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HomeMy WebLinkAboutDillingham - Monokotak Electrical Study Final Report 1988Care) November 1, 1988 Alaska Power Authority 701 East Tudor Road Anchorage, Alaska 99519-0869 SUBJECT: Dillingham - Manokotak Electrical Study FPE #APA88032 ATTENTION: Mr. Donald L. Shira Director of Program Development and Facilities Operations Gentlemen: This letter transmits three copies of the feasibility study regarding a proposed transmission line between the facilities of Nushagak Electric Cooperative, Inc. in Dillingham and the system in the Village of Manokotak. This study was authorized in your notice to proceed issued under Contract APA 2800097, Work Order #1 dated August 30, 1988. The report analyzes the economics of the proposed intertie. We think you will find the results illuminating and informative. After you have had the opportunity to review the information, we will be happy to dis- cuss any aspect of the data with you or your appointed representative. This study, coupled with the earlier (September 15, 1988) report identifying the problems within the power generation and distribution system in Manokotak, will prove to be valuable tools in the assessment of how best to address the regional power issues surrounding the Village of Manokotak. Thank you for the opportunity to assist you in this challenging project. Please contact us if we may be of service in any way. Sincerely, FRYER/PRESSLEY ENGINEERING, INC. ames R. Pressley, P.E. ice President xc: APA88032 File 1. 2. 3. Table of Contents SUMMARY... ccccccccccccccccccccncesccsesscesescssssssssssesel INTRODUCTION. ...cccccccccvcccccccccccceccesscssseccesscsseel METHODOLOGY... ccc cccccccccccccccccccccscccccessessccsvcsecel 3.1. REVIEW EXISTING PROJECT DOCUMENTATION..............50- 1 3.2. REVIEW MANOKOTAK’S EXISTING ELECTRICAL SYSTEM......... 2 3.3. REVIEW DILLINGHAM’S SYSTEM.......cccsccccccscrcccccces 2 3.4. ANALYSES OF MANOKOTAK’S AND NEC’S SYSTEM.........-.+-- 2 3.5. METERING PLAN AND OWNERSHIP RECOMMENDATIONS........... 2 3.6. POSSIBLE SAVINGS TO STATE AND VILLAGE CONSUMER........ 3 3.7. LAND STATUS AND PERMITS REQUIRED...........eeeeeeeeeee 3 3.8. COST ESTIMATES... . cc ccccccccccccccenscscereseccecscees 3 &. ANALYSES AND EVALUATIONS... .ccccccccccccccccccescscsssssce cl 4.1. REVIEW OF FURNISHED PROJECT DOCUMENTATION............. 4 &.2. MANOKOTAK’S ELECTRICAL SYSTEM. ... 2... ccc ccc cece cc cccecs 4 4&.3. COSTS-TO NEC TO IMPLEMENT INTERTIE.. 2.2.2... 2c. cece cece 5 &.H. METERING PLAN... ccc ccccc ccc ccc cc cccccccccsesccccccccs 6 4.5. OWNERSHIP RECOMMENDATIONS...... BiCIM! le) Wile low ieee Sle fe elo e ve iz 4.6. DETERMINE POSSIBLE SAVINGS TO STATE.........eeeeeeeeee iL 4.7. DETERMINE POSSIBLE SAVINGS TO THE CUSTOMER............ 8 4.8. DETERMINE LAND STATUS AND PERMITS REQUIRED............ 8 aOr a SCOLS? Ol ALTOSKO esc cicielssieie cia ici eieiersicisiecisicicieicic ele 19 SO a OOOO Liteleicieclejeielclerciciclclelaleledelcicicielelelelelcreleleleielelelelels 11 &.9. COST ESTIMATES... ooo ccc ccc ccicceccccsccccccccsceesce 13 4.9.1. Assumptions for Overhead Line.............0+0- 13 4.9.2. Assumptions for Direct-bury Cable............. 14 %. RECOMMENDATIONS... ccccccccccccccccccccccccccccvcccescsescs th 6. ESTIMATED COSTS FOR INTERTIE CONSTRUCTION........++++++++-16 6.1. Estimated Costso. occa cnccecn cc ccc ccc coc cleicicinianlsisisicisiss 16 Gatots For Overhead Cine. ccc sce ccc cscicisic)slel ciclo 16 6.1.2. For Direct—bury Line... ...cccccccsccccsccccwes 16 Appendices A. DOCUMENTS REVIEWED FOR THIS REPORT.......cccccccccccccvces 17 B-) POWER SYSTEM (DATA. corso wee ieiesieloicielereieisio sloleleleielelee io eae 26 C. VOLTAGE DROP AND LOAD FLOW CALCULATION.............200000 21 D2) ETEEMCYCLE COSTS “ANALYSES iicgeteieterererer- ol ototelelolsicleleieieielolciele)eeieielwis 22 SE, ccuscasecnewasensaseuwadensas seeawnerenseseneucceseeee sae DILLINGHAM-MANOKOTAK ELECTRICAL INTERTIE 1. SUMMARY The proposed interconnection between the power distribution system of Nushagak Electric Cooperative, Inc. in Dillingham and the Village of Manokotak is not feasible when evaluated on an economic basis. The construction costs are among the highest imaginable for similar systems due to the terrain and subsurface con- ditions which intervene between the two locations. For the same reasons, the probability of early and possibly complete failure of the line is quite high. Other factors exacerbating the ability of the intertie to recoup its required in- vestment costs included very little load in the Village, a poor load profile for energy use within the Village and a relatively low per KWH rate historically charged for energy within the Village. In short, it would be more advantageous to spend smaller amounts of money in upgrading and making more reliable the ex- isting power generation and distribution system in the Village of Manokotak than to spend considerable sums of capital building a system that cannot be justified by its potential economic return and has a high probability of catastrophic failure. 2. INTRODUCTION The Alaska Power Authority authorized a review and reevaluation of the pos- sibility of intertieing the Dillingham electrical generating utility system (Nushagak Electric Cooperative) and the village of Manokotak’s electrical system for the purposes of transmitting power from Dillingham to Manokotak. The economics of such a transmission line has been under investigation for a number of months and there have been various reports and letters offered to the Alaska Power Authority originating from multiple sources. This report uses the avail- able data to develop a comprehensive treatment of the proposed project. The dis- cussion and findings are arranged in the order in which they were presented in the Notice to Proceed issued by the Alaska Power Authority on August 39, 1988. 3. METHODOLOGY 3.1. REVIEW EXISTING PROJECT DOCUMENTATION The entire complement of reports and other data offered by the Alaska Power Authority relative to the Dillingham/Manokotak Proposed Power Intertie was researched and investigated to gather as much information as possible about the techniques and results of the earlier studies. Among the information researched are the sources whose titles ‘and/or descriptions are included in the Appendix titled “Earlier Reports and Other Documents". The information was quite dis- parate in presentation, depth of treatment of the subject and findings. Although the results of all the reviewed project documentation varied in fairly significant degrees, they all agreed on one thing. The costs of constructing the intertie line, regardless of the method and materials used, is very high. Main- tenance and operation aspects of the line were addressed only peripherally ina few areas of the earlier documents. The earlier efforts, while never stating in direct terms, found the long-term survival of this line highly questionable and quite problematical. The earlier studies also demonstrated that no single route is specifically advan- tageous or superior when compared with any other proposed routing. Soils and conditions are uniformly poor in all places where the new intertie could be con- structed. Detours to route the line through more stable soils results in lengthening the distance the line must run. The results end up about the same in terms of costs. 3.2. REVIEW MANOKOTAK’S EXISTING ELECTRICAL SYSTEM A field trip was made to Manokotak and extensive work was conducted to determine the revisions required to interconnect the Village’s system with a potential in- tertie from Dillingham. Other issues were also identified at that time. Specific conclusions, recommendations and cost estimates were presented in a report to the APA published on September 15, 1988. That report is independent of the investigations and evaluations conducted for this study and the costs to upgrade the Manokotak system and abate the identified hazards in that system are not included in the economic considerations presented here. 3.3. REVIEW DILLINGHAM’S SYSTEM The Nushagak Electric Cooperative, Inc. (NEC) in Dillingham has sufficient gener- ation reserves to accept the approximately 175 KW additional load the entire vil- lage of Manokotak would bring to the system. The NEC system as it related to this possible intertie was the subject of a meeting held in Dillingham with Mr. Dave Bouker of NEC immediately following the field review visit to Manokotak. Some possible problems were identified during those discussions. Pertinent rate schedules were requested and the approximate costs for NEC to connect to the in- tertie were also discussed. 