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HomeMy WebLinkAboutAnalysis of Proposed Bethel Utility Corporation Purchase by the City of Bethel, Ak 9-1991 ANALYSIS OF PROPOSED BETHEL UTILITY CORPORATION PURCHASE BY THE CITY OF BETHEL, ALASKA Prepared for Alaska Energy Authority 701 East Tudor Road Anchorage, AK 99519 Prepared by Economic Analysis CH2M HILL 777 108th Avenue N.E. Bellevue, WA 98004 Environmental Analysis FPE/ROEN Engineers, Inc. 1028 Aurora Drive Fairbanks, AK 99709 September 1991 FPE/Roen Engineers, Inc. 1028 Aurora Drive Fairbanks Fairbanks, Alaska 99709-5529 Anchorage PH: (907) 452-1414 e FAX (907) 456-2707 September 23, 1991 Alaska Energy Authority P.O. Box 190869 701 East Tudor Road Anchorage, AK 99519-0869 Re: Analysis of Proposed Bethel Utility Corporation Purchase by the City of Bethel, Alaska Ladies and Gentlemen, Attached is our report on the Analysis of the Proposed Bethel Utility Corporation Purchase by the City of Bethel, Alaska. The report is divided into two major sections, including an economic and environmental analysis of the Utility completed independently by CH2M Hill and FPE/ROEN Engineers, Inc. respectively. FPE/ROEN Engineers, Inc. and CH2M Hill would like to take this opportunity to extend our appreciation to the Alaska Energy Authority, the City of Bethel, and the Bethel Utility Corporation for their contributions in completing this effort. The report provides a baseline of economic and environmental information that will be beneficial in consideration of the proposed utility purchase. We trust that this information is sufficient for your needs at the present time. If you have any questions or if we can be of further assistance, please feel free to call. ly, Mp “<i in M. Hargeshei Chief of Environmental Engineering Enclosure ECONOMIC ANALYSIS OF PROPOSED BETHEL UTILITY CORPORATION PURCHASE BY THE CITY OF BETHEL, ALASKA sysAjeuy 21u0u027 Prepared for Alaska Energy Authority 701 East Tudor Road Anchorage, AK 99519 Prepared by CH2M HILL 777 108th Avenue N.E. Bellevue, WA 98004 September 1991 Engineers ‘7 hn Planners ceria §=Economists BE scientists August 30, 1991 ANC31425.A0 Alaska Energy Authority P.O. Box 190869 701 East Turdor Road Anchorage Alaska 99519-0869 Subject: AEA Economic Study on Bethel Acquisition of BUC It has been a pleasure to work with AEA, the City of Bethel, the Bethel Utilities Corporation (BUC) and FPE/Roen on the modeling and analysis of the potential acquisition of the BUC electric and cogeneration utilities by the City of Bethel. In particular the staff and owners of BUC appear to be have a well organized and run electric utility. We also would like to thank AEA for its assistance in explaining the City and BUC’s concerns, finalizing our data requests, and resolving sponsor comments. Because we value our relationship with AEA, the City and BUC, we provided more analysis than was originally requested. Part of the reason for the additional analysis has been the lack of data we originally requested at the start of this assignment. Another component has been the changes of major assumptions requested by the sponsors. While it has been a slow process, the information and the assumptions appear to be final. While initial drafts suffered from a lack of data, we believe that the AEA, City, and BUC comments and information have improved the analysis. This final version more thoroughly quantifies the value of the BUC facilities. It also incorporates the special administrative support fee needs indicated by the City. The information within the report should be sufficient so that the City and BUC can either proceed with negotiations or determine they are not likely to reach consensus on a purchase price. If the City and BUC determine that they are reasonably close, then the City should retain a financial advisor, special legal counsel, and an investment banker to provide background for the negotiations and the marketability of the bond issues. CH2M HILL Seattle Office 777 108th Avenue N.E., Bellevue, WA 98004 206.453.5000 P.O. Box 91500, Bellevue, WA 98009-2050 Fax 206.462.5957 Alaska Energy Authority Page 2 August 30, 1991 ANC31425.A0 If negotiations are to proceed, then CH2M HILL would be happy to furnish additional assistance in the acquisition process. We believe that both FPE/Roen and CH2M HILL can assist the parties in finalizing the potential BUC acquisition. Sincerely, CH2M HILL fi’ in Zz Lo yt Motel by, ot d PAN Robert K. Schneider Electric Utility Consulting AEA-9/30/91 Enclosures (1) cc: J. Hargesheimer/FPE » CH2M HILL AEA ECONOMIC STUDY ON BETHEL ACQUISITION OF BUC TABLE OF CONTENTS INTRODUCTION 1 Bethel, Alaska 1 Purpose of the Report 1 BETHEL UTILITIES CORPORATION : 5 History and Description 5 Condition of the Electric System 9 Hazardous Substances and Environmental Costs 10 Staff and Management 11 Customers, Energy Sales, and Energy Requirements 11 Historic Operating Results 15 PROJECTED OPERATING RESULTS : 18 Method of Analysis : 18 Cost Changes Due to City Ownership 20 Other Cost Relationships 21 Proposed Electric System Management 21 Customers, Energy Sales, and Energy Requirements 22 Power Cost Equalization Program Benefits 23 Analysis of the City-owned Electric System 25 Electric System Capital Improvements 27 ALTERNATE CASES 28 Alternate Evaluation Cross Check of Asset Values 28 Alternate Case Overview 30 Initial Case 31 Special Initial Year Scenario 32 Load Reduction Scenario 32 Moderate Load Growth Scenario 32 5 Percent 1991 Rate Increase Scenario 32 Moderately High Environmental Cost Scenario 32 Special Initial Year & 5% Bond Issue Scenario 33 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS 46 CONCLUSIONS 48 APPENDIX A APPENDIX B CH2M HILL AEA ECONOMIC STUDY ON BETHEL ACQUISITION OF BUC LIST OF FIGURES Figure 1 - Bethel Location Table 1 Table 2 Table 3 Table 4 Table 5 Table 6 Table 7 Table 8 Table 9 Table 10 Table 11 Table 12 Table 13 Table 14 Table 15 Table 16 Table 17 Table 18 Table 19 Table 20 Table 21 Table 22 Table 23 Table 24 Table 25 Table 26 Table 27 Table 28 Table 29 Table 30 LIST OF TABLES City of Bethel Population Alternative Cases Major Historical Events at BUC Generation Plant Summary 1989 Distribution Plant Summary Mobile Equipment Summary Bethel Population Data Rate of Average Growth Over the Operating Period 1985 - 1989 Diversity of Revenues Customers, Energy Sales, and Energy Requirements Ten Largest Customers Electric Bill Comparison Historic Operating Results Fuel Cost Plant-in-Service and Depreciation Initial Case: Projected Customers, Energy Sales, and Energy Requirements Initial Case: Projected Operating Results Projected Fuel Cost All Cases Plant-in-Service and Depreciation Historic Working Capital Special Initial Year Scenario: Projected Operating Results Special Initial Year Scenario: Projected Customers, Energy Sales, and Energy Requirements Load Reduction Scenario: Projected Operating Results Load Reduction Scenario: Projected Customers, Energy Sales, and Energy Requirements Moderate Load Growth Scenario: Project Operating Results Moderate Load Growth Scenario: Projected Customer, Energy Sales, and Energy Requirements 5 Percent 1991 Rate Increase Scenario: Project Operating Results 5 Percent 1991 Rate Increase Scenario: Projected Customers, Energy Sales, and Energy Requirements Moderately High Environmental Cost Scenario: Projected Operating Results Moderately High Environmental Cost Scenario: Projected Customers, Energy Sales, and Energy Requirements CH2M HILL AEA ECONOMIC STUDY ON BETHEL ACQUISITION OF BUC Table 31 Special Initial Year & 5% Bond Issue Scenario: Projected Operating Results Table 32 Special Initial Year & 5% Bond Issue Scenario: Projected Customers, Energy Sales, and Energy Requirements ANALYSIS OF PROPOSED UTILITY PURCHASE BY THE CITY OF BETHEL, ALASKA ECONOMIC STUDY INTRODUCTION Bethel, Alaska The City of Bethel (the City) is located approximately 420 air miles west of Anchorage and 517 air miles southwest of Fairbanks, Alaska. Bethel is located near the Bering Sea, inland from the Kuskokwim Bay, and on the Kuskokwim River. The community is generally built upon permafrost. The City’s location is shown in Figure 1. The Russian trading post of Mumtrekhlagamiut Station was established at the present site of Bethel around the 1850’s. In 1867 an American company took over the Russian interests that were eventually turned over to the Northern Commercial Company. The Moravian Christian mission to the Eskimo people was established in 1885. Shortly thereafter, the community became known as Bethel. The Bethel population has grown from 278 people in 1929 to 4,674 people in 1990. Information furnished by the City (Table 1) projects the population to grow at approximately 2 percent per year for the next two decades. Commercial fishing, seafood processing, government services, and transportation currently dominate the local economy. Bethel is a major transportation hub for southwestern Alaska. The Bethel Airport is the sixth largest airport in Alaska on the basis of takeoffs and landings. Ocean going ships and barges navigate up the Kuskokwim River to Bethel. At Bethel freight is off loaded during the summer months. Smaller barges transport freight farther up river or air taxi services distribute freight to other villages. Purpose of the Report The City is considering purchasing the Bethel Utilities Corporation (BUC). The Alaska Energy Authority (AEA), as a service to the City, has retained the engineering firms of FPE/Roen Inc. and CH2M HILL. This report by CH2M HILL presents our evaluation of the condition of BUC’s facilities and analyses of the financial results of the City owning and operating the electric and heating utility systems. Our analysis presents a range of bond debt service that can be supported by the City-owned system. This estimate is based upon an extrapolation of current conditions. From the range of debt service that can be supported, the City can determine the acceptability of certain rate increase and administrative support fee assumptions in determining if a purchase should be pursued. While many details need to be addressed prior to a purchase offer, this report should help the City and BUC determine whether the City can support a price within which BUC would be willing to sell. 2 790 1-269) Crs ANC31425.A0 BE SKA © Fairbanks 4” Figure 1 _BETHEL LOCATION Table 1 CITY OF BETHEL POPULATION Year City Population 1929 278 1939 376 1950 651 19 1,258 1970 2,416 1980 3,576 1990 4,674 5,700* 2010 6,900* *estimated by the City of Bethel g S To provide the City of Bethel with guidance on the acquisition of the BUC properties, three major tasks were performed: a financial model of the electric utility was created, a site inspection was conducted, and an environmental evaluation (by FPE/Roen separately reported) was performed. If the City purchases the BUC properties, it is assumed that the City would finance the acquisition by issuing tax exempt revenue bonds. A purchase price has not been negotiated. Therefore, a range of potential purchase prices were examined by a financial model. Table 2 shows a summary of the range of potential purchase prices analyzed and the conditions assumed in each analysis. From this information and the assumptions and detailed analysis contained within the rest of this report, the City can examine the financial impacts of acquiring the BUC utility and decide whether to pursue the negotiations. This analysis is different from an Engineer’s Report traditionally found as part of the support within a bond issue official statement. While we have documented the existing system as we found it in 1990, this analysis is structured to help the City determine if negotiations are possible. In a traditional Engineer’s Report, a purchase price has been agreed upon, and bond counsel, a financial advisor, and an investment banker have determined that the important elements of the sale along with any disclosure requirements to test for sensitivity. The financial advisor and investment banker also determine the marketability of the bonds, any credit supports and the likely concerns of the bond market. If negotiations proceed and bonds are issued, an Engineer’s Report will need to address a single purchase price and perform sensitivity studies based on the purchase price and any significant disclosure items. “Table 2 ALTERNATIVE CASES City Owned Electric System Scenario Purchase Major Assumptions Price Initial Case $47,000 No rate increase for 5 years; No supportable 17.75% Admin. Support Fee } purchase Special Initial Year $5,996,000 Admin. Support Fee initially 17.75 % growing to 22.75%; 10% City rate increase; rates raised annually for inflationary costs Load Reduction $5,724,000 Same as Special Initial Year Case except -2%/year decline in residential customers Moderate Load Growth $6,274,000 Same as Special Initial Year Case except 2%/year increase in residential customers 5 Percent 1991 Rate $4,178,000 Same as Special Initial Year Case Increase except a 5% initial year rate increase Moderately High $5,905,000 Same as Special Initial Year Case Environmental Cost except a 0.25 %/year of Op. Expense increase in environmental costs Special 5 % Bond Issue $2,000,000 in cash and Same as Special Initial Year Case | and Initial Year $7,475,000 special 30 | plus a 30 year, 5% tax-exempt bond year 5% bonds with 1% issuance costs } yeilding $486,259/year BETHEL UTILITIES CORPORATION History and Description BUC is an investor-owned electric utility owned by Harold A. and Virginia Borrego (husband and wife) who are residents of Bethel, and Edward L. Tilbury, Frances J. Davidson and Elaine R. Tilbury. According to records filed with the FERC, these are the only stockholders. BUC was originally incorporated by George Tilbury and Harold Borrego. BUC bought the electric power generation and distribution system of the Northern Commercial Company in February, 1972. The Northern Commercial Company served several hundred customers and the power plant consisted of a number of small 300 kW Caterpillar diesel generator sets. An extensive renovation and upgrading occurred after the purchase. Service was expanded to include the Bethel airport, the Bureau of Indian Affairs and the White Alice facilities south of town. In December of 1975, a fire destroyed the generating plant. A new generating plant was built by Bethel Utilities’ personnel during the summer of 1976. This power plant currently supplies power to the City of Bethel and economy energy to two neighboring communities. The new plant utilized five General Motors Electro Motive Division 16 cylinder 645 cubic inch displacement per cylinder diesel generator sets (GM EMD 16-645). These diesels provided a total plant capacity of 10,500 kW, which was more than twice the capacity of the plant that was destroyed. Financing for the new facility was supplied by a long term 6.625 percent interest Small Business Administration Disaster Loan that matures in 2002. This loan is assumed to be transferred to the City upon sale of BUC. BUC has grown dramatically. Gross sales for eight months of operation in 1972 were less than $400,000. In 1990 BUC served approximately 1,800 customers with gross revenues in excess of $5,000,000. As of the end of 1990, BUC had 20 full-time employees located in Bethel and Anchorage. In the early 1980’s, a BUC subsidiary, Bethel Cogeneration Utility (BCU), constructed a heat distribution system to allow the sale of "waste" heat from electrical generation to nearby users. This project was financed in part by a $1 million loan from the Alaska Energy Authority (AEA). The AEA loan matures in 1996 and is also assumed to be transferred to the City upon the sale of BUC. In 1990 over 30 billion BTU’s of heating energy were provided to BCU customers. BCU gross 1990 revenues exceeded $250,000. BUC functions as a self-sufficient electrical "island" wholly dependent on diesel engines for power generation. Distribution voltage level interties or transmission to nearby villages have been funded by the Alaska Energy Authority. Two interties have been built and can be used to supply economy energy to the villages of Napakiak, Oscarville, and Napaskiak. The intertie to Napaskiak is currently not operational. Table 3 MAJOR HISTORICAL EVENTS AT BUC Bethel Utilities Corporation eee amend ee ee 1972_| BUC purchased from NCC | | 1975 Fire destroys powerhouse City without power 1976 SBA loan finances Available generation new powerhouse capacity doubles 1980 SWGR intertie to Napakiak economy energy sales to Napakiak Bethel Cogeneration Utility Reduced heating costs (BCU) formed and for major public buildings financed by an AEA loan As described below, the electric system consists of: generation plant, distribution plant, cogeneration or waste heating system, and general plant. Generation Plant. The generation plant consists of five diesel-generator units manufactured by the General Motors Electro Motive Division that have a combined capacity of 10,500 kilowatts (kW). These units are a conventional design with a history of reliable operation in similar applications. The units are located in a single powerhouse near the Airport on the southwest side of Bethel, and all were fully operational in December of 1990. Table 4 is a summary of the generation plant. The 10,500-kW combined capacity of the generation plant is about twice the current electric system peak load. At the historic peak load of 5,250 kW, set on December 3, 1990, the utility can serve its load with its largest unit (2,100 kW) out of service, while maintaining adequate reserve capacity; under most load situations, the utility can meet load with two to three units out of service. Table 4 GENERATION PLANT SUMMARY Bethel Utilities Corporation General Motors 645 E (V-16) Electro Motive Division General Motors 645 E (V-16) Electro Motive Division General Motors 645 E (V-16) Electro Motive Division General Motors ny (2) Electro Motive Division General Motors 645 E (V-16) Electro Motive Division General Motors 645 E (V-16) Electro Motive Division Notes: (1) Unit 5 is a naturally aspirated diesel engine. (2) Unit 5 has been retired and removed from the main power house, but is being stored in an adjacent building. Distribution Plant. There are six distribution circuits or feeders that leave the power plant. Three of the feeders are at 2.4 kV. The remaining three feeders are at 7.2kV. The distribution system is almost exclusively overhead delta construction. There are two interconnections at distribution voltage levels with adjacent villages. BUC owns the metering equipment so that it can sell power over the interconnections. BUC does not own the interconnecting distribution lines that were funded by AEA. These interconnections are a source of potential sales revenues. The first interconnection is an unusual single wire ground return system to the village of Napakiak. The second interconnection is to the village of Oscarville and Napaskiak. This second interconnection is a more traditional design single phase overhead pole line and a portion was not operational during the site visit in December of 1990. The purpose of the interconnections is to provide added reliability and economy energy to the villages of Napakiak, Oscarville, and Napaskiak. As of the end of 1989, BUC had 488 transformers of which 198 were in stock and 290 were serving customers. Also at the end of 1989, BUC had 2,164 meters of which 1,758 were in use by customers. More recent information suggests that the number of transformers is substantially higher. This 1990 information indicated that there are 717 transformers of which 262 are in stock and 455 are in service. We have not had the opportunity to independently verify the documentation associated with this increase. Table 5 1989 DISTRIBUTION PLANT SUMMARY Bethel Utilities Corporation Description Primary Overhead 2.4 kV 3 feeders Primary Overhead 7.2 kV 3 feeders Transformers serving load 290 Transformers in stock meters serving customers meters in stock Total customers Waste Heating System. BUC owns Bethel Cogeneration Utilities, Inc. (BCU) which owns, operates and sells cogenerated waste heat. BUC has indicated that it would include BCU as part of the assets it would sell to the City. In the early 1980’s, BCU constructed a heat distribution system to allow the sale of "waste" heat from electrical generation to nearby users of heat. The principal customers of BCU are: the State Department of Corrections, the State Youth Facility, the Yukon Kuskokwim Delta Regional Hospital, the Kuskokwim Community College, Calista Homes, and the City of Bethel. This project was financed in part by a $1 million loan at 5 percent interest from the Alaska Energy Authority. In 1990 total BCU gross revenues were $254,087. Revenues are projected upon an escalation of unaudited information provided by BUC. Maintenance costs for BCU, as provided by BUC, are small, and for this report we assume that they do not significantly increase the operating costs of BUC. Waste heat from the normal operation of the diesel generating units is sold to publicly owned buildings in the area of the power plant. In 1990 over 30 billion BTU’s of heating energy were provided to BCU customers. Exhaust heat recovery boilers are installed and would allow additional energy to be recovered from the diesel engines. The waste heat system currently recovers energy from the cylinder water jackets of the diesel generating units. Current sales of waste heat for buildings are at a level where the exhaust heat recovery boilers are not required. Therefore, there is a potential for greater utility revenues if the City were to purchase and expand the BCU system. Documents supplied by AEA indicate that the waste heat system was designed to serve approximately 140 billion BTU’s per year of heating. This is almost five times the current level of energy sold. CH2M HILL has not examined the economics of expanding the existing system or determined the market need for additional cogeneration services. The waste heat is distributed principally by an above ground insulated hot water system. The system is looped. Special BTU meters are installed at each building to measure energy use. General Plant. The general plant consists of certain land, and office building, service building, mobile equipment, and spare parts. The land includes the area around the power plant and an additional parcel where the Bethel office is located. The service building is adjacent to the power plant building and provides covered storage and garage space for some of the mobile equipment. Table 6 summarizes BUC’s mobile equipment. Table 6 MOBILE EQUIPMENT SUMMARY Bethel Utilities Corporation Line Service Bucket Trucks Drill Rigs Fork Lift ee Pole Trailer OL Pick-up Trucks General Purpose Truck 1 Cement Mixer Condition of the Electric System On December 17 and 18, 1990, A CH2M HILL representative visited Bethel to observe the electric system’s general condition and investigated other characteristics of BUC. During a period of approximately 36 hours in Bethel, he observed the generation plant, toured a representative sample of the distribution plant, and held conversations with Hal Borrego, the President of BUC; Jerry Springer, Plant Mechanic Foreman; Rodney Rogers, Line Foreman; Mark Earnest, then City Manager; Corlis Taylor, City Administrator/Personnel Manager; Tom Graham, City Finance Manger; Mayor Gary Vanasse and others, including members of the City Council. The extent of our examination was not of a depth necessary to reveal all conditions with regard to safety or conformance with agreements, codes, permits, rates, or regulations of any party having jurisdiction with respect to construction, operation, and maintenance of the electric system. It was, however, of a scope deemed sufficient to allow CH2M HILL to assess whether the electric system was capable of performing the functions assigned to it. After leaving Bethel, CH2M HILL’s representative visited the BUC offices in Anchorage and had conversations with Ed Tilbury, Vice President of BUC; Tom Sterrett, BUC Controller, and others. At this time we collected historic data for the calendar years 1985 to 1989. The physical condition of the generation plant was found to be good. Both routine mainten- ance and major repairs reportedly have been performed regularly. Most work on the engines and generators has been performed by the BUC staff. Regular 1000 hour maintenance inspections are observed. Lube oil samples for each machine are reportedly taken on a monthly basis for laboratory analysis. Several hours were spent touring the utility service area by truck to become familiar with the community and to observe the type of overhead construction used and the general physical condition of the distribution plant. In some locations poles were visually examined from ground level, but no boring or other physical testing was performed. Overall, the overhead system seems to be well constructed, of conventional design, and in good physical condition. Most wood members (poles and crossarms) visually appear to be free of decay. Throughout the system, new poles are evident, suggesting that renewal has been a regular process. The poles appeared to be well guyed. In the City’s decision as to whether to purchase the BUC facilities, an important component will be how much capital in excess of the purchase price will be required to continue the operations of the utility. Based upon information furnished by BUC, no major additional capital replacement or expansion expenditures are forecast. Specifically, no known major distribution capital requirements and no engine replacements will be required during the next 5 to 6 year period. Should an engine fail and require replacement, BUC has more generation than is currently required to serve the loads assumed in this report. This generating reserve capacity provides a capital cushion against load growth higher than the initial case analysis and against unexpected generation equipment failure. Similarly, should significant load growth require expansion of the distribution system, the new customers would provide an additional source of revenue that could be used to finance the distribution capital requirements. Environmental and regulatory related costs have been addressed within the FPE/Roen report and included within the financial modeling. The observed general plant also appeared in good condition. In summary, based upon the site visit and the factors discussed above, the generation plant, distribution plant, and the general plant were found to be in good condition. While these facilities, in general, are not new, we would expect that, with regular maintenance and occasional replacements, the electric system should have a normal useful life similar to facilities located in other areas of the Pacific Northwest. The existing facilities, therefore, appear adequate to serve the continuing and forecast needs of the utility. Hazardous Substances and Environmental Costs Investigation of the presence, use, or disposal of hazardous substances by BUC was an assignment of FPE/Roen Inc. FPE/Roen performed a site visit, a survey of environmental costs for similar Alaskan utilities, and other analysis. For the economic analysis of the initial case, 1989 historic