream flows (4000-14000 cfs daily) created by the Devils Canyon powerhouse peaking operation. ·other negative impacts wctuld result from construction of both the re-regulation dam a1nd a relatively long tunnel·. Tunnel impacts are similar to those of Schemes 2 and 4 and include disturbance of Susitna tributaries as a result of tunnel access and the potential pt"obiems associated with disposal o~ a relatively large volume of tunnel mucic~ 2.2 Scheme 2 Like Scheme 1, this scheme involves adverse environmental impacts associated with variable downstream flows caused by peaking operation at the Devils Canyon powerhouse (4000-14000 cfs). Without the re-regulation dam, however, less land would be inundated and the impacts associated with construction of this relatively small dam would be avcided, although flow fluctuations above Devils Canyon would be more severe. Like Scheme 1 too~ the long tunnel proposed here will have negative consequences, including disturbance of tributaries for tunnel access and the potential problems connected with tunnel muck disposal. 2.3 Scheme 3 The overall environ~ental impact of this scheme is considered less ·than that related to the two previous schemes, and also less than that related to the fourth scheme as amended (Appendix B). The relatively constant discharge (about 8300-8900 cfs) from the Devils Canyon powerhouse ·is desirable for maintaining downstr~am fish habitat and recreational potential.. Since it may allow anadromous f·ish access to 3 I I I I I I I I I I 'I I I I I :1 I f a pre'(iously inaccessible 15-mile stretch of the Susitna River, Scheme 3 could, in fact, offer a rare opportunity for enhancement of the fisheries resource. The newly availabl~ section of river could ' perhaps be actively managed to create or improve spawning habi~at for salmon. This mitigation potential is dependent upon the 1ocat\1n of the downstream powe~ho4se (above or below the present rapids"} and the determination of whether project flows through Devils Canyon will still constitute a barrier to fish passage.. The data needed for this determination are not yet available. A compensation flow release of 1000 cfs at the re-regulation dam is not the same as 1000 cfs at 1:he Watana dam. Because fewer tributaries will augment the compensation flow under this re-regu1ation scheme~ the compensation flow will need to be slightly greater than with the other schemes to result in the eguivalent flow at Devils Canyon. -Compensation flow should be sufficient to maintain a certain degree of riverine character, and thus should be kept to a maximum even in the· absence of a salmon fishery. Of course, if the via~ility of a tunnel scheme is jeopardized, the impacts of the alternative scheme must he. compared to the impacts of a lesser compensation flow. As with any of the tunnel schemes, the wildlife habitat in the stretch of river bypassed by the tunnel might improve temporarily because of an increase in riparian zone vegetation. With Scheme 3, however, this stretch of river is shorter than witb the other tunnel schemes;. ~so a smaller area would benefit. The wildlife habitat downstream ·of Devils Canyon powerhouse may well benefit from the flow from the hydroelectric project., regardless of the tunne.l scheme chosen. The improvements to that habitat. rnay be· s6mewha~ greater, though, with the constant flows allowed in Scheme 3 than with the variable flows resulting from peakir.g in the other tunnel schemes. One environmental disadvantage of this scheme compared to the tothers is the larger area to be inundated by the re-regulation reservoir. This area includes known archeological sites in ~~dition to wildlife habitat. Nevertheless, it is felt that this di~advantage is o'Ffset by the more positive environmental factars:associated with constant discha~.ge from the 'Devils Canyon powerhouse. 4 1··1 •• I .. 1 I ·I I I I I I I I JJ I I I I I ·,· 2.4 Scheme 4 ·scheme 4, as originally· described (Appendix A), was determined to be . environmentally superior to the ather tunnel schemes, because of constant downstream flows combined with the lack of a lower reservoir. However, Acres• analysis determined that this baseload operation is most likely incapable of supplying the peak energy demand. ·Scheme 4~ as amended (Appendix B), is a peaking operation at Watana with baseload operation at the tunnel. Since the net daily fluctuations in flow below Devils Canyon would be considerable (in the order of 4000-13000 cfs), the amended Scheme 4_was judged as less desirable than Scheme 3 from an environmental standpoint.. Although Scheme 4 would avoid the impacts associated with the lower dam and its impoundment (as planned under Scheme 3), the adverse impacts that would result from fluctuating downstream flows are .. considered to be an overriding factor. Another, less si.gnificant disadvantage of Scheme 4 (and shared by Schemes 1 and 2) in contrast to Scheme 3 is the longer tunnel length planned for the former and, perhaps, the proposed -location of the tunnel on the north side of the river. The sites chosen for disposal of tunne 1 muck and for the required access roads in any of these ' schemes {as yet undetermined) will further inf·luence this comparison. 2.5 Location of Devils Canyon Powerhouse Alternative locations for the Devils Canyon .powerhouse have· been proposed. These consist of an upstream location about 5 m i 1 es above the propo'Sed Corps of Engineers dam s~ite and a downstream location about 1.5 miles below Portage Creek, as alternatives to the site illustrated in Appendix A. The major environmental consideration is that a powerhouse upstream of De.vils Canyon would preserve much of the aesthetic value of the canyon. In addition, the shorter tunnel would confine construction activitie!S to a smaller area and may result in slightly less ground disturbance, particularly if there are fewer access points, as well as a smaller muck dispos.a1 problem.. A downstream powerhouse, location, on the other hand, might create a 5 I I -I I I I I I I I I I I I I I I I I :: mitigation opportunity by opening up·a longer stretch of river that perhaps could be managed_ to create salmon spawning habitat. Until large-scale aerial photographs and cross-sectional data on the canyon have been received and analyzed, a determination cannot be made as to whether project flows through the canyon will s~ill constitute a . barrier to fish passage. Our primary responsibility is to avoid, or at least to minimize, adverse impacts to the environment~ and it must take precedence over our desire to enhance or expand a resource. It is our opinion that iosing a resource (the aesthetic value of the Devils Canyon ra.pids) is worse than losing a possible mitigation opportunity. It is n~ot yet known if this opportunity even exists. Furthermore, there are always other means by which to enhance the fishery, although not necessarily so conveniently associated with the hydroelectric project. Thus, at this time the upstream powerhou~;~~ location is preferred. 