3.4. ANALYSES OF MANOKOTAK’S AND NEC’S SYSTEM Using the information provided by APA, in conjunction with notes, interviews and photographs obtained during the field review of the Manokotak system and the dis- cussions with NEC, a few possible scenarios for the new transmission line were developed to the conceptual level. After refining these conceptual schemes, the generic materials necessary to construct the proposed line were defined. Finally, the initial costs of the selected methods were estimated. The two schemes selected for analysis and evaluation were analyzed for reasonable main- tenance and operating costs in order to more accurately estimate the true life- cycle amounts for each type of line. The Manokotak and Dillingham systems were only addressed relative to the intertie line and its proposed configuration and characteristics. 3.5. METERING PLAN AND OWNERSHIP RECOMMENDATIONS Various combinations of ownership and how specific metering arrangements were in- vestigated. None of the proposed schemes proved particularly advantageous over any other. 3.6. POSSIBLE SAVINGS TO STATE AND VILLAGE CONSUMER The costs of power in both communities was researched. The life-cycle costs of the proposed intertie were calculated. The life-cycle costs were then factored into the base rates of NEC’s charges for energy to determine the actual price of power delivered to the Village. There were other calculations which pro-rated certain costs and resulted in different values. 3.7. LAND STATUS AND PERMITS REQUIRED Various agencies and publications were consulted in an effort to determine all the applicable parameter within this catergory. After the basic identification of those entities which might have interests in the areas surrounding the vil- lage, near Dillingham or along the proposed routes for the construction, phone calls were made and offices visited in order to confirm those items affecting the installation of the transmission line. 3.8. COST ESTIMATES In order to produce conceptual level cost estimates for this Project, certain as- sumptions were necessary. In some cases, the assumptions were required as part of the "standard" design that would remain common to any intertie line. A good example of that type of criteria would be total line length. In all cases, the equipment at each end (reclosers, etc. in the NEC plant, transformers and other items) was considered to be the same costs for each alternative. Only two ap- proaches for the transmission intertie line were considered - an overhead line using relatively conventional construction configurations and materials and an underground line. Other basic assumptions made during the course of this evaluation and applicable to each of the possible alternatives were a. The rights-of-ways could be obtained from all entities and no alternative would be monetarily penalized for difficulty in achieving agreements for rights-of-way. b. All permits could be obtained by the Contractor within the construction of this Project and would be the same for each of the alternatives. Costs of such permits are not identified separately in this study. Cc. The transmission line in each case would connect at the termination of the Manokotak Heights Subdivision system’s pole nearest the point where the in- tertie approaches the Manokotak Heights’ system. d. Systems must be standard construction for the voltage and method of instal- lation proposed. For instance, overhead lines must use REA standards and line construction materials and configurations found in their standards for the proposed transmission voltage. e. The system must be capable of possible expansion and arranged so it may be easily extended at some future date should other interties become viable. 3 if The losses inherent in the transmission line are included in this study’s cost data as part of the ongoing cost of the installation and its opera- tion. g. Power rates for the energy delivered to the individual Village consumers by this line are calculated without regard to subsidies from any source. The inverted structure presently used by NEC for invoicing industrial customers of load sizes similar to this one is used in determining the costs for the system losses. All kilowatt-hours delivered to the Village at its point of interconnection within the Village system are considered to be priced the same regardless of quantity. The charge is calculated as a flat rate in present worth dollars. The life of the line for the purposes of this study is assumed to be 2% years. 4. ANALYSES AND EVALUATIONS 4.1. REVIEW OF FURNISHED PROJECT DOCUMENTATION A number of common items are found throughout the existing documentation fur- nished for review. There is repeated reference to the bad soils, high water tables and marginal conditions of the terrain between the Village and Dillingham, for example. There appears to be agreement that costs of construction, operation and maintenance will be relatively high. There are pervasive concerns about the long-term survival and short-term reliability of any type of transmission line that traverses the area between these two communities. This investigation and evaluation of the conditions uncovered no new data that would ameliorate these negative factors. 4.2. MANOKOTAK’S ELECTRICAL SYSTEM An extensive investigation and evaluation of the existing generation and dis- tribution system and equipment in the Village of Manokotak has been accomplished. The findings, recommendations and cost estimates resulting from that effort are contained in a report submitted earlier to the Alaska Power Authority. Relative to the requirements for this study, the Village’s generation system is adequate for the new Manokotak Heights Subdivision loads and for any foreseeable addi- tional loads. The distribution system, however, is only marginally acceptable for its present use and should be the object of a major upgrade. The installa- tions violate provisions in the National Electrical Code and the National Electrical Safety Code. Some of the existing situations constitute hazards to people and property. The system should at least be adequately and effectively grounded for safety. It may prove worthwhile to expend funds to renovate the Village’s existing systems and distribution rather than build an intertie that will terminate in this marginal system. Currently, the flat rate charge assessed consumers within Manokotak is $9.39 per KWH. There is no demand charge. Total annual KWH generated in the period of January, 1987 through December, 1987 was 549,866. The amount paid for fuel was $41,988.69. The cost for fuel during this period was $1.97 per Gallon. There- fore, 549,866 KWH were generated using 38,499 Gallons of fuel. Those numbers yield 14.988 KWH/Gallon, indicating a very efficient system. A report was 4 recently completed by Fryer/Pressley Engineering under a contract with the South- west Regional School District that determined the use of waste heat from the ex- isting generation units in the Village of Manokotak could be potentially economi- cally feasible to aid in heating the school, even though that heat had to be transported via pipeline some 199% (+) feet to the school complex. To recap the major points discussed above, the generation plant in Manokotak is operating efficiently. The distribution system is in need of a major upgrade. There are serious hazards and deficiencies within the system that must be cor- rected before they lead to injury, death or catastrophic failure and property destruction. 