levels of environmental costs were assumed. Recent costs have included removal of PCB transformers and the replacement of diesel oil day tanks. No additional costs for installing additional air pollution control technology or for removing or mitigating any hazardous substances were assumed. These topics are covered in a report by FPE/Roen Inc. CH2M HILL takes no position, nor does CH2M HILL warrant or accept any responsibility whatsoever for the presence, storage, future discovery, spillage, disposal, or damage resulting from any hazardous substance whatsoever relating to BUC, the City, or others. As an alternate case, we increased environmental costs to 1.25 percent of the total utility 10 operating budget in 1995. This increase and its basis were determined by FPE/Roen through a survey of other Alaska utilities. The sensitivity analysis in the alternate case was to cover potentially increasing regulatory requirements of the City owned electric utility system. Staff and Management The present utility management staff consists of Hal Borrego, who serves as President and in charge of all BUC Bethel operations; Jerry Springer, who serves as Powerhouse Mechanic Foreman; Rodney Rogers, who serves as the Line Foreman; Ed Tilbury, who is Vice President and in charge of Anchorage operations, planning, accounting and personnel functions; and Tom Sterrett, Controller. As of the end of 1989, BUC had 23 full-time employees and three part-time employees located in Bethel and Anchorage. Since that time BUC has reduced its staff to 20 full-time employees in Bethel and Anchorage. Customers, Energy Sales, and Energy Requirements During the period 1985 through 1990, population in the Bethel Census area (Table 7) grew at a rate of approximately 0.9 percent per year. The Bethel Census area is larger than the incorporated City. During this period the total number of BUC customers grew at a rate of about 1.2 percent per year. Table 7 BETHEL POPULATION DATA Population Population Customers jase |_sass tear | __va__ pe |_ae _1_sast_{ sa _] Table 8 provides a comparison of 1985 to 1989 BUC customer and sales statistics. Table 10 shows historic BUC customer, energy sales and energy requirements by year from 1985 to 1989. Total energy sales increased at 3.6 percent per year during the 1985 to 1989 period. This rate of growth in energy sales exceeded the 1.2 percent per year rate of customer growth. Therefore, energy sales per customer increased during this period. The total residential energy sales increased 5.0 percent per year, small commercial energy sales 11 decreased 4.5 percent per year, and large commercial and resale sales increased at 33.0 percent per year. The decline in small commercial sales and the increase in large commercial and resale sales was due to a reclassification of customers between the two rate classes. Total energy requirements appear to have increased 6.2 percent per year during this same period. BUC has indicated that the apparent increase in system losses is a result of improvements in BUC’s ability to more accurately measure energy use and generation. Table 8 RATE OF AVERAGE GROWTH OVER THE OPERATING PERIOD 1985 - 1989 Bethel Utilities Corporation PEATE CEVECTELL Meee Total Energy Sales (kWh) Energy Requirements (kWh) * Reclassification of Small Commercial and Large Commercial & Resale customers occurred between 1985 and 1989; The rate of growth of the two combined customer classes was about 10.8 percent/year Table 9 shows the distribution of 1989 sales revenues among customer classes. It shows that the principal source of revenues is from small commercial sales. Residential sales are the next largest source of revenues, with large commercial and resale comprising 22.5 percent of revenues. Table 11 shows energy sales and revenues from BUC’s ten largest customers from 1987 through 1989. This documents BUC’s diversified customer revenues. Table 9 DIVERSITY OF REVENUES Bethel Utilities Corporation | | | | | 1989 Sales Mwvenues_| Percent of Total | sisese79 | aaa Tas ee Large Commercial & Resale Sales $1,068,460 22.5% $4,754,402 100.08 | 12 CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS Bethel Utilities Corporation Residential Commercial 263 Large Commercial/Resale 4 Total Customers 1,691 Electric Sales Revenues ($) Residential 1,330,993 1,355,608 1,403,052 1,574,240 Commercial 2,516,978 2,192,698 2,128,934 2,297,237 2,102,263 Large Commercial/Resale 352,904 594,648 708,914 1,015,567 1,068,460 Total Sales Revenues 4,200,875 4,142,954 4,240,900 4,887,044 4,754,402 Delinquent fees 36,742 38,674 33,049 27,797 39,495 Misc Service Revenues 2,716 3,082 3,164 2,666 4,183 Other Electric Revenues 2,438 5,910 Tot Elec. Operating Revenues 4,240,333 4,184,710 4,277,113 4,919,945 4,803,990 Sales Revenue per Customer ($) Residential 970 965 985 1,084 1,072 Commercial 9,832 8,466 8,095 8,702 7,508 Large Commercial/Resale 117,635 _ 148,662 177,229 169,261 178,077 All Customer Classes . 2,576 2,484 2,508 2,838 2,695 Sales per Customer (kWh) Residential 5,079 5,391 5,470 5,652 5,729 Commercial 58,597 52,609 50,314 50,514 44,521 Large Commercial/Resale 743,976 1,032,144 1,227,450 1,069,517 1,164,103 All Customer Classes 14,838 15,185 15,335 16,236 15,826 Energy Sales (kWh) Residential 6,968,784 7,574,236 7,789,724 8,206,031 8,466,838 Commercial 15,000,877 13,625,756 13,232,608 13,335,607 12,465,913 Large Commercial/Resale 2,231,927 4,128,576 4,909,800 6,417,100 6,984,620 Total Customer Sales 24,201,588 25,328,568 25,932,132 27,958,738 27,917,371 Utility Use 291,732 411,476 296,400 288,800 394,652 Losses 946,680 2,736,756 4,355,468 4,331,462 4,086,377 Losses & Utility use (kWh) 1,238,412 3,148,232 4,651,868 4,620,262 4,481,029 Losses & Utility use (%) 5.1% 12.4% 17.9% 16.5% 16.1% Energy Requirements (kWh) 25,440,000 28,476,800 30,584,000 32,579,000 32,398,400 The ten largest BUC customers have purchased 33.5 percent of BUC’s total energy sales and produced 30.6 percent of its total operating revenues during 1989. The largest customer is the Public Health Service (PHS) Hospital. In 1989, PHS Hospital purchased 10.6 percent of BUC’s total energy sales and produced 9.4 percent of the total operating revenues. The next five largest customers individually purchased between 2.0 and 6.4 percent of BUC’s total energy sales and contributed between 1.9 and 5.7 percent of the total operating revenues during 1989. 13 Table 11 TEN LARGEST CUSTOMERS Bethel Utilities Corporation PHS Hospital $447,477 937, $455,433 LK School District 541, 231,885 F 281,624 Federal Aviation Agency . 136,838 162,934 150,689 Swansons Store . 104,867 138,263 127,758 City of Bethel (master) 581,520 88,740 96,866 92,218 State Corrections 574,360 87,654 x 102,385 eS 91,873 City of Bethel (pump) 493,040 75,512 89,970 90,312 B.LA. 646,800 96,344 101,868 89,252 | Bethel Native Store 369,280 61,944 a 77,862 72,399 Kemp & Palucci Seafood 143,160 22,074 28,225 24,909 | Total 9,147,520 $1,353,335 $1,535,430 $1,456,952 |} Total All Customers 25,932,132 $4,240,900 $4,887,044 27,917,371 $4,754,402 It is assumed that these energy purchases from the BUC electric system will continue into the future. The largest customers are primarily funded by federal and state revenues. However, most of the services provided by these utility customers are of a regional nature and can be described as basic services. While federal and state funding levels can change, the types of services (regional hospital, regional school, flight control, regional correctional facility, etc.), and the infrastructure present at Bethel, should allow these services and their electric power requirements to remain. BUC rate schedules are shown in Appendix A. They include the APUC rate increase approved in December of 1990, but they do not include a recently approved APUC increase of 4.54 percent. Through an administrative process, changes in fuel costs are passed through to the ratepayers when they occur. BUC also participates in the State of Alaska’s Power Cost Equalization (PCE) Program whereby the state provides a subsidy to ratepayers. For 1989 the total PCE amount collected from the State was $674,540 or approximately 14 percent of total sales revenues. In the 1990 approved rates, BUC’s fuel surcharge was 1.31 cents/kWh and the PCE rate was 10.21 cents/kWh. These values were based upon a rate case fuel cost of $1.2705 per gallon. In 1991, a twenty percent reduction in the state funding of PCE Program benefits occurred. Table 12 shows a comparison of bills for residential customers in Bethel and other western Alaska communities. BUC’s rates appear reasonable in comparison. Similarly, BUC’s rates are reviewed and approved by the APUC, which exercises an oversight role to protect ratepayers’ financial interests. 14 Table 12 ELECTRIC BILL COMPARISON Bethel Utilities __________Bethel Utilities Corporation Notes: 1989 data. Source: Alaska Energy Authority, Alaska Electric Power Statistics 1960-1989, dated October 1990. Historic Operating Results BUC sources of operating revenues during the 1985 through 1989 period were from residential customers, commercial customers, large commercial and resale customers, the State of Alaska through its PCE Program, and other miscellaneous sources. Table 13 shows the sources of operating revenue. During the 1985 through 1989 period, small and large commercial customers combined contributed 67.4 percent of the operating revenues. This percentage indicates a broad commercial customer base. Total operating revenues increased 3.2 percent per year during the period 1985 through 1989. During this same period, revenue from residential customers increased 4.4 percent per year, from small commercial customers decreased 4.4 percent per year, and from large commercial and resale customers operating revenue increased 31.9 percent per year. Again there was a reclassification of customers between the commercial and large commercial groups. BUC’s operating and maintenance expenses for the period 1985 through 1989 are also shown in Table 13. Total operating expenses before depreciation increased 4.7 percent per year during the period 1985 through 1989. Fuel expenses increased 2.6 percent per year. BUC’s salary expense increased 6.7 percent per year during the 1985 through 1989 period. Employee Benefits increased approximately 13.0 percent per year. Net operating revenues before depreciation have remained relatively constant between 1985 and 1989. 15 Table 13 HISTORIC OPERATING RESULTS Bethel Utilities Corporation $4,184,710 (3,082) 48,929 0 Other 4 1,217 Total Operating Expenses(w/o deprec.) 4,531,165 Net Operating Revenues i 493,140 Interest Income 12,953 Other Income 17,875 Revenues Available for Other Purposes 470,408 498,335 523,968 (219,209) (236,583) a (219,493) (122,157) (141,015) (245,353) (65,073) 15,377 (198,910) $136,114 0.00% 0 oO o (2,475) (139,788) (14,009) 6,688 1,249,500 1,183,016 50,000 0 $1,183,016 $1,049,916 16 Table 14 shows that fuel prices have increased about 1.8 percent per year. Fuel efficiency has also generally improved from 12.5 kWh per gallon in 1985 to 14.6 kWh per gallon in 1989. Even though total energy sales increased at 3.6 percent per year, total fuel costs increased by only 2.6 percent per year over the period. Table 15 shows plant-in-service and depreciation values between 1985 and 1989. The five year average depreciation rate was 3.28 percent of beginning plant-in-service. Table 14 FUEL COST Bethel Utility Corporation 25,440,000 | 28,476,800 | 30,584,000 | 32,579,000 | 32,398,400 Sr rece ee kWh Generated per Gallon 12.5 13.8 2] 49 | ts | iueser | —aaaoue | —nomiase | aanise | as | Fuel Cost ($) 2,413,326 2,272,492 2,323,243 2,771,541 2,675,527 | Paced Powe: Cot 0 0 «[ =| _8| Table 15 PLANT-IN-SERVICE AND DEPRECIATION Bethel Utilities Corporation 1986 $4,499,827 263,210 4,763,037 198 $4,872,461 (41,348 o 1987 $4,763,037 116,727 4,879,764 1988 $4,879,764 (7,303) 4,872,461 Utility Plant $4,348,437 151,390 4,499,827 Beginning Plant-In-Service Net change in Plant-In-Service Ending Plant-In-Service Utility Plant Depreciation Ss 1,761,744 146,334 1,908,078 222,520 2,130,598 148,951 Beginning Accumulated Depreciation 2,279,549 Net Change in Accumulated Depreciation 206,238 2,312,209 $2,518,904 1,761,744 $2,738,083 4.74% 1,908,078 $2,854,959 3.25% 2,130,598 $2,749,166 4.67% 2,279,549 $2,592,912 Ending Accumulated Depreciation Net Plant-In-Service (Year end) Average Depreciation Rate ° a a R 17 PROJECTED OPERATING RESULTS Method of Analysis To determine a potential range of purchase prices for the BUC utility, CH2M HILL created a financial model. This financial model projects electric utility revenues and costs for the years 1991 to 1995. The following section describes the initial case, the major assumptions, and the methods of projection. In determining the initial case, numerous assumptions were agreed to by the City and AEA. The initial case was designed to be very attractive to the City. It includes a 17.75 percent administrative support fee paid by the City-owned utility to the City and contains no rate increase from 1991 to 1995, except for fuel cost adjustments. In the analysis of the alternate cases, where rate increases are allowed, the administrative support fee is allowed to increase to 22.75 percent to provide the City with some ownership benefits. From these and other assumptions, we projected both the utility cash flow and the maximum debt service that could be supported. Then, based upon an 8.5 percent interest rate and a one time transaction cost of 3 percent, a maximum bond issue size was calculated. The transaction costs cover the cost of bond issuance and credit enhancement. In discussing this assumption with AEA, we concluded that the tax-exempt bonds would need to be issued with credit support from some other organization. An example of a credit support could be bond insurance, a letter of credit, or issuance by another agency. The bond issue proceeds represent a maximum purchase price at which the utility will be still able to operate without raising rates based upon the initial case assumptions. To test the initial case assumptions and to provide guidance on a range within which a purchase price should be negotiated, a sensitivity analysis was performed. This range was then examined against other methods to cross check the reasonableness of the results. The projected operating results are based upon forecasts of future costs and revenues of the utility under City ownership. The method of projection was to take historic 1985 to 1989 costs and adjust them for changes due to City ownership, future rates of inflation, and for other known changes. The following paragraphs describe how the principal expense items and revenues were estimated. Diesel fuel accounts for over 50 percent of the operating expenses. The principal determinants of the level of fuel expense are the amount of energy sold, diesel engine efficiency, and the rate at which the price of diesel fuel escalates. Detailed population projections or load forecast were not available to estimate the amount of energy sold. Different factors could impact future loads. Examples of factors that could increase loads are: the proposed expansion of the hospital; gradual population growth that has occurred historically; or increased economy energy sales to adjacent villages. Examples of factors that could cause a reduction in loads include: the recent 20 percent reduction in state PCE funds, causing a price elasticity impact on sales; reductions in state spending due to reduced oil revenue monies; or implementation of more energy efficient appliances and devices, such as 18 compact fluorescent lights. Because of the lack of a forecast and these factors, loads were assumed to remain constant over the forecast period. The impact of increases or decreases in the load level was examined in alternate scenarios or cases. The diesel generator efficiency was assumed to be the 1985 to 1989 average of 14.2 kWh/gallon of diesel fuel. Electrical utility use and distribution losses were assumed to remain constant at 16.8 percent that is the weighted 1987 to 1989 average. Diesel fuel cost in 1991 was reduced by $150,000 in taxes that the City would not charge itself. As recommended by AEA the fuel price was then escalated at 2 percent per year above the 4.5 percent general inflation rate. The next major component to the operating expense is an administrative support charge. The value of 17.75 percent was furnished by the City. The administrative support fee was calculated by multiplying 17.75 percent times the sum of operating costs before depreciation and estimated annual depreciation. In 1991, the administrative support fee at 17.75 percent was estimated to be $777,061. This support fee is a payment to other City departments for services they will provide. Currently the billing, accounting, payroll, data processing and personnel functions of BUC are performed in Anchorage. These functions, certain other clerical costs, office space, rent, installation and collection costs, and professional fee expenses, would become the responsibility of the City under the proposed purchase. The City will need to expend funds to perform these and other functions in support of a City- owned electric utility. The 1991 cost reduction to a City-owned utility by transfer of these functions to other departments is estimated to be $659,681 ($565,768 in wages & benefits and $93,913 in rents, etc.) There is also an assumed $150,000 per year reduction in City fuel tax revenues. Therefore, the imposition of the City’s standard 17.75 percent administrative support fee upon a City-owned utility for transferred functions appears reasonable based on the cost savings provided. A 1991 administrative support fee of 22.75 percent would collect $995,510. Salary and wages were estimated based on 1990 costs. The number of employees at the end of 1990 was reduced by 8 positions, whose duties were assumed transferred to other City Departments. The salary and wage expense category was further reduced by the salary of Mr. Harold Borrego. A new manager’s salary of $65,000 per year was added. Employee benefits were calculated by multiplying the revised salary and wage costs by the ratio of the remaining employees’ 1990 employee benefits to their 1990 salary cost. Due to transfer of functions and the reduced management costs, 1991 salary, wage, and employee benefits total $783,322. Other expense items were escalated from 1989 values at the 4.5 percent escalation rate furnished by AEA. The electric sales revenues were projected by multiplying the number of customers by the estimated 1991 revenue per customer for the residential, commercial, and large commercial classes. The 1991 revenue per customer was estimated from the 1989 historic value adjusted by the December 1990 and the recent 1991 APUC approved rate increases. As the price of diesel fuel increases, the fuel adjustment clause within the rate results in an automatic increase in the rate each customer pays. This element is also modeled and included in the "revenues per customer" estimates. Sales revenues for 1992 to 1995 were calculated in a similar way. In the alternate cases, sales revenues per customer were adjusted for an additional 5 or 10 percent City imposed rate increase. The total electric sales revenues for the alternate cases include an allowance for inflationary increases in non-fuel utility costs. 19 The revenues from the Bethel Cogeneration Utility are also a function of the price of diesel fuel and were so modeled. Miscellaneous revenues were assumed to increase at the general inflation rate. Interest income was calculated on each year’s beginning working capital fund and on the bond reserve fund. The interest rate was set at 90 percent of the bond issue rate to prevent loss of tax exempt status due to arbitrage. Cost Changes Due to City Ownership If the City acquires the BUC facilities, certain elements in the operations of the utility will change. For example, investor-owned utilities such as BUC set rates on the basis of recovering operating costs, depreciation, and providing a return on the rate-base (or assets.) A municipal utility generally sets rates based upon the utility’s cash flow requirements and any bond covenants. The different treatment of depreciation and debt service is the significant change in the cost structure. The financial model used to project future operating revenues accounts for these changes. In pursuing negotiations to the next logical step, a financial advisor and bond counsel will need to be retained. City departments also will need to examine and plan for the transfer functions they will be required to perform. We assume that the City will finance its potential purchase of the BUC properties with tax exempt bonds. While interest rates vary, a conservative rate of 8.5 percent for 20 year tax- exempt bonds was used. If the City pursues a purchase and bond market rates at the time of purchase are below 8.5 percent, then the City will either be able to offer a higher price, reduce rates below those projected, or set up a reserve fund for other purposes allowed under the bond covenants. Another change in the cost of the electric utility would be a reduction of approximately $150,000 per year in City fuel expense taxes. Similarly, certain utility staff functions such as personnel, accounting and billing were assumed to be combined with similar existing City functions. For the initial case, the City believes that a value of 17.75 percent for the administrative support fee is appropriate. Other City revenue fund enterprises also pay a 17.75 percent administrative support fee. A new electric utility manager will need to be hired to replace Mr. Borrego when he retires and sells his stock. While the new manager position could be combined with other City public works duties, we have assumed a separate electric utility manager. We have estimated that such a position would have a salary of approximately $65,000 per year and a benefits package of approximately $41,140 per year initially. As part of the conditions of the sale, we assume that the City will assume the outstanding AEA loan used to finance the cogeneration facilities and the Small Business Administration loan used to finance the current powerhouse after the 1975 fire. We have assumed no debt service coverage requirements on these loans. The 1990 year end balance on the AEA loan was $481,566. The 1990 year end balance on the Small Business Administration loan was $1,258,414. We further assume that all other long term debt is retired as a condition of the sale. 20 Other Cost Relationships Most of the other significant costs of the utility will not change with ownership. For example, the principal operating expenses, such as the basic cost of diesel fuel before City taxes, should remain the same. The basic fuel efficiency of the engine generators, the costs of line equipment and replacement parts should also be independent of the ownership of the utility. Finally, Power Cost Equalization program payments to utility customers should be equivalent. The effects of future inflation should not be a function of ownership. The costs and revenues of the cogeneration utility also should not change with ownership. As explained elsewhere within this section, we are assuming that most, but not all, Bethel operating labor expenses would be similar under City or private ownership. Therefore, assuming the retention of qualified operating people, most operating expenses will remain roughly the same. This means that the major changes will be in the areas of the treatment of debt service versus depreciation, and in the reductions in labor costs versus the 17.75 percent administrative support fee. Proposed Electric System Management The City-owned electric system, like most other municipality-owned utilities, should not be subject to regulation by the Alaska Public Utilities Commission (APUC). However, to provide for a smooth transition to City ownership we assume that the City initially intends to conduct its electric system business in accordance with the rules and regulations as currently approved by the APUC for BUC (i.e., policies relating to new connects, disconnects, deposits, fuel surcharges, etc.) After a reasonable period of operating experience, the City may change these rules and regulations if it determines such change is in the best interest of the City and electric system ratepayers. Prior to a sale, the City should obtain either APUC, legal counsel, or the State Attorney General’s opinion on City regulation by the APUC. City representatives have indicated that the City intends to retain, to the extent practical, the existing BUC staff to provide operation and management services for the electric system. This decision should also assist in a smooth transition to City ownership. The ability of the electric utility to continue to operate will depend upon the capability of the staff retained and hired by the City. The City Departments are assumed to perform the transferred functions as effectively as current BUC staff. Our analysis is based upon the assumption that past practices and efficiencies will continue for the forecast period. For our analysis we also assume that the Bethel City Council will approve budgets and establish rates sufficient to pay for electric system services. The City has indicated an intent to establish a separate board to advise the City Council on all matters relating to the ownership or operation of the electric system. Such an advisory board is often used by cities owning their own electric utilities. The City of Nome’s Joint Utility System can serve as a good example of how such a utility board can be structured. In Nome the utility board is composed of five members elected to staggered terms of office in the general City elections. Three board members have three year terms and two have two year terms. The size and the terms of office provide for 21 continuity of policy recommendations. Typically, the Nome Joint Utility System Board meets once a month as a committee of the whole to make its policy recommendations. The Board hires and supervises the utility manager. It also approves the budgets, capital and O&M plans of the utility and labor negotiations. Budgeting and labor negotiations sometimes require additional workshop meetings. The City Council has an approval/disapproval vote on the annual Utility System budget, any changes in rates, and any bond issues. While the Utility System Board can request changes to specific items within the budget, the City Council only reviews the budget as a whole. For Nome the annual Utility System Board cost is about $10,000 to $12,000. The board has no staff, except for the staff that reports to the general manager. Specific costs of the board have not been included in the analysis. It is assumed that the board would be funded by the City from the administrative support fee. The Nome Joint Utility System is currently an electric, water and sewer utility. The employees of the Nome Joint Utility System are organized into three union or bargaining groups. One group is the operating engineers for the powerhouse employees. A second group is the IBEW electrical line workers. The third group is for utility