2.6 Disposal of Tunnel .Muck There are a. number of options to be considered for disposal of the rock removed in creating the tunnel .. These include: stockpiling the material for use in access road repair, construction of the re-regulation dam, or stabilization of the reservoir shoreline; disposal in Watana reservoir; dike construction; pile, cover~ and seed; and disposal in a ravine or other convenient location. It is unlikely that the most environmentally acceptable option will also be the most economical. Because many unknown factors now exist, a firm recommendation cannot be made without further evaluation. It is quite' likely, however, that a combination of disposal methods will be the best solution. Stockpiling at least some of the material for access road repairs is environmentally acceptable, provided a suitable l-ocation i~ selected for the stockpile. Perhaps the material-could be utilized for construction of any of the access road spurs or temporary roads that are not already comp-leted at the time the tunneJ is dug. 6 I :1 : •. I I I I ·I I I I I :1 I I I I I I Another acceptable solution might be to stockpile the material for use in construction of the re-regulation dam. This rock could also be a P'?tential source of material for stab·i]ization of the reservoir shoreline if required. As with the previous option, an environmentally acceptable location of the stockpile would be required. Disposal of the material in Watana Reservoir might also be environmentally acceptable. Consideration should be given·to the . feasibility of using the material in the. construction of any impoundment control structures such as dikes. A sma 11 amount of tunnel muck could possibly also be used for stream habitat development. Witil any of th~se options, the possible toxicity of minerals exposed to the water should be first determined by assay, if there is any reason to suspect the occurrence of such miner· a 1 s. To pile, cover, and seed the material is worthy of further consideration, and would require proper planning$ For examples borrow areas used in dam construction could perhaps be restored to original contour by this method.. The source of soi 1 for cover is a major consideration, as earth should only be taken from an area slated for future disturbance or inundationo If. trucking soil from the reservoir area is determined to be feasible, it might also be worthwhile to· transport a portion of the muck back for disposal in the reservoir area. The most economical solution might be to fill a ravine with the \ material or to dispose of it in another convenient locati·on.: Unless the chosen disposal site will eventually be inundated, however, such an arrangement is environmentally unacceptable, especially since better options are obviously available. 7 I I I ·I I I :I I I I I .I I ·I .I I 'I I I ·> 3 -COMPARISON OF TUNNEL SCHEME 3 WITH CORPS OF ENGINEERS' '5CHEME Scheme 3 emerged as superior in Acres• preliminary economic and technical screening.. After amendment of Scheme 4, Scheme 3 was also considered to be the best scheme from an environmental standpoint.. Therefore, Scheme 3 is to be compared with the two-dam scheme proposed by the U.S. Army Corps of Engineers. • Further analysis will be in order after complete details are available on Tunr .. el Scheme 3. At present, many gaps exist in the available data. Additional information on design, operation, and hydrology, combined with environmental field investigations at the locations of project facilities, would permit a much more detailed comparison of these two development alternatives. Nevertheless, from what is presently understood about Scheme 3, there is little doubt that it is, by far, environmentally superior to the Corps of Engineers• proposal. Of course, extensive additional study needs to be performed on whatever scheme is selected to identify its impacts and to develop mitigation plans. Tunnel Scheme 3 has, by any measure, a less adverse environmental impact than the Corps of.Engineers' scheme. By virtue of size alone, construc- t_ion of the smaller dam (245 ft.) would have less environmental impact than the .Devils Canyon dam proposed by the Corps. The river miles flooded and the reservoir area created by the Scheme 3 re-regulation dam would.ba about half those of the Corps• plan for Devils Canyon~ thereby reducing negative consequences, such as loss of wildlife habitat and possib'1e archeological sites. In addition, the adverse effects upon the aesthetic value of Devils Canyon would be substantially lessened with Scheme 3, particularly with the powerhouse location upstream of the proposed Corps dam site. Furthermore, Tunnel Scheme 3 may possibly present a rare mitigation opportunity by creating new salmon spawning habitat that could be actively managed. With the increase in riparian zone vegetation allowed by Scheme.3, the wildlife habitat in the stretch of river bypassed by the tunnel might be temporarily improved. The impacts associated with tunnel access and disposal of tunnel muck necessitated by Scheme 3 are more than offset by the plan's advantages. Thus~ Tunnel Scheme 3 far exceeds .the U.S. Army Corps of Engineers• proposal in terms ofenvironmental acceptability. 8 .(, I I I I I I I I I --:.:-··· I I I I I I I I I • APPENDIX A DESCRIPTIONS OF TUNNEL SCHEMES \ I I I I I I I I I :I I I I I I I I c 0 Terrestrial Environmental Specialists, Inc. R .. D. 1 Phoenix, NY. 13135 Attention: Vince Lucid October 29, 1980 P5700.06 T507 • Dear Vince: Susitna Hydroelectric Project Subtask 6 .. 02 We would like you to review the environmental aspects of the tunnel alter- native (Subtask 6.02), which you \vere introduced to on October 3, 1980. Your environmental assessment will be includerl in the Subtask 6.02 close-out report, November 1980. In order to complete this close-out report on schedule the environmental assessment is required by November 13, 1980. The environmental assessment should include a ~mall sectiQn on each of the four tunnel schemes (Schemes 1, 2, 3, & 4). Physical factors·of the schemes and the COE selected! plan ~are presented in Table 1. Tunnel scheme plan view and alignments are emclosed. Scheme 1 is composed of the COE Watana Dam and powerhouse~ and a small re-regulation dam w·ith power tunnels leading to a powerhouse at Devil Canyon. Peaking operations 1.