4.3. COSTS TO NEC TO IMPLEMENT INTERTIE This analysis begins by making the assumption NEC will not participate in the funding of any portion of construction of the transmission intertie between its facilities and the termination point selected at the Village of Manokotak’s power distribution system. The corollary of that assumption is also assumed to hold true. It is assumed NEC will provide equipment and connections from its genera- tion and distribution system to the intertie once the line is installed and ready for energizing. A final assumption places NEC in the role of operating and main- taining the transmission line once it is commissioned and acceptable to them. This role may be funded through agreement between NEC and whomever owns the transmission line or other arrangements, but it seems only logical to have NEC operate and maintain the installation. Costs that NEC will incur as a result of supplying power through this new line include equipment at the generation plant, reclosers, regulators (if necessary), controls, monitoring, metering and extensions of existing buses and lines for in- terconnection. In addition, the losses which will occur in the transmission line will have to be recovered. The simplest way to insure those losses are ac- curately measured is to meter the transmission line at the point in NEC’s system where the connection to the Dillingham end of the intertie is made. There may be other costs to NEC, as well. Among possible other costs are upgrading certain portions of the existing distribution system in order to increase the capacity of the system to the point of connection to the new line, revising existing service connections to balance the loads on affected feeders after the new line is in operation, lost revenue during the downtime necessary to make the revisions within the system and administration costs. For this study, however, only the simplest costs were considered. A life-cycle costs analysis of expenses and annual costs was conducted. It was assumed there would be $59,909.98 in required capital costs, yearly losses in the impedance of the transmission line and there would be annual costs for NEC to maintain the transmission line. The results of that calcualtion are included in this report in the appendixD. Life Cycle Cost Analyses. The result of the calcualtion indi- cates the costs to NEC of this transmission line is $32,986.9% annually without including any costs for maintenance of the intertie. If it is assumed the same base rate for power were charged at the point of delivery to the new intertie line termination point in NEC’s system and all these costs must be recouped ina flat rate KWH charge to the consumers in the Village of Manokotak, the base KWH rate must be increased by at least $8.961 per KWH over the base charge NEC as- sesses its present large power consumers. These costs were considered to be about the same for any selected intertie construction, routing and configuration. 4.4. METERING PLAN There are several approaches to metering the energy proposed to be delivered by this Dillingham/Manokotak intertie. The three basic metering installations con- sidered practical for these circumstances consist of: * Master metering in Dillingham at point of connection of the intertie and NEC’s system. Master metering at the point of connection where the intertie and the Village’s system join. Individual user metering at the point of consumption within the Village of Manokotak or wherever energy is tapped from the line. A brief discussion of pros and cons of each type of metering installation is presented here for consideration. a. Master metering in Dillingham With the master meter located at this point all line losses will be included in the measured consumption, eliminating all conjecture about the efficiency of the transmission line and allowing exact revenue to be calculated to offset losses. If it were deemed appropriate to invoice some other fund for the losses or to quantify the losses for seasonal rate adjustments, a second master meter could be located at the Manokotak end of the line. b. Master metering in Manokotak The issues resulting from only bulk metering at the end of the line in Manokotak touched upon in 1. above. However, due to the nature of the losses in the line the revenue to be recouped for NEC due to those losses would undoubtedly be the subject of negotiation. It seems if master metering is the chosen solution, there should be two points of master metering as suggested in proposal 1. above. Again, it should be pointed out that such metering means that neglecting to make a payment could result in the entire power supply to the Village of Manokotak being interrupted. The Village would be placed in the role of reseller and col- lection agency for energy in this scenario, just like in number 1. above. c. Metering Individual Users There are distinct advantages to using point-of-use metering. Recording the ac- tual energy consumed by any entity allows the assessment of that use. Conserva- tion measures may be implemented to reduce consumption and costs and the effects can be almost immediately assessed. Only those entities desiring and utilizing electrical service must pay for it. Under schemes 1. and 2. above, every Village member subsidizes the cost of electrical energy directly or indirectly whether or not he is connected to the system. The default of an individual customer will not result in the entire Village being disconnected from the power supply. There is some (albeit small) amount of control that can be exercised by the utility personnel over the abatement or cessation of hazardous installations or utiliza- tion practices. For example, the utility company may refuse to serve or continue service to a user that has a hazardous service installation. 4.5. OWNERSHIP RECOMMENDATIONS The complete costs of constructing the intertie must be guaranteed and paid by some entity other than the Village of Manokotak or Nushagak Electric Coop., Inc. The economics reveal that recovering the costs of the intertie’s construction within the rates charged to consumers will not be reasonable. The life-cycle costs in the appendix D. Life Cycle Cost Analyses show clearly that the cost of power to the individual Villagers would more than double for at least twenty years in order to amortize the construction of the line. This result indicates the high costs of the intertie cannot be justified on economic grounds. There- fore, if the line is to be constructed the capital costs must be borne by some other agency or entity and cannot be part of the rate structure. However, the Owner of the line should contract with NEC for maintenance of the intertie. The costs of the intertie’s maintenance is also reflected in the life-cycle costs contained in the appendix D. Life Cycle Cost Analyses and can be part of the proposed rate structure. Including this maintenance costs for the intertie in the rates still resulted in some savings to users in Manokotak. Due to high probability of failure of this transmission line, the ownership should remain vested in the constructing agency for a minimum of 5 years to determine the long-term survival characteristics and the true costs of maintaining the line in operation. If it can be determined the line will survive for the remainder of the 29% years’ programmed life at the end of that initial 5 year period and main- tenance costs are not exorbitantly high, then the line could be transferred to the Village of Manokotak or to Nushagak Electric Coop., Inc. Preferably, NEC would own the line since it would be easiest for them to continue in their role of maintainer of the intertie. However, if by that time, the presence of power along the route has resulted in interest in development along the power line cor- ridor or nearby, it may be advantageous for the Village of Manokotak to purchase the line in order to gain some leverage over any development which might occur within their area of influence and/or control. 