clerical, sewer, and water utility employees. The City of Nome is currently exploring moving the water and sewer functions to the Public Works Department and keeping the electric utility operations as a separate function. This potential realignment of functions recognizes that power generation and electric distribution system operation are fundamentally different than other City functions. If the City purchases the BUC facilities, it will be important to provide the City-owned utility with a management structure that is oriented toward providing electric service and a reliable cost effective system. Electric utilities have long term (ten to thirty year) capital commitment and investment horizons. Utility operations management and policy guidance needs to retain such a long term focus. This is why many successful utilities have policy boards appointed or elected to terms longer than typical City Council members and why City Councils do not usually have budget line item authority. In addition to structuring an effective utility board, Bethel will need to hire a qualified electric utility general manager who has both power production, power operations and utility economics skills. Customers, Energy Sales and Energy Requirements As was discussed above, diesel fuel expenses represent over half the operating expenses. The fuel expense is a function of the rate at which the price of fuel is expected to increase, engine generator efficiency, and the total energy requirement. The energy requirement is a function of system electrical losses and of energy sales. Energy sales are projected to be a function of the number of customers by class and an average energy consumption per customer for each class of customer. CH2M HILL has prepared projections of customers, energy sales, and energy requirements for the period 1991 through 1995 for the initial case and each alternate case or scenario. The initial case assumes that there is no growth in the number of customers. Because of the lack of detailed population projections, we contacted the Institute for Social and Economic Research (ISER) and found that while they had no current forecast, their unofficial 22 expectations were for little to modest growth in the Bethel area. There are several factors that could either increase or decrease the number of customers or the level of electric sales. Based upon this information and discussions with AEA, we determined that an assumption of no customer increases is appropriate. Increases or decreases in the level of loads were examined with alternate scenarios. The initial case also assumes that there is no change in the current energy use per customer patterns. Even though historic energy sales per customer have shown a steady increase, for our analysis we assumed that energy sales per customer will remain unchanged during the study period. This assumption results in no growth in energy sales and energy requirements as shown in Table 16. Future uncertainties in load growth and load reduction are examined by the use of alternate scenarios and were discussed in the "Alternate Case" section. Electric sales revenues per customer were forecast at 1989 levels adjusted for the rate increases approved by the APUC in 1990 and 1991. Under that rate structure, increases in fuel prices will increase the fuel surcharge. Future forecasts of revenues and revenues per customer have been increased by projected increases in the fuel surcharge. The fuel surcharge increases due to the assumption that fuel prices will increase at 2 percent above the 4.5 percent general inflation rate. Revenues, including those from the fuel adjustment clause, were tested to see that they would maintain a minimum 45 days working capital requirement and that debt service coverage on initial City-owned utility bonds exceeds the 1.20 minimum. No coverage requirement was assumed on either the AEA or the SBA debt. Working Capital is defined as Current Assets minus Current Liabilities, and refers to the balance available for payment of normal operating costs. A 45 days Working Capital requirement is an generally accepted industry value. Because of the size and nature of the administrative support fee, we have assumed that Working Capital is calculated on the basis of total operating expenses exclusive of the administrative support fee. Debt service coverage of 1.20 is indicative of a bond below investment grade. In discussions with AEA, we learned that other small Alaska municipals, which issue bonds with credit enhancements, can base their coverage on a 1.20 debt service requirement. Sales revenues include historic levels of sales to Napakiak and Oscarville but not recent sales to Napaskiak. In 1989 Napaskiak used 43,000 gallons of diesel fuel and generated 345 MWh of electricity according to AEA documents. Their fuel efficiency was approximately 8 kWh/gallon. This is well below the 14.2 kWh/gallon five year BUC average. Therefore, sales should benefit both communities economically. In 1989, total BUC sales were approximately 27,917 MWh. If the City served the total Napaskiak load, the City’s load would increase about 1.24 percent. This is within the moderate growth scenario discussed in the "Alternate Cases" section. Power Cost Equalization Program Benefits For 1989 Power Cost Equalization (PCE) payments by the state totaled $674,604. This was equivalent to about 14 percent of the total sales revenues for 1989. Sales revenues reported by BUC and contained within Table 9 are based on the full tariff rate. The revenues include both customer and state PCE payments. Revenue projections in Table 16 and Table 17 are also based upon the full tariff. 23 If PCE program payments are decreased by the state, the forecast revenue values would not change. However, the reduction in PCE payments would result in increased consumer payments and costs. These costs would principally impact the residential and small commercial customers. These increased costs could have “price elasticity" impacts on consumption, reducing energy consumption per customer. While we have not explicitly modeled such a scenario, a load reduction scenario was modeled. We examined the recent 20 percent reduction in PCE benefits and concluded that the impact was within the impact of the load reduction scenario. Table 16 INITIAL CASE PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System 1991 1992 1993 1994 1995 Customers Residential 1,478 1,478 1,478 1,478 1,478 Commercial 280 280 280 280 280 Large Commercial/Resale 6 6 6 6 6 Total Customers 1,764 1,764 1,764 1,764 1,764 Electric Sales Revenues Residential $1,773,560 $1,828,594 $1,887,862 $1,951,364 $2,018,252 Commercial 2,347,532 2,428,560 2,515,822 2,609,316 2,707,797 ‘Large Commercial/Resale 1,189,855 1,235,255 1,284,147 1,336,532 1,391,710 Additional Revenue for Debt Service Coverage 0 0 0 0 0 Additional Revenue for Working Capital 0 0 0 0 0 Total Sales Revenues 5,310,946 5,492,409 5,687,831 5,897,211 6,117,758 Unit Revenue or Average Retail Rate(cents/kWh) 19.0 19.7 20.4 21.1 21.9 Delinquent fees $36,575 $38,221 $39,941 $41,738 $43,616 Misc Service Revenues 3,135 3,276 3,423 3,577 3,738 Other Electric Revenues 4,180 4,368 4,565 4,770 4,985 Total Electric Operating Revenues 5,354,836 5,538,274 5,735,760 5,947,296 6,170,097 Sales Revenue per Customer Residential (1989 Actual) 1,072 1,072 1,072 1,072 1,072 1990 & 91 increases & fuel adjustment 128 166 206 249 294 Revised Res Rev/Customer 1,200 1,237 1,277 1,320 1,366 Commercial (1989 Actual) 7,508 7,508 7,508 7,508 7,508 1990 & 91 increases & fuel adjustment 876 1,165 1,477 1,811 2,163 ‘Revised Com Rev/Customer 8,384 8,673 8,985 9,319 9,671 Large Commercial/Resale (1989 Actual) 178,077 178,077 178,077 178,077 178,077 . 1990 & 91 increases & fuel adjustment 20,232 27,799 35,948 44,679 53,875 Revised Large Com Rev/Customer 198,309 205,876 214,024 222,755 231,952 All Customer Classes, Revised 3,011 3,114 3,224 3,343 3,468 Energy Sales (kWh) Residential 8,466,838 8,466,838 8,466,838 8,466,838 8,466,838 Commercial 12,465,913 12,465,913 12,465,913 12,465,913 12,465,913 Large Commercial/Resale 6,984,620 6,984,620 6,984,620 6,984,620 6,984,620 Total Sales (kWh) 27,917,371 27,917,371 27,917,371 27,917,371 27,917,371 Losses & Utility use (kWh) 4,690,118 4,690,118 4,690,118 4,690,118 4,690,118 Losses & Utility use (%) 16.8% 16.8% 16.8% 16.8% 16.8% Total Energy Requirements (kWh) 32,607,489 32,607,489 32,607,489 32,607,489 32,607,489 24 Analysis of the City-owned Electric System The projected operating results for the initial case of the City-owned electric system are shown in Table 17. The forecast is based upon energy sales and requirements shown in Table 16. Total operating revenues for this case are projected to increase 3.6 percent per year during the period 1991 through 1995. During this same period, revenues associated with residential customers are projected to increase 3.2 percent per year, commercial customers 3.6 percent per year, and large commercial and resale operating revenues 4.0 percent per year. Projected future operating expenses are based on BUC’s 1989 revenue adjusted for the December 1990 and the recent 1991 APUC approved rate increases plus estimated fuel surcharges. Total projected operating expenses are assumed to increase 5.7 percent per year during the period 1991 through 1995. Fuel expenses are assumed to increase 6.6 percent per year and most other expenses were assumed to increase at the inflation rate of 4.5 percent per year. Net operating revenues are forecast to decrease at about $108,600 per year for the 1991 to 1995 period. For the initial case this result is caused by the assumption that non-fuel expenses increase with inflation, but that rates are not changed to reflect these increased costs. It is unlikely that either a City-owned or privately-owned utility would be operated in this fashion. For this reason, alternate cases were examined that assume rates would be increased for the purpose of passing along inflationary costs. During the 1991 through 1995 period, large and small commercial customers are projected to contribute 67 percent of the operating revenue; and residential customers, the State of Alaska and other miscellaneous sources contribute the remaining operating revenues. Both the AEA and SBA loan payments are assumed to continue upon sale to the City. Projected fuel expenses are shown in Table 18. In accordance with AEA’s recommendation, the average price of fuel is projected to increase at 2 percent above the assumed 4.5 percent per year general inflation rate. It increases at an average rate of 6.6 percent per year (1.066 = 1.045 x 1.02) between 1991 and 1995. Fuel efficiency is assumed to remain constant at 14.2 kWh/gallon, which was the five year average from 1985 to 1989. 25 Table 17 INITIAL CASE PROJECTED OPERATING RESULTS City Owned Electric System $5,310,946 $5,687,831 $5,897,211 $6,117,758 43,890 45,865 47,929 50,085 52,339 5,354,836 5,538,274 5,735,760 5,947,296 6,170,097 2,777,607 2,960,622 3,155,578 3,363,623 3,585,216 479,702 501,289 523,847 547,420 572,054 121,609 127,081 132,800 138,776 145,021 25,384 26,526 27,720 28,967 30,271 35,237 36,823 38,480 40,212 42,022 299,936 313,433 327,537 342,276 357,678 Employee Benefits 303,620 317,283 331,561 346,481 362,073" Insurance 166,661 174,161 181,998 190,188 198,746 Rent, Office, Professional fees, Installation and collections 0 0 0 0 0 Uncollectible accounts 598 625 653 682 713 Other 9,187 9,600 10,032 10,483 10,955 Added Environmental costs 0 0 0 0 0 Administrative Support Fee $777,061 $792,971 $839,612 $889,117 $941,593 Admin. Support Fee Percent 17.75% 17.75% 17.75% 17.75% 17.75% Total Operating Expense (w/o deprec.) $4,996,602 $5,260,414 $5,569,818 $5,898,225 $6,246,342 fj Net Operating Revenues 358,234 277,860 165,942 49,071 (76,245) Interest Income (WC and Reserve Fund) 42,303 61,015 76,024 84,706 86,276 Bethel Cogeneration Utilities net income 254,750 271,538 289,432 308,506 328,837 Other Income Funds Available for Debt Service and other purposes 655,287 610,413 531,398 442,283 338,868 Debt Service Initial Bonds 32,547 32,547 32,547 32,547 32,547 Small Business Admin. Loan 204,804 204,804 204,804 204,804 204,804 AEA BCU Loan 94,966 94,966 94,966 94,966 94,966 Total Debt Service $332,317 $332,317 $332,317 $332,317 $332,317 Debt Service Coverage on Initial Bonds 10.92 9.54 712 4.38 1.20 Minimum Debt Service Coverage on Initial Bonds 1.2 1.2 1.2 1.2 1.2 Beginning Working Capital $520,200 $764,795 $960,989 $1,074,483 $1,095,010 Balance Available for Other Purposes 843,170 1,042,891 1,160,071 1,184,449 1,101,561 Capital Improvements (78,375) (81,902) (85,588) (89,439) (93,464) Ending Working Capital $764,795 $960,989 $1,074,483 $1,095,010 NOTES ON INITIAL CASE (1) General Inflation rate = 4.50% (2) Dec. 1990 rate increase= 10.09% source APUC U-90-33 page 5 of 8 (3) APUC approved 1991 rate increase = 4.54% (4) Min. Debt Service Coverage = 1.2 (5) Bond Term is for 20 (©) Bond interest rate is 8.50% (7) Bond Size $308,000 (8) Purchase Price $47,000 (9) Reserve Fund 32,784 (10)Short term interest rate 7.65% (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating Revenues escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $220,000 if from Bond Proceeds. Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses less Administrative Support Fees [45/365*(TOE-ASF)]. (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt (15)Non-fuel cost increases passed on to customers starting after 1991 26 Table 18 PROJECTED FUEL COST ALL CASES City Owned Electric System Average Fuel Price ($/Gallon) $1.2096 $1.2893 $1.3742 $1.4648 Fuel Cost ($) 2,960,622 3,155,578 3,363,623 Electric System Capital Improvements Capital improvements for the distribution plant were modeled base on changes in the number of customers and our experience and judgment obtained in connection with the design and construction of similar electric system facilities. Table 19 shows our projections of plant-in- service, annual capital additions, and depreciation. BUC staff indicated that no new diesel engines are required until after the year 2000. Changes in depreciation are based upon 3.28 percent of the annual beginning plant-in-service. The 3.28 percent is based on the 1985 to 1989 average depreciation rate. Capital additions are assumed to start at about $3,800 per new customer and $75,000 per year in 1990 dollars. These values are increased at the inflation rate. Because the initial case assumes no increase in the number of customers, the increase in plant-in-service is limited to the miscellaneous unspecified renewals and replacements which range between $78,375 in 1991 and $93,464 in 1995. Table 19 PLANT-IN-SERVICE AND DEPRECIATION City Owned Electric System 1992 1993 1994 1995 Beginning Plant-In-Service $4,984,488 $5,066,390 $5,151,978 $5,241,417 Net change in Plant-In-Service 78,375 81,902 85,588 89,439 Ending Plant-In-Service 4,984,488 5,066,390 5,241,417 5,334,881 Utility Plant Depreciation Beginning Accumulated Depreciati 2,470,476 2,631,201 2,794,492 2,960,467 Net Change in Accumulated Depreciati 160,724 168,779 171,709 2,631,201 2,794,492 2,960,467 Net Plant-In-Service (Year end) $2,353,287 $2,271,898 $2,112,171 i i (| Average Depreciation Rate 27 ALTERNATE CASES The future electric system operating results depend on a number of factors. The principal factors are changes in retail rates, numbers of customers, energy sales, diesel fuel cost, and the purchase price of BUC assets. The constraints place upon the initial case, specifically the requirement of no rate increase for 5 years, does not lead to a practical outcome. Therefore, to provide the City with guidance on a purchase price we performed two types of ‘additional analysis. The first type of analysis was to estimate the value of the utility based upon a review of asset values. The second approach involved the estimation of supportable bond issue sizes based on alternate sets of assumptions. Alternate Evaluation Cross Check of Asset Values While not within the scope of work contracted by AEA, an independent cross check is a valuable tool in reviewing the results of computer modeling. The results of the initial case also required us to test the key assumptions that had originally been agreed to by both AEA and the City. Therefore, we performed a cursory examination of the value of the BUC assets not based upon projected revenues or bond issue sizes. This examination is documented in this section. Two methods sometimes used to evaluate the cost of purchasing electric utility facilities by a City are: (1) net book value or original book cost less depreciation; and (2) reproduction cost less depreciation (RCLD). The 1989 BUC Financial Statement shows BUC net book value at $2.5 million ($4.8 million original cost and $2.3 million depreciation). The net book value method generally results in a sale price lower than an owner will voluntarily accept. We next estimated the value based on RCLD. Based upon work for another Alaska utility, the cost of 10,500 kW of new GM-EMD engine generators, switchgear, I&C, construction and freight should be about $6.4 million. To this we added $2.2 million to cover the cost of a metal building to enclose the generators. For our modeling of capital additions we are assuming about $3,800 per customer. This value was from previous work for Yakutat. AEA requested us to contact other Alaska utilities to discuss the reasonableness of our $3,800 value. Based upon our discussions with individuals at both AVEC and AEL&P a value of $3,800 appears reasonable. Therefore, for approximately 1,764 customers at $3,971 ($3,800 * 1.045) per customer requires distribution plant replacement capital of $7,004,844. The 1989 balance sheet shows the original value of general plant at $0.8 million. We estimated the replacement cost to be about $1 million. Combined generation, distribution, and general plant replacement costs total about $16.6 million. The current facilities are depreciated to about 48 percent ($2.3 million/ $4.8 million). Therefore the replacement cost less depreciation would be about $8.6 million ($16.6 million - $8 million). This amount should be increased for BCU properties. We do not have a replacement cost estimate or depreciation values for BCU. The outstanding balance on the loan that financed the BCU properties is about $0.5 million. We assumed this $0.5 million approximately represents the depreciated value of BCU. The total value of the assets calculated by this method is roughly $9.1 million. The RCLD method values the long term capital assets and system that would be turned over 28 to the City. The City also wishes to acquire an operating entity and therefore, desires the inventory, accounts receivables and other current assets. If the City acquires the current assets it should also be responsible for the operating current liabilities. As such, the price could be adjusted to account for the working capital transferred by BUC. Our analysis assumes a typical working capital value of 45 days annual total operating expenses (exclusive of administrative support fee.) To the extent working capital is below this value we would recommend that the bond issue proceeds be used to fund the 45 day level. Another adjustment that would need to occur would be to reduce the sale price for any assumed long term debt that would be transferred by BUC to the City. In this case the value should be reduced by the combined outstanding principal on the AEA and SBA loans. While we do not have figures on current levels of working capital and the current outstanding SBA and AEA debt, we have historic values. The working capital for BUC from 1986 to 1989 is shown in Table 20. The 1989 value was unusual and due principally to a $500,000 note. We assume that working capital transferred by BUC at the time of sale would be close to the 1986 to 1988 average of roughly $300,000. This is roughly half of the total required Working Capital assumed in our analysis. The combined year end 1989 outstanding balance on the SBA and AEA loans was approximately $1.7 million. Table 20 HISTORIC WORKING CAPITAL Bethel Utilities Corporation Working Capital 1989 -$511,323 SC Sk Therefore, a rough approximation of the system value using the RCLD method would be $7.7 million ($9.1 million + $0.3 million - $1.7 million.) This value assumes a transfer of working capital and AEA and SBA debt to the City. All other significant debts would not be transferred to the City at the time of the sale. In the 1989 Financial Statement, additional long term debt totaled about $2.5 million. A third estimate of the value of the BUC properties can be derived from a 1982 appraisal study. The results of that study established a value of approximately $4.159 million as of the end of 1980. Since the appraisal was performed the BCU assets have been added, much of the distribution system has been replaced, and 468 customers, about a quarter of the distribution system, have been added. However, the system has also had a decade of additional depreciation. Based upon the above considerations a purchase price in the range of $4 to $6 million 29 calculated by the financial model appears appropriate. Again, the purpose of this section was to provide a crude independent cross check on the results of the computer analysis. Alternate Case Overview The principal method of evaluation used for this report was to determine the amount of bond proceeds that a City owned utility can support based upon a forecast of expected costs and revenues. To estimate the bond proceeds we constructed a financial model of the utility. This model, when combined with certain assumptions and data provided by the project sponsors, estimated the annual funds that can be applied to debt service and the changes in working capital. From this a maximum bond issue can be sized that will not violate either the 1.2 debt service coverage requirement or the 45 day working capital requirement. Because the future cannot be absolutely predicted, variations in the values used for some of the major assumptions were examined so that the City can judge how sensitive the results are to these assumptions. We were instructed by AEA to use for all but the Initial Case, an administrative support fee on operating expenses and depreciation of 22.75 percent. Similarly, in all but the initial case, sales revenues and rates were allowed to increase so that inflationary costs are incorporated into the sales revenues. We also initially agreed to run a load reduction scenario, a moderate load growth scenario, a moderate environmental cost increase scenario, and an initial year rate increase scenario. These initial modeling instructions produced results that would not support bond issues of a value within the range determined by the cross check. A special case was also requested that would have supported a purchase with two bond issues. The first bond issue would be a normal 8.5 percent interest rate, 20 year tax-exempt issue with 3 percent issuance costs that would yield $2 million in net proceeds. The second bond issue would be a thirty year tax-exempt issue, at 5 percent interest rate, with 1 percent issuance costs. The second bond issue was to be sized so that its initial annual debt service plus the initial debt service on the $2 million in proceeds issue was equal to the debt service on an 8.5 percent interest rate, 20 year tax-exempt bond issue used in the initial case. Without an initial year rate increase or an initial reduction in the first year’s administrative support fee, this case resulted in a purchase price below the range determined by the cross check. In examining the impact of either load reductions or moderate load increases there were minor changes in the size of the supportable bond issues. The reason for the minor changes is that we were assuming that any changes in non-fuel operating expenses would be passed on to the customers. Therefore, in the load reductions scenario, loads were reduced, but the amount of inflationary rate increase each customer would see would increase. In the moderate load growth assumption, the new customers require new capital expenditures but also spread the inflationary costs over more kWh sales. The moderately high environmental cost increase scenario also reduces the bond issue size slightly. The reduction is slight because of the assumption allowing the utility to pass inflation related costs onto the customers. 