-1ill occur at both Watana and the Devil Canyon power- houses. A constant compensation flow discharge will be provided between Watana and Devil Canyon. Peaking operatio"nS will create daily water level fluctuations of unknown magnitude downstream of Devil Canyon~ Scheme 2 is composed of the COE Watana Dam and powerhouse with power tunnels from the Watana Reservoir to a powerhouse at Devil Canyon. Upon completion of the. tunnel scheme the Watana power.house will be reduced to 35 MW and will supply a constant compensation flow between Watana and Devil Canyon. The Devil Canyon powerhouse. will operate as a peaking hydro facility. Water level fluctuations downstream of Devil Canyon are similar to that of Scheme 1 • . - Scheme 3 is composed of the COE·Watana Dam and powerhouse, and are-regulation dam with poNer tunnels· 1 eading to a po\tJerhouse at Devil Canyon. The Watana powerhouse will operate as a peaking facility which discharges into·a re-regulation reservoir. The re-regulation reservoir is capable of storing the daily peak discharges and releasing a constant discharge into the power tunnels. A four_ foot daily water level fluctuation in·the re-regulation reservoir is required. The De vi 1 Canyon powerhouse wi 11 operate as a base 1 oad facility, thus, no daily water 1 evel· fluctuations ~1ill occur downstream of Devil Canyon. ACRES AMERICAN INCORPOR-ATED Consulting Engineers The Liberty Bank Building, Maio at Court Buffalo. New York 14202 · Telephone 716-853·7525 Telex 91-6423 ACRES BUF " --c=-,·::~- (;)ther Offices: Cotumbia. MP.: Fittsburgh. PA: Raleigh. NC: Washihgton/OC 'I I I I I I I I I I I I •• I I I I I I /' ' ' • • • / ' . I • . -~ . . . . . . Vince lucid Terre$trial Environmental Specialists, Inc .. October 299 1980 - 2 The general layout of Scheme 4 is similar to Scheme 2. Scheme 4 is a base loa~1 scheme and has a very limited potential to produce additional peak ene1rgy. Daily water· level fluctuations downstream of Devil Canyon are simi 1 ar, to Scheme 3. . · . Pr~~liminary economic and te~hnical screening showed Scheme 3 as superior. Preliminary environmental assessment ranked Scheme 4 environmentally superior. Scheme 4 is most likely not capable of supply the required peak energy demand. Thus, Scheme 3, ranked second environmentally, was prelim- inarily chosen as the best tunnel scheme. If you should disagre1e with the selection of Scheme 3 please contact me as .soon a~ possible. ' The objective of Subtask 6.02 is to compare the best tunnel schf~me with the COE selected scheme (High Watana.and Devfl Canyon). The environmental assessment should include a section compar.ing the impacts of tunnel Scheme 3 with the COE selected scheme. ·Include conclusions and a description of additional study required •.. In regards to disposal of tunnel mucl<·(rock removed .to create tunnel) we can assume that additional costs wi·ll be incured to dispose of the muck in an environmentally acceptable manner. An environmental assessmt~nt of alternative·disposal methods would he1p to define this added cost. The following lists only a few disposal ideas, feel free to consider others .. -Stockpile and use for access road repairs. -Stockpile and use for dam mate~ial (Scheme 3 only). -Dump in Watana Reservoi.r. -Fill the nearest ravine. -Leave in ·the most convenient location. -Pile, cover~ and seed~ Please do not hesitate to contact me for any additional information that may be required .. Sincerely, RJW:ccv ACRES AMERICAN INCORPORATED : .. ,. ' . I •• I·· •• Reservoir Area (Acres) I .. River Miles ' ' Flooded .I Tunnel length (Miles) -··· Tunnel Volume (Yd 3 ) I Compensation Flow ( cfs) · I DO\'/nstream Reservoir Volume . I {Acre-Feet) Devil Canyon Powerhouse I Discharge Dam Height I (feet) I ·I I I I I ·:. COE .. TABLE 1 Susitna Tunnel Schemes Physical Factors . . .. Devi·l Canyon 1 2 3 4 ~~--~~------~------~~--------~~--------~--~ .. 7,500 320 . · .. -0-·. ,. ' -· .. ~· 31 .. 6 . -o~· ... ~.. 29 . --10,749,000 11,545,000 500 . 500 --·-.. ,-:··to to ... ·,. ·.... .. .. "1000 1000 l, 100,000 9 500 . : . ' -0- Constant Peaking Peaking 520 .. . -- . . 3,900 .... 15.8 ·_; . 4,285,000 500 to :· lOOQ Constant. 245 . ·. 6,494,000 500 to .1000 -0- -.. Constant . . .. . . . ,. ... .. . . . .·. • , a.~ e .. .,0 ') ... 2 ltciet -t 0 rJ • ) c ~oo ~a -~ t f .. .,.; 2 lotoo -iooo .. , • 0 -• .. I t6 ! • '· i\ \ ~~.e..li ~~ MJ....a~ I ·~ -I J21~ ,AL.ItgNM~~ {=a.IE!MICS 1,244) ~ a .'s a'S0N.::s. 1,..., Mtut!S ' -" . . ·: -I t -ff I . F £ - • 0 e .6 .. , . -10 -• -j -.. ---~-f l --., -• --. -t .. 0 , - •st' 'i8 I' I 1414 - D e • .. ·~ • I .... • ~"''INCit 1N ~·~ ~~eME-.3-AicitiNMS.NT • t I. . • t .. ......... ___ "' ....... -,.,..., ': . 4 .. •• •• I . ..... ·~ ... ·-..... t ~ .... • ., . I I -·-- 1 I I I I •• I I I I I I I I I I I ... APPENDIX B A~1ENDED DESCRIPTION OF TUNNEL SCHEME 4 0 Mr. Vince.Lucid Terrestrial Environmental Specialists, Inc. RD l Box 388 . Phoenix, New York 13135 December 11, 1980 P5700.11.30 T.606 Dear Virice: -. Susitna Hydroelectric Project· Revi:sed Description of Tunnel Alternatives Enclosed please find a memo from B. tvart outlining our revised description of tunnel alternatives. . •. Please use this description in your assessment of tunnel alter- nativeso . In addition2 I have completed your table outlining tunnel design information .. Sinc_erely, KRY/ljr /""? -~~~4' ~Kevin Young · Environmental Coordinator Enclosure ·ACRES :AMERICAN INCORPORAT-ED_ Consulting Engineers The Liberty Bank 1:3uilding. Main at Court BJJlfaJo. New York 1-4202 Telephone 716-853•7525 . Telex Sl-6423 ACRES .BUF Other Offices: ~Q}~~~l;l,iii~ ~D: pttts}lurgh • .PA:-Raleigh, NC:-Wasbi~gton• oc =~,;....;;__--'-'-'"-~-""'~'~-~(""'-",, o;,_'"' ~-''"'--"''" ,.:.._.· -~-""'-'-~"''·"·~· '..,._,~.-•• ·~"· --~_.-.,._~•-~"' ';_,' • ,; "~·-·~ ' • _· . : . • , . . , . -. -j .• •· I • I • . ~ . -.. -· . -.. , l .• • . . .. . .. ·Range of r1 ver stage : be1 O'it Devil Canyon powerhouse ( co.rre- sponding to discharges 1 is.ted · above) · ~\ax1mum fluctuations ·{ft) in .do\btnstream . . . reservo1r . - . . . dai1Y. ·. seasonal •• 'll: .. . .... · ·. s_;,tr · I · . · ,b,~r · , ... ~·-qr ·-: ::. · · ;s-~ .. t.t'. . ~?oc-· . ' ')a . J:)/.1't!r.-. ;Oo ZJe/..•1k/ ~~At~ .... r /.s· ;J-·~4~/, J/c. · · .. e '· NA .. 4 .. . . NA •• ! ~latana . . . . . . . * . · . ~ · .. ~·:---w......-· -·~· _· ·_7_. r_· ·~--· _. oo~-·-· _79..._· e ..... ·. ____ . -+--~3_S""'_C_'1_1 ...... Zi)..... ·-· t--· ---~ ....... ~~-----· · -r· _. ___... ........ ~?.....,9......,..~:..--·· .. . ·~ Generating · Capacity 04W) . oev11s · · . Canyon . rj7£ ·: SS'"D. · · //S"" ·· ·· · .. ?cF..~ 3i:f's- -------------------4--~~~~+---b-~~----~~-------------+--~--------~~--·---.------~--------------. .... . " . Total Project CO~}s '(.$) .. • . .. . .. . i . • • + . . . '2i/$(}~ l:JtJ(j,J fJDD • i. • • .. · . . ;• ~7o..lf .... -. . . .. .