4.6. DETERMINE POSSIBLE SAVINGS TO STATE Analysis of the life-cycle costs of the proposed intertie between Dillingham and Manokotak shows there will be no savings to the State of Alaska if this line is constructed. The resulting costs for electrical energy to the individual con- 7 sumer would be so high as to encourage disconnecting one’s facilities from the intertie and generating power on-site. Only if the costs of installing and con- structing the line are ignored are there any savings to the individual Villager. Even then, the savings can only be classified as moderate and the State would never be able to justify the costs of the intertie through reduction in payments made to Villagers under the present PCE legislation. The net results from apply- ing life-cycle cost analysis to the construction of the intertie clearly show the PCE incremental savings would be quite small compared with the large annual costs of the transmission line. 4.7. DETERMINE POSSIBLE SAVINGS TO THE CUSTOMER The flat rate the consumers in the Village of Manokotak have been charged per KWH historically is $%.38. The equivalent price per KWH for the same amount of KWH the entire Village used in 1987, if they had been purchasing power from NEC at the large customer rate used for Kanakanak would have been $%.1995. However, the additional costs to connect the intertie line to NEC’s system must be added to. this equivalent rate to make the comparison valid. From the life-cycle costs in the appendix D. Life Cycle Cost Analyses, the additional annual costs of $32,996.69 must be recovered in the rate structure. Using the same total KWH for 1987 as used above, the rate would have to increase by $#.%61 per KWH to recoup the expenses. Therefore the new rate (without considering the cost of the intertie’s construction or on-going maintenance) for the Villagers would be $2.2695, a savings of $$.6395 per KWH for consumers in Manokotak. These calcula- tions were based on bulk metering of the energy transferred from Dillingham to Manokotak. If individual metering of each user was installed, it must be assumed the equivalent cost per KWH would be higher. The net savings (again using the total consumption of 548,886 KWH in 1987) for the entire Village would be $21,365.69. It must be remembered these calculations do not include the con- struction or maintenance of the new intertie. If those costs were added to the rate structure in an attempt to amortize the line costs over 29 years, the equiv- alent rate would have to rise to $%.69%85 per KWH consumed. If one takes the stance that this study and its results are only 1/2 right or twice as pessimistic as reality, the new rate would still have to be $%.445 per KWH, an increase of almost 5% % over the present rate charged consumers in Manokotak. 4.8. DETERMINE LAND STATUS AND PERMITS REQUIRED a. LAND STATUS The gamut of ownership of the land this intertie could cross is wide and varied. The area around Dillingham and along the road to Kanakanak is almost exclusively held by private parties. As the distance from Dillingham increases, the land comes under the purview of the Department of Interior, United States Fish and Wildlife Service because it is contained within the boundaries of the Togiak Na- tional Wildlife Refuge. As one approaches the Manokotak township, the land is controlled by the Bristol Bay Native Corporation and the Village native governmental entity, Manokotak Natives Ltd. Finally, within and near the area of the Village proper the land control is vested in the Second Class City of Manokotak. The interests of the USFWS overlay the Bristol Bay Native Corp., Manokotak Natives Ltd. and the City of Manokotak. It is only the vicinity near Dillingham that is not influenced by the policies of USFWS. 8 Preliminary discussions with the USFWS indicate that routes which traverse greater distances across wetlands are less desireable than routes which do not traverse. That philosophy would tend to favor routes more to the south as they cross Refuge property over the more northerly routes. However, the soils to the south of the Refuge are worse (less stable) than possible northern routes. USFWS personnel stated that rates and rights-of-way are normally set by the USFWS for construction within their areas of control. Other holders of claims or rights to property are then apportioned parts of any payments required based upon their share of ownership. It appears that, depending on the intertie’s chosen route, design and construc- tion will have to be approved by Ms Department of Interior, US Fish and Wildlife Service = Bristol Bay Native Corporation - Manokotak Natives Limited * City of Manokotak * Private landowners where applicable. b. POSSIBLE PERMITS REQUIRED TO CONSTRUCT THE INTERTIE Research of the agencies and regulatory bodies which may require one or more per- mits or submittals for construction, operation and maintenance of this proposed intertie transmission line resulted in the following list of contacts. 4.8.1. State of Alaska State of Alaska 1) Division of Policy Development and Planning Contact: Office of Coastal Management Division of Policy Development and Planning Office of the Governor Pouch AP Juneau, Alaska 99811 Phone 465-3549 Permits or Submittals: Submit Project Description 2) Alaska Department of Fish and Game Contact: Regional Habitat Protection Supervisor Alaska Department of Fish and Game 333 Raspberry Road Anchorage, Alaska 99591 Phone 344-9541 Permits or Submittals: Waterway/Waterbody Use Request Critical Habitat Area Permit Anadromous Fish Protection Permit 10 Department of Natural Resources Contact: Division of Land, Forest and Water Management Department of Natural Resources 323 East 4th Avenue Anchorage, Alaska 99591 Phone 279-5577 Permits or Submittals: Conditional Use Permit Miscellaneous Land Use Permit Rights-of-way or Easement Permit Special Land Use Permit 4.8.2. Federal Federal 4) United States Department of Interior Contact: Superintendent Bureau of Indian Affairs P.O. Box 347 Bethel, Alaska 99559 Phone 543-2726 Permits or Submittals: Rights-of-way or Easement Permit Submit Survey and Owner’s Consent United States Department of Interior Contact: State Director Bureau of Land Management 701 C Street Box 13 Anchorage, Alaska 99513 Phone 271-5966 Permits or Submittals: Submit Application Submit Description of Power Plant Submit Number of Customers Served Submit Route Description Rights-of-way or Easement Permit 11 6) United States Department of Interior Contact: Togiak National Wildlife Refuge Refuge Supervisor US Fish and Wildlife Service 1911 East Tudor Road Anchorage, Alaska 99593 Phone 276-3899 Permits or Submittals: Special Use Permit 7) Corps of Engineers Contact: U. S. Army Corps of Engineers Alaska District Regulatory Branch P.O. Box 898 Anchorage, Alaska 99596-9898 Phone 753-2712 Permits or Submittals: Navigable River Crossing Permit Wetlands Permit There may be other permits and approvals required at the local level of which the only records would be the original charters which formed the various groups that may control certain areas along the selected intertie route. There is no way to determine the fees that would be charged for the permitting process since many of the agencies which would be in that process have no fixed fees and their charges are based on the amount of work they are required to accomplish prior to granting approval. It is, however, estimated the costs of the work necessary to prepare and comply with all the information requests forthcoming during the process of obtaining all the permits and approvals necessary for the construction and opera- tion of the intertie will be about $15,999.96. This amount would accrue to the project expenses prior to beginning the design. It is not unreasonable to assume the cost of design would be in the neighborhood of $59,929.99 to $166,909.96 depending on the responsibilities defined for the designing firm. The cost es- timates presented below do not include the costs of preparing data for securing permits ($15,990.98) or for design ($5%-$60,969.9%). There would be other costs for the administration of the Project by APA and for monitoring the construction of the intertie. 