30 In examining the alternate cases, certain factors dominate the analysis. For example, by allowing the rates to increase for non-fuel operating expenses, generally, if debt service coverage requirements can be meet for the first year, they will be met for all subsequent years. This is because the BCU and other nonoperating income are also increasing with time, resulting in the such funds available for debt service increasing faster than total operating expenses. Similarly, for most cases where bond issues are in the range of $2 million to $10 million, debt service is a more binding constraint that working capital. In examining the first year projections, there are two ways in which the City could increase the ability of a City-owned utility to meet the 1.2 times debt service coverage requirement. The first would be to reduce the first year’s administrative support fee from 22.75 percent to 17.75 percent. Even by doing this the maximum supportable purchase price is about $2.1 million. The second alternative is to impose an additional rate increase in 1991. If the administrative support fee is kept at 22.75 percent and an additional 10 percent 1991 rate increase is imposed, then a maximum purchase price of about $4.395 million can be supported. If both an initial year 17.75 percent administrative support fee increasing in subsequent years to 22.75 percent and an initial year 10 percent rate increase are assumed, then the supportable purchase price increases to $5.996 million. Because of these factors, we ran a series of additional cases that support a purchase within the range determined by the cross check. This analysis was based upon assumptions that may or may not be acceptable to the City and the customers of BUC. Therefore, the results will need to be carefully examined and discussed with Bethel. Our additional analysis of alternate cases is based upon a 10 percent rate increase in 1991 (above current APUC approved rates) and an initial 17.75 percent administrative support fee. In subsequent years the administrative support fee is allowed to increase to 22.75 percent and rates are allowed to increase for non-fuel inflationary costs. In examining the additional cases, it should be pointed out that the inflationary cost based rate increases could be reduced slightly and still meet minimum debt service and working capital requirements. Similarly, if a 10 percent initial rate increase is judged too high, then a slightly lower purchase price will be necessary. If the initial year’s administrative support fee must be above the 17.75 percent value, then a slightly lower purchase price should be agreed upon. There is much that needs to be done before a final agreement can be made between the City and BUC. Legal counsel must be retained, draft contracts negotiated, investment bankers will need to determine the marketability of bonds and the method of credit support. The analysis contained within this report is to determine if the City and BUC are close enough so that negotiations should be pursued to the next logical step of defining price and terms. Initial Case The initial case was based upon no population growth, no increase in energy consumption, fuel prices escalating at 2.0 percent above the assumed 4.5 percent general inflation rate, and no retail rate increase until 1996. The level of rates included the assumption that the recently approved 4.54 percent rate increase was the basis from which rate changes were measured. The conclusion from this case is that the City cannot successfully negotiate the purchase of the BUC properties without being willing to have a rate increase above the 31 current levels. What leads to this result is that operating expenses were increasing faster than operating income because non-fuel expenses were not included in the fuel adjustment surcharge. As a result, the amount of additional bonds that the City-owned utility could support and maintain at a 1.2 debt service coverage ratio and a minimum 45 day Working Capital level are well below the amount needed for an acceptable offer to BUC. Special Initial Year Scenario As discussed above, we assumed that the 1991 administrative support fee was set at 17.75 percent and allowed to increase to 22.75 percent and remain there during 1992, 1993, 1994 and 1995; that an initial City rate increase of 10 percent above existing rates is initiated; and rates are raised to collect additional revenues equal to increases in inflationary costs. Under these assumptions a purchase price of $5,996,000 is supportable by the utility. The projected costs and revenues are detailed in Table 21. The revenue requirement in cents per kWh, which is a proxy for the average retail rate, is also calculated and shown in Table 22. Load Reduction Scenario The assumptions in the "Special Initial Year Scenario" were retained and we examined the electric system’s sensitivity to a load decrease or "load reduction scenario." The load reduction scenario assumed an annual compound decrease in residential customers of 2.0 percent per year over the 1991 through 1995 period. This scenario reduced the supportable purchase price to $5,724,000. Tables 23 and 24 document the resulting revenues, costs and expenses. As was pointed out above the purchase price does not appear to be extremely sensitive to the load level because of the assumption that the City could pass costs on to the remaining customers. Moderate Load Growth Scenario A moderate load growth scenario was examined. This analysis assumed that the number of residential customers increases at 2 percent per year. The 2 percent value was based upon the City furnished population estimate. This results in a supportable purchase price of $6,274,000. Tables 25 and 26 contain the detailed analysis. 5 Percent 1991 Rate Increase Scenario If we assume that the City of Bethel would be willing to raise it rates in 1991 only 5 percent above the existing rates, then the supportable purchase price would decrease to $4,178,000. This was detailed in Tables 27 and 28. A 5 percent change in the initial year’s retail rate represented about a $1,818,000 change in the purchase price. This represented over $300,000 in supportable purchase price per percentage point of initial retail rate. Moderately High Environmental Cost Scenario FPE/Roen has performed a survey of Alaska utilities and determined that a moderately high environmental cost scenario would have environmental costs increasing at about one quarter of one percent of the operating budget (before administrative support charges) per year. 32 Therefore, the added environmental expenses started at 0.25 percent and increased to 1.25 percent in 1995. These added costs reduced the supportable purchase price from our "Special Initial Year Scenario" to $5,905,000. Tables 29 and 30 contain the information on this alternate case. Special Initial Year & 5% Bond Issue Scenario Our final alternate case was to combine the "Special Initial Year Scenario" assumptions with two tax-exempt bonds issues of 5 percent and 8.5 percent interest rates. The first bond issue would be a 8.5 percent interest rate, 20 year, 3 percent issuance cost, tax-exempt bond issue that would yield $2 million in cash proceeds plus $220,200 in working capital and a reserve fund. The second bond issue would be a thirty year, tax-exempt issue, at 5 percent interest rate, with 1 percent issuance costs. The second bond issue was to be sized so that its initial annual debt service plus the debt service on the 8.5 percent interest rate, 20 year tax-exempt bond issue with $2 million in proceeds equaled the debt service of the special initial year 8.5 percent interest rate bond issue. This analysis is shown in Tables 31 and 32. It resulted in a supportable purchase price composed of $2,000,000 in cash from the proceeds of the 8.5 percent interest rate, 20 year, tax-exempt bonds and a 5 percent interest rate bond issue sized at $7,475,000 that provides annual debt service payments of $486,259 for 30 years to current owners of BUC. CH2M HILL makes no claim as to whether such privately placed bonds would be tax-exempt or if the 8.5 percent bond issue would be marketable. We suggest that the City retain the services of special bond counsel and a financial advisor help in the structuring of non-traditional financing. 33 Table 21 SPECIAL INITIAL YEAR SCENARIO PROJECTED OPERATING RESULTS City Owned Electric System $5,807,978 $6,297,138 $6,623,831 $7,337,248 43,890 45,865 47,929 50,085 52,339 5,851,868 6,343,003 6,671,760 7,021,454 7,389,587 2,777,607 2,960,622 3,155,578 3,363,623 3,585,216 479,702 501,289 523,847 547,420 572,054 121,609 127,081 132,800 138,776 145,021 25,384 26,526 27,720 28,967 30,271 35,237 36,823 38,480 40,212 42,022 299,936 313,433 327,537 342,276 357,678 Employee Benefits 303,620 317,283 331,561 346,481 362,073 Insurance 166,661 174,161 181,998 190,188 198,746 Rent, Office, Professional fees, Installation and collections 0 0 0 0 0 Uncollectible accounts 598 625 653 682 113 Other 9,187 9,600 10,032 10,483 10,955 Added Environmental costs 0 0 0 0 0 Administrative Support Fee $777,061 $1,016,343 $1,076,122 $1,139,572 $1,206,830 Admin. Support Fee Percent 17.75% 22.75% 22.75% 22.75% 22.75% Total Operating Expense (w/o deprec.) $4,996,602 $5,483,786 $5,806,328 $6,148,680 $6,511,579 Net Operating Revenues 855,266 859,216 865,432 872,774 878,007 Interest Income (WC and Reserve Fund) 97,653 103,240 110,570 120,024 131,927 Bethel Cogeneration Utilities net income 254,750 271,538 289,432 308,506 328,837 Other Income 0 0 0 0 0 Funds Available for Debt Service and other purposes 1,207,669 1,233,994 1,265,434 1,301,304 1,338,771 Debt Service Initial Bonds 756,499 756,499 756,499 756,499 756,499 Small Business Admin. Loan 204,804 204,804 204,804 204,804 204,804 AEA BCU Loan 94,966 94,966, 94,966, 94,966 94,966 Total Debt Service $1,056,269 $1,056,269 $1,056,269 $1,056,269 $1,056,269 Debt Service Coverage on Initial Bonds 1.20 1.23 1.28 1.32 1.37 Minimum Debt Service Coverage on Initial Bonds 1.2 1.2 1.2 1.2 1.2 Beginning Working Capital $520,200 $593,225 $689,049 $812,625 $968,222 Balance Available for Other Purposes 671,600 770,951 898,213 1,057,661 1,250,724 | Capital Improvements (78,375) (81,902) (85,588) (89,439) (93,464) } Ending Working Capital $593,225 $689,049 $812,625 $968,222 $1,157,260 NOTES ON ALTERNATE CASE (1) General Inflation rate = 4.50% (2) Dec. 1990 rate increase = 10.09% source APUC U-90-33 page 5 of 8 (3) APUC approved 1991 rate increase = 4.54% Additional City 1991 increase of 10 % (4) Min. Debt Service Coverage = 1.2 on initial bonds (no excess coverage on AEA or SBA debt service) (5) Bond Term is for 20 years (6) Bond interest rate is 8.50% (7) Bond Size $7,159,000 (8) Purchase Price $5,996,000 (9) Reserve Fund 756,314 (10)Short term interest rate 7.65% (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating Revenues escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $220,000 is from Bond Proceeds. Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses less Administrative Support Fees [45/365*(TOE-ASF)]. (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt (15)Residential customer load growth at 0.00% per year (used for sensitivity analysis) (16)Added environmental costs increasing annual at 0.0% of pre-Administrative Support operating budget (sensitivity analysis) (17)Non-fuel cost increases passed on to customers starting after 1991 34 Table 22 SPECIAL INITIAL YEAR SCENARIO PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System Residential 1,478 1,478 1,478 Commercial 280 280 280 Large Commercial/Resale 6 6 6 Total Customers 1,764 1,764 1,764 Electric Sales Revenues Residential $1,939,096 $1,994,130 $2,053,398 $2,116,900 $2,183,788 Commercial 2,567,332 2,648,360 2,735,622 2,829,116 2,927,597 Large Commercial/Resale 1,301,551 1,346,951 1,395,843 1,448,228 1,503,406 Additional Revenue for post 1991 non fuel cost increases 0 307,696 438,968 577,126 722,457 Additional Revenue for Debt Service Coverage 0 0 0 0 0 Additional Revenue for Working Capital 0 0 0 0 0 Total Sales Revenues $5,807,978 $6,297,138 $6,623,831 $6,971,369 $7,337,248 Unit Revenue or Average Retail Rate (cents/kWh) 20.8 22.6 23.7 25.0 26.3 Delinquent fees $36,575 $38,221 $39,941 $41,738 $43,616 Misc Service Revenues 3,135 3,276 3,423 3,577 3,738 Other Electric Revenues 4,180 4,368 4,565 4,770 4,985 Total Electric Operating Revenues $5,851,868 $6,343,003 $6,671,760 $7,021,454 $7,389,587 Sales Revenue per Customer ($) Residential (1989 Actual) 1,072 1,072 1,072 1,072 1,072 1990 & 91 increases & fuel adjustment 240 278 318 361 406 Revised Res Rev/Customer - 1,312 1,349 1,389 1,432 1,478 Commercial (1989 Actual) 7,508 7,508 7,508 7,508 7,508 1990 & 91 increases & fuel adjustment 1,661 1,950 2,262 2,596 2,948 Revised Com Rev/Customer 9,169 9,458 9,770 10,104 10,456 Large Commercial/Resale (1989 Actual) 178,077 178,077 178,077 178,077 178,077 1990 & 91 increases & fuel adjustment 38,848 46,415 54,564 63,295 72,491 Revised Large Com Rev/Customer 216,925 224,492 232,640 241,371 250,568 All Customer Classes, Revised 3,293 3,395 3,506 3,625 3,750 Energy Sales (kWh) Residential 8,466,838 8,466,838 8,466,838 8,466,838 8,466,838 Commercial 12,465,913 12,465,913 12,465,913 12,465,913 12,465,913 Large Commercial/Resale 6,984,620 6,984,620 6,984,620 6,984,620 6,984,620 Total Sales (kWh) 27,917,371 27,917,371 27,917,371 27,917,371 27,917,371 Losses & Utility use (kWh) 4,690,118 4,690,118 4,690,118 4,690,118 4,690,118 Losses & Utility use (%) 16.8% 16.8% 16.8% 16.8% 16.8% Total Energy Requirements (kWh) 32,607,489 32,607,489 32,607,489 32,607,489 32,607,489 35 Table 23 LOAD REDUCTION SCENARIO PROJECTED OPERATING RESULTS City Owned Electric System Operating Revenues Energy Sales Revenues $5,731,190 $6,175,569 $6,456,961 $6,756,784 $7,072,414 Other Revenues 43,890 45,865 47,929 50,085 52,339 Total Operating Revenues 5,775,080 6,221,434 6,504,890 6,806,869 7,124,753 Operating Expenses Fuel & Purchased Power 2,744,249 2,907,819 3,081,282 3,265,610 3,461,090 Salaries & Wages 479,702 501,289 523,847 547,420 572,054 Operation-generation 121,609 127,081 132,800 138,776 145,021 Operation-distribution 25,384 26,526 27,720 28,967 30,271 Operation-customer 35,237 36,823 38,480 40,212 42,022 Maintenance 299,936 313,433 327,537 342,276 357,678 Employee Benefits 303,620 317,283 331,561 346,481 362,073 Insurance 166,661 174,161 181,998 190,188 198,746 Rent, Office, Professional fees, Installation and collections 0 0 0 0 0 Uncollectible accounts 598 625 653 682 713 Other 9,187 9,600 10,032 10,483 10,955 Added Environmental costs 0 0 0 0 0 Administrative Support Fee $771,140 $1,004,331 $1,059,220 $1,117,274 $1,178,592 Admin. Support Fee Percent 17.75% 22.75% 22.75% 22.75% 22.75% Total Operating Expense (w/o deprec.) $4,957,323 $5,418,971 $5,715,130 $6,028,369 $6,359,215 Net Operating Revenues 817,757 802,464 789,760 778,500 765,538 Interest Income (WC and Reserve Fund) 94,768 103,614 112,845 122,765 133,619 Bethel Cogeneration Utilities net income 254,750 271,538 289,432 308,506 328,837 Other Income 0 0 0 o ° Funds Available for Debt Service and other purposes 1,167,275 1,177,616 1,192,037 1,209,771 1,227,994 722,895 722,895 722,895 722,895 722,895 204,804 204,804 204,804 204,804 204,804 94,966 94,966 94,966 94,966 94,966 $1,022,665 $1,022,665 $1,022,665 $1,022,665 $1,022,665 Debt Service Coverage on Initial Bonds 1.20 1.21 1.23 1.26 1,28 Minimum Debt Service Coverage on Initial Bonds 1.2 1.2 1.2 1.2 1.2 Beginning Working Capital $516,100 $631,741 $752,401 $882,070 $1,023,960 Balance Available for Other Purposes 660,710 786,691 921,773 1,069,175 1,229,290 Capital Improvements (28,970) (34,291) (39,703) (45,215) (50,838) Ending Working Capital $631,741 $752,401 $882,070 $1,023,960 $1,178,451 NOTES ON ALTERNATE CASE (1) General Inflation rate = 4.50% (2) Dec. 1990 rate increase = 10.09% source APUC U-90-33 page 5 of 8 (3) APUC approved 1991 rate increase = 4.54% Additional City 1991 increase of 10 %. (4) Min. Debt Service Coverage = 1.2 on initial bonds (no excess coverage on AEA or SBA debt service) (5) Bond Term is for 20 years (6) Bond interest rate is 8.50% (7) Bond Size $6,841,000 (8) Purchase Price $5,724,000 (9) Reserve Fund 722,697 (10)Short term interest rate 7.65% (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating ReveMwes escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $216,100 is from Bond Proceeds. Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses less Administrative Support Fees [45/365*(TOE-ASF)]. (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt (15)Residential customer load growth at -2.00% per year (used for sensitivity analysis) (16)Added environmental costs increasing annual at 0.0% of pre-Administrative Support operating budget (sensitivity analysis) (17)Non-fuel cost increases passed on to customers starting after 1991 36 Table 24 LOAD REDUCTION SCENARIO PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System Commercial 280 280 2380 Large Commercial/Resale 6 6 6 Total Customers 1,677 1,649 1,595 Electric Sales Revenues Residential $1,862,308 $1,876,860 $1,893,989 $1,913,510 $1,934,492 Commercial 2,567,332 2,648,360 2,735,622 2,829,116 2,927,597 Large Commercial/Resale 1,301,551 1,346,951 1,395,843 1,448,228 1,503,406 Additional Revenue for post 1991 non fuel cost increases 303,399 431,507 565,931 706,920 Additional Revenue for Debt Service Coverage 0 0 0 0 Additional Revenue for Working Capital 0 0 0 0 Total Sales Revenues $5,731,190 $6,175,569 $6,456,961 $6,756,784 $7,072,414 Unit Revenue or Average Retail Rate (cents/kWh) 20.8 22.5 23.7 a9 26.2 Delinquent fees $36,575 $38,221 $39,941 $41,738 $43,616 Misc Service Revenues 3,135 3,276 3,423 3,577 3,738 Other Electric Revenues 4,180 4,368 4,565 4,770 4,985 Total Electric Operating Revenues $5,775,080 $6,221,434 $6,504,890 $6,806,869 $7,124,753 Sales Revenue per Customer ($) Residential (1989 Actual) 1,072 1,072 1,072 1,072 1,072 1990 & 91 increases & fuel adjustment 240 278 318 361 406 Revised Res Rev/Customer 1,312 1,349 1,389 1,432 1,478 Commercial (1989 Actual) 7,508 7,508 7,508 7,508 7,508 1990 & 91 increases & fuel adjustment 1,661 1,950 2,262 2,596 2,948 Revised Com Rev/Customer 9,169 9,458 9,770 10,104 10,456 Large Commercial/Resale (1989 Actual) 178,077 178,077 178,077 178,077 178,077 1990 & 91 increases & fuel adjustment 38,848 46,415 54,564 63,295 72,491 Revised Large Com Rev/Customer 216,925 224,492 232,640 241,371 250,568 All Customer Classes, Revised 3,360 3,501 3,653 3,817 3,990 Energy Sales (kWh) Residential 8,131,551 7,968,920 7,809,542 7,653,351 7,500,284 Commercial 12,465,913 12,465,913 12,465,913 12,465,913 12,465,913 Large Commercial/Resale 6,984,620 6,984,620 6,984,620 6,984,620 6,984,620 Total Sales (kWh) 27,582,084 27,419,453 27,260,075 27,103,884 26,950,817 Losses & Utility use (kWh) 4,633,790 4,606,468 4,579,693 4,553,453 4,527,737 Losses & Utility use (%) 16.8% 16.8% 16.8% 16.8% 16.8% Total Energy Requirements (kWh) 32,215,874 32,025,921 31,839,768 31,657,337 31,478,554 37 Table 25 MODERATE LOAD GROWTH SCENARIO PROJECTED OPERATING RESULTS City Owned Electric System Operating Revenues Energy Sales Revenues $5,886,318 $6,427,702 $6,809,174 $7,216,189 $7,646,597 Other Revenues 43,890 45,865 47,929 50,085 52,339 Total Operating Revenues 5,930,208 6,473,567 6,857,103 7,266,274 7,698,936 Operating Expenses Fuel & Purchased Power 2,811,640 3,015,581 3,234,468 3,469,799 3,722,397 Salaries & Wages 479,702 501,289 523,847 547,420 572,054 Operation- generation 121,609 127,081 132,800 138,776 145,021 Operation-distribution 25,384 26,526 27,720 28,967 30,271 Operation-customer 35,237 36,823 38,480 40,212 42,022 Maintenance 299,936 313,433 327,537 342,276 357,678 Employee Benefits 303,620 317,283 331,561 346,481 362,073 Insurance 166,661 174,161 181,998 190,188 198,746 Rent, Office, Professional fees, Installation and collections 0 0 0 0 0 Uncollectible accounts 598 625 653 682 113 Other 9,187 9,600 10,032 10,483 10,955 Added Environmental costs 0 0 0 o 0 Administrative Support Fee $783,102 $1,028,846 $1,094,069 $1,163,727 $1,238,039 Admin. Support Fee Percent 17.75% 22.75% 22.75% 22.75% 22.75% I Total Operating Expense (w/o deprec.) $5,036,676 $5,551,248 $5,903,165 $6,279,011 $6,679,969 Net Operating Revenues 893,532 922,319 953,937 987,263 1,018,967 Interest Income (WC and Reserve Fund) 100,601 102,507 107,618 116,464 129,531 Bethel Cogeneration Utilities net income 254,750 271,538 289,432 308,506 328,837 Other Income 0 0 0 0 0 Funds Available for Debt Service and other purposes 1,248,883 1,296,364 1,350,987 1,412,233 1,477,335 Debt Service Initial Bonds 790,842 790,842 790,842 790,842 790,842 Small Business Admin. Loan 204,804 204,804 204,804 204,804 204,804 AEA BCU Loan 94,966, 94,966 94,966 94,966 94,966 Total Debt Service $1,090,612 $1,090,612 $1,090,612 $1,090,612 $1,090,612 Debt Service Coverage on Initial Bonds 1.20 1.26 1.33 1.41 1.49 Minimum Debt Service Coverage on Initial Bonds 1.2 1.2 1.2 1.2 1.2 Beginning Working Capital $524,400 $549,309 $616,126 $731,756 $902,574 Balance Available for Other Purposes 682,671 755,061 876,501 1,053,377 1,289,297 Capital Improvements (133,362) (138,935) (144,745) (150,803) (157,121) Ending Working Capital $549,309 $616,126 $731,756 $902,574 $1,132,176 NOTES ON ALTERNATE CASE (1) General Inflation rate = 4.50% (2) Dec. 1990 rate increase = 10.09% source APUC U-90-33 page 5 of 8 (3) APUC approved 1991 rate increase = 4.54% Additional City 1991 increase of 10 % (4) Min. Debt Service Coverage = 1.2 on initial bonds (no excess coverage on AEA or SBA debt service) (5) Bond Term is for 20 years (6) Bond interest rate is 8.50% (7) Bond Size $7,484,000 (8) Purchase Price $6,274,000 (9) Reserve Fund 790,648 (10)Short term interest rate 7.65% (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating Revenues escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $224,400 is from Bond Proceeds. Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses less Administrative Support Fees [45/365*(TOE-ASF)]. (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt (15) Residential customer load growth at 2.00% per year (used for sensitivity analysis) (16)Added environmental costs increasing annual at 0.0% of pre-Administrative Support operating budget (sensitivity analysis) (17)Non-fuel cost increases passed on to customers starting after 1991 38 Table 26 MODERATE LOAD GROWTH SCENARIO PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System Commercial Large Commercial/Resale Total Customers 1,918 Electric Sales Revenues Residential $2,017,436 $2,116,187 $2,222,664 $2,337,228 $2,459,300 Commercial 2,567,332 2,648,360 2,735,622 2,829,116 2,927,597 Large Commercial/Resale 1,301,551 1,346,951 1,395,843 1,448,228 1,503,406 Additional Revenue for post 1991 non fuel cost increases 316,204 455,045 601,617 756,295 Additional Revenue for Debt Service Coverage 0 o 0 0 Additional Revenue for Working Capital 0 0 0 0 Total Sales Revenues $5,886,318 $6,427,702 $6,809,174 $7,216,189 $7,646,597 Unit Revenue or Average Retail Rate (cents/kWh) 20.8 22.6 23.8 25.1 26.4 Delinquent fees $36,575 $38,221 $39,941 $41,738 $43,616 Misc Service Revenues 3,135 3,276 3,423 3,577 3,738 Other Electric Revenues 4,180 4,368 4,565 4,770 4,985 Total Electric Operating Revenues $5,930,208 $6,473,567 $6,857,103 $7,266,274 $7,698,936 Sales Revenue per Customer ($) Residential (1989 Actual) 1,072 1,072 1,072 1,072 1,072 1990 & 91 increases & fuel adjustment 240 278 318 361 406 Revised Res Rev/Customer 1,312 1,349 1,389 1,432 1,478 Commercial (1989 Actual) 7,508 7,508 7,508 7,508 7,508 1990 & 91 increases & fuel adjustment 1,661 1,950 2,262 2,596 2,948 Revised Com Rev/Customer 9,169 9,458 9,770 10,104 10,456 Large Commercial/Resale (1989 Actual) 178,077 178,077 178,077 178,077 178,077 1990 & 91 increases & fuel adjustment 38,848 46,415 54,564 63,295 72,491 Revised Large Com Rev/Customer 216,925 224,492 232,640 241,371 250,568 All Customer Classes, Revised 3,228 3,296 3,369 3,449 3,533 Energy Sales (kWh) Residential 8,808,898 8,985,076 9,164,778 9,348,073 9,535,035 Commercial 12,465,913 12,465,913 12,465,913 12,465,913 12,465,913 Large Commercial/Resale 6,984,620 6,984,620 6,984,620 6,984,620 6,984,620 Total Sales (kWh) 28,259,431 28,435,609 28,615,311 28,798,606 28,985,568 Losses & Utility use (kWh) 4,747,584 4,777,182 4,807,372 4,838,166 4,869,575 Losses & Utility use (%) 16.8% 16.8% 16.8% 16.8% 16.8% Total Energy Requirements (kWh) 33,007,015 33,212,791 33,422,683 33,636,772 33,855,143 39 Table 27 5 PERCENT 1991 RATE INCREASE SCENARIO PROJECTED OPERATING RESULTS City Owned Electric System Operating Revenues Energy Sales Revenues $5,559,322 $6,048,482 $6,375,175 $6,722,713 $7,088,592 Other Revenues 43,890 45,865 47,929 50,085 52,339 Total Operating Revenues 5,603,212 6,094,347 6,423,104 6,772,798 7,140,931 Operating Expenses Fuel & Purchased Power 2,777,607 2,960,622 3,155,578 3,363,623 3,585,216 Salaries & Wages 479,702 501,289 523,847 547,420 572,054 Operation-generation 121,609 127,081 132,800 138,776 145,021 Operation-distribution 25,384 26,526 27,720 28,967 30,271 Operation-customer 35,237 36,823 38,480 40,212 42,022 Maintenance 299,936 313,433 327,537 342,276 357,678 Employee Benefits 303,620 317,283 331,561 346,481 362,073 Insurance 166,661 174,161 181,998 190,188 198,746 Rent, Office, Professional fees, Installation and collections 0 0 0 0 0 Uncollectible accounts 598 625 653 682 713 Other 9,187 9,600 10,032 10,483 10,955 Added Environmental costs 0 0 0 0 0 Administrative Support Fee $777,061 $1,016,343 $1,076,122 $1,139,572 $1,206,830 Admin. Support Fee Percent 17.75% 22.75% 22.75% 22.75% 22.75% Total Operating Expense (w/o deprec.) $4,996,602 $5,483,786 $5,806,328 $6,148,680 $6,511,579 Net Operating Revenues 606,610 610,560 616,776 624,118 629,351 Interest Income (WC and Reserve Fund) 80;712 82,908 86,588 92,112 99,786 Bethel Cogeneration Utilities net income : 254,750 271,538 289,432 308,506 328,837 Other Income 0 0 0 0 0 Funds Available for Debt Service and other purposes 942,072 965,006 992,796 1,024,736 1,057,974 Debt Service Initial Bonds 535,223 535,223 535,223 535,223 535,223 Small Business Admin. Loan 204,804 204,804 204,804 204,804 204,804 AEA BCU Loan 94,966 94,966 94,966 94,966 94,966 Total Debt Service $834,993 $834,993 $834,993 $834,993 $834,993 Debt Service Coverage on Initial Bonds 1.20 1.24 1.29 1.35 1.42 Minimum Debt Service Coverage on Initial Bonds 1.2 1.2 1.2 1.2 1.2 Beginning Working Capital $520,200 $548,904 $597,016 $669,230 $769,535 Balance Available for Other Purposes 627,279 678,918 754,818 858,974 992,516 Capital Improvements (78,375) (81,902) (85,588) (89,439) (93,464) Ending Working Capital $548,904 $597,016 $669,230 $769,535 $899,052 NOTES ON ALTERNATE CASE (1) General Inflation rate = 4.50% (2) Dec. 1990 rate increase= 10.09% source APUC U-90-33 page 5 of 8 (3) APUC approved 1991 rate increase = 4.54% Additional City 1991 increase of 5% (4) Min. Debt Service Coverage = 1.2 on initial bonds (no excess coverage on AEA or SBA debt service) (5) Bond Term is for 20 years (6) Bond interest rate is 8.50% (7) Bond Size $5,065,000 (8) Purchase Price $4,178,000 (9) Reserve Fund 534,854 (10)Short term interest rate 7.65% (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating Revenues escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $220,000 is from Bond Proceeds. Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses less Administrative Support Fees [45/365*(TOE-ASF)]. (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt (15)Residential customer load growth at 0.00% per year (used for sensitivity analysis) (16)Added environmental costs increasing annual at 0.0% of pre-Administrative Support operating budget (sensitivity analysis) (17)Non-fuel cost increases passed on to customers starting after 1991 40 Table 28 5 PERCENT 1991 RATE INCREASE SCENARIO PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System Commercial Large Commercial/Resale Total Customers Electric Sales Revenues $1,939,096 $1,994,130 $2,053,398 $2,116,900 $2,183,788 Residential 2,567,332 2,648,360 2,735,622 2,829,116 2,927,597 Commercial 1,301,551 1,346,951 1,395,843 1,448,228 1,503,406 Large Commercial/Resale 307,696 438,968 577,126 722,457 Additional Revenue for post 1991 non fuel cost increases 0 0 0 0 Additional Revenue for Debt Service Coverage 0 0 0 0 Additional Revenue for Working Capital $5,807,978 $6,297,138 $6,623,831 $6,971,369 $7,337,248 Total Sales Revenues 20.8 22.6 23.7 25.0 26.3 Unit Revenue or Average Retail Rate (cents/kWh) $36,575 $38,221 $39,941 $41,738 $43,616 Delinquent fees 3,135 3,276 3,423 3,577 3,738 Misc Service Revenues 4,180 4,368 4,565 4,770 4,985 Other Electric Revenues $5,851,868 $6,343,003 $6,671,760 $7,021,454 $7,389,587 Total Electric Operating Revenues Sales Revenue per Customer ($) 1,072 1,072 1,072 1,072 1,072 Residential (1989 Actual) 240 278 318 361 406 1990 & 91 increases & fuel adjustment 1,312 1,349 1,389 1,432 1,478 Revised Res Rev/Customer 7,508 7,508 7,508 7,508 7,508 Commercial (1989 Actual) 1,661 1,950 2,262 2,596 2,948 1990 & 91 increases & fuel adjustment 9,169 9,458 9,770 10,104 10,456 Revised Com Rev/Customer 178,077 178,077 178,077 178,077 178,077 Large Commercial/Resale (1989 Actual) 38,848 46,415 54,564 63,295 72,491 1990 & 91 increases & fuel adjustment 216,925 224,492 232,640 241,371 250,568 Revised Large Com Rev/Customer 3,293 3,395 3,506 3,625 3,750 All Customer Classes, Revised 8,466,838 8,466,838 8,466,838 8,466,838 8,466,838 Energy Sales (kWh) 12,465,913 12,465,913 12,465,913 12,465,913 12,465,913 Residential 6,984,620 6,984,620 6,984,620 6,984,620 6,984,620 Commercial 27,917,371 27,917,371 27,917,371 27,917,371 27,917,371 Large Commercial/Resale 4,690,118 4,690,118 4,690,118 4,690,118 4,690,118 Total Sales (kWh) 16.8% 16.8% 16.8% 16.8% 16.8% Losses & Utility use (kWh) 32,607,489 32,607,489 32,607,489 Losses & Utility use (%) Total Energy Requirements (kWh) 41 Operating Revenues Energy Sales Revenues Other Revenues Total Operating Revenues Operating Expenses Fuel & Purchased Power Salaries & Wages Operation-generation Operation-customer Maintenance Employee Benefits Insurance Rent, Office, Professional fees, Installation and collections Uncollectible accounts Other Added Environmental costs Administrative Support Fee Admin. Support Fee Percent Total Operating Expense (w/o deprec.) Net Operating Revenues Interest Income (WC and Reserve Fund) Bethel Cogeneration Utilities net income Other Income Funds Available for Debt Service and other purposes Debt Service Initial Bonds Small Business Admin. Loan AEA BCU Loan Total Debt Service Debt Service Coverage on Initial Bonds Minimum Debt Service Coverage on Initial Bonds Beginning Working Capital Balance Available for Other Purposes Capital Improvements Ending Working Capital NOTES ON ALTERNATE CASE (1) General Inflation rate = (2) Dec. 1990 rate increase= (3) APUC approved 1991 rate increase = (4) Min. Debt Service Coverage = (5) Bond Term is for (6) Bond interest rate is (7) Bond Size (8) Purchase Price (9) Reserve Fund (10)Short term interest rate less Administrative Support Fees [45/365*(TOE-ASF)]. (15)Residential customer load growth at (16)Added environmental costs increasing annual at (17)Non-fuel cost increases passed on to customers starting after 1991 $5,807,978 43,890 5,851,868 2,777,607 479,702 121,609 25,384 35,237 299,936 303,620 166,661 0 598 9,187 10,549 $778,933 17.75% $5,009,023 842,845 96,941 254,750 0 1,194,536 745,614 204,804 94,966 $1,045,384 1.20 1.2 $521,500 670,652 (78,375) $592,277 4.50% 10.09% 4.54% 1.2 20 8.50% $7,056,000 $5,905,000 745,705 7.65% 0.00% 0.25% 42 Table 29 MODERATELY HIGH ENVIRONMENTAL COST SCENARIO PROJECTED OPERATING SULTS City Owned Electric System $6,312,135 45,865 6,358,000 2,960,622 501,289 127,081 26,526 36,823 313,433 317,283 174,161 0 625 9,600 22,337 $1,021,425 22.75% $5,511,205 846,795 102,356 271,538 0 1,220,689 745,614 204,804 94,966 $1,045,384 1.24 1.2 $592,277 767,582 (81,902) $685,680 $6,654,957 47,929 6,702,886 3,155,578 523,847 132,800 27,720 38,480 327,537 331,561 181,998 0 653 10,032 35,477 $1,084,193 22.75% $5,849,876 853,010 109,501 289,432 0 1,251,943 745,614 204,804 94,966, $1,045,384 1.28 1.2 $685,680 892,239 (85,588) $806,651 source APUC U-90-33 page 5 of 8 Additional City 1991 increase of 10 % $7,020,434 50,085 7,070,519 3,363,623 547,420 138,776 28,967 40,212 342,276 346,481 190,188 0 682 10,483 50,091 $1,150,968 22.75% $6,210,167 860,353 118,755 308,506 0 1,287,614 745,614 204,804 94,966 $1,045,384 1.32 1.2 $806,651 1,048,881 (89,439) $959,442 $7,406,221 52,339 7,458,560 3,585,216 572,054 145,021 30,271 42,022 357,678 362,073 198,746 0 13 10,955 66,309 $1,221,916 22.75% $6,592,974 865,586 130,444 328,837 0 1,324,867 745,614 204,804 94,966, $1,045,384 1.37 1.2 $959,442 1,238,925 (93,464) $1,145,461 on initial bonds (no excess coverage on AEA or SBA debt service) years (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt per year (used for sensitivity analysis) (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating Revenues escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $221,500 is from Bond Proceeds. Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses of pre-Administrative Support operating budget (sensitivity analysis) Table 30 MODERATELY HIGH ENVIRONMENTAL COST SCENARIO PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System Commercial Large Commercial/Resale Total Customers Electric Sales Revenues Residential $1,994,130 $2,053,398 $2,116,900 $2,183,788 Commercial 2,567,332 2,648,360 2,735,622 2,829,116 2,927,597 Large Commercial/Resale 1,301,551 1,346,951 1,395,843 1,448,228 1,503,406 Additional Revenue for post 1991 non fuel cost increases 0 457,672 750,229 1,067,781 1,412,192 Additional Revenue for Debt Service Coverage 112,444 86,273 56,999 25,702 0 Additional Revenue for Working Capital 0 0 0 0 0 Total Sales Revenues $5,920,422 $6,533,386 $6,992,090 $7,487,726 $8,026,982 Unit Revenue or Average Retail Rate (cents/kWh) 21.2 23.4 25.0 26.8 28.8 Delinquent fees “$36,575 $38,221 $39,941 $41,738 $43,616 Misc Service Revenues 3,135 3,276 3,423 3,577 3,738 Other Electric Revenues 4,180 4,368 4,565 4,770 4,985 Total Electric Operating Revenues $5,964,312 $6,579,251 $7,040,019 $7,537,811 $8,079,321 Sales Revenue per Customer ($) Residential (1989 Actual) 1,072 1,072 1,072 1,072 1,072 1990 & 91 increases & fuel adjustment 240 278 318 361 406 Revised Res Rev/Customer 1,312 1,349 1,389 1,432 1,478 Commercial (1989 Actual) 7,508 7,508 7,508 7,508 7,508 1990 & 91 increases & fuel adjustment 1,661 1,950 2,262 2,596 2,948 Revised Com Rev/Customer 9,169 9,458 9,770 10,104 10,456 Large Commercial/Resale (1989 Actual) 178,077 178,077 178,077 178,077 178,077 1990 & 91 increases & fuel adjustment 38,848 46,415 54,564 63,295 72,491 Revised Large Com Rev/Customer 216,925 224,492 232,640 2A1,371 250,568 All Customer Classes, Revised 3,293 3,395 3,506 3,625 3,750 Energy Sales (kWh) Residential 8,466,838 8,466,838 8,466,838 8,466,838 8,466,838 Commercial 12,465,913 12,465,913 12,465,913 12,465,913 12,465,913 Large Commercial/Resale 6,984,620 6,984,620 6,984,620 6,984,620 6,984,620 Total Sales (kWh) 27,917,371 27,917,371 27,917,371 27,917,371 27,917,371 Losses & Utility use (kWh) 4,690,118 4,690,118 4,690,118 4,690,118 4,690,118 Losses & Utility use (%) 16.8% 16.8% 16.8% 16.8% 16.8% Total Energy Requirements (kWh) 32,607,489 32,607,489 32,607,489 32,607,489 32,607,489 43 SPECIAL INITIAL YEAR & 5% BOND ISSUE SCENARIO PROJECTED OPERATING RESULTS City Owned Electric System $5,807,978 $6,297,138 $6,623,831 $6,971,369 $7,337,248 43,890 45,865 47,929 50,085 52,339 5,851,868 6,343,003 6,671,760 7,021,454 7,389,587 2,777,607 2,960,622 3,155,578 3,363,623 3,585,216 479,702 501,289 523,847 547,420 572,054 121,609 127,081 132,800 138,776 145,021 25,384 26,526 27,720 28,967 30,271 35,237 36,823 38,480 40,212 42,022 299,936 313,433 327,537 342,276 357,678 Employee Benefits 303,620 317,283 331,561 346,481 362,073 Insurance 166,661 174,161 181,998 190,188 198,746 Rent, Office, Professional fees, Installation and collections 0 0 0 0 0 Uncollectible accounts 598 625 653 682 13 Other 9,187 9,600 10,032 10,483 10,955 Added Environmental costs 0 0 0 0 0 Administrative Support Fee $777,061 $1,016,343 $1,076,122 $1,139,572 $1,206,830 Admin. Support Fee Percent 17.75% 22.75% 22.75% 22.15% 22.75% Total Operating Expense (w/o deprec.) $4,996,602 $5,483,786 $5,806,328 $6,148,680 $6,511,579 Net Operating Revenues 855,266 859,216 865,432 872,774 878,007 Interest Income (WC and Reserve Fund) 97,629 103,216 110,548 120,003 131,907 Bethel Cogeneration Utilities net income 254,750 271,538 289,432 308,506 328,837 Other Income 0 0 0 0 0 Funds Available for Debt Service and other purposes 1,207,645 1,233,970 1,265,412 1,301,283 1,338,751 Debt Service Initial Bonds (8.5% & 5%) 756,460 756,460 756,460 756,460 756,460 Small Business Admin. Loan 204,804 204,804 204,804 204,804 204,804 AEA BCU Loan 94,966 94,966 94,966 94,966 94,966 Total Debt Service $1,056,230 $1,056,230 $1,056,230 $1,056,230 $1,056,230 Debt Service Coverage on Initial Bonds 1.20 1.23 1.28 1.32 1.37 Minimum Debt Service Coverage on Initial Bonds 1.2 1.2 1.2 1.2 1.2 Beginning Working Capital $520,200 $593,240 $689,079 $812,672 $968,287 Balance Available for Other Purposes 671,615 770,981 898,260 1,057,726 1,250,808 ff Capital Improvements (78,375) (81,902) (85,588) (89,439) (93,464) Ending Working Capital $593,240 $689,079 $812,672 $968,287 $1,157,344 | NOTES ON SPECIAL ALTERNATE CASE (1) General Inflation rate = 4.50% (2) Dec. 1990 rate increase= 10.09% source APUC U-90-33 page 5 of 8 (3) APUC approved 1991 rate increase = 4.54% Additional City Initiated 1991 Rate Increase or 10% (4) Min. Debt Service Coverage = ee (5) Bond Term is for 20 years (6) Bond interest rate is 8.50% for publicly placed bond (7) 8.5 % Bond Issue Size = $0 35 % Bond Issue Size = $7,475,000 (8) Purchase Price $2,000,000 in cash plus 5% Bonds with 30 annual payments equal to $486,259 (9) Reserve Fund 755,994 (10)Short term interest rate 7.65% (11)The Administrative Support charge is calculated on the basis of operating expenses and annual depreciation (12)Net 1990 Bethel Cogeneration Utilities Operating Revenues escalated at the general inflation rate and the real price of oil (13)$300,000 Working Capital is assumed to be transferred from BUC. An additional $220,200 is from Bond Proceeds Total Working Capital is not allowed to drop below 45 days of the annual Total Operating Expenses less Administrative Support Fees [45/365*(TOE-ASF)]. (14)AEA and SBA loans assumed by the City; the City assumes no other long term debt (15)Residential customer load growth at 0.00% per year (used for sensitivity analysis) (16)Added environmental costs increasing annual at 0.0% of pre-Administrative Support operating budget (sensitivity analysis) (17)Non-fuel cost increases passed on to customers starting after 1991 44 Residential Commercial Large Commercial/Resale Total Customers Electric Sales Revenues Residential Commercial Large Commercial/Resale Additional Revenue for Working Capital Total Sales Revenues Delinquent fees Misc Service Revenues Other Electric Revenues Total Electric Operating Revenues Sales Revenue per Customer ($) Residential (1989 Actual) 1990 & 91 increases & fuel adjustment Revised Res Rev/Customer Commercial (1989 Actual) 1990 & 91 increases & fuel adjustment Revised Com Rev/Customer Large Commercial/Resale (1989 Actual) 1990 & 91 increases & fuel adjustment Revised Large Com Rev/Customer All Customer Classes, Revised Energy Sales (kWh) Residential Commercial Large Commercial/Resale Total Sales (kWh) Losses & Utility use (kWh) Losses & Utility use (%) Total Energy Requirements (kWh) Additional Revenue for post 1991 non fuel cost increases Additional Revenue for Debt Service Coverage Unit Revenue or Average Retail Rate (cents/kWh) 2,567,332 1,301,551 $5,807,978 20.8 $36,575 3,135 4,180 $5,851,868 1,072 240 1,312 7,508 1,661 9,169 178,077 38,848 216,925 3,293 8,466,838 12,465,913 6,984,620 27,917,371 4,690,118 16.8% 32,607,489 45 Table 32 SPECIAL INITIAL YEAR & 5% BOND ISSUE SCENARIO PROJECTED CUSTOMERS, ENERGY SALES, AND ENERGY REQUIREMENTS City Owned Electric System $1,994,130 2,648,360 1,346,951 307,696 0 0 $6,297,138 22.6 $38,221 3,276 4,368 $6,343,003 1,072 278 1,349 7,508 1,950 9,458 178,077 46,415 224,492 3,395 8,466,838 12,465,913 6,984,620 27,917,371 4,690,118 16.8% 32,607,489 $2,053,398 2,735,622 1,395,843 438,968 0 0 $6,623,831 23.7 $39,941 3,423 4,565 $6,671,760 1,072 318 1,389 7,508 2,262 9,770 178,077 54,564 232,640 3,506 8,466,838 12,465,913 6,984,620 27,917,371 4,690,118 16.8% 32,607,489 $2,116,900 2,829,116 1,448,228 577,126 0 0 $6,971,369 25.0 $41,738 3,577 4,770 $7,021,454 1,072 361 1,432 7,508 2,596 10,104 178,077 63,295 241,371 3,625 8,466,838 12,465,913 6,984,620 27,917,371 4,690,118 16.8% 32,607,489 $2,183,788 2,927,597 1,503,406 722,457 0 0 $7,337,248 26.3 43,616 3,738 4,985 $7,389,587 1,072 406 1,478 7,508 2,948 10,456 178,077 72,491 250,568 3,750 8,466,838 12,465,913 6,984,620 27,917,371 4,690,118 16.8% 32,607,489 PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS In the preparation of this report and the opinions that follow, we have made certain assumptions with respect to conditions that may occur in the future. While we believe these assumptions are reasonable for the purpose of this report, they are dependent upon future events, and actual conditions may differ from those assumed. In addition, we have used and relied upon certain information provided to us by AEA, BUC, the City and others. While we believe the sources to be reliable, we have not independently verified all of the infor- mation and offer no assurances with respect thereto. To the extent that actual future factors differ from those modeled or assumed herein or provided to us by others, the actual results will vary from those forecast. The principal considerations and assumptions made by us and the principal information provided to us by others include the following: 1. The City will buy all of the outstanding corporate shares of BUC, including BCU, and certain real property located in Bethel, and that all rights to operate the electric system will be transferred to the City, free and clear, by purchasing these corporate shares. The City will select and successfully implement a management and staffing plan that emphasizes retaining qualified personnel to provide total operation and management services for the electric system, or hire qualified people to operate and manage the electric system; the City will form a Utility Board to provide policy direction for the utility; and the electric system will operate and manage the electric system in accordance with prudent electric utility practice. The City will issue tax-exempt bonds with an 8.5 percent interest rate and 20 year term. The bonds will have issuance costs, including credit enhancement, of 3 percent. Our projection of the electric system’s energy requirements will occur as shown in Table 16 and Bethel’s largest customers will continue their existing operations in Bethel and continue purchasing their electric energy requirements from the City. Our projection of the electric system’s capital improvements, operation and maintenance expenses, and fuel expenses will occur as shown in Tables 17, 18, and 19. The future annual general inflation rate will be 4.5 percent per year and the escalation rate of the cost of diesel fuel delivered to the Bethel power plant will be an additional 2.0 percent per year. 46 10. The City, if necessary, will institute rate increases that provide the revenues as needed to cover all costs of operation, maintenance, and debt service to meet the following financial objectives: a) 1.20 minimum debt service coverage ratio on the bonds b) Year end working capital balances of not less than 45 days of total operating expenses, exclusive of the administrative support fee. The City will continue the collection policies of BUC. The State of Alaska will continue to fund the PCE Program at current levels. The City will not be regulated by the APUC 47 CONCLUSIONS Based on the studies, investigations, analyses, and the considerations and assumptions set forth in this report, we conclude that: 1. Based upon our site visit, we found the generation plant, distribution plant, and the general plant are in good condition. While these facilities, in general, are not new, we would expect that, with regular maintenance and occasional replacements, the electric system should have a normal useful life as similar facilities located in other areas of Alaska and the Pacific Northwest. If the City is to seriously negotiate for the purchase the BUC electric system, it will be necessary for the City to be willing to increase its revenues per kWh sold above current APUC approved rates or reduce its administrative support fee below the desired 22.75 percent level. A City-owned electric utility should be able to support debt service that would allow a purchase price between $4 million and $6 million. This value is toward the middle to high end of the range of values documented in our cross check of BUC value. To support a higher purchase price would require higher initial retail rate increases, lower bond interest rates, a reduction of initial debt service, or possibly non-levelized debt service. Exploring alternate assumptions beyond those used for this report will require careful input from financial advisors and investment bankers to structure a marketable bond issue. If the City and BUC decide to pursue negotiations, then the City should retain special legal counsel, bond counsel, a financial advisor, an investment banker, and a consulting engineer to refine the analysis and to advise the City on the detailed requirements for issuing bonds and structuring a purchase agreement. The City should not make a binding purchase offer before such counsel and advisors are retained. 48 APPENDIX A Table A-L RATE SCHEDULES Bethel Utilities Corporation SCHEDULE OF RATES FOR POWER - RESIDENTIAL Character of Service: Continuous-Alternating current 60 cycle 120/240 or 120/208 volts single phase. Characteristics depend upon available circuits. Rate per month: First 50 kilowatt hours, per kilowatt hour 26.955¢ Next 200 kilowatt hours, per kilowatt hour _ 22.992¢ Over 250 kilowatt hours, per kilowatt hour 18.038¢ Minimum Charge: $9.91 per month, per meter Special provisions: a. Commercial use When a customer operates a commercial establishment (incidental to his residence) in the same premises as his residence and takes his entire service through one meter, this rate schedule will apply for the entire service only if the connected load in the residential portion exceeds that in the commercial portion, provided that the connected load in the commercial portion does not exceed 1,500 watts. If the reverse is true, the appropriate commercial service rate schedule will apply to the entire service. However, the customer may elect to take the service under both the residential and commercial rates, in which case there will be a separate meter for the residential portion and a separate meter for the commercial portion. Power cost equalization: These rates are eligible for power cost equalization in an amount per kWh identified on Sheet No. 30.2 Pursuant to Order No. 2 of Docket U-90-33. Effective: 11/29/90 Seasonal service When a customer desires service at a premises normally occupied or used only during the period between May 1 and October 31, service shall be supplied under this rate schedule except that the minimum charge shall be $19.83 per month for the above six month minimum period and no billing shall be required for the period outside the seasonal service period as defined above. Between renters The minimum charge under a Between Renter’s Agreement shall be $4.95 during a billing period or any fraction thereof. Fuel cost rate adjustments A surcharge or credit may be applied to each billing for service rendered under this schedule to reflect increases or decreases in the cost of fuel compared to the cost of fuel at $1.2705/gallon, and shall be calculated as follows: Current fuel cost - $1.2705/gallon (¢/gal) Surcharge = Average kWh sold per gallon of fuel consumed during the preceding 12 months Table A-2 RATE SCHEDULES Bethel Utilities Schedule SCHEDULE OF RATES FOR POWER - COMMERCIAL Se ee et Character of service: Continuous-Alternating current 60 cycle 120/240, 120/208, 208, 240, 480 volts single or three phase. Characteristics also depend upon available circuits. Rate per month: First 50 kilowatt hours, per kilowatt hour 26.955¢ Next 450 kilowatt hours, per kilowatt hour 21.121¢ Next 2,500 kilowatt hours, per kilowatt hour 19.139¢ Next 22,000 kilowatt hours, per kilowatt hour 18.038¢ Over 25,000 kilowatt hours, per kilowatt hour 17.488¢ Minimum charge: $9.91 per month, per meter where the installed transformer capacity is 5 KVA or less. If the installed transformer capacity is greater than 5S KVA due to the customer’s load requirement, the minimum charge will be $1.98/KVA of installed transformer capacity per month. Special provisions: a. Seasonal service Seasonal customers purchasing all power requirements from the Company may, upon 30 days written notice to the Company, have their minimum charge reduced or waived on disconnection, for a period of not more than six months consecutively in the winter (November | to April 30) each year. b. Standby service Whenever the service is supplied for standby, the charge shall be $5.94 per KVA of installed transformer capacity. Electric energy sold under this provision shall be tilled at the applicable rate in addition to the standby charge. The term under this provision shall not be less than one year. Power cost equalization: These rates are eligible for power cost equalization in an amount per kWh identified on Sheet No. 30.2 c. Fuel cost rate adjustment A surcharge or credit may be applied to each billing for service rendered under this schedule to reflect increases or decreases in the cost of fuel compared to the cost of fuel at $1.2705/gallon, and shall be calculated as follows: Current fuel cost - $1.2705/gallon (¢/gal) Surcharge = Average kWh sold per gallon of fuel consumed during the preceding 12 months Pursuant to Order No. 2 of Docket U-90-33 Effective: 11/29/90 Table A-3 RATE SCHEDULES Bethel Utilities Corporation SCHEDULE OF RATES FOR POWER - BULK PRIME Character of service: Continuous-Alternating current 60 cycle primary distribution system 2400/7200/12470 volts single phase or three phase. Metering through one point and customer to own, service and maintain their own secondary distribution service system at 120/240, 120/208, 208, 240, 480 volt single or three phase. Rate per month: First 50,000 kilowatt hours, per kilowatt hour 17.488¢ Next 50,000 kilowatt hours, per kilowatt hour 16.937¢ Next 50,000 kilowatt hours, per kilowatt hour 16.607¢ Next 50,000 kilowatt hours, per kilowatt hour 16.277¢ Next 50,000 kilowatt hours, per kilowatt hour 15.836¢ Next 50,000 kilowatt hours, per kilowatt hour 15.506¢ Next 50,000 kilowatt hours, per kilowatt hour 14.956¢ Over 350 kilowatt hours, per kilowatt hour 14,625¢ Special provision: Fuel cost rate adjustment A surcharge or credit may be applied to each billing for service rendered under this schedule to reflect increases or decreases in the cost of fuel compared to the cost of fuel at $1.2705/gallon and shall be calculated as follows: Current fuel cost - $1.2705/gallon (¢/gal) Surcharge = Average kWh sold per gallon of fuel consumed during the preceding 12 months Power cost equalization: These rates are eligible for power cost equalization in an amount per kWh identified on Sheet No. 30.2 Pursuant to Order No. 2 of Docket U-90-33 Effective: 11/29/90 - APPENDIX B QeNDRiy, & . HENDRIX & ESSLINGER & <¢ Certified Public Accountants SSLING 3510 Spenard Rd.. Suite 102. Anchorage. Alaska 99503 (907) 258-0200 Board of Directors Bethel Utilities Corporation, Inc., and Subsidiary Independent Auditor's Report We have audited the accompanying consolidated balance sheets of Bethel Utilities Corporation, Inc., and Subsidiary as of December 31, 1989 and 1988, and the related consolidated statements of income and retained earnings and cash flows for the years then ended. These financial statements are the responsi- bility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Bethel Utilities Corporation, Inc., and Subsidiary as of December 31, 1989 and 1988, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. February 20, 1990 Ye LIABILITIES AND STOCKHOLDERS’ EQUITY 1989 1988 STOCKHOLDERS’ EQUITY . horized 99,999 Common stock, no par value; authorize , shares; issued 40,000 shares $ 150,000 $ 150,000 Additional paid-in capital 42,000 42,000 Retained earnings 1.049916 1 016 1, 241,916 1,375,016 Minority interest in subsidiary L76:.52) __ 45,509 1,418 437 1,420,525 ADVANCES ON CONSTRUCTION 1.206 LEASE DEPOSITS 19,524 _ 1,130 LONG-TERM DEBT 3.79447 1,996,897 CURRENT LIABILITIES Current portion of long-term debt 193,600 148,793 Notes payables 500,000 5,000 Accounts payable Trade 310,514 296,771 Affiliate 103,016 - Customer refunds 37,801 244,417 Customer deposits 131,874 144 , 933 Accrued expenses 222.226 140,038 Total current liabilities 1,499,031 979.952 $6,732,668 $4,398,504 See notes to financial statements. -2- BETHEL UTILITIES CORPORATION, INC., AND SUBSIDIARY SOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS 1 Years ended December 31, 1989 and 1988 1989 1988 OPERATING REVENUES / Electricity sales to customers $4,799,807 $4,914,840 Other 179,792 105,385 Rental, net of expenses ——_ 44,706 36.756 5,024,305 5,056,981 OPERATING EXPENSES Fuel and purchased power 2,675,710 2,771,805 Salaries and wages 852,436 797,774 Operation - generation 111,361 108 , 826 Operation - distribution 23,245 20,005 Operation - customer sa ieae o Maintenance , , Employee benefits 325,733 274,032 7 cre Ere: nsurance , , Professional fees 25,292 97,967 Office and administrative 50,421 66,823 Rent 10,286 33,109 Other pe a 1,592 4,750,658 4.748 078 Income from operations 273 647 308 903 OTHER INCOME (EXPENSE) Interest income 12,953 13,106 Interest expense (245,353) (145,282) Miscellaneous income 17,875 ie Gain (loss) from disposition of fixed assets (198,910) (68,423) Litigation settlement ee ~ (110.779) (400,059) (311, 378) Net loss before minority interest (126,412) (2,475) MINORITY INTEREST IN SUBSIDIARY’S INCOME (LOSS) 6, 688 (14,009) Net loss (133,100) (6,484) RETAINED EARNINGS, beginning 1,183,016 1,249,500 DISTRIBUTIONS : (50,000) $1,049 916 $1,183 .016 RETAINED EARNINGS, ending See notes to financial statements. Ke BETHEL UTILITIES CORPORATION, INC., AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31, 1989 and 1988 CASH FLOWS FROM OPERATING ACTIVITIES: Net loss § (133,100) $(16,484) Adjustments to reconcile net (loss) to net cash provided by operating activities: Depreciation 264,135 236 , 511 Minority interest in (income) loss of subsidiary (6,688) 14,009 Loss on disposition of utility plant 198,910 68,422 Decrease in receivables 96,886 60,425 Increase in inventory (26,114) (70,835) (Increase) decrease in prepaid expenses 10,304 (24,619) Increase in accounts payable 116,759 31,448 (Decrease) increase in accrued expenses 82,188 (675) Increase (decrease) in customer deposits (13,059) 14,696 Increase (decrease) customer refunds (206,616) 244 417 Net cash provided by operating activities 383,605 557,315 CASH FLOWS FROM INVESTING ACTIVITIES: Utility plant additions * (403,559) (145,118) Deposits (made) received 30,114 (30,864) Utility future use additions (304,174) ~ (28,026) Proceeds from disposition of utility plant 59,164 500 Rent property purchased (2,346,018) (449 ,056) Increase lease deposits 18,394 1,130 Increase deferred costs (9 948) (3.373) Net cash used in investing activities (2,956,027) (654,807) CASH FLOWS FROM FINANCING ACTIVITIES: Increase minority interest in subsidiary 137,700 31,500 Distributions - (50,000) Proceeds from long-term debt 2,000,000 375,000 Reduction of long-term debt (157,618) (137,557) Increase advances on construction 1,204 - (Increase) decrease notes receivable (42,203) 6,590 Net proceeds from line of credit 495 000 5.000 Net cash provided by financing activities 2,434 083 230,533 NET INCREASE (DECREASE) IN CASH (138,339) 133,041 CASH, beginning of year 284,995 151,954 CASH, end of year $146 656 $284,995 See notes to financial statements. eGs Ls BETHEL UTILITIES CORPORATION, INC., AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1989 and 1988 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Bethel Utilities Corporation, Inc. is engaged in the sale of electric services to the Bethel, Alaska area under the authority of the Alaska Public Utilities Commission. The accounting policies that affect the more significant elements of the financial statements of the Company are summarized as follows: a. Principles of consolidation: The consolidated financial statements include the Company and a 55% owned partnership. All significant intercompany transactions are eliminated. The partnership was formed October 13, 1988. The Company maintains its book of accounts in accordance with the uniform system of accounts prescribed by the Alaska Public Utilities Commission. Electric plant. is recorded at cost. When electric plant is retired, the book cost of the plant plus cost of removal and less any amounts received is charged to ac- cumulated depreciation. The cost of maintenance and repairs is charged to income as incurred, whereas, sig- nificant renewals and betterments are capitalized and deduction is made for retirements resulting from the renewals or betterments. Depreciation is computed using the straight-line method. Inventory of materials and supplies is valued at the lower of cost or market determined on the first-in, first-out method. The Company, with the consent of its shareholders elected, for the years ended December 31, 1989 and 1988, to be taxed under the provisions of Subchapter S of the Internal Revenue Code, which provides that, in lieu of corporation income taxes, the stockholders are taxed on the Company's taxable income. PROPERTY AND EQUIPMENT Electric plant in service at December 31, 1989 and 1988 is as follows: Depreciable Lives 1989 1988 Production plant 5-20 years $3,025,427 $3,101,421 Distribution plant 5-25 years 971,604 1,100,730 General plant 3-10 years 834.082 670,310 4,831,113 4,872,461 Less accumulated depreciation 2,312,209 25279549 $2,518,904 $2,592,912 2. BETHEL UTILITIES CORPORATION, INC., AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT'D) December 31, 1989 and 1988 PROPERTY AND EQUIPMENT (Cont'd) Rental property at December 31, 1989 and 1988 is as follows: 1989 1988 Land “ $ 480,000 $ 5 Office buildings 2,453,050 441,467 Tenant improvements ___ 162,024 7.589 2,795,074 449,056 Less accumulated depreciation 48.703 4,061 $2,746,371 $444,995 Depreciation charged to income was $264,135 and $236,511 in 1989 and 1988 respectively. RELATED PARTY TRANSACTIONS Year end receivables from affiliates are as follows: 1989 1988 Receivables: Bethel Cogeneration Utilities, Inc. $ - $ 3,621 Chugach Construction Co., Inc. . 