~J~lt.J/.J·~dt>_,~t:JO. ' .· . . . . .. .. . . . 2.) t!J .,..,~ ~C)O_, t\00 . ·· s-'os-'~ ... : .. · · · ~?2!-9: ·! .. : · ··~~~o ... • .. • .._ • ,.. '· • • ~!!: ..,, ~ • • .• .• • • ;; •· !" .. . . ' 'l," .... * .,. ... -.. W' "' .... 0 0 0 .. ·-- ... ...... - --.. -·. ~ ...... -: ... ·. .• -·-.& - . ' .J!ATAHA WOHi"Hl.Y STORAGE FREoy£NCY FoR ·TK£ DEV1L CIJ.MVQ.)f A.~ WATANte SYSTEM .... : . . . .. ·~ --. -· ---··· -· .. --i . -. ! !- -i . . .. •. • "liLA"( •. .• -~ .. . . .. . . ltlf[~114 At,.Olf 10\JTHC~.:tlRlt. fl41t.I(LT Aftt.\, At.l$kA . I• • ·. . ·' .. . I I I I I I ·I I I I I : •. I Project Manager Susitna Hydroelectric Project Acres American~ Ihc. Liberty Bank Building Main at . Court Buffalo~ New York 14202 Attention: Kevin Young Re.: Alternative Develooment Schemes . . Dear Kevin: January 16, 1981 2l8e443 In response to your request of December 10, 1980, and as discussed in my letter.to you on January 8, 1981, TES, Inc. has prepared some corrments on the Vee/High Devil Canyon/Olson scheme in comparison with the Watana/Devil Canyon scheme. Enclosed for your review and comment is. a draft of a brief report entitled ••Environmental Cons ider.at ions of Alternative Hydroelectric Development Schemes for the Upper Susitna Basin ... We will be pleased to discuss the contents of this report with you. VJL/v·l ·Enc. cc: R. Krogseng Sincerely, u.~t,. Vtncent J. Lucid, Ph.D. Environmental Studies Director n • __ . ___ .....:::...-..:...o..:.-· ·-·· --:-- ... ·--., I ·I ~. .I i I I t .I I I I I I I I I ,. •· f . ALASKA POWER AUTHORITY SUSITNA HYDROELECTRIC PROJECT ENVIRONMENTAL CONSIDERATIONS OF ALTERNATIVE HYDROELECTRIC DEVELOPMENT SCHEMES FOR THE UPPER SUSIT~A BASIN by . Terrestrial Environmental Specialists, Inc. Phoenix, New York for Acres American, Inc. Buffalo, New York January 16 ;. 1981 . I I I .. •• I I ·I I I I 'I I I I I I TABLE.OF CONTENTS Page l -INTRODUCTION • • • • ., • • • • • • • • . . "' •·-. . . . . . ........ l, . 2 -APPROACH • • •. • =· • • • • • • • • • • ~ 0 u • • 0 • • • • 2 2 .l The Oeve 1 opment Schemes • • .. • • • • • .. • • • • • .. .. • .. 2 2.2 Assumptions of Environmental Constraints . . ~ . . 2 3 -DISCUSSION • • • • • • r: • • ,. • • • • 0 • • • 0 • • • 3 3.1 Socioeconomics • • • • • • ~ e • •. G e e ~ e e e a • • G e • 3 3.2 Cultura 1 Resources -· .. • • • . .. ,.. • • • • • • • • . . ... . . 3 3.3 land-use •••• . . . . . .. . . . . . . ·-. . . . . . . . . 4 3.4 Fish Ecology • .. • • • • • • • • • • • o • ·• a • a • • • • • 5 3.5 Wildlife Ecology • • . • . .. " • • • • • • • • • • • •• 5 3.6 Plant Ecology . • • • • • • • • • • • • • • • • • • • • ~ a( 7 . 3.7 Transmission Line Impacts • & 1 • • • 0 • • • • • 5 • • • ' 8 3.8 Access Road Impacts • e. • • e· 4 • ~ e • • • • • •· • • ~ ., •: 9 3.9 Summary • • • • • • • • • Q • .. • • • • • • • • • • • • • • 9 4 -CONCLUSION • • • • • • • • • • • • . . . . .. 11 APPENDIX A .... DESCRIPTION OF STAGING ALTERNATIVES . ,~, I I 'I - •• I I I I I I I I I I I l -INTRODUCTION This report docume!nts preliminary environmental considerations of.· alternative hydroe~lectric development schemes for the Upper Susit.~u Basin. The need for the report stems from _discussion at a meeting held· in Buffa 1o on Oece!mber -2, 1980 between staff of Acres American and TES~ Inc. The alternative development schemes are described in a December 4., 1980 memo from I. Hutchison to K. Young for transmittal toTES, Inc. (Append.ix A). Additional details were obtained and the approach agreed upon in subsequent. conversations and data transmittal between K. Young and V. Lucid conce!rning these alternative development schemes. The fallowing asse!Ssment is based upon a fami 1 i arity with the Watana/ Devil Canyon area obtained dur.ing. the first year of environmental studies.. At this writin·g, however, we do not have the benefit of information to be contained in the 1980 Annual Reports~ which are to be completed by TES subcontractors by March 1981.. Because much of the Vee . reservoir lies outside of the study area for many d·isciplines, comments concerning this impoundment rely heavily upon .intuitive judgement ... I I I I •• • - I I I I I -~ I I ' I I I I I ('{. 2 -APPROACH 2.1 The· Development Schemes Environmental considerations were pr~liminarily identified for two different hydroelectric development schemes for the Upper Susitna Bas in: Watana/Devi1 Canyon and Vee/High Devil Canyon/Olson. The three staging variations for each of these schemes (Appendix A) will likely have different short-term impacts 5 but an attempt to address these possible differences at this time would be too speculative in most disciplines to be meaningful. In disciplines such as socioeconomics and land use~ however 5 the staging of the development will largely determine the magnitude of impacts. Thus, the environmental considerations identified in this report are based in most cases upon the two ultimate schemes with occasional references to the staging options. It was assumed that whatever· staging alternative is selected~ all stages of develqpment would be completed. The result would be one of the two schemes outlined in Table 1. 2.2 Assumptions of Environmental Constraints The identification of potential advantages and disadvantages. of the two schemes~ from an environmental standpoint, requires that certain assumptions be made concerning environmental constraints that will · govern the design and operation of the fac i 1 ities. Among these are: (a) that constant, or nearly constant,. downstream f1ows be maintained~ both during and after development, whether by means of a re-regulatian facility or operational constraints; -~ ~ (b) that drawdown of the reservoirs would be similar in magnitude to corresponding reservoirs in the other scheme (e. g.. Watana vs. Vee} 3 ° and would ebe within environmental constraints; and_ (c) that a minimum :release or compensation flow be maintained (of a • volume to be determined) to preserve the riverine habitat between the reservoirs. . - I I I ,. I I I I I I I . . I I I I I I t ' . Table 1 Descriptions of Two Alternative Hydroe1 ectr.ic Development Schemes for the Upper Susitna Basin(a) Maximum pool elevation (ft) Dam Height {ft} Installed Capacity ·(MW) (l Probable On-Line Date of Last Stage Daily Peaking Approximate(b) . Reservoir Area (acres} Approximate(b) River Miles Flooded{c) Watana/Devi1 Canyon 2200/1450 750/570 800/600 2010 to 2020 Yes/No Q 40,000/7,500 (Total = 47,.500) 60/30 (Total = 90) 0 Vee/High Devil Canyon/Olson 2300/1750/1020 425/725/120 400/800/100+ -~ 2020 Yes/Yes/No 16,000/21,700/900 (Total .... 