12 4.9. COST ESTIMATES The cost estimates which appear as the final section of this report were based on some specific assumptions made in order to assess the probable magnitude of costs for this intertie. It is apparent the cost of this transmission line, regardless of method or routing of its installation, will be quite high. The installation has a relatively high probability of failure before it reaches the end of its program life even when special construction techniques are implemented to over- come the poor soils and other conditions detrimental to the long-term survival of the transmission line. Additional measures implemented in the construction to increase the likelihood of survival would at least double the already high es- timated costs of installation. The estimates are based on what would normally be categorized as installation of power lines in marginal soils and premium costs for additional effort and materials necessary to place power lines in poor soils are included. Unusual or unforeseen conditions are not included in the es- timates, but the chance of encountering strange or conditions significantly worse than the ones assumed for estimating would seem to be quite high. It must be noted the life cycle cost analyses were accomplished using the lowest estimated costs of construction of several which were developed for this Project’s analyses. The estimated costs ranged from the indicated low of about $1.2 Mtoa high of around $3.2 M. The approximate figure which seemed to engender the most confidence was near $2.8 M. It is obvious that a Project which is not feasible when the lowest possible estimate is used, is not feasible if a higher cost is estimated for its initial construction. 4.9.1. Assumptions for Overhead Line Assumptions include OVERHEAD LINE/CROSSARM CONSTRUCTION - 3 PHASE, 4 WIRE, 12.5 KV ~ Total intertie length is 18 miles (very conservative - could be as long as 25 (+) miles depending on chosen route) * Typical REA pole line installation * Greater than ordinary setting depth for poles * Each pole will require a minimum of 5 yards of NFS compacted backfill * Ruling span will be relatively short (estimated about 275’) Some spans will require special treatment to prevent galloping and other possible resonance behavior * #1/% ACSR must be used for strength * Every pole will be butt grounded Poles will be set in augered holes 1S) Screw anchor guys will be used where necessary (assume minimum of 19 guys per mile) Rights-of-way and easements are granted with no costs to Owner All work is competetively bid and constructed by one contractor within one project (no alternates or phases) 4.9.2. Assumptions for Direct-bury Cable DIRECT-BURY CABLE INSTALLATION - 3 PHASE, 4 WIRE, 12.5 KV * Total installed cable length is 15 miles (very conservative - length could be 25 (+) miles depending on chosen route) * #1/% Aluminum is used for voltage drop/cost considerations No spare cable or conductor is included in cost estimate At least one pulling cabinet, sectionalizer switch or other grade structure is necessary per mile of cable * Cable is bedded in 6" of sand and covered with 12" of sand At least 590% feet of flexible pvc duct or other protective outer sleeving is required for unusual circumstances during the cable’s installation PVC coated galvanized rigid conduit will be installed to protect entrances and exits of cable at grade structures * Concrete saddles will be necessary for the river crossings * Rights-of-ways and easements are granted with no costs to Owner a The Project is competetively bid, awarded to one general contractor and is constructed all at once (no alternates or phases within the Project) 5. RECOMMENDATIONS The primary recommendation which immediately results from assimilating all the data presented herein is the intertie is not economically feasible as a sub- stitute for a reasonably reliable power generation and distribution system within the Village of Manokotak. However, if there are other reasons to build the in- tertie, then it is recommended the overhead line be chosen as the method of in- stallation. It is felt the maintenance aspects of the overhead installation are superior to those of the underground line since the major components of the sys- tem are readily accessible without resorting to excavation (most likely impos- sible during certain periods of the year). It is also fairly certain that soils, water tables, frost lines and active layers are constantly shifting in this regime and accessibility means the overhead pole line can be repaired, adjusted and otherwise revised as the need becomes apparent. 14 It is recommended that 3 phase, 4 wire 7.2/12.5 KV service be the selected con- figuration of the transmission intertie. Even if only single phase was required during the initial operating years, future considerations and the extreme dif- ficulties involved in installing new hardware on the transmission structures means it would be a prudent measure to have the capability to upgrade the system to the higher voltage level simply and without additional construction along the power line. The presence of power along the power line corridor may lead to development in areas currently deemed difficult to improve or use. Such develop- ment may require significant levels of energy from the transmission line cur- rently not considered in the economics of this study. It would be unfortunate if the transmission line proved to be the negative factor which doomed a promising enterprise in this region because it could not supply the required power so es- sential to economic development. 15) 6. ESTIMATED COSTS FOR INTERTIE CONSTRUCTION 6.1. Estimated Costs Item Description Costs($' 999s) 6.1.1. For Overhead Line us Class 4, 35 ft. Pole, Min. 6 ft. long crossarms, hardware, normally set, 19 poles per mile x 18 miles = 342 poles @ $1599.89 each $ 513.9 25 Increase setting depth by at least 3 feet, each pole requires compacted NFS backfill for stabilization, includes special handling & equipment $759.86 per pole x 342 poles 256.5 3. #1/%8 ACSR - $1258 per 1996 ft. x 5.28 . 1996 ft. per mile x 18 miles x 3 wires 297.8 4. #6 SDBC - 35 ft. of #6 per pole for grounding x 342 poles x $ 625/199% ft 7.5 5. 2 transformers (1 step-up & 1 step- down) with pole platforms and hardware 35.9 Total $1199.98 6.1.2. For Direct-bury Line ue Trenching (18 miles x 528% feet per mile= 95049 feet) @ $5.94 per foot $ 475.2 an Sand (Assume at least 2 feet wide trench & 1 1/2 feet sand depth in trench x 95949 feet) 19568 yards @ $35.9% per yard, in place 369.6 3. 1 box, switch or other grade structure per mile at $3996.6% each, in place 54.9 ft 5909 feet of flexible pve conduit 25.8 5. 95049 feet if 4 #1/8, 15 kv cable 389.2 6. Backfill and compaction 199.9 Total $1494.98 16 Appendix A. DOCUMENTS REVIEWED FOR THIS REPORT Ue May 28, 1985 Mr. Robert E. Dryden (Dryden & Larue) letter report to Manokotak Village Council describing generation and distribution system’s deficiencies. February 4, 1986 Mr. Adelheid Herrmann (Representative, District 26) letter to Alaska Power Authority referring to mutual interests in a possible transmission line in- terconnecting the Manokotak electrical system with the Nushagak Electric Cooperative, Inc. system in Dillingham. February 14, 1986 Mr. Peter Hansen (APA) and Mr. Tanzeem Rizvi (APA) memorandum to file describing field trip to Manokotak February 4, 1986. April 2, 1986 Mr. Earle Ausman (Polarconsult Alaska, Inc.) letter with preliminary proposal to perform feasibility study to APA. May 1, 1986 Mr. Earle Ausman (Polarconsult Alaska, Inc.) letter to Mr. David Bouker (Nushagak Electric Cooperative, Inc.) requesting Mr. Bouker’s suggestions for routing the proposed intertie line. May 6, 1986 Mr. Peter Hansen (APA) letter to Mr. David Bouker (NEC) outlining the basic feasibility study and related work surrounding the proposed Dillingham- Manokotak intertie. May 24, 1986(Estimated) Mr. Peter Hansen (APA) field trip report describing observations and recom- mendations resulting from field trip to Manokotak and Dillingham May 21 and 22, 1986. UU 19. 