2,072 4,095 Due from stockholders/Partners 15.936 7.003 $18 008 $14,719 Accounts Payable: Bethel Cogeneration Utilities, Inc. $103 016 g_- The major stockholders of Bethel Utilities Corporation, Inc. are 100% owners of all affiliated companies listed above. These corporations engage in the construction and repairs to electrical plant and waste heat sales in Bethel, Alaska. All receivable and payable balances are unsecured, non-interest bearing, and without specific repayment terms. NOTES PAYABLE The Company has a line of credit at an Anchorage bank bearing interest at prime plus 1.5% of $500,000 and $300,000 at December 31, 1989 and 1988 respectively. The outstanding balance is $500,000 and $5,000 at December 31, 1989 and 1988 respectively. LONG-TERM DEBT Long-term debt at December 31, 1989 and 1988, is summarized as follows: 1989 1988 Note payable to Small Business Administration, secured by most of the production and all of the general plant, payable at $17,067 per month including interest at 6.625%. $1,374,160 $1,484,375 BETHEL UTILITIES CORPORATION, INC., AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT'D) December 31, 1989 and 1988 LONG-TERM DEBT (Cont'd) Note payable to National Bank of Alaska, secured by a small portion of the production plant, payable at $5,612 per month including interest at prime plus 1-1/2%. 252,800 286,521 Real estate contract secured by Compro building and payable in monthly installments of $3,017 including interest at 9%. The final payment will be November 1, 2018. 371,118 374,794 Real estate contract secured by Denali building and payable in monthly installments of $4,935 including interest at 8% through March 8, 1992. On March 8, 1992 the note payments will be changed to reflect amortization of the remaining balance over a 20 year period from the date of the note with interest at 8.5%. Starting March 2, 1995, the note payments will be adjusted annually based upon United States Government Securities, one-year Treasury constant market yield, as published by the Federal Reserve. The note is due in full March 1, 2004. 580,741 Promissory note secured by the Bel Aire buildings and payable in monthly installments of $11,423 including interest at 9% through May 1, 1993, and $12,910 including interest at 10.5% through May 1, 1995. On May 1, 1995 a balloon payment of $50,000 is due and the note will be reamortized over the remaining life with interest at 10.5%. The note is due in full April 1, 2005. 1,350,000 Note payable to National Bank of Alaska secured by real estate, payable at $845 per month including interest at prime plus 1.5% | a 3,988,072 2,145,690 Less current portion —__193 600 148.793 $3,794,472 $1,996,897 Current maturities of required payments of long-term debt at December 31, 1989 are as follows: 1990 $193,600 1991 208,500 1992 220,000 1993 240,000 1994 259,125 BETHEL UTILITIES CORPORATION, INC., AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONT'D) December 31, 1989 and 1988 RETIREMENT PLAN The Company has a pension and profit sharing plan which covers all full-time employees defined as those with service of 1,000 hours and are still employed on December 31st of each year. The plan provides for payment of an annual contribution to a trust fund of an amount determined by the Board of Directors, but subject to limitation of the maximum amount deduct- ible under Section 404 of the Internal Revenue Code of 1954, as amended. The contribution amounted to $227,507 and $201,605 for 1989 and 1988, respectively. INCOME TAXES Pursuant to the election to be taxed as a Subchapter S Corporation in 1986, the Company owes no tax (nor receives the benefit of losses), as its income or loss is reported by the shareholders. RETAINED EARNINGS January 1, 1986, the shareholders elected to be taxed under provisions of Subchapter S of the Internal Revenue Code. The components of retained earnings at December 31, 1989 and 1988, are as follows: Accumulated Accumulated Tax Adjustments Earnings and Timing Account Profits Adjustments Total Balance January 1, 1988 $ 42 $1,084,644 $164,814 $1,249,500 Taxable income - 1988 (101,265) - - (101,265) Dividends (50,000) - (50,000) 1988 excess tax over book depreciation ee de ter 84.781 84.781 Balance December 31, 1988 (1013223) 1,034,644 249,595 1,183,016 Taxable loss - December 31, 1989 (191,491) - - (191,491) 1989 excess tax over book depreciation - - 80,369 80,369 1989 excess book over tax partnership loss - - (3,437) (3,437) 1989 excess book over tax gain on asset cane = (18,541) _ (18,541) Balance December 31, 1989 $(292.714) $1,034 644 $307,986 $1,049,916 ENVIRONMENTAL ANALYSIS OF PROPOSED BETHEL UTILITY CORPORATION PURCHASE BY THE CITY OF BETHEL, ALASKA Prepared for Alaska Energy Authority 701 East Tudor Road Anchorage, AK 99519 : S g 3 = = b 3 = 2 Prepared by FPE/ROEN Engineers, Inc. 1028 Aurora Drive Fairbanks, AK 99709 September 1991 FPE/Roen Engineers, Inc. 1028 Aurora Drive Fairbanks Fairbanks, Alaska 99709-5529 Anchorage PH: (907) 452-1414 « FAX (907) 456-2707 September 16, 1991 Alaska Energy Authority Attn: Gary Smith, Manager of Rural Projects 701 East Tudor Road P.O. Box 190869 Anchorage, AK 99519-0869 Re: Preliminary Environmental Analysis Bethel Utilities Corporation Contract No. 2800285; AEA-FPE-005 Ladies and Gentlemen: Attached is our report of our findings, analysis and opinions regarding the preliminary environmental assessment and limited site sampling of the Bethel Utilities Corporation properties. The purpose of our investigation was to identify significant environmental liabilities or concerns that would have a major impact on the financial condition of the utility. It is our understanding that the information will be used by the City of Bethel in its consideration of purchasing the Utility. Based on the analysis of the investigation findings as well as the considerations and assumptions set forth in the report, we are of the opinion that: 1. The investigation’s findings disclosed no significant indication of major environmental liabilities involving the Bethel Utilities Corporation properties. There is indication that the power plant and office sites are contaminated with petroleum hydrocarbons and Polychlorinated Biphenyls (PCB) from former operational procedures as well as overfills and spills during refueling of on-site bulk storage tanks and vehicles. Contaminant migration as well as contamination of the deep aquifer used locally for drinking water appears to be mitigated by the restrictive characteristics of the permafrost underlaying the sites. The minor intermittent quantities reported spilled and the known site conditions are not considered symptomatic of a major remediation cost. A limited Phase Il sampling of the deep aquifer groundwater did not identify any contamination and developed a groundwater quality base line for the facility prior to the property transfer. The Utility has initiated partial upgrading of bulk fuel storage by installing secondary containment as well as overfill and spill protection equipment. Additional costs to complete secondary containment of the lube oil and vehicle fueling facility will be required in the future in order to minimize potential for site contamination. 4. While completing the environmental analysis scope of work, Bethel Utilities Corporation was directed by the Alaska Department of Environmental Conservation (ADEC) to restrict the Utility’s operation, apply for an air quality permit and submit the required information to complete the Prevention of Significant Deterioration (PSD) determination for the engine exhaust emissions. While additional air quality control expense may be required for future permits or plant modifications, on March 13, 1991 ADEC issued Bethel Utility Corporation a five year permit to operate. 5 With the ever increasing public and regulatory attention to environmental concerns, future utility management should anticipate a continuing increase in routine environmental compliance costs. In addition, the expense for those historical concerns identified in this assessment may involve notable funds to correct. In accordance with the amended scope of work, a limited survey was completed to quantify only routine environmental budget-expenses. Based on information analyzed, it is recommended that the Utility budget a minimum environmental expense starting at 0.25%, increasing annually on the order of 0.25% of its annual budget towards environmental protection and regulatory compliance. In the preparation of this report and these opinions, we have made certain assumptions based on the investigation’s findings. It is our opinion that these assumptions are reasonable and adequate for the purposes of this report. However, at the time of the initial site inspection the properties were obscured with seasonal snow cover and the scope of work was restricted to a preliminary assessment, limited site sampling, and no audit of operational compliance. Actual site conditions may differ and operational concerns may exist. Our primary considerations and assumptions are presented in detail in the attached report. FPE/ROEN Engineers, Inc. has enjoyed working with Alaska Energy Authority, the City of Bethel, the Bethel Utility Corporation, and CH2M Hill. Specifically, we would like to thank the staff at Bethel Utility Corporation for their significant support during the site inspection and sampling as well as all individuals who assisted FPE/ROEN in data collections and resolution of project concern. We trust that this information is sufficient for your needs at the present time. if you have nay questions, or if we can be of further assistance, please feel free to call. iA eiperbe—§ John M. Hargesheimer;, P.E. hief of Environmental Engineering FPE/ROEN Engineers, Inc. Preliminary Site Assessment Bethel Utility Corporation September 1991 TABLE OF CONTENTS FPE/ROEN Engineers, Inc. Preliminary Site Assessment 1.0 2.0 3.0 4.0 5.0 6.0 7.0 Bethel Utility Corporation September 1991 TABLE OF CONTENTS INTER OD UCONN err rrtc seer ecto stare cere er ve orte ew enectee ce eateece ee ieee ofr ese oe vee 1 BEMREL UmIEMMYACORRORATION Secret coerce cet ee cote eee recente eee 3 aut Hy i ee 3 LOCATION AND DESCRIPTION OF PROPERTIES .......-..2200200e ee eee 4 a1 Generating Facility Properties ......... 2... ce eee eee ee eee eee 4 ie — Cae PC a 7 3.9 Reedeitiel PrOpOrtiOG occ ce ve eee ee 10 SITE CHARACTERIZATION Sop cctecterceycterge ep oreo enotenencr cic = oops ceo oneee Geo. 10 4.1 Regional Topography and Vegetation .........-..-+2 +e ee eee eens 10 oe — Glee ee eee ee itl 4.3 SURFACE AND GROUNDWATER CONDITIONS ............-2++5- 2 AERIAL PHOTOGRAPH INTERPRETATION .........-0 000 e eee eee eee 12 SITE INSPECTION AND INTERVIEWS . 0.2. cece te eee ee Hew ee 14 6.1 GOME ACI ESIC vio rector sooo woo ei ohio le oe vireo wie oy 8) Toe) oye Toe of ote 15 6.1 a Generator Building and Engine Exhaust Emissions .......... 15 6.1 b Warehouse/Shop and Waste Oil Burner ..............254- 17 6.1 c. PCB and Hazardous Material Storage ..............20085 18 5.1 OT TO ne es ee 21 6.1 e. Exterior Transformer, Material and Equipment Storage ....... 22 6.2 Office Property avs nc cco ee rere reece eet bbe KC EEE EE 23 G.2 Rasidendel Properties... ck ccc cca awe eae ie 23 PUBLIC RECORDS/AGENCY REVIEW .... 2... . 0... eee eee eee eee 24 Tal Progerty TGOG Dee oo ew ow ee 24 7.2 Environmental Protection Agency ... 2 ccs cc ccs revere nensnnee 24 7.3. Alaska Department of Environmental Conservation............... 25 7.3 a. Cooling Water Surface Discharge ................00000% 25 7.3 b. Open Burning of Waste Oil ........ 2.2... 2.0... eee ee eee 26 7.3 °C Air Quality Control POtmit ssc ne oc wo ne wo cs eo ste oe 26 7.3 d. Underground Storage Tanks and Contaminated Site Database .. 26 FPE/ROEN Engineers, Inc. Preliminary Site Assessment Bethel Utility Corporation September 1991 8.0 ANALYSIS OF PRELIMINARY FINDINGS ......... 0.000 e ee eee ee eee 26 8.1 Site Conditions 2.0... .... ccc cet eee ee ee eee eee eee tees 27 8.2 Bulk Fuel Storage ... 1... ec ee ee eet teens 28 8.3 PCH end Hazerdous Materialia... ccc caw ee eee eee iee 29 8.4 ADECG Air: Ouiallity: Pe nerit ooas erors eet le ol ott lal Oe 0 a toe ole es 30 8.5 Fesideritia! PrODO@rtiOs . «= sc wo ew ed kh E SRNR eR ews 31 9.0 ADDITIONAL EVALUATION AND SITE SAMPLING ..............220005 31 9.1 Groundwater Site Sampling ... 2... 2... ee eee eee eee eee eee 32 9.2 Air Quality Control Permit Requirements .............-.2200000% 32 9.3 Survey of Environmental Costs .......... 0c eee eee eee 35 10.0 CONCLUSIONS AND RECOMMENDATIONS ..........0 0:00 ee ee eee 37 a\h Je ome 1 [pW FLO) bo samt erg gee eae rg mee ee eee emer ne eee ne ree aC rare 38 APPENDIXES APPENDIX A: Property Ownership History of Parcels APPENDIX B: FPE/ROEN Phase | Environmental Assessment Audit Form for Potential . Acquisitions APPENDIX C: Laboratory Results LIST OF FIGURES FIGURE 1: LOCATION and VICINITY MAP FIGURE 2: CITY OF BETHEL AND LOCATION OF BETHEL UTILITIES PROPERTIES FIGURE 3: AERIAL PHOTOGRAPH of the CITY OF BETHEL FIGURE 4: GENERATION FACILITY PROPERTIES FIGURE 5: OFFICE PROPERTY LIST OF TABLES TABLE ONE: SUMMARY OF PCB VIOLATIONS TABLE TWO: BULK STORAGE TANKS FPE/ROEN Engineers, Inc. Preliminary Site Assessment Bethel Utility Corporation September 1991 PRELIMINARY SITE ASSESSMENT FPE/ROEN Engineers, Inc. Page 1 Preliminary Site Assessment Bethel Utility Corporation September 1991 1.0 INTRODUCTION FPE/ROEN Engineers, Inc. assisted the Alaska Energy Authority in the evaluation of the Bethel Utilities Corporation properties by completing a preliminary environmental assessment as well as a limited site sampling effort. The initial scope of our services for the preliminary assessment was in accordance with our proposal dated October 29, 1990. An additional services request dated March 26, 1991 amended the scope of services to include additional analysis of future environmental costs, air quality control issues, as well as a limited groundwater sampling effort. We understand the information will be used by the City of Bethel in its consideration to purchase the Utility. This report summarizes our investigation, findings, analyses, and opinions regarding the environmental condition of the Bethel Utilities Corporation properties. The project scope and extent of our examination was not of a depth necessary to reveal all environmental issues. It was, however, considered sufficiently thorough to identify major environmental concerns associated with the proposed property transfer that would significantly impact the financial condition of the Utility. The information is provided to assist in the effort of "all appropriate inquiry" recommended by current environmental legislation necessary to address the strict, joint and severable, liability associated with the transfer of real estate. The environmental statutes that are most frequently encountered in the real estate context and considered in this investigation include the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or "Superfund"), the Resource Conservation and Recovery Act (RCRA), and the Clean Air Act, and Clean Water Act. Included in this report: ° A brief project background description and an explanation of the purpose and the scope of work. ° Historical data reviews and information including aerial photographs, regulatory agency files, oral reports and property ownership records. . Records of site visit observations, investigations and interviews completed with the owners and manager of the facility. ° Analyses of the information provided including classifying the site according to a hazardous material rating system into four degrees of risk. e Conclusions are presented regarding FPE/ROEN’s opinion of whether there is significant indication of contamination based on the findings. 1 FORT YUKON, 2S LOCATION AND VICINITY MAP BETHEL UTILITIES vf" || CORPORATION | | Preliminary Site | | | gases iY NUNAPITCHUK °° ATMAUTLUAK TULUKSAK KWETHLUK ARIAK’ sKOKWIM Lo) Assessment i| \| \| | BETHEL, ALASKA || | —— FIGURE 1 A560 East 34th Ave., Suite 300 Anchorage, Alaska 99503-4116 Ph: (907)452-1666 FAX: (907)561-7028 1028 Aurora Drive Fairbanks Alaska 99709-5526 Ph: (907)452-1414 FAX: (907)456-2707 FPE/ROEN Engineers, Inc. Page 3 Preliminary Site Assessment Bethel Utility Corporation September 1991 . Recommendations are provided, where appropriate, for further investigation or site sampling in order to further delineate and characterize any significant indication of contamination. 2.0 BETHEL UTILITY CORPORATION 2.1 History Bethel Utility Corporation (BUC) presently operates and maintains the electrical generation and distribution system for the City of Bethel, Alaska. The corporation is an investor-owner electric utility formed in 1972 by George Tilbury and Harold Borrego. Current stockholders include Harold and Virginia Borrego (husband and wife), Edward Tilbury, Francis J. Davidson, and Elaine R. Tilbury. The Utility was formed to purchase the electrical utility in Bethel Alaska from the Northern Commercial Company. Following purchase, BUC undertook extensive upgrading and renovation to meet the expanding demand in the area. Commercial service during the period between 1972-75 was expanded to include the airport, BIA and the White Alice site south of town. In late 1975 the generating plant at the current office property site burned down. The current generating facility was constructed at the new power plant site in 1976 with long term disaster loan financing from the Small Business Administration. During the late seventies and early eighties BUC participated with the U.S. Energy Research and Development Administration and their contractor TRW in a project involving power plant waste heat and an aquifer thermal energy storage system. The project, conceived to be a grid connected integrated community energy system, received only initial funding for conceptual planning and site studies. As part of the site investigation several deep wells were installed on-site into the aquifer below the permafrost. During the period from 1976 to present the Utility continued to grow at a significant rate. In the early 1980’s a waste heat distribution system was constructed providing lower cost heating sources to nearby users. In addition, regional interties, funded by the Alaska Energy Authority, have been completed to the nearby villages of Napakiak, Oscarville, and Napaskiak. FPE/ROEN Engineers, Inc. Page 4 Preliminary Site Assessment Bethel Utility Corporation September 1991 Currently, annual sales are reported to be in excess of 30,000,000 MWH involving more than 1,700 customers. Between the Anchorage administrative offices and the Bethel generating facility, BUC employs approximately 23 full-time as well as several part-time employees. During the summer when the majority of new construction and maintenance is completed, employment reaches a peak. The current generating facility consists of five diesel generator units with a combined capacity of 9,400 kilowatts manufactured by General Motors. Future plans for growth include the potential for expanding the regional power distribution capability as well as the continued growth in demand anticipated within the City of Bethel itself. 3.0 LOCATION AND DESCRIPTION OF PROPERTIES Bethel Utilities Corporation leases its accounting and administrative offices located in Anchorage, Alaska. The generating facility, Bethel office and residential properties involved with the proposed ownership transfer are located in the City of Bethel. The City of Bethel is located in the Lower Kuskokwim River Delta of southwestern Alaska (Figure 1). Bethel is approximately 400 air miles west of Anchorage and located on the north bank of Kuskokwim River, 86 miles inland from the sea. The population of Bethel is estimated to be 4,500. Location of the Bethel properties is shown on Figures 2 and 3, and described in the following sections. 3.1 Generating Facility Properties The generation facility is located on the southwest side of town. The parcel is comprised of lot 6, 10D, 10E, and 10F of Plat Number 82-17 located in U.S. Survey 4117 and consists of total of approximately 11.4 acres. The lots were previously undeveloped and owned by Tundra Development Company or the Calista Corporation. The parcels are located in a "general use" district land use designation. This district is intended to allow a mix of compatible residential and commercial uses. Noxious, injurious, or hazardous uses are not permitted in the district designation. v MUNICIPAL OFFICE BUILDING / LIBRARY SITE LOCATION MAP | BETHEL UTILITIES 1) | CORPORATION | Preliminary Site Assessment BETHEL, ALASKA lI | FIGURE 2 | foen @560 East 34th Ave., Suite 300 Anchorage, Alaska GPE 99503-4116 Ph: (907)452-1666 FAX: (907)561-7028 i 1028 Aurora Drive Fairbanks Alaska Engineers, -| 99709-5526 Ph: (907)452-1414 FAX: (907)456-2707 || Oe STE OFFICE K——FICURE 3} | #560 East 34th Ave., Suite 300 Anchorage, Alaska 99503-4116 Ph: (907)452-1666 FAX: (907)561-7028 , (]1028 Aurora Drive Fairbanks Alaska Engineers, Inc.| 99709-5526 Ph: (907)452-1414 FAX: (907)456-2707 || FPE/ROEN Engineers, Inc. Page 7 Preliminary Site Assessment Bethel Utility Corporation September 1991 To the north and west is undeveloped property owned by the Bethel Native Corporation. To the south and east the adjacent land is owned by the Calista Corporation. To the east is the closest building consisting of a 40 unit apartment complex owned by the Calista Corporation. A listing of property record ownership, including mailing address and date of transfer as available from the City of Bethel records is provided in Appendix A. Figure 4 is a sketch of the generating facility parcel showing adjacent lots and current ownership. A legal survey of property improvements was not completed as part of project work scope. It should be noted that based on the plot plans and aerial photographs reviewed that the warehouse may not be entirely located on BUC’s property. 3.2 Office Property The downtown billing and meter office property is located at 160 State Highway, immediately northeast of the Municipal Office Building and the Library site. The parcel, Lot 3 Block 2 of Plat Number 73-244, USS 870, is the previous location of the original power generation facility which burned down in 1975. The existing parcel is approximately 200’ by 300’ with 59,999 sq. ft.. The parcel is located in a "general use" district land use designation. This district is intended to allow a mix of compatible residential and commercial uses. Noxious, injurious, or hazardous uses are not permitted in the district designation. Originally the parcel included the parcel to the northwest which was donated to the VFW. The parcel is bordered on the southwest by Ariak Drive and State Highway or Airport Road on the southeast. To the northwest is lot 2 which is currently undeveloped. A listing of property record ownership, including mailing address and date of transfer as available from the City of Bethel records is provided in Appendix A. Figure 5 is a sketch of the parcel showing adjacent lots and current ownership. A legal survey of property improvements was not completed as part of project work scope. It should be noted that based on the plot plans and aerial photographs reviewed that the office may not be entirely located on BUC’s property. BULK FUEL STORAGE AREAS CURRENT MATERIAL STORAGE ACCESS HISTORICAL AREAS OF SPARE MATERIAL AND TRANSFORMER EXISTING STRUCTURES AND IMPROVEMENTS RAZED STRUCTURES PRIOR TO CURRENT IMPROVEMENTS DEVELOPED PAD AREA OF SITE mums CURRENT SITE BOUNDARY EeeEPr= Engineers, Inc. STORAGE FROM AERIAL PHOTOGRAPH U.S. SURVEY NO. 4000 APARTMENT COMPLEX CURRENT USED TRANSFORMER AND MATERIAL STORAGE AREA POWER PLANT SITE BETHEL UTILITIES CORPORATION Preliminary Site Assessment BETHEL, ALASKA | 560 East 34th Ave., Suite 300 Anchorage, Alaska 99503-4116 Ph: (907)452-1666 FAX: (907)561-7028 1028 Aurora Drive Fairbanks Alaska 99709-5526 Ph: (907)452-1414 FAX: (907)456-2707 BARREL & MATERIAL QUANSET HUT— STORAGE (PRIOR STORAGE (PRIOR TO EXISTING TO EXISTING IMPROVEMENTS IMPROVEMENTS) LOT a4 3 BUILDING LEGEND: OFFICE SITE | BETHEL UTILITIES | | | RAZED STRUCTURES AND | mrna anne se sl — MATERIAL STORAGE AREAS PRIOR TO EXISTING IMPROVEMENTS APPROXIMATE SHORE LINE — — — — LOCATION PRIOR TO PRESENT IMPROVEMENTS CORPORATION TL] BSBVgustigrTrss Preliminary Site Assessment ORIGINAL SITE womens CURRENT SITE BOUNDARY BETHEL, ALASKA FIGURE 5 oem @560 East 34th Ave., Suite 300 Anchorage, Alaska FE /(S3) 99503-4116 Ph: (907)452-1666 FAX: (907)561-7028 7 1028 Aurora Drive Fairbanks Alaska Engineers » Imc.]