38,600) 95/58/7 (Total = 160) a Derived from descriptions of th·ree staging alternatives for each scheme, which are presented in-Appendix A. b Preliminary values. c Mainstream Susitna only, tributaries not included. \ I • ,. r " ;I .. I I I I I I I I . I I I I t I ..--,. .. 3 -DISCUSSiON . Potential advantages and· disadvantages of the two development schemes are presented below for· each of the major environmental study disciplines .. 3 .1 Soc ioeconomi.cs There. could be significant differences in type, degree, and chronology of socioeconomic· impacts resulting from the various plans under consideration. An important concern relates to a 1 tern at ive staging plans and associated factors such as: (aj cost of stage, (b) scheduling of various stages (i.e., length of construction period per stage and spacing), (c) construction manpO\'Ier requirements by time period, (d) access point of origin, and (e) whether or not a construction 11 Communityu will be established. Imp~cts generally wi11 fall into two categories: those associated with project economics and construction~ and those associated with power production and sales.. Both types of impacts will exhibit a variety of local, Railo~nt, and state\tJide ramifications. In the absence of practically any project econoiJlics ' information, detailed analysis is impossible at this time. ln general, however, it can be expe!cted that a scheme involving on-1 ine product ion capability of 800 MW by the year 2000 will have greater and rore significant impacts thaft a scheme in which that capability is not attained until 2010 (e.g., Plan 1 compared to Plan 2). This difference would occur because, in the latter plan, the demand on resources· will be · spread out over time. ln addition, it is reasonable to expect that the economic base of Mat-Su BOl"'ough will be larger in 2010 than in 2000, even without the project. Therefore, there 1 ikely would be a greater capacity to deal with project impacts .. 3.2 Cultural Resources Field surv~ys i.n th~ Watana/Devil Canyon impoundment area during the sumner of 1980 have documtented 37 archeological sites.. A pre1 iminary assessment of the dat·a indicates a greater number of arch~ologica1 sites 3 ·I. I I I I I I I I I :1 I I I I I I I ' ~.,--. . ' . • ~f to\1ards the east end of the study area. In 1953, a pre1 iminary field survey conducted for the National Park Service near Lakes Louise, Susitna, and Tyone identified approximately.six archeological sites. There is a high potential for-discovering many more sites along the lakes, streams, and rivers in this easterly region of the Upper Susitna River Basin.. Additional sites are_ expected to_ be· identified near caribou crossings of the Oshetna River. In summary, a preliminary assessment of available information suggests that there perhaps could be a greater number of archeologica·i s-ites .associated with the Vee/High Devil Canyon/Olson scheme than with the Watana/ Devil Canyon scheme. 3.3 Land Use At present, much of the Upper Sus itna Basin is subjected to almost negligible human activity. Eithe·r of t~e development schemes (and any of the staging plans) will cause changes in land use patterns in the Upper Susitna Basin. Regardless of the scheme chosen~ impacts on local land usa9e and human act ivi~y in the Upper Bas in \'lill be signif;icant in terms of area inundated and land cover changes resulting from project facilities. With either the Watana/Devi1 Canyon or Vee/High Devil . Canyon/Olson s.t:heme, Deadman Falls will be inundated and Devil Canyon will be greatly reduced in scenic value. The Vee/High Devil Canyon/Olson scheme would also eliminate Tsusena Falls and would destroy the existing aesthetics of Vee Canyon by dam construc~ion at this site. Although the Vee/High Devi 1 Canyon/Olson sch~me has a smaller reservoir area, it would inundate approximately 70 miles mare of the Sus!tna River than would the --~atana/Oevi 1 Canyon scheme (Table 1}. Development of a recreation plan for the project would vary accord~ng to the design scheme and staging plan selected. Broader concerns associated with land use are related to staging, as discussed in the previous sect ion regarding soc ioeconomic!S. The influence of stagi-ng on land use impacts app1 ies to land use f~ctors concerned with e>tisting regional transportation systems. The e~isting 0 • ' - ~ransportation systems {and comnunities and land uses assc1ciated with them l which connect to the se 1 ected access route. wi 11 be affected by construction-related activity. ln this context, the degree of , 4 1. I I I •• I I I I I I I I I I I I I I n construction-related activity within a given time frame could be a significant factor. This consideration is similar to the socioeconomic concern identified previously. The proportionately greater degree of . construction activity as.sociated with a p1an in which 800 MW capability would be achieved by 2000 -as compared with one in which this would not be achieved until 2010 -concentrates impacts on land uses in a shorter time frame. 3.4 Fish Ecology All development. schemes must be examined with the downstream anadromous fishery receiving primary consideration. Any ?Cherne or staging plan. that allows for daily p·eaking without a re-regulation .dam downstream could be detrimental to this resource. Therefore~ the maintenance of constant, or nearly constant, downstream flows is an environmental constraint that must be met for any development scheme to be acceptable. The Vee/High Devil Canyon/Olson scheme has at least one major disadvantage, with respect to fish ecology> in comparison to development at Watana/Oevil Canyon. It i.s that the Olson site is downstream of . Portage Creek, which is known to be a very important spawning stream for salmon. · Dam developm~mt at the Olson site would provide an obstruction to anadromous fish passage and two miles of Portage Creek would be inundated. Even with facilities for fish passage, the impacts ·an this spawning area could be severe. Because the Vee/High Oevi 1 Canyon/01son scheme would inundate about 70 . . additional miles of the Susitna River, plus different tributaries, than would the Watana/Devi 1 Canyon scheme, impacts on resident fish can be ... expected to differ between the two schemes. Data are not presently avai 1 able to permit an. assessment of these impacts. 