11. 12. 13. 14. 15. June 26, 1986 Mr. Earle Ausman (Polarconsult Alaska) letter to APA transmits 1 copies of their completed feasibility study analyzing the Dillingham- Manokotak in- tertie. August 13, 1986 Gwen Obermiller (APA) memorandum to Mr. Peter Hansen (APA) containing sum- mary of comparisons made among 5 alternative approaches to the construction and maintenance of the proposed transmission line. March 12, 1987 Mr. Don Shira (APA) letter to Mr. David Bouker (NEC) transmitting a copy of the final Polarconsult Alaska June 26,1986 report. June 16,1987 Mr. Robert E. Dryden (Dryden & Larue) letter report to Nushagak Electric Cooperative, Inc. containing results from their review of the Polarconsult Alaska June 26, 1986 feasibility study. December 2, 1987 Mr. Thomas D. Humphrey (Humphrey Company) letter to Mr. Brent Petrie (APA) requesting he be copied with all relevant material concerning APA’s power system work within the area of Manokotak or that might otherwise affect Manokotak. December 7, 1987 Mr. David F. Bouker (NEC) letter to Mr. Adelheid Herrmann (Representative, District 26) documenting reservations and concerns NEC had about the proposed intertie. March 15, 1988 Mr. Peter Hansen (APA) memorandum to Mr. Brent Petrie (APA) relating a phone conversation Mr. Hansen had with Mr. Moses Toyukak of Manokotak on March 8, 1988. June 22, 1988 Mr. Don Shira (APA) letter to Mr. Mark Fryer (Fryer/Pressley Engineering, Inc.) requesting a proposal to conduct a feasibility study of an intertie between Dillingham and Manokotak for power transmission. 18 16. 17. August 11, 1988 Mr. Mark Fryer (FPE) letter to Mr. Don Shira (APA) outlining tasks and budgets for the analyzing the Dillingham to Manokotak intertie. September 15, 1988 Mr. James R. Pressley (FPE) transmits 2 copies of the report "Manokotak Electrical System Review" to Mr. Don Shira (APA). 19 Appendix B. POWER SYSTEM DATA 20 [dn oko tek Oyo ten Keeten RAYA - FE0O32. lofjo/s8 io / Cer/ of /anckofeh Genevatm Fee hy, l¢ ABI -SOE2Z cr ble C Lee often Vii per weeeorrs) _ ee Ashe abort —cercent producion _gcosts, # Latest Pyures Ai «lhe a Oe fer KWH _ belvre —geheche echoes aL, apghed. Lolest frel_-casts fron _B-9-8% _, 351@ gallons Gee ead _ C$/07 = $41 088. ae cree : Eners, use. proble:: sti Rt ia Mh nase =a Jo. 87 61 746, Feb $1,282 Marcel 56, 620 Ap-il 51,184 Moy ease oe st Jone al ¢ Generalers were not gperakiimel | Tuly — | August 73 4&7 | September 52/03 rea Ob 7 OSS Tele eer eee IE ea Dec. Oe O13 : ee : ee eee Le talal 7 SO, BAO RU ee ee | There are no eect _walves ee ae) gti BE ea al, NUSHAGAK ELECTRIC CO-OPERATIVE, INC. P.0. BOX 350 TELEPHONE (907) 842-5251 DILLINGHAM, ALASKA 99576 * %* TELECOPIER (907)842-2799 * * ' Telecopy Transmittal Sheet (Transmitting from Canon FAK-610) TO: ie -Heasley H Attn: FAX Number: S6/ Ore Besa | ens sese |e |||) | ara 2ofelee ; TIME: ingl. this page) FROM: M_E. 8 S$ A GE Aa pene thie, €VCLOSED LATE sscHEDute B PART K Wich Re4ATe, 7 MSATAL AT KAW ACA: AVE DertAWwd Fre ssh wit WW 16 FE 9S 267.6 Eo MOF, Joa Cseees Ae cen MY trescrey 4s! )\. TE K-CRO 1S NEGATIVE FICuRE oe %0.2924 Fer kw Ae pee Ker. Hive” ALSO ENCLOSED COPY OF Hered Fore JU ke TAvercH =| JSenry hse 7 Sash) KAbWLES JEGPE ies prt Wets- AF VYHERE ARE ANY PROBLEMS WITH THIS '(RANSMISSION, PLEASE CALL: (907) 842-5251 OR (907) 842-5295 APUC No, 45 Tenth Revised Sheet No, —_—_— Cancelling: Ninth Revised Sheet Ho. NUSHAGAK ELECTRIC COOPERATIVE, INCORPORATED SCHEDULE B AVAILABILITY: Available for commercial, ‘industrial, three-phase residential consumers and public facilities. TYPE OF SERVICE; Single-phase and three-phase, 60 cycles, at‘available secondary voltages. ¢ Pak foRAe= 02.924 a ku RATE (Subject to fuel adjustment clause): As oF /o/z/yx rv Part A. When billing demand is less than 20 KW. Energy Charge: First $0 KWH per month at 32.24 cents per KWH ibd Next 50 KHH per month at 24.11 cents per KWH ;7 ok Next 2,900 KWH per month at 20.63 cents per KWH ee) Over 3,000 KWH per month at 18.89 cents per KWH 5932-1 When billing demand is 20 KW or more, charge all kW at $4.06 per KW of billing demand. Energy Charge: D Os First 5,000 KWH per month at 20.05‘cents per KWH 97" Next 20,000 KWH per month at 18.89 cents per KWH n/| Over 25,000 KWH per month at 17.73 cents per KWH Part B. MINIMUM CHARGES: The monthly minimum under the above rate shall be $16.12, the demand charge, or the contract minimum under the line extension D policy, whichever is greater. POWER PRODUCTION COST ASSISTANCE: These rates for local community facilities and charitable organizations are eligible for power production cost. assistance in an amount per KWH identified on Tariff Sheet No. 31, Tariff Advice No, 83 _ Effective: NUSHAGAK ELECTRIC COOPERATIVE, INCORPORATED Y General Manager aururr oo autor @ FOr S*LIL9L B4LIL79 NUDOHGHR LU Ur> es June 10, 1988 To: Susan ee Fron: wichaet\Y%deria, doe ot Engineer IV, APuCc Jerry Larson fe rot Rural Projects, APA REN Subject: Efficiency c tandards for PCE Eligible Utilities On May 5, 1988, the Alaska Power Authority (APA) and the Alaska Public Utilities Commission Staff (APUC) prepared a joint memo~ randum of understanding that outlined both agencies policy con- cerns regarding the Power Cost Equalization (PCE) program. The memorandum of understanding included a provision that the en- gineering staffs of both agencies determine efficiency standards for rural electric utilities that participate in the PCE program. Mr. Michael Tavella of the APUC Staff and Mr. Jerry Larson of the APA Staff were assigned the task of producing the efficiency standards. An inefficient system translates into excess fuel being burned to produce a given quantity of electricity, which increases the to- tal cost to the state. It is a goal of both the APA and the APuUC : Staff to effect an increase in system efficiency throughout the ' state. To that end, we believe that the following standards are appropriate: Thermal Efficiency A diesel engine-generator set has an overall thermal efficiency or heat rate that is expressed in KWH per gallon of fuel. All engines have thermal efficiency limits that can not be exceeded, based on the laws of thermodynamics, For diesel engines, the theoretical maximum efficiency in KWH/gal is approximately 15.5 kwh/gal. This means that no diesel engine can operate with a higher heat rate than 15.5 kwh/gal and that practically, diesel engines will operate at a somewhat lower level than 15.5 kwh/gal. In many instances, larger rural villages and towns have efficien- cies in the 12-14 kwh/gal range. Practically speaking, however, in the smaller villages, efficiencies in this range will take some time to achieve because many of the smaller villages have engine-generator sets that are not sized properly to the load; they lack experienced operators and maintenance personnel; and the engine-generator sets are not technologically current. Based on these considerations, we believe that the efficiency that can be reasonably obtained for all villages is 10 kwh/gal when using No. 1 arctic fuel. In many cases, village utilities are not presently achieving this level. We propose, therefore that a two year compliance period be instituted to enable these villages to get assistance and to make the changes needed to bring up this level. During this period, the Commission could establish a sliding scale of efficiencies to allow some relief for the smaller utilities. We have attached a schedule, as ex~- hibit A, showing two different scales that might be used, along Appendix B -1i- R-88-6 (1) with an explanation of each scale. In both cases, we believe that the initial efficiency should be established at 8 kwh per gallon or above. System Line Losses There are line losses inherent in every electric system. A well. maintained