- 99709-5526 Ph: (907)452-1414 FAX: (907)456-2707 FPE/ROEN Engineers, Inc. Page 10 Preliminary Site Assessment Bethel Utility Corporation September 1991 3.3) Residential Properties Bethel Utilities Corporation owns two residential properties. Both are currently used by employees as residences. One is located on the generation facility parcel which is designated as "general use" district. It reportedly consists of a three bedroom home. The second residential property is located on Lot 9 of Blueberry Acres (Plat 82-12, USS 4117) comprised of 10,000 square feet. The subdivision is designated as a "residential" land use. The address is 1687 Alex Hately Drive and consists of a two bedroom home. A listing of property record ownership, including mailing address and date of transfer as available from the City of Bethel records is provided in Appendix A. 4.0 SITE CHARACTERIZATION 4.1 Regional Topography and Vegetation The Lower Kuskokwim Region exhibits a regional topography characteristics of a mature river delta. The land is basically flat and poorly drained with features such as river meanders, meander cut-offs, small drainage ponds and abandoned channels. While the majority of the land is underlain with permafrost these features can cause soil profiles to change dramatically within a short distance. A significant portion of the city of Bethel is reported to lie below the 100 year flood level. While the office property is located downtown it is noted that the primary parcel involving the generating facility is located on higher ground. The actual generating plant site is a small swale on the parcel that naturally drains either to a small pond located to the west or to alow lying area near the hospital site to the east. Local vegetation is that typical of permafrost regions where standing water is almost always present in summer. The insulating tundra mat is formed by the dominant vegetation of sedges and cottongrass. In non permafrost and/or higher/dryer sites, a few woody and herbaceous plants such as willows and alders are typical. FPE/ROEN Engineers, Inc. Page 11 Preliminary Site Assessment Bethel Utility Corporation September 1991 4.2 Site Soil Conditions The overlying tundra mat insulates those areas of the parcels not altered by development. Typically, the tundra mat is approximately 1.5-2.5 feet thick and grades from minimally decomposed organics to a highly decomposed reddish brown material at depth. At the interface of the organic layer and underlying soils ice rich soils are generally found. The material beneath the organic layer is typically a fine grained grayish brown sand with some silt. With increasing depth soils grade to slightly coarser materials.' The thickness of the permafrost varies depending on the site. A U.S. Air Force well (#2) log identified frozen material to a depth of approximately 600 feet.” All of the involved parcels natural characteristics have been modified by activities of development. The sites are accessed and/or served by roads as well as building pads. These site modifications are typically constructed of readily available local material sources consisting primarily of silty sands. In addition, it is standard practice to develop and maintain drainage channels along roadways and adjacent to building pads to remove surface runoff and prevent ponding. These activities of development will alter the permafrost. A geotechnical field investigation of the generating facility parcel completed in 1980 by R&M Consultants involved seven test borings to a maximum depth of 30 feet below the ground surface. The investigation provided the following information regarding the condition of the permafrost at the time of the report:* The major disturbance to the site is attributed to degradation of the permafrost underneath the roadway fill. In areas where the insulating tundra mat is undisturbed the presence of permafrost was detected within 18 inches of the ground surface, whereas the permafrost beneath roadways usually varied between 6 and 7.5 feet deep. ‘Geotechnical Investigation for Aquifer Thermal Energy Storage System Bethel Alaska; Prepared by R&M Consultants, Inc.; September 1980; page 6. ?Alaska Regional Profiles; Southwest Region; prepared by The Joint Federal Land Use Planning Commission for Alaska. Sibid. footnote 1. FPE/ROEN Engineers, Inc. Page 12 Preliminary Site Assessment Bethel Utility Corporation September 1991 The depth to permafrost beneath the roadway fill near the Plant’s storage shed was an exception and frozen ground was encountered at a depth of 15 feet. This additional thawed soil is attributed to heating of the shed. 4.3. SURFACE AND GROUNDWATER CONDITIONS The subsurface permafrost conditions creates a restrictive layer allowing perched ground and surface waters to accumulate. Typically, the quality of these relatively stagnant water sources is not potable and may contain high amounts of dissolved solids. In some areas due to past undesirable waste disposal practices surface the shallow ground waters perched on the permafrost may be contaminated with sewage or other contaminants. Potable water is usually drawn from deep wells drilled through the permafrost into aquifers located several hundred feet below the frozen layer. The water source is characterized as quite good and having moderately high dissolved minerals.* 5.0 AERIAL PHOTOGRAPH INTERPRETATION Aerial photographs were reviewed for both the office and generating facility sites back to a date when both parcels were observed to be vacant and essentially undeveloped. Figure 3 is a reproduction of a 1990 photograph taken in August at a scale of 1 inch = 500’. The following are the significant observations noted for each parcel for the aerial photographs reviewed by the year of the photograph: 1968 Generating Facility: Photography did not include the site, however was possible to verify that the existing access road (Kwethluk Lane) to site was not constructed. Next earlier aerial photograph reported to be in the 1950's. Office: Site undeveloped. Gravel pad development in process for the City building as well as improvements to Akiak Drive and the State Highway. Majority of site with natural vegetation with little or no debris. Some associated gravel pad work underway on subject parcel. *The Demonstration of a Grid-Connected Integrated Community Energy System; Technical Proposal by Energy Resources Division of North-West Industries, Inc., November 1976. FPE/ROEN Engineers, Inc. Page 13 1972 1973 1979 1990 Preliminary Site Assessment Bethel Utility Corporation September 1991 Generating Facility: Site undeveloped. Marginal trail (Kwethluk Lane) from location of residence to the southwest. Small shack/structure at end of trail at approximate location of current generating facility. Office: Original generating facility constructed on gravel pad. Pad area and adjacent property fairly clean with minimal or no debris and material on site. Office not yet constructed. Generating Facility: No change, site not developed. Kwethluk Lane not constructed. Office: Substantial amount of materials, barrels and equipment stored on west end of site beyond location of generating plant. Quonset hut located in the same area north east of main power plant. Office on southeast end of parcel currently under construction. Lumber and building material stored around building. Generating Facility: Main building and warehouse constructed. Associated pad is limited to minimal area around building footprint. Material, equipment and barrel storage noted along both sides of Kwethluk Lane in both directions extending to the residence located to the southwest. Office: Original generating facility gone reportedly burned in December 1975. Quonset hut still present. Gravel pad observed with minimal debris. Office present. Generating Facility: Site pad significantly extended to the northwest-southwest sector within close proximity of lake. Barrels and material storage along Kwethluk Lane removed. Material storage noted throughout site pad. Office: Quonset hut removed. VFW facility constructed. Office on site. Original pad apparent with minimal debris and vegetation recovering in area. FPE/ROEN Engineers, Inc. Page 14 Preliminary Site Assessment Bethel Utility Corporation September 1991 6.0 SITE INSPECTION AND INTERVIEWS On December 17 and 18, 1990 a representative of FPE/Roen, Engineers Inc. made a limited site inspection of the BUC properties located in Bethel, Alaska. During the site visit we visually inspected the generating facility and completed a drive by of the office site and residential properties. Meetings and informal conversations were conducted with the following Utility and City of Bethel personnel as well as members of the City Council. Harold Borrego BUC President Rodney Rogers BUC Foreman Mark Earnest City Manager Corlis Taylor City Administrator/Personnel Manager Tom Graham City Finance Manager Jack MacDonald Chief of Police Gary Vanasse Mayor Wally and Buster Richardson City Council Ben Dale City Council Wally Wallace City Council Following the site inspection of the Bethel BUC properties we visited with Ed Tilbury, BUC Vicé-President, and Tom Sterrett, Controller, in the Anchorage administrative offices of BUC. The general consensus of the informal conversations and discussions with the City staff as well as the City Council indicated that the current operational efforts of the Bethel Utility Corporation are considered environmental sensitive and responsible. Several comments were made regarding the Utility’s level of community concern and the recent efforts by the Corporation to upgrade the facility. This operational appreciation carried over to purchase considerations wherein the City staff reported no desire to alter management and concern over short term political control if they became the owner. While the current operation received praise, the individuals interviewed expressed historical concerns regarding operational practices and observed site conditions. As is often the case the activities were not considered intentional but a reflection of the changing awareness of routine operational practices. Visible contamination of site surfaces was reported. On-site storage of contaminating fluids including PCB contaminated transformers was noted. Historical discussions repeatedly noted the general absence of current environmental concerns and operational practices previously existed. FPE/ROEN Engineers, Inc. Page 15 Preliminary Site Assessment Bethel Utility Corporation September 1991 Comprehensive interviews and completion of Phase | Environmental Assessment Audit Form for Potential Acquisitions was undertaken with Harold Borrego and Edward Tilbury. During the drafting of this report the completed questionnaire contained in Appendix B was reviewed by the interviewees for accuracy and agreement. While in Bethel Mr. Borrego and the foreman, Randy Rogers, assisted in the site inspection and field tour of the Bethel properties. Historical background information was provided by Mr. Borrego and Mr. Tilbury, available references and public records. The following is a summary by site of the site inspection, interviews, and information reviewed during the field trip. 6.1 Generating Site The generating site consists of the power plant building (housing the generators and control equipment), warehouse/shop and a residence at the south end of the parcel. In addition, spare material, equipment, fuel and hazardous material storage areas are located on-site. Figure 4 is a sketch of the lots involved and the location of the respective facilities. Drinking water is provided from a deep well installed by TRW as part of the aquifer thermal energy storage system project during the early eighties. Wastewater is collected in a below grade holding tank with a lift pump that discharges to the community collection system. 6.1 a Generator Building and Engine Exhaust Emissions The generators, engines, and electrical control equipment are housed in a metal building approximately 130’ X 70’. The building has a refrigerated (with both passive and active components) concrete slab foundation on pilings. At the time of the inspection the interior of building was orderly and neat suggesting routine operational and maintenance practices that regularly address cleaning and maintenance that would effectively minimize potential for site contamination. No floor drains were observed. Waste oil, debris and other waste products were observed to be separated and stored in containers. An inspection of the generating facility completed in August of 1990 by the Alaska Department of Environmental Conservation "determined that: 1) the facility requires and Air Quality Control Permit to Operate, and 2) additional information about the facility is required before we can reach a decision to grant a permit." Specifically, the generators are subject to the State Air Quality Control Regulations 18 AAC 50.050(a)(1) for visible emissions, (b)(1) FPE/ROEN Engineers, Inc. Page 16 Preliminary Site Assessment Bethel Utility Corporation September 1991 for emissions of particulate matter, (c) for emissions of sulfur dioxide and (d) oxides of nitrogen. In addition the engine generating capacity and characteristics were interpreted by the Department as subjecting the facility to the Prevention of Significant Deterioration (PSD) provisions of applicable State and federal regulations. The PSD permitting process is a recognized significant investigation. ° Ambient air and meteorological data. ° Ability to attain ambient air quality standards and increments. e Best available control technology. e Visibility, vegetation and soils analyses. . Operating restrictions. Bethel Utilities Corporation preliminary response to ADEC’s permit requirement and request for information was filed January 3, 1991. Alaska air quality regulations (18 AAC 50.300 (a)(C)) allow the "grandfathered" operation of a facility without requiring the PSD permitting process if the facility existed prior to August 7, 1977 and has not been modified since August 7, 1980. It is the BUC’s position that generating capacity has not been modified to the extent that operation has exceeded the statutory maximums established by the permit exemption. Therefore, the facility should be automatically "grandfathered in" with regard to the maximum allowed emissions. Their written response to the Department provided engine emission data and calculations substantiating their position that modifications and operational records have not resulted in emissions that have exceeded the regulatory limits established by the "grandfathered" permit exemption emission limits. Based on his discussions with the Department Mr. Tilbury reported that he was confident that the facility would qualify for the grandfather exemption. During the completion of this report and following ADEC and BUC discussions, BUC requested a PSD avoidance Air Quality Control Permit to Operate on February 4, 1991. ADEC subsequently issued the BUC power plant a five year permit on March 13, 1991. BUC was not required to provide the information for the PSD determination since they requested limitations on operations to reduce emissions to levels below those specified in 18 AAC 50, resulting in PSD avoidance. Conditions in the permit include limitations on the total power generated, the gallons of diesel fuel burned, and the sulfur content of the fuel; source testing of one of source Nos. 1 - 4 for nitrogen oxides and carbon monoxide emissions; continuous emission and process monitoring; and routine analysis of fuel oil. During the preparation of this report Ed Tilbury with BUC indicated that a contract for the required air emission test had been developed and was currently being completed. FPE/ROEN Engineers, Inc. Page 17 Preliminary Site Assessment Bethel Utility Corporation September 1991 The engines are cooled via a closed loop water cooling system. In addition a waste heat distribution system providing lower cost heating sources is utilized throughout the urban areas of Bethel. The waste heat system currently is only using energy recovered from the cylinder water jackets of the diesel generating units. Current waste heat demand is at a level where the additional waste heat from exhaust heat recovery boilers is not required. Excess heat in the cooling water is dissipated through radiators. Prior to 1987 when additional radiators were installed it was intermittently necessary to waste excess heat by discharging cooling water to the surface and/or the small lake located on-site. While the Utility indicated that they requested a discharge permit they ultimately avoided the regulatory requirement with installation of additional radiators eliminating the need to discharge cooling waters. Cooling water and waste heat distribution fluids are routinely monitored. Chemicals are added to control corrosion and provide color for easy identification in the event of a system leak. Cooling water analysis reports were provided by BUC and reviewed. Laboratory analysis included results for pH, P, Mg, Cl, SO,, and NO,. The information and comments indicate the PH is maintained ideally at "around 9.0". NO, is maintained in the range of 800-1,200 ppm. While no samples were collected none of the building materials observed with the exception of the small amount of drop in ceiling tiles in the office area would be suspected of containing asbestos. While typically it can be assumed that some asbestos materials may exist in equipment gasketing or nonfriable building materials no friable insulation materials suspected of containing asbestos were observed. 6.1 b Warehouse/Shop and Waste Oil Burner The shop warehouse is a metal building approximately 75’ by 50’ with four main stalls. The building is used to provide heated area for vehicle and equipment storage and repair as well as spare parts inventory. Building heat is provided by a waste oil burner. The entire building has a concrete floor which is partially sloped to drain toward the front of the building. No floor drains were observed. The building was originally constructed with a concrete slab only in the eastern most section or equipment stall. The remaining concrete slab floor was installed recently. Mr. Borrego indicated that vehicle maintenance, including oil changes, was routinely practiced in portions of the shop without a concrete floor prior to its installation. He indicated that the concrete floor had been installed to reduce the potential for ongoing contamination of the gravel subbase material by providing containment and a surface that could be easily maintained in a clean condition. FPE/ROEN Engineers, Inc. Page 18 Preliminary Site Assessment Bethel Utility Corporation September 1991 In the past substantial quantities of waste oil were generated by the routine maintenance on the diesel fired generators. In recent years the practice of regularly replacing the engine oil has been significantly decreased through the use of a higher quality engine oil. It was reported that the majority of waste oil currently generated and used in heating the warehouse is accumulated from engine oil from the Utility’s vehicles and equipment fleet. A small day tank of waste oil for the burner is located inside the warehouse building. It was reported that due to the waste oil impurities regular maintenance and cleaning of the waste oil burner was required to keep the unit operational and clean burning. In addition to the containment provided by the concrete floor, a drip tray and oil spill cloths where evident where small quantities of waste oils spillage was expected and maintenance activities were required. Rack storage of new product purchased in standard barrel quantities including insulating and lubricating oils, antifreeze, etc. was housed in the warehouse in the area where the concrete floor had been installed originally. In addition, maintenance compounds and fluids purchased in 5 gallon quantities and in use were stored in this area of the building. Bulk storage of these materials not in use were reported to be stored in the hazardous material facility located adjacent to the shop/warehouse and addressed below. The concrete floor in the vicinity of the in use storage area of these materials was noticeably stained from spillage. However, there was oil absorbent cloths and materials present and evidence that in the event of a spill employees have routinely taken the necessary effort to clean up spillage that would normally be contained on the concrete floor. 6.1 c. PCB and Hazardous Material Storage Over the past 1-2 years BUC has undertaken a significant program to eliminate all PCB contaminated transformers and dielectric oils. In 1988 the Environmental Protection Agency completed a site inspection specifically for PCB contaminated materials. The inspection reportedly confirmed the presence of PCB transformers, technical regulatory violations as well as the presence of PCB contaminated site soils from the leakage of transformers. Mr. Borrego and Mr. Tilbury indicated that this resulted in a formal EPA complaint, BUC response and consent agreement that is currently in effect. Copies of the referenced documents were requested and provided by the Utility. Review of the United States Environmental Protection Agency PCB complaint (Docket No. 1090-02-31-2615) dated February 27, 1990 alleged a total of 26 violations of federal regulations addressing the use and/or disposal of polychlorinated biphenyl (PCB) promulgated FPE/ROEN Engineers, Inc. Page 19 Preliminary Site Assessment Bethel Utility Corporation September 1991 under section 15 of the Toxic Substances Control Act (TSCA). Table One is a summary breakdown of the violations and the corresponding regulations and requirements. TABLE ONE SUMMARY OF PCB VIOLATIONS As Alleged By USEPA Complaint Docket No. 1090-02-31-2615 VIOLATION COMPLAINT REGULATORY APPLICABLE REGULATION NUMBER REQUIREMENT 1-3 | Disposal 40 CFR 8 761.60 4-8 Disposal 40 CFR § 761.60 Quarterly Inspections 40 CFR § 761.30 Registration 40 CFR § 761.30 Labeling/Marking 40 CFR 8 761.40 Storage for Disposal 40 CFR § 761.65 | : 22-26 | Recordkeeping 40 CFR § 761.80 Section 16 of TSCA USC § 2615, and the regulations promulgated thereunder , 40 CFR Part 761, authorize a civil penalty of up to $25,000 per day for each violation of TSCA. Actual penalties are determined according to a standardized procedure provided in the Guidelines for Assessment of Civil Penalties Under Section 16 of TSCA; PCB Penalty Policy. As prescribed by the penalty assessment matrix the extent of these violations was represented as "minor" and the proposed penalty calculated in each complaint was a total of $66,000. Following the Informal Response to Complaint filed by the Bethel Utilities Corporation, a Consent Agreement and Final Order was signed in October 1990. An adjusted civil penalty of $11,730 with $7,038 suspended and deferred pending satisfactory compliance with the remaining conditions of the Final Order was agreed upon. The $4,692 cash portion of the penalty was paid. The Final Order condition for deferment forever of the suspended portion of the civil penalty was: FPE/ROEN Engineers, Inc. Page 20 Preliminary Site Assessment Bethel Utility Corporation September 1991 "Within one year from the date of entry of this Order, Respondent shall file with EPA an affidavit and appropriate documentation to verify that the Respondent sampled, tested, and disposed of PCB-contaminated Transformers and PCB Transformers with useful remaining life after June 1, 1990" During the site inspection shipping manifests were reviewed that confirmed proper packaging and shipment of PCB contaminated transformers, oils and soils for disposal at an approved facility. A letter from the approved disposal facility confirming receipt and providing notification of the schedule of destruction was provided. Pending final disposal scheduled during 1991, a certificate of destruction will be issued to the Utility. The documents were reviewed and, pending the certificate of destruction, the final order condition should be satisfied. A restricted access and enclosed storage facility was constructed as part of the disposal of PCB materials. An enclosed area designed and approved to serve as temporary storage of PCB containing equipment is located at the west end of the warehouse/shop building. In addition to being completely enclosed, waterproof and lockable secondary containment adequate to hold twice the volume of the largest item or 25% of the total stored volume was provided to prevent site contamination in the event of container leak. The restricted-access exterior hazardous material storage is fenced and located immediately adjacent to the enclosed storage. The area was properly labeled warning of hazardous material storage. Inspection of the area and stored barrels did not disclose any leaking containers or noticeable site contamination. The barrels were appropriately stored upright, one high, labeled and segregated into separate locations by content. At the time of the inspection the hazardous materials area had the following types of labeled wastes: Waste Oil with Lead (awaiting transport out of Bethel) Oil with Gas and Dirt Good Used Oil Miscellaneous Electrical Transformers in Storage While seasonal snow cover prohibited a thorough inspection of the site surface, those limited areas that were wind blown clean did not exhibit any visual evidence of contamination. FPE/ROEN Engineers, Inc. Page 21 Preliminary Site Assessment Bethel Utility Corporation September 1991 6.1d Bulk Storage Tanks Table Two provides a tabulation of the bulk storage tanks located on site. Other than the domestic wastewater holding tank there were no underground storage tanks reported on-site. Figure 4 identifies where on-site those storage tanks are located including the wastewater holding tank. All of the tanks, except the lube oil purchased in bulk skid mounted containers, are delivered as required from standard fuel distribution vehicles. The filling frequency varies for each product. The generator fuel oil day tanks are filled daily. Interviews with Utility personnel reported that overfills and spills have occurred. Mr. Borrego indicated that he felt the largest of the spills would probably be less then 200 gallons. While standard procedures are to take immediate steps to cleanup and contain any spillage, he reported that these efforts had not always been practiced in the past or were not considered feasible during inclement weather conditions. Only the two 20,000 gallon recently installed fuel oil day tanks for the generators have secondary containment. In addition it was reported that a overfill "Tank Minder" device was currently being installed. The remainder of the tankage was single wall above ground tankage. Mr. Borrego indicated that the Utility had plans underway to install a liner and dikage for secondary containment of the lube oil tankage. During the site inspection, a delivery of fuel to the generating engines fuel oil day tanks was observed. A five gallon bucket left on-site was utilized by the driver to catch any fuel drips at the hose connection at the vehicle and the storage tank. The vehicle operator indicated that during the winter the fuel strainer associated with the storage tank pump routinely froze with filtered debris and required cleaning at least monthly. The physical arrangement, location, and design of the pump strainer did not appear to permit draining and was reported to cause minor spillage during removal for cleaning. Inspection of surface soil conditions in the vicinity of the tankage was limited due to seasonal snow cover. The recently installed double contained fuel oil day tanks, as well as the lube oil tanks, had exposed surface soils visible beneath them. While no confirmation samples were collected, these soils appeared visibly contaminated. FPE/ROEN Engineers, Inc. Page 22 Preliminary Site Assessment Bethel Utility Corporation September 1991 TABLE TWO BULK STORAGE TANKS Gasoline Vehicle <500 gallon 5-6 Company Vehicles Diesel Vehicle < 500 gallon Above Minimal - Cat & Bucket