3.5 Wildlife Ecologl . Although the area that would be inundated by the .Vee reservoir has not been thoroughly investigated; project personnel have sufficient fami1 iarity \1ith the area to make a fairly strong recorrrnendation at 5 I I I I I I I I I I I I I 1 I I I I I this time. With the exception of impacts on avian species, it is felt that the Watana/Oevi 1 Canyon scheme is superior from_ a wi.1d1 ife impact standpoint to the Vee/High Devil Canyon/Olson scheme. The basic trade- offs associated with this comparison involve the arf~as to b~ flooded by the Vee dam as opposed to the flooding of much of tine ~latana Creek drainage and the. higher portions of the canyon walls a.long the Susitna. .For a variety of reasons the area to be flooded by the Vee dam seems more valuable for wildlife "than the areas that would be inundated by the Watana/Oevi 1 Canyon dams. A Vee/High Devil Canyon/Olson·. scheme would flood more acreage of critical river bottom hab1tat than would the Watana/Devil Canyon scheme. These ar·eas are important far moose during severe winters and . ' the additional reduction in such habitat could have a major impact on moose populations. In addition, the Vee "impoundment would flood key winter habitat for at least thtee subpopul at ions of moose that range over 1 arge areas east of the Sus i tna and north of the MaC1 aren River. The area that would be saved by the Vee da.'lt scheme, the Watana Creek drainage, is inhabitated by a subpopu1at ion of moose that appears to be declining in condition and increasing in age, thus indicating that within 10 to 15 years this subpopul at ion may be far less important than • at present. The habitat quality within the Watana Creek dr-ainage also seems to be decreasing. TES has previously recommended that the pool elevation of Watana be lowered to preserve as much of the Watana Creek drainage as possible. Nevertheless, the trade-off between Watana Creek and the Vee impoundment favors flooding the Watana Creek area. ihe area. that would be flooded by the Vee dam is historically used by . the Nelchina caribou herd, particularly in moving to their calving gr·1Junds near Kosina Creek. Although caribou movement patterns are hi~Jhly variable and appear to change as the size of the herd changes, thfs area has been frequently traversed by members of this herd. The l potential for impacting caribou movement is greater than with the pr~~sent Watana scheme. Like Watana~ the Vee reservoir would be subject to 1 arge drawdown and possible ice-shelving. In add it ion, the three-d~ scheme would result in a greater division of the Nelchina herd's range due to the greater length of the impoundments involved and thus increase the likelihood of impacts on this herd:e ,~·~· 0 -..... -.., ' : ,.:.k. -~ •. ' ' . I I I "I 'I I I I I . I I I I I. I I I I I -·~---· .. · .. . There is an indication that the area to be flooded by the Vee dam is more important.to some key furbearers, .the red fox in-particular, than areas such as Watana Creek that would be spared by a Vee dam. There is . also more trapping conducted by residents in the area upstream from the Vee site than in areas downstream ~om that area. The Vee dam, especially due to the drawdown schedule that would be operative with this dam, also has the potential of roore severely impacting both muskrat and beaver populations. It appears that only avian species might suffer less adverse impacts from the Vee/High Devil Canyon/Olson scheme than from Watana/Oevil Canyon. Although the Vee dam would eliminate more river bottom habitat~ it would spare a considerable amount of deciduous forest (birch· and aspen) that exists along the south-facing slopes of the Susitna canyon and along some of the tributaries. This is the only area, of any extent, that contains this type of habitat, and its associated avifauna, within the Upper.Susitna Basin • Although a more detailed recommendation could be made if a better data base were available~ the reasons given above seem to indicate that the Watana/Devil Canyon scheme is superior to a Vee/High Devi 1 Canyon/ . Olson scheme. This is especially true if _one. considers that the greatest potential for more severe impacts concern moose and caribou, which are unquestionably the key big game species in the area. 3.6 Plant Ecology . Both schemes will primarily flood deciduous forests (white birt:h, ba 1 sam pop 1 ar, and aspen types), coniferous woodlands and forests (white spruce and black spruce), and shrub comnunities (alder, birch, and willow types). The relative amounts of habitats flooded will vary with the two schemes. The Vee/High Devil Canyon/Olson combination will probably flood more floodplain habitats such as balsam poplar forests, while the Watana/Devil Canyon scheme will probably flood more birch and aspen forests. . 7 I. I I I I •• I I ·I I :1 I I il I . Ia I I I I . The primary advantage of the Vee/High De vi 1 Canyon/01 son scheme 'is that approximately 9,000 fewer acres would be flooded {Table 1). The primary disadvantages of this scheme are: more lakes and wetlands flooded, more river floodplains flooded, and a greater amount of associated floodplain habitats, such a:s balsam poplar, eliminated.. The amount of wetland eliminated would be a very small proportion of the total wetland in the region.. Nevertheless, the importance of wetlands~ floodplains, and associated habitats has been emphasized by Executive Orders and ~arious federa 1 agencies • 3o7 Transmission Line Impacts Because of the distance 'traversed, the construct ion of a transmission 1 ine to the intert ie from a Vee/High Devil Canyon/Olson project offers several disadvantages when compared to a line constructed from a Watana/Devil Canyon project. A line from the Parks Highway to Watana would be approximately 50 miles in length. Following the same route to Watana and extending the line to the Vee site would add approximately 40 miles to its tot a 1 length, an increase in mi1 eage of some 80 percent. Generally~ the longer the line, the greater the impact. In add it ion, the added length would cross a presently roadless remote . parcel of land, thereby necessitating additional miles of access road construction. Additional vegetation clearing would be required due to the longer route. Assuming a 300 foot wide right-of-way, approximately 1500 additional acres would need to be cleared during construction and maintained during operation of this line, thereby potentially impacting wildlife habitat. To the extent that =land use, aesthetic and· recreational opportunities are impaired by transmission facilities, a larger impact zone will be created. Similarly, areas of significant cultural resource potential will be impacted to a greater degree than with the shorter ·line. A greater number of streams tributary to the Susitna River will need to be crossed, posing additional areas of potential impact. In summary, constructing transmission facilities t1 the Vee site considerably increases the potential impact of project transmission lines. a ' .... [I r i •• I I I I I I I I :1 I I I I I I I I 3.8 Access Road Impacts At present, an access route for the Watana/Devil Canyon scheme has not 'be·en decided upon, and no information at all is available with regard to access for the Vee/High Devil Canyon/Olson scheme. Also, it has not even been determined which of the two schemes would have the shorter access road. By virtue of the relative dispersion of the dam sites 7 however, the two +schemes m~y differ with respect to the area opened up to access and the resultant dispersi~n of human disturbance over the Upper Susitna. Basin. The Watana/Devil Canyon scheme may confine access to a smaller portion of the basin, especially if access is from the west. The Vee/High De vi 1 Canyon/0 1 son scheme, especially if it is a staged deve 1 opment, may be roore likely to have access from both north (Denali Highway) and west, thereby opening access to a larger area, and from several directions. 