system will have a typical line loss of approximately 9 to ll percent. Line losses can vary considerably; although Petersburg and Cordova have cut line losses to less than 5 per- cent, line losses have been recorded as high as 50 percent or more in some villages. Occasionally, the utility has actually "sola" more KWH than it produced. The causes for high line losses are two fold: first, the system itself may be improperly configured or operating in an overloaded state. Because line losses are a function of the current squared and the resistance of the conductors, a system that has small diameter conductor and high loads (i.e. high current flows) will have a higher loss level. For the mast part, however, system configuration and condition is not the primary cause of line los- ses. We believe that in most cases, high line losses (the dif- ference between kwh generated and sold divided by kwh generated) are due to poor or nonexistent metering or improper meter read- ing. Metering is a highly specialized art that is subject to a variety of errors, including improper installation, improper reading, and failed or malfunctioning meters. In fact, Peters- burg and Cordova have just completed a two year intensive mater-= ing inspection and correction program, which played a major role in reducing the line loss to less than 5 percent. Based on this analysis, we believe that for PCE calculations, the system line losses should not exceed 10 percent. Station Service Losses Another component of utility operations is station service power. This is power used by the utility to provide lights and heat within its buildings, and power to operate equipment and machin- ery within the plant. We believe that the station service use should not exceed 1 percent of total generation (this 1 percent station service figure is included in the overall 10 percent overall system loss discussed above). The problem with station service efficiency is than in many cases, station service use is not metered, making it impossible to determine the station ser- vice use. : Implementation Suggestions Although not directly requested, we offer some suggestions on how these efficient standards can be implemented, On thermal ef- ficiency, we believe that a sliding scale on PCE can be developed in that the assistance level increases as the efficiency in- creases, This can be accomplished by reducing the initial PCE assistance level by imputing an efficiency of 10 kwh per gallon on utilities with poor efficiencies. As the efficiency improves, the PCE level would remain constant although the efficiency would increase. An alternative would be by offer an incentive for higher efficiency. Another alternative could be to offer a 5 percent incentive "bonus" to utilities that use waste heat to increase thermal efficiency. Unfortunately, even with incentives, these standards cannot be implemented without extensive technical and financial assistance. In many cases, engine-generator sets will have to be replaced with units properly sized to the load. Metering installations will have to inspected, repaired and, if needed, installed for the first time. Finally, thé villages will need more training to ensure that generating plants are properly maintained and oper- ated and that meters are working and are being read properly. &e Exhibit A Method 1 is simply to select a reasonable efficiency level to begin the compliance period. We are recommending 8 kwh per gallon for the initial efficiency level, which would increase to 9 kwh per gallon in the second year and 10 kwh per gallon after the 2 year compliance period. The 8 kwh per gallon figure is the median value of the utilities shown in Table 3, Power Cost Equalization Summary Statistics, which is attached to the Governor's report on the Power Cost Equalization program. Out of 87 utilities, 50 % are below 8 kwh per gallon and 50% are above 8 kwh per gallon. The utilities have a fairly flat distribution between 5 and 13 kwh per gallon efficiency levels. Approximately 16 % of the utilities have an efficiency less than 5 kwh per gallon. ; The second method would be to establish efficiency levels based on the level of kwh sales. For example, the Commission can establish a schedule similar to the one shown below: Utility Sales Minimum Efficiency < 100,000 kwh 8.0 kwh/gal 100,000 to 500,000 kwh :8.5 kwh/gal 500,000 to 1,000,000 kwh 9.0 kwh/gal 1,000,000 to 10,000,000 kwh 10.0 kwh/gal > 10,000,000 kwh 11.0 kwh/gal This scale can be extended or updated over the length of the compliance period. These two methods are examples only. We believe that the final method must be established through the public review process that would accompany any regulatory proceeding. Appendix C. VOLTAGE DROP AND LOAD FLOW CALCULATION 21 LOAD FLOW AND VOLTAGE DROF STUDY — AFABBOS2 DILLINGHAM/MANOKOTAK INTERTIE STUDY FRYER/PRESSLEY ENGINEERS — ANCHORAGE, ALASKA DATE: 10 21 88 TIME: 2 51 PM ALL INFORMATION PRESENTED IS FOR REVIEW, APFROVAL INTERPRETATION AND AFFLICATION BY A REGISTERED ENGINEER ONLY DAFFER (LOAD FLOW AND VOLTAGE DROF MINI/MICRO VERSION 3.3 LEVEL 2.1) COPYRIGHT SKM SYSTEMS ANALYSIS, INC. 1983 DATE: 10 21 88 TIME: 2 51 FM LOAD FLOW AND VOLTAGE DROF STUDY -— APABEOT2 DILLINGHAM/MANOKOTAK INTERTIE STUDY FRYER/FRESSLEY ENGINEERS -— ANCHORAGE, ALASKA PAGE 2 FEEDER DESCRIPTION FEEDER FROM FEEDER TO NO NAME NO NAME /PH L=-L MTRS SIZE TYPE DUCT INSUL 1600 NEC PLANT 200 MANOKOTAK 1 14000, 95040, 1/0 A N IMPEDANCE: -1682 + J .1076 OHMS/1000 M DATE:10 21 88 TIME: 2 S51 PM PAGE 4 -DAD FLOW AND VOLTAGE DROF STUDY - AFABBOS2 JILLINGHAM/MANOEOTAK INTERTIE STUDY FRYER/PRESSLEY ENGINEERS — ANCHORAGE, ALASKA 200 MANOKOTAK 160. 70. CONSTANT EKVA LOAD DATE: 10 21 88 TIME: 2 51 FM PAGE So -OAD FLOW AND VOLTAGE DROF STUDY - AFASS8OE2 DILLINGHAM/MANOEOTAK INTERTIE STUDY FRYER/FPRESSLEY ENGINEERS — ANCHORAGE, ALASKA #%% SOLUTION COMMENTS **#* SOLUTION FARAMETERS PER UNIT DRIVING VOLTAGE : 1.0000 BRANCH VOLTAGE CRITERIA : 3.00 % BUS VOLTAGE CRITERIA : 3.00 % EXACTC(ITERATIVE) SOLUTION : YES TRANSFORMERS MODELED : YES <<PERCENT VOLTAGE DROFS ARE BASED ON NOMINAL DESIGN VOLTAGES>> DATE:10 21 88 TIME: 2 51 PM PAGE é -OAD FLOW AND VOLTAGE DROF STUDY — AFABS8O32 JILLINGHAM/MANOKOTAK INTERTIE STUDY FRYER/PRESSLEY ENGINEERS — ANCHORAGE, ALASKA EALANCED VOLTAGE DROF AND LOAD FLOW ANALYSIS (SFECIAL BUS LOAD REPORT) EHR KK KK KK EAH KHER EEE HEHEHE EHS EEE ISIS IEEE SII ISERIES IKARIA VOLTAGE EFFECT ON LOADS MODELED TRANSFORMER VOLTAGE DROF MODELED fOLTAGE DROF CRITERIA: BRANCH = 3.00 % BUS = 3.00 YER UNIT DRIVING VOLTAGE = 1.0000 -GAD BUS: 100 NEC PLANT DESIGN VOLTAGE: 14000 LOAD VOLTAGE: 14000 %VD: «0 “OAD TO: 200 MANOKOTAK FEEDER AMPS: 7 VOLTAGE DROP: 227.9 ZVD: 1.70 *ROJECTED FOWER FLOW: 1463. EW 72. EVAR 178. KVA FE 292 LAGGING LOSSES THRU FEEDER: 2.6 EW 1.6 KVAR 3.1 EVA -OAD FROM: *#**# SOURCE FEEDER AMPS: 7 VOLTAGE DROF: -O ZVD: «00 PROJECTED FOWER FLOW: 163. KW 72. KVAR 178. KVA PFs «92 LAGGING LOSSES THRU FEEDER: »O KW -0O EVAR -O KVA LOAD BUS: 200 MANOKOTAK DESIGN VOLTAGE: 14000 LOAD VOLTAGE: 123762 “VD: 1.7 SPECIAL BUS LOAD: 160. KW 7QO. KVAR LOAD FROM: 100 NEC PLANT FEEDER AMFS: 7 VOLTAGE DROP: 227.9 ZVD: 1.70 PROJECTED FOWER FLOW: 160. KW 70. KVAR 175. KVA PFs 092 LAGGING -OSSES THRU FEEDER: 2.6 KW 1.4 KVAR 3.1 KVA 2 BUSES eee TOTAL SYSTEM LOSSES #** 3. EW 2. KVAR Appendix D. LIFE CYCLE COSTS ANALYSES 22 -CC SUMMARY FOR NUSHAGAE CASH REQUIREMENTS “INANCING-RELATED COSTS ANNUALLY RECURRING O&M COSTS NON-AN. RECURRING O&M COSTS ENERGY COSTS *ROFERTY TAXES REPLACEMENT COSTS LESS: TAX ADJUSTMENTS TOTAL LCC (WITHOUT TAX ADJUSTMENTS) TOTAL LCC (WITH TAX ADJUSTMENTS) *RESS “<ENTER> TO CONTINUE? LECTRIC INTERTIE COSTS PRESENT VALUE £0 £40,447 £197,751 €11,771 £133,060 $4,765 £125,824 £16,376 $525,619 £507,244 ANNUAL VALUE £0 £3,921 £12,180 $764 £8,432 $509 535,968 £32,906 BUILDING CHARACTERISTICS FILE TILE NAME: 83210-12.