3.9 Summary In each of the environmental study disciplines, differences exist .in the potential impacts of the Vee/High Devil Canyon/Olson scheme in comparison to the Wa~ana/Devi 1 Canyon scheme •. The Vee/High Oevi l Canyon/01 son scheme . has more apparent disadvantages than advantages; most of these disadvantages are due to the Vee impoundment rather than the High Devil Canyon impoundment. In socioeconomics and in some aspects of land use" the differences due to staging are of roore significance than those due to the location of the dams. Nevertheless, it is noteworthy that the Vee/High Devil Canyon/Olson scheme may affect roore ,canyons and waterfalls of outstanding scenic value than would Watana/Devil Canyon. Existing information suggests that there is a high potential for occurrence of cultural resources in the vicinity of the Vee reservoir, perhaps even more than in the vicinity of Devi 1 Canyon and Watana. A major disadvantage of the Vee/Hi'gh Devil C~nyon/Olson scheme is the impact of Olson on anadromous fish spawning in Portage Creek; daily peaking from High Devil Canyon without re-regulation is also environmentally unacceptable. There is evidf!fl~,~. ~,{it _jmpacts upon big game (particularly moose a~d caribou) ~ . -- and furbearers would be more severe with the Vee/High Devil Canyon/Olson scheme than with Watana/Oevil Canyon, although this is not necessarily the case with birds. Although the Vee/High Devil Canyon/Olson scheme \'lould 9 I I I II I I I I I I I I I I 'I I I •• I flood less acreage than Watana/Devil Canyon, a larger amount of floodplain and wetland habitat would be inundated. Because of tne longer distance traversed, potentia 1 impacts of the transmission 1 ine would be proportionately greater with deYelopment at the Vee site. The dispersion of the dam sites in the Upper Basin with Vee/High Devil Canyon/Olson would also likely re.:;ult in a larger impact zone due to increased access. . 10 I. :1 I I I ·I I I I I I I I I I I I ;I ' I 4 -CONCLUSION Although some potentia'! advantages and disadvantages have been identified for both the Watana/Devi 1 Canyon scheme and the Vee/High Devil Canyon/Olson seheme)l sufficient information is not yet available upon which to base a firm recommendation. The evidence that is av~ilable, however, when combined with intuitive judgement, suggests that the Watana/Devil Canyon scheme may be preferable to the 'lee/High Devil Canyon/Olson combination. The <;omnents contained in this report will be reviewed and refined after ·the 1980 Annual Reports are available and when more construction and operational details are known. Comparison of the two schemes will still be hampered by the scarcity of information concerning the Vee impoundment area. e 0 ll .. I I I I I ·I I I I I :I I I I I I I I ,I APPENDIX A . DESCRIPTION OF STAGING ALTERNATIVES .... ' •, I·'~· ,;. ... · ...... ... . . ..... .. ....... . .. .-... .• .. ~:... 1: .... ~. ·.""· _ ... ·-• .. "' ... -..... .. .... . ... ~ .. .. . ... .. .. .. -· .. .. · •• - I I 1 .. . .. ·. I .. • .· •. . . . . -. . . . , .. '· "' ~ . . .. '· ... .... . . -" ,;-··-.... t ... ... --.~:..,,.. .. -~ ~-~.{_:,.· ~ ~!:-:~~·";•• .. ... ~.:~ ; ~:;.;.:·-;:~· ~ .. .., -·· ~ ........ ; .. . ' . . ·. .. .- ~ ~::: ~::. ~ ·• ~ • "'l.:t.. 4 ..... ~- -•• 01.~ t .. ... . .. ::... .. -···· ~-.;:,,.. ~-~· .. ., ~y.....: ~ .. .... ..,._ ..... ,~ "'~ .···-~~ :~; ~ " ... ~ ~: • ..,~.~.,~ .. ::1, : ~ ••. .:~~-:-!" .. ;;. -~~·--~·~*4t ., ............... . - • .. ---- SCHEME Plqn 1 Stage I Deve loQme,n~ Dam Site Watana (22001 Height 750 . ft. Installed Capacity 800 .f-1\~ - Probable on Line Date 1995-2.0.00 -··--·--... -. . . . . . ' . .. (Total installed cap~ci ty = 1400 ·r.1\~) · . Stage II ·Development Sta_,.qe .III Deve10[!lJ1en:t. · · Dam Site :oey1J ~ilo·voo (!450) Dam Site------- Height 570_ ft. ·: Installed Capacity ~600 t·1W · Probab1 e on · Line Date .2010-20 ·Height ft* ~ · · ----- Installed Capaci~ty __ ~1\tl · · Probab lt: on Line Date ---.. .. ' Stage IV ·nevelrwment_ Dam Site -' .. ------ Height __ ft. Installed Capacity -·--l-\W Probable on Line·oate __ _ · . Daily · · Mode of Operation Peaking · No Daily . Mode of Oper.ati ?" e.eakjng · Node: of Operati o.n -----. Mode of Opera.t1c-n ---- Separate . •· Separate Re-regul ation Dam Possibl¥ .Re-regulat~on Dam ..... .t~:.-.o __ •. . . . . NOTE: Figures in brackers behind dam site name ind.icate. maximum water surface elevation in feet. • I ' . . . . . .. . . . " . . . . . . . ~ . . . . • I . . . . . .. ,, ...• . . ,.. :" .. Separate Re-r~gulation Dam __ _ . . . . .. . " "' .. . . .: . . . ' .. .. •,. . . . . . . . . ~ .. ~ .. • . .. . . .. .,. . . ! ' .• . . . . ' · . • . ' ' . ' . . . . . . . Separate Re-regulation d~m . . " ... "' --- .. I ' . .. . . . . . ..... .. . . ... • ·. a ---·-· --.,. ,, . .· a ·. •. -·--••. ~. •' .. . .. ·~ .:~·~* .•.•• :·.---......... ,_.:.,. .. __ . . . . . • .... >lj -•. --. . 'i SCHEME .. fl an 2 • (Total installed capacity = 1400 f~) Dam Site .J~atan~ (2000)_ Height 550 ft. Installed Capacity _·....,.4..-o ..... o _ Probable:on r~w Line Date l9QS_ . Daily Mod~· of. Operation J:g~kiog Separate Re~regulation Dam jossibly . . • • ~' -' . .. . . . .. I. . ' . . . . .. . .. . . . . . . Sta9e II pevelopment Dam Site \~atana ,[2200) ·- Height 7.50 ft. ... Installed Capacity 800 P)'Obab1 e on .Line Date 2000-lQ. · Daily Mode of Operation P~akjng . Separate . ... Re-regulation Da~_Poisibly Watana Dam raised 200' Installed Capacity Increase~ by 400 J.1W . . . . . . . ·. . . . ,• ... . .- .. ... .... ... . ' . ., . . ~ . • Jj ..... 1- "' . . -. Stage IV Deve'tQl'mnenic ............... I. ,4 :fit -- Dam Site Deyjl. Canyqri (1!501) Da~l Site __ ,.,..._ __ _ Height ~57...-.0_ ft. Height--·--.f't .• Installed Installed Capacity __..6..,..00,.,__·~~1 · Capacity ___ ~M .. . "' -· ·: ·: ~ · Probable on .. . . . .,; Line Date .... 