-88 FILE LAST MODIFIED ON 10-24-1988 10:05:08 PROJECT TITLE: NUSHAGARK ELECTRIC INTERTIE COSTS STUDY PERIOD: 21 YEARS CONSTRUCTION PERIOD (PRIOR TO OCCUFANCY): 1 YEAR(S) PROJECT STARTING DATE: 1989 BASE DATE FOR DISCOUNTING: 1989 DISCOUNT, INTEREST, AND FRICE ESCALATION RATES INCLUDE INFLATION (NOMINAL) DISCOUNT RATE (ANNUAL): 3 % TAX STATUS: FOR PROFIT (1) MARGINAL FEDERAL INCOME TAX RATE: O % MARGINAL STATE INCOME TAX RATE: 1 % FPROFERTY TAX RATE (% OF ASSESSED VALUE): 2 % CAPITAL GAINS ADJUSTMENT FACTOR: © % DEPRECIATION RECAPTURE CODE: 2 DEPRECIATION BASIS ADJ. FACTOR: © % SALES TAX RATE: 2 % CAPITAL COMPONENT AND REFLACEMENT COST DATA: NUMBER OF CAPITAL COMFONENTS: 1 CAFITAL COST COMFONENT DATA: COMPONENT NAME INTERTIE E INITIAL COST 50000 FERCENT SUBJECT TO SALES TAX 10.00% EXPECTED COMPONENT LIFE(YRS) 15 DEPRECIATION CODE S.L. (1) DEPRECIATION LIFE (YEARS) 15 DEFR. ACCELERATION RATE 0.00% SALVAGE VALUE FACTOR 0.00% ADD’L FIRST YR DEPRECIATION 16.00% AVG PRICE ESC RT DURING CONST. 0.00% AVG FRICE ESC RT DURING OCC. 7.00% PROF. TAX ASSESSMENT FACTOR 50.00% TAX CREDIT RATE 7.00% RESALE VALUE FACTOR : 0.00% NUMBER OF REPLACEMENTS 2 COST-FHASING SCHEDULE BY YEAR OF CONSTRUCTION AND AT OCCUFANCY: 1 0.00% : AT OCCUPANCY 100.00% REPLACEMENTS TO CAPITAL COMPONENTS: REPLACEMENTS TO INTERTIE EQUIPMENT: REPLACEMENT NUMBER 1 2 YEAR OF REPLACEMENT 6 iS COST OF REPLACEMENT 15000 65000 ‘“ERCENT SUBJECT TO SALES TAX 25.00% 25.00% DEFRECIATION LIFE (YEARS) 15 15 SALVAGE VALUE FACTOR 0.00% 0.00% EXPECTED REPL. LIFE (YRS) i5 i5 rowre IRA MOOROOICNI rRuUIUN Wes Lele MORTGAGE LOAN DATA: CONSTRCT. PERMANENT Pe com ae meme ee ce mere LOAN LOAN (S) LOAN NUMBER a 1 % OF TOTAL COST BORROWED 100.00% 100.00% LOAN TYPE CODE 2 1 ANNUAL INTEREST RATE 8.00% 7.450% LIFE OF LOAN (YEARS) o 16 NUMBER OF FAYMENTS/YR 2 1 FOINTS FAID (% OF LOAN) 0.00% Oo. 00% OPERATING AND MAINTENANCE COST DATA: ANNUAL RECURRING O AND M COST = £3000 ANNUAL RATE OF INCREASE FOR A.R.C. = 12.50% NUMBER OF NON-ANNUAL RECURRING O AND M COSTS = 3 ANNUAL RATE OF INCREASE FOR N.A.R.C. COSTS = 12.5% NON-ANNUAL RECURRING O&M COSTS: # YEAR AMOUNT 1 3 #1500 2 z #1500 = 10 #2500 ENERGY COST DATA: NUMBER OF ENERGY TYPES = 1 ENERGY TYPE NO. 1 = ELECTRICITY LOSSES ANNUAL COST = £4850 ANNUAL RATE OF INCREASE DURING CONSTRUCTION PRICE INCREASES DURING OCCUPANCY: NUMBER OF DISCRETE TIME INTERVALS = 4 # DURATION ANNUAL (YEARS) RATE x 5.0% 4 3.0% & 10.0% 7 7.0% i 0.0%° td hubhe eeeeeee exe EH H HE : ke KK RH KH HHH HK KK KR KR HHH HR KKH KEKE HEH HH HH HH BLCC ANALYSIS HR KKH KKK HH HR HH KKK KKH KH HK HK PART I - INITIAL ASSUMPTIONS AND COST DATA PROJECT NAME: NUSHAGAEK ELECTRIC INTERTIE COSTS RUN DATE: 10-24-1988 10:08:02 BLDG. CHAR. FILE NAME: 83210-12, LAST MODIFIED 10-24-1988 10:05: LCC OUTFUT FILE NAME: 83210-12, CREATED 10-24-1988 10:05:56 STUDY FERIOD: 21 YEARS (1989 THROUGH 2009) CONSTRUCTION FERTIOD: 1 YEARS (1989 THROUGH 1989) OCCUPANCY BEGINS: 1990 AFTER-TAX DISCOUNT RATE: 3.0% (NOMINAL?) TAX STATUS: FOR PROFIT INCOME TAX RATE: 1.0% (COMBINED FEDERAL, STATE, CITY) EFFECTIVE CAPITAL GAINS TAX RATE: O.O% NOMINAL FROFERTY TAX RATE: 2.00% NOMINAL SALES TAX RATE: 2.00% INITIAL CAFITAL COMFONENT COSTS (NOT DISCOUNTED) INVESTMENT YEAR cost ACTUAL SALES TOTAL CATAGORY PHASING cosT TAX | cost INTERTIE EGU «1990 -«100.0% +=—S=S=«50,000.-—~CS~*«S‘D.—Ss=“(i*«‘«éaRSO, 1. TOTAL FOR INTERTIE EQUIPMENT «$50,000 —«H00—S—S—S~«SSO 100 TOTAL FROJECT COST $50,000 $100 $50,100 FINANCIAL REQUIREMENTS (NOT DISCOUNTED) A. INVESTOR’S INITIAL CASH REQUIREMENTS (UF TO AND INCLUDING OCCUPANCY): (NOT ADJUSTED FOR INCOME TAX SAVINGS) YEAR PROJECT ‘FOINTS’ INTEREST TOTAL DURING CONSTRUCTION 1989) 2 So #0 AT OCCUPANCY 1990 £0 £0 #60 £0 TOTAL 8 HO HO #0 PLUS FREFAID FROFERTY TAXES AT OCCUPANCY #500 TOTAL CASH REQUIREMENTS : fs SpRigS00 B. BORROWING REQUIREMENTS: (1) TEMPORARY FINANCING (DURING CONSTRUCTION): YEAR 1989 TOTAL AMOUNT INTEREST FOINTS FAID TYFE FAYMENTS / BORROWED RATE 00 wane enn YEAR weenenne naan % AMOUNT 9 --------------- 0 --------- #0 8.00% 0.00% #0 INTEREST ONLY 2 £0 £0 LOAN AMOUNT LIFE INTR. POINTS PAID TYFE PAYMENTS/ NO. BORROWED RATE 9 --------------- YEAR pan- 0 pee nnn nn- 2 ---- ------ PERCENT AMOUNT -------------- --------- 1 $50,100 10 YRS 7.50% 0.00% #0 AMORTIZED 1 TOTAL $50,100 #0 eM 4 eH HH HW H HH HK HK HH HK HH HH KH HK HH HH HHH HE KH KH HH HH HH eH HH HH HH HEH HH HHH HH HHH HH HHH HHH HH HH HHH KH KH KE FART II -— LIFE-CYCLE COST ANALYSIS: DISCOUNT RATE = 3.0% (NOMINAL) PRESENT VALUE ANNUAL VALUE (1989) A. CASH REQUIREMENTS AS OF OCCUPANCY (EXCEPT PREPAID FROFERTY TAXES): DURING CONSTRUCTION £0 £0 AT OCCUPANCY £0 £0 SUBTOTAL #0 £0 E. FINA@NCING-RELATED COSTS (AFTER OCCUFANCY): FRINCIFAL £40,770 $2,645 INTEREST £19,678 £1,277 SUBTOTAL $60,447 €3,921 C. OPERATING, MAINTENANCE & RELATED COSTS: ANNUALLY RECURRING COSTS (NON-ENERGY) , £187,751 $12,180 NON-ANNUALLY RECURRING COSTS $11,771 $764 ENERGY COSTS £133,060 £8,632 PROPERTY TAXES: FREPAID AT OCCUPANCY £485 $31 FAID AFTER OCCUPANCY £4,280 £278 SUBTOTAL ; #337,348 $21,884 D. REPLACEMENTS TO CAPITAL COMPONENTS £125,824 $8,162 E. INCOME TAX ADJUSTMENTS (#): TAX SAVINGS FROM O AND M COSTS r £3,372) ( £219) TAX SAVINGS FROM DEPRECIATION: INITIAL INVESTMENT ( $395) ( $26) REFLACEMENTS TO CAFITAL ( £597) ( £39) TAX SAVINGS FROM SALES TAX: INITIAL INVESTMENT ( #1) ( £0) REFLACEMENTS TO CAFITAL ( #4) ( #0) TAX SAVINGS FROM INTEREST AND FOINTS: DURING CONSTRUCTION ( £0) r #0) DURING OCCUPANCY : ( £197) ( £15) TAX CREDITS: INITIAL INVESTMENT ( $3,299) ( $214) REPLACEMENTS TO CAPITAL ( £8,509) ( - $552) SUBTOTAL ( £16,376) ¢ $1,062) F. REMAINING VALUE AT END OF OCCUPANCY ( £0) ( £0) G. TOTAL LIFE-CYCLE FROJECT COST: WITHOUT INCOME TAX ADJUSTMENTS #523 ,619 $33,968 WITH INCOME TAX ADJUSTMENTS $507,244 £32,906 € HH KR HH KH RH HH KH HHH HH HHH KH HHH KKH KH HK KH KKH KH KHER %* INCOME TAX SAVINGS ARE DISCOUNTED FROM THE END OF THE YEAR IN WHICH THEY ARE EARNED; TAX CREDITS AND TAX SAVINGS FROM SALES TAX ON INITIAL INVESTMENT ARE Peenrren AT Tur ein ae Tur Creer verae Me nreeiinancy SUMMARY FOR AFASBSO32 — DILLINGHAM/MANOKOTAEK PRESENT VALUE ASH REQUIREMENTS $1,200,006 QPUALLY RECURRING 02M COSTS $644,612 -AN. RECURRING 02M COSTS $124,565 EPLACEMENT COSTS $2,247,467 ‘AL LCC $4,216,643 RESS <ENTER> TO CONTINUE? INTERTIE ANNUAL VALUE £75,579 £40,599 £7,845 $141,551 $265,574 ee ee HK HHH KH HH HH HHH HH KH HH HH HH KH HH KH HH HH HH KH KH * PART II - LIFE-CYCLE COST ANALYSIS: DISCOUNT RATE = 3.0% (REAL) i PRESENT VALUE ANNUAL VALUE (1990) A. CASH REQUIREMENTS AS OF OCCUFANCY (EXCEFT FREFAID FROFERTY TAXES): DURING CONSTRUCTION #0 £0 AT OCCUFANCY $1,200,000 £75,579 SUBTOTAL $1,200,000 £75,579 C. OPERATING, MAINTENANCE & RELATED COSTS: ANNUALLY RECURRING COSTS (NON-ENERGY) £544,612 £40,599 NON-ANNUALLY RECURRING COSTS £124,565 £7,845 ENERGY COSTS £0 £0 SUBTOTAL £769,177 £48,445 D. REPLACEMENTS TO CAPITAL COMPONENTS $2,247,467 #141,551 F. REMAINING VALUE AT END OF OCCUFANCY ( £0) ( £0) G. TOTAL LIFE-CYCLE FROJECT COST: WITHOUT INCOME TAX ADJUSTMENTS $4,216,643 $265 ,574 ee He HH HH HH KH HH KH HHH He HHH KH HHH HH KH KH HH HH HK HH HHH HK Index A ANALYSES AND EVALUATIONS, 4 Cost Estimates, 12 Costs to NEC to Implement Intertie, 5) Determine Land Status and Permits Required, 8 Determine Possible Savings to State, 7 Determine Possible Savings to the Customer, 8 Manokotak’s Electrical System, 4 Metering Plan, 6 Ownership Recommendations, 7 Review of Furnished Project Documen- tation, 4 ESTIMATED COSTS FOR INTERTIE CONSTRUC- TION, 15 I INTRODUCTION, 1 M METHODOLOGY, 1 Analyses of Manokotak’s and Nec’s Systems, 2 Cost Estimates, 3 Land Status and Permits Required, 3 Metering Plan & Ownership Recommen- dations, 2 Possible Savings to State & Village Consumer, 3 Review Dillingham’s System, 2 Review Existing Project Docmenta- tion, 1 Review Manokotak’s Electrical Sys- tem, 2 R RECOMMENDATIONS, 13 s SUMMARY, 1 23 pes Mel el ee Se ee W971 SEE un hase Pas IG, Coda ye Guys only 4 GAS ayy gus ndyh Sor 7ie, Elst ee Bel aoe BL Ly (Gg 40.15 AEF: Det ens LOohat 2 (se cs ih et ik. | aa h ls "C2s77/008 @st asf 2) bow = at rine GY vy S (By c Ts ANGo Gs Yo ACSI. 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