2QlQ 7 20 .: · •. · : .. Line Date · . · · · 'No· Da 11y · · Probable on .. Hade. of Operation .eeaking Mode of Operat'ion· __ _ '· .Separate . Re-regu 1 a ti on Dam J-Jq . ·Separate Re-regulation ~'m .· . . . .. .. . . . . . . .. . . • \ ~ .. •"'. . , . .. . .. -.. . . . .. ' .. . . . . . . . . . . . . . .. . , . . .. . . . . " . ---- .· . . .. .. . . ..... . . ... •• • • ·~4 .. .. ! '• .. '!' ~ ' .. " . .. ... . . · .... . . ' . . . . . . . . .. . ... • . . ' . . . ~ .... .. , .. ~. .. ·•· . . .. . ,, .. . . *.; ' ' • ·-.. 4 . . . ,· .. .• •. . "· .. ·•"' •' ' . .. '" . . I • ' . . ' .• ·' l •• • •••• 1t" t: . . . . . . ·. • f I .. . ~ ,. . ... ~--·---------·· ·~· -· .... .. ... . ' • ' . . ·. • • .. .. .. .. . . . . .. . . ' .. ... SCHEME ... ., ..... (Total installed ·capaci t.Y = 1400 t·1l~) .. . . Stage I DeveloEment:, ~tage II Oevelopmen~ . Jttage III Development • Oam Site Watana • • b Height 750 ft. (22ou),_ .. · .. Dam Site Jl.g;tgna (2200)_· · Hei g~t .J.5 .. Q_ ft. Installed Capacity-_4_00_. _ Probable on Line Date 1995 Daily t·1ode of Operation· Peaking Separate Re-regulation Oam • • .. . . ·. . . .. ···•·· • • • . . . . . ,. .. .. . . . .. . . . •, , .. .. .. -· . . ' "' .. ' .. . .. , •· . " . .. f t • . . ,, . . ~ ~ . . .. ... ,. "'' .... . f .... ·!. Possibly ·. . . .... i. . ... ·• .. . . . . ~ . . . . .. . . ,. . Installed Capacity 800 Probable .on Line Date 2000-10 Mode .of Operation .. Separat,e ·. . . Daily Pea~iP9. · Re ~·-gu· ., --•..t-n -.·c:: 1 a~ 1 u 1 Dam fi)ssibJY · .Ir.sta lled Capacity Increased by. 400 t1W · . . ' .. ' . .. . . . . . ._ .... . . ·' ; . . . _. t I • ~ • .. • • . . . .. . "'.. : . ' '• .. . . .. .. ~ .. . . . . .· •"' . .. . . Dam S 1 te .De~; 1 .r.a oyon~ . Height. _. 570 ft~ .• .. . installed Capacity ~-L 1·1\tl. .. Probable on ~ . Line Date _2010-20 . " No Daily· .. t1bde Qf Operation ..ffl9king :·~ Separate . Re-r~gulation O~m ""-~..N~.~_.~.o_...__ . . . . . . .. . ·, . .. ... ,, . .. . . . • .. : .· . . ... . ~ .. :• ._o ... . ,. .. : .. .. ... . .· ''l --•. "'.· §.tage IV DevelO@!!!ent Dam Site }1e1ght lnstal1ed Capacity ----. . Probable on Line Date ~\W Mode of Operation Separate ~e-regulation'dam :· • . . . .. . • • . . ·. .. .. · : . . . • .· ,, . ---····=--· -. . -· -. . ' . -•. .. .. I ' ·-. . . ···~ ~::··!~-~ .. .. ..;.• .. . . · .. : . . --... .. .. SCHEME Plan 4 '(Total installed c;apacity 1300 f·1W)': .•. .. -- . + ......... \ •,. ... .. .· .. •• . ,,. ' • . • l ' .. ,• ' •' . · . ~ . . : . . . .... : ,, • .•• 't .• " •· . •• . ., .. • ~tage I ·oevelopmen,S Stage Il .Deve1.opment Dam Site Jii gh ll.&C, (.1Z55} Dam Site Vee.{?3Q9J . ·Height 725 ft. . Height 425 ft. Insta1Jed Insta.lled Capacity·.......,.so ....... o_ t:\W .. .. Capacity _4QO •' ...... . .,. .. ____ _ Probable on Line Date 1995-2000 f·1ode of Daily Operation .fea.~ing Separate .. Re~regulat1on Dam Possibly* * • .. ·, ·. . . .· . ,. Probable'on Line Oa te . 201 0;40.. . Daily· Mode. of Operation _pea ~iDg Separate Re-regul at ion ·Dam ·. . . I No . . • • :• I • .. • ·• .. • • • • '···"t*· .. -... .. .. .. .. \ I . ~ . •• • ' 'I • ' .... ~ ;\ ,..~ ....... . .. •. -~ f . .. ; . . . . . .. · . .. .. .. . . . . •' . . .. .. .. • • ••• ~· ... · ... .... .. . .. ~ • • • • .. ' . . /' .• . . • ,"' ..... •' •• · . .. . : ' .. ... .. • . '• .. .. •. . •. :· . . .-: .. ... §_t}_ge III Development : .. ,·:.~ Dam Site .Q1sol') .. (lQ10l.: Height • J4Q ~-·ft • .. . -.... ...... ,. .. .. .· . .. ' ~ .. . •. ~ ·-.. ' ,. , Dam Site ----· ·Height Installed Capacity :1:100 · •' Installed Capacity -----MA Probable on Line Date .2020 - .. . . ~ ..... ' .. . '•· No Dail~. · t'klde of Operation .eaa.kiruJ · Separate Re-regulation Dam . . . ·. .. . . ... . . . . ' ·~ . •, . . • i "' . .... · . Probable on Line Oat~ Mode of Operation Separate Re-regulation df).m . · ~ : . .. t . ,. .. . .. ,. ' . ... .... . . . ;• . . .. . • .. .. ... " .. " •· .. . . • .· .. .. .. ', ~'\ ~: •i " .. . . -~ ·' . . ... ... :. ... ~ • • e • • • • •• • . . ~ ... 'li. . .. .• • . ' , ' I . . .. .. ... . "" .. ·, .. .. ' . . . . . .. · . .. .. ... "' . . . • i· .. . ... -· . . • • .. .. .. t • • • ~ ' . . ·, -. SCHEME ·(.rotai installed capacity ·. • c •• -· -~ge Il Development .. -. Dam Site _,H ..... i.....,g....,.h....,.D_e .... v.-i l~·co;;.;an~yon:. ·bam Site High Oeyi f canyon { 1610) . . .. . . . '. (1750) }ieight Installed Capacity. 570 ft. 4oo · r4\~ .. . . . •. ...... ·.Height·~ 725 -ft. . !.~ .. ~.;.: ... ~. ... "! ....... .. . · ... i . .. ......... ;; ·:~ .. ·". ... . : .. . . . Installed Capaci~y 800 t·M Probable on ... ?·;-··_.Probable on .. line Date 1995 · ::· t::_··-; .:Line Date 20QQ:.lO· . ~.... Daily ·..... · ':. ~~-·. f·1ode of Operation Peaking.'::. -.:··Mode of Operati an .. . .-·:.... ·.: .-.. J Separate ...... Daily Peaking .. = 1300 f·R~) .· ... ~ . .. .... Stage JII Development: : ... ~ .Heig_~~- .. .. ' · ... 425 ., Installed Cap ac.i ty · 400 Probable on Line Date .. ·separ~te . Re-regu)ation Dam fgssibly* Se!')arate Re-r:..yulation Dam Possibly*' Re-r~gulati-nn Dam . ..• .. . • •• . , . . . · .. .. .. . . . ,• .. . . .. .. .. .. ·;:_~ . ....... - .. -.• : .. ; --.· Dam Site Ols• .. ll020l .. ±10€& installed Capacity b ....... - - No Da11y -~f Operatl~n Pe:akiJ19 . .. . ... .. • . . . . ' . ... . . . . . .. . ... No '0 · . . ' .. . . . .. . .. . ._; •• . • ••·"'"' . .. ·- . . . . .. I •• ;< •. t • I J • I • .. • .. .. • ~ .... -t . • • a' :· ~ t .. ; .... ,.. f •• . . l :, .. ·-----, -·---... ·~ SCHEME . .. Plan§ (Total installed capacity a 1300 t·U~} .. .St29e I Development Dam Site JU gb.Q.e'lj 1 Height 725 ft. Installed Capacity. -4..-..:0~Q-• .l~ Probable on Line Date 1995 . . Canl!on (1750) .. ·. Sta.ge I 1 Development Height • zgs • Installed Capacity -B~OO~ Probable on t-1W · · Line Date 2000-10 Oa ily ·· Daily Peaking ' . :Made of O~eratibn Separate Re .. regulat.ion Dam '* •• . . ·' ., • t"' ., Peaking . .-Mode of Operation . . . •• . ; S~parate. Possibly* Re~r~gulation Damep~s~b]y*' . • • • .. •. . . . . . . : ··. Installed by 400 111~ , . · . . . ' . . . •,. . .. .. . .. ' ... • • '* .. ,. · .. ·. . ... ..... . ... ~ . ·~· j • . .. . . Capacity increased .. • • .. ·. . . s.tage III Dev.elopment. / .. Dam S <i te .... V..-.e~e---.. --.--........ . . H~i ght . 425 · Installed Capacity Probable on ft. . . ' Line Date 2010-20 ' .. · .. . .. ... .. .,. .. . ; . . . . ... .. ~Daily t~de of Operation Peaking Separate Re-r~gulation .Dam· ... ,No .' ' .. . . : . ~ .• .. 4 . . . .. : : ... . . .. .. l '. . . :. . .. ' .. ---- .. . · . ~tage IV Develsppment - Dam Site Qlsoe {]020) Height .. ,120 ft. Installed Capacity ±.}06 Probaule on Line Date 2020 -.. .. - Mode .of . • No· Qaily Operat1on f~aking '". Separate ~ Re-regul at1 on dllnt ..--tlu..~.o__: I • •. : ... . . ., .. ,· •· ... . . .. .. . ~