Ground Truck Waste Oil Tank in 300 gallon Above Feed for Waste Oil Burner Shop Building (since 1977-78) Ground for Bldg. Heat Inside Engine Generator 2-20,000 gallons Above Double Wall Tanks. Fuel Oil Day Tanks Ground Currently installing a tank Installed in minder and overfill 1989-90 protection. Lube Oil 2-10,000 gallon Insulated Tanks Installed 1984-86 Additional Skid Mounted Lube Oil Bulk Storage was Temporarily On-site 6.1 e. Exterior Transformer, Material and Equipment Storage Significant portions of the gravel pad not used for access, parking and buildings are used for transformer, spare parts and equipment storage. South of the power plant there currently exists a substantial number of surplus transformers that were awaiting resale. Plant personnel reported that none of the transformers contained PCB’s and all of the transformers observed were properly labeled. On portions of the gravel pad adjacent to the on-site lake, additional equipment, boats, containers and miscellaneous spare parts were observed. FPE/ROEN Engineers, Inc. Page 23 Preliminary Site Assessment Bethel Utility Corporation September 1991 6.2 Office Property The only building currently located on the office parcel is the local billing and meter office for Bethel Utilities Corporation. The structure is wood frame constructed in 1973. Behind the office building to the north, was previously located the generating facility which burned in December of 1975. The footprint of the generating plant is shown on Figure 5. The adjacent triangle-shaped parcel to the north was originally part of the power generation parcel during this earlier period. Following the 1975 fire and relocation of the power plant to the current generating site this portion of the property was donated by the corporation to the local VFW. Based on interviews and aerial photograph review the location of material, equipment and barrel storage for the Utility, during this period when this site was used for power generation, was to the north of the power plant on the property currently owned by the VFW. Observations (from a 1973 aerial photograph) of barrels and materials stored in this area as well as a quonset hut used to store spare parts and equipment are included on Figure 5. Verbal reports suggested that the gravel pad in the vicinity of the power plant was likely to have been contaminated by routine operational practices of BUC in the 1970's. Construction of the VFW facility involved importing substantial quantities of material to raise the site and pad. Review of aerial photographs taken since 1975 did not identify any significant site use other than the office facility and exhibited signs of vegetation regrowth on the pad due to non use. 6.3. Residential Properties The Utility owns two residential properties. Both are single family residences, providing housing for Utility employees. The three bedroom unit located on the generating site is an older structure dating to the sixties. The earliest aerial photograph that included the residence was taken in 1968. The area surrounding the structure appeared to be in use as a garden of a significant size. The two bedroom residence is located on a standard size city lot in a recently developed subdivision northeast of Bethel. FPE/ROEN Engineers, Inc. Page 24 Preliminary Site Assessment Bethel Utility Corporation September 1991 Water and wastewater for the residences as well as the majority of Bethel is provided by holding tanks. Drinking water is delivered by tanker. Wastewater is typically collected in a buried holding tank and removed periodically by septage hauler. Both residences are heated through the burning of heating fuel provided in above grade storage tanks located on-site. These fuel storage containers are refueled by routine delivery via standard fuel oil distribution vehicles and hoses, representing a potential for site contamination. While leakage may occur in some instances the above ground, visible aspect of the tanks and Bethel’s inclement weather would suggest that overfills and spills would be the primary concern. Seasonal snow cover at the time of the inspection prevented any visible examination of the site’s surface soils in the vicinity of the storage tanks. Neither residence was inspected inside. 7.0 PUBLIC RECORDS/AGENCY REVIEW Ten Property Records The City of Bethel provided a summary of property records available form their property records. The information included all relevant property transfers since the late sixties including the name and address of the current owner, land use planning classification and the legal description. The information provided the basis for understanding the history of each site and was used during the interviews and inspections to direct our questions and inquiry as well as in the preparation of this report. The information is appended to this report in Appendix A. 7.2 Environmental Protection Agency The Environmental Protection Agency (EPA) was contacted numerous times during the investigation to identify existing files and verify the information. A written Freedom of Information request to identify all existing files was registered with Mary Neilson, EPA Region 10 Freedom of Information Officer. Response to the request confirmed that no record of any files existed in any other division of EPA except Toxic Substances (PCB). Specifically, this search included the Air, Water, and Superfund sections of EPA. FPE/ROEN Engineers, Inc. Page 25 Preliminary Site Assessment Bethel Utility Corporation September 1991 With regards to the Toxic Substances Division’s file we talked with Barbara Ross and William Hedgebeth with EPA Region in Seattle, Washington. The EPA file addresses the proper handling of PCB contaminated materials determined by an EPA site inspection on August 31, 1989. Ms. Ross who is currently responsible for the file indicated that the inspection found numerous PCB violations including contaminated site soils from spillage and transformer leakage. Subsequent to the inspection she reported that a complaint and ultimately a consent agreement had been completed in the case. She indicated that if | had available for review the complaint and the consent agreement that | "would have the essence of the EPA file”. That information was received and reviewed. Valerie Haney in the Anchorage office of EPA was contacted. She confirmed the PCB file and comments as well as the absence of any other EPA files. It was recommended that the Alaska Department of Conservation be contacted. a3 Alaska Department of Environmental Conservation Alaska Department of Environmental Conservation personnel were contacted in the Bethel, Wasilla, Anchorage, and Juneau offices. The Wasilla office of ADEC was visited and their files reviewed. The ADEC personnel interviewed and BUC files reviewed included information on the following complaints or issues. 7.3 a. Cooling Water Surface Discharge During the 1987 there were internal memos and letters to BUC regarding the apparent discharge of cooling water to the surface of the ground and the pond on-site. The Utility requested a permit to discharge excess cooling water which it had been doing intermittently during periods when operating conditions necessitated it. The Department wanted the Utility to cease the discharge until a permit application had been provided and the permit was granted. Apparently the issue became moot when BUC installed additional cooling water radiators to eliminate all discharge of waste heat cooling water. FPE/ROEN Engineers, Inc. Page 26 Preliminary Site Assessment Bethel Utility Corporation September 1991 7.3 b. Open Burning of Waste Oil In May of 1990, an episode of open burning of waste oil was reported. From the file it was unclear whether the waste oil burner used by the facility was malfunctioning and emitting black smoke or waste oil was improperly being burned in an open container. The Utility was notified and indicated that they would cease burning of waste oil. 7.3 c. Air Quality Control Permit At the time the Agency review was completed, file memorandums and copies of correspondence provided by BUC indicated that the Department considered the Utility to be out of compliance with Air Quality regulations 18 AAC 50. The Department interprets the modifications undertaken since August 7, 1980 to violate the modification condition voiding the grandfather exemption rights provided in the regulations for facilities constructed prior to August 7, 1977. During our discussions Department personnel suggested that this was going to be their position regardless of whether the modifications have not resulted in emissions that exceed the grandfather exemption levels permitted. Section 6.1 a. Generator Building and Engine Exhaust Emissions as well as Section 9.2 Air Quality Control Permit Requirements provides additional discussion regarding BUC air emissions. 7.3 d. Underground Storage Tanks and Contaminated Site Database Dave Belyea with the Central Office for ADEC in Juneau was contacted regarding contaminated sites and underground storage tank registrations. Both computerized databases were checked and no record of a listing in either was found under the name of the facility or the principal owners, Mr. Borrego or Mr. Tilbury. Written verification of the file check was provided and is available upon request. 8.0 ANALYSIS OF PRELIMINARY FINDINGS Bethel Utilities Corporation is an investor owned electric utility regulated by the Alaska Public Utilities Commission serving the City of Bethel, Alaska. Revenues in 1989 exceeded 4.5 million for energy requirements in excess of 30,000,000 kWh. At the time of our inspection the facilities were orderly and neat, suggesting routine operation and maintenance practices FPE/ROEN Engineers, Inc. Page 27 Preliminary Site Assessment Bethel Utility Corporation September 1991 and a management attitude that would effectively minimize the potential for intentional site contamination. The general consensus of those interviewed, including employees, city staff, long-time residents/customers and city council members, was that Bethel Utilities Corporation is currently a well-run, environmentally sensitive and responsible utility. As could be expected with any existing utility with almost a twenty year operating record and our society’s increased environmental awareness and regulations, a number of historical areas of environmental concerns were identified and noted below. Where appropriate it is recommended that further investigation be undertaken to accurately delineate the magnitude of the concerns prior to the transfer. Based on the facility’s revenue capability and the analysis of the findings the investigation disclosed no significant indication of any major environmental liabilities involving the Bethel Utilities Corporation properties. With the ever-increasing public. and regulatory attention to environmental concerns, utility management should anticipate a continuing increase in routine environmental compliance costs. In order to minimize these future expenditures it is recommended that an operational audit and compliance program be developed to monitor site conditions, operational practices and regulatory requirements essential to a timely cost-effective mitigation of any concerns within budget and scheduling capabilities. Additional evaluation of this area of concern was completed under a subsequent contract modification. The findings of fact and analysis are provided in Section 9.3 Survey of Environmental Costs. A legal survey of property improvements was not completed as part of project’s work scope. It should be noted that, based on the plot plans and aerial photographs reviewed, the warehouse and office may not be entirely located on BUC’s property. It is recommended that a formal boundary survey be completed prior to any property transfer. 8.1 Site Conditions The Bethel Utility’s properties are located in the Lower Kuskokwim region which has a regional topography characteristic of a mature river delta. The land is basically flat, poorly drained and typically underlain with deep permafrost with an active layer as shallow as 1.5 to 2.5 feet. Under developed areas and surface waters the permafrost has typically receded due to thermal degradation. Beneath the organic layer the soils are fine grained sands with some silt grading to coarser materials with depth. FPE/ROEN Engineers, Inc. Page 28 Preliminary Site Assessment Bethel Utility Corporation September 1991 The presence of permafrost beneath the parcels will act as a restrictive layer to contaminant migration as well as contamination of the deep aquifer below the permafrost used locally for drinking water. Degradation of permafrost depth will result in subsurface ponding and/or channeling of migrating contamination. The presence of several deep wells on-site which penetrate the restrictive permafrost layer represent potential pathways of contamination to the deep aquifer. We recommend baseline sampling of the wells to verify groundwater conditions. Additional evaluation of this area of concern was completed under a subsequent contract modification. The findings of fact and analysis are provided in Section 9.1 Groundwater Site Sampling. 8.2 Bulk Fuel Storage Management and employees reported intermittent petroleum hydrocarbon spills and overfills at the bulk fuel storage containers on-site. Long term residents and past observations of the Utility properties suggest intermittent but long term site contamination from past operational practices and bulk fuel control. Visible evidence of petroleum hydrocarbon contamination was noted on the generating site beneath the fuel oil day tanks where the snow cover was absent. While standard procedures are to take immediate steps to cleanup and contain any spillage, management confirmed that these efforts had not always been practiced in the past or considered feasible during inclement weather conditions. While it is apparent that site contamination is present, the positive management attitude, known site conditions, intermittent characteristics and small quantities reported spilled are not symptomatic of a major remediation cost or unmanageable expense for the Utility. It is recommended that a Phase II sampling of the site soils and groundwater be completed in order to delineate the extent of contamination and the development of a base line of site conditions for the facility prior to the property transfer. Additional evaluation of this area of concern was completed under a subsequent contract modification. The findings of fact and analysis are provided in Section 9.1 Groundwater Site Sampling. The Utility has recently upgraded the 2 - 20,000 gallon fuel oil day tanks to double containment and is reportedly installing a "tank minder" for overfills and spills. While double FPE/ROEN Engineers, Inc. Page 29 Preliminary Site Assessment Bethel Utility Corporation September 1991 containment and overfill and spill protection modifications have been undertaken, additional efforts are required with all of the facilities fuel storage. 8.3. PCB and Hazardous Materials Over the past 1-2 years BUC has undertaken a significant program to eliminate all PCB- contaminated transformers and dielectric oils. While some of the progress or perhaps the rate of progress came as a result of an EPA inspection, complaint and subsequent consent order, it is our opinion that the Utility’s current management intentions are to operate in an environmentally sound manner. In the process of addressing the PCB concerns, the Utility has developed their management and handling of hazardous materials on-site by constructing approved exterior and enclosed storage for these types of materials. At the present time the facility if awaiting a certificate of destruction for the PCB contaminated materials shipped outside for disposal at an approved facility. Based on our review of documents and interviews with EPA, the PCB final order will be resolved to the satisfaction of the regulatory agency upon receipt of the certificate of destruction. It was noted in the PCB information provided that suspect transformer oils were observed to be leaking at.the time of the site inspection by EPA. Subsequent shipping manifests indicate that the Utility did ship for disposal soils suspect of being contaminated with PCB’s. However, it is well known that PCB transformers have been in use by electric utilities throughout the nation including Bethel Utilities for a long time. In addition, storage and handling of these materials historically has not been as restricted or of concern as it is today. Review of aerial photographs taken over the past twenty years revealed that exterior site storage of various materials and spare parts including transformers has occurred along the road access and the gravel pads developed on the site. Now that BUC appears to be achieving a "PCB free” condition, it is recommended that random site sampling of the surface soils in these areas be completed to provide final site closure to the PCB concern. The generating facility and warehouse were inspected for the presence of asbestos-suspect materials. No confirmation sampling was requested or completed for this effort. While typically it can be assumed that some asbestos materials may exist in equipment gasketing or nonfriable building materials, the visible inspection did not disclose any friable insulation suspected to of contain asbestos. FPE/ROEN Engineers, Inc. Page 30 Preliminary Site Assessment Bethel Utility Corporation September 1991 8.4 ADEC Air Quality Permit Based on an earlier facility inspection, the Alaska Department of Environmental Conservation (ADEC) notified BUC in October 1990 that it was in violation of Air Quality Regulations 18 AAC 50. Specifically, the facility was restricted from full operation and notified that the engine exhaust source would require a State Air Quality permit to operate. The permit process requires the Prevention of Significant Deterioration (PSD) determination involving a significant investigation into the following site information: e Ambient air and meteorological data; e Ability to attain air quality standards and increments; e Best available control technology; ° Visibility, vegetation and soil analysis. It is worthwhile to note that "ability to attain" suggests economic considerations are included that would presumably not be allowed to have a major impact on the financial condition of the Utility. It should be cautioned that actual agency flexibility in this consideration may often be minimal, if nonexistent, from the applicant’s perspective. Currently, the Utility has no monitoring, treatment control devices or costs for air quality regulatory requirements. BUC’s position is that they have grandfather rights provided in 18 AAC 50.300 (6)(c), wherein it state that a facility of this size installed prior to August 7, 1977 and not modified after August 7, 1980, is "grandfathered in" with regard to the acceptable maximum level of various air emissions allowed from the engine exhaust. It appears that the Department's belief is that the installation of additional engine capacity in the years 1984 and 1986 represents a modification to the source which eliminates the exemption and subjects the facility to the issuance of an air quality permit involving the Prevention of Significant Deterioration determination. BUC’s response does not deny the installation of additional engines during the eighties. Using manufacturer’s data BUC’s response calculates the maximum allowable emissions under the exemption from the original plant’s capacity and compares the exemption’s maximum allowable emissions to the maximum amount of emissions possible from the modified generating facility, based on known fuel consumption. The information portrays that, while the capacity may have increased, the actual level of emissions has not exceeded the maximum allowable amounts permitted under the exemption. FPE/ROEN Engineers, Inc. Page 31 Preliminary Site Assessment Bethel Utility Corporation September 1991 The resolution of these differing interpretations is considered moot and best left up to BUC and the ADEC. The actual length of the stay is limited, if not by ADEC alone then through the anticipated growth and subsequent modifications to the plant. It was suggested that this was understood by BUC in its long-term planning. The schedule and budgeting of the upgrade and the expense regarding operations is the primary issue for a public utility. Accurate estimation of cost would require a trial PSD computation the results of which would still be subject to actual data and negotiation with the ADEC. Additional evaluation of this area of concern was completed under a subsequent contract modification. The findings of fact and analysis are provided in Section 9.2 Air Quality Control Permit Requirements. As noted by the recent ADEC complaint regarding open burning of waste oil, this current practice of using a waste oil burner for warehouse heat and waste oil disposal may come under increasing scrutiny, not necessarily because of the incident but due to increased awareness and concern by our society and regulations in particular. It was noted that current management reported an increase in operational expense for environmental concerns and has recently initiated a separate expense category. 8.5 Residential Properties The residential properties were not physically inspected. Primary areas of environmental concern would be the above ground heating oil storage and the wastewater holding tank. Considering the site conditions and operational aspects of the two systems, it is our opinion that the potential environmental risk and cost associated with site contamination from these systems would not be symptomatic of a significant concern for the Utility. 9.0 ADDITIONAL EVALUATION AND SITE SAMPLING Following completion and review of the draft preliminary assessment report the Alaska Energy Authority modified the work scope to provide additional evaluation and site sampling to address the following areas of concern identified. FPE/ROEN Engineers, Inc. Page 32 Preliminary Site Assessment Bethel Utility Corporation September 1991 9.1 Groundwater Site Sampling Preliminary site assessment confirmed the presence of on-site surface contamination. The existence of a significant permafrost layer beneath the site will act as restrictive layer to contaminant migration to the deep aquifer below the permafrost utilized locally as the community’s public water supply. However, several deep wells on-site which penetrate the permafrost restrictive layer represent potential pathways of contamination to the deep aquifer. Secondary site sampling of the two deep wells on-site currently in use was undertaken in order to verify groundwater conditions including the presence of contamination as well as to establish a base line analysis. Currently, one of the wells is used as a make up and domestic water supply for the utility. While the quantity of water used is minimal the past practice has been to run the well continuously at significant flow rate. The excess water provided by this practice is discharged for disposal back to the aquifer via the second deep well currently in use. To ensure that the data generated was of known quality sampling procedures followed were according to the Alaska Department of Environmental Conservation requirements and FPE/Roen’s Quality Assurance Plan for well sampling. This included standardized procedures, chain ‘custody jas well as QA/QC analysis. A total of 86 compounds were analyzed for each, wellsincluding the primary and secondary contaminants of concern for public drinking wat supplies; regulated volatile organic compounds (VOC) and Polychlorinated Biphenyls (PCB). All of the contaminant analysis results reported were nondetect and/or below Maximum Contaminant Levels (MCL) established by current regulation. Secondary contaminants and aquifer characteristics (iron, Ph, manganese, etc.) were within allowable limits and did not exhibit any characteristics of aquifer contamination. A complete listing of the laboratory analysis and results is contained in Appendix C. 9.2 Air Quality Control Permit Requirements An air quality control permit is required by the Alaska Department of Environmental Conservation under 18 AAC 50. This statue requires a permit to operate facilities that emit more than a specified amount of regulated pollutants, whether the facility is new or modified. The regulated air contaminants include carbon monoxide, nitrogen oxides, sulfur dioxide, FPE/ROEN Engineers, Inc. Page 33 Preliminary Site Assessment Bethel Utility Corporation September 1991 particulate matter, ozone, lead, asbestos, beryllium, mercury, vinyl chloride, fluorides, sulfuric acid mist, hydrogen sulfide, and reduced sulfur compounds. The information needed to complete an Air Quality Control permit application includes a layout of the facility, a map of the vicinity, the proposed operation and emission estimates, a description of emission control devices, and the construction or modification schedule. The department may also require ambient air impacts analysis and a plan to reduce emissions during air episodes. An application for an air quality control permit incorporates Prevention of Significant Deterioration (PSD) provisions from the Clean Air Act. The EPA’s nationwide PSD program emerged from the 1977 Clean Air Act Amendments and was intended to protect the nation’s air resources from deterioration. Only stationary sources or modifications to existing stationary sources in areas that exceed the ambient air quality standards are subject to review. Physical or operational changes that result in a significant net increase in emissions of any regulated pollutant are considered to be modifications. Before the agency can conduct a PSD review, the following information is required: ambient air and meteorological data, ambient air impact analysis, Best Available Control Technology (BACT) analysis, and analysis of the impacts on visibility, vegetation, and soils. The ambient air impact analysis entails predicting the effects that emissions will have on the concentration of regulated pollutants in the ambient air. This requires the use of computer air quality models. The models require site specific ambient air quality and meteorological data for input. The results of the computer models affect the determination of emission limitations and ultimately operational constraints on the source. The agency determines the Best Available Control Technology for the source of emissions on a case by case basis, considering energy, environmental, and economic impacts and other costs. On October 12, 1990, ADEC notified the Bethel Utilities Corporation (BUC) that the facility required an Air Quality Control Permit to Operate, and that ADEC also required additional information before a permit could be granted. The Department found that the facility had: e allowable emissions of more than 250 tons of regulated air contaminants per year, . the facility had not been previously reviewed under the PSD provisions of the state or federal regulations, . the diesel generators were subject to regulation for visible emissions and emissions of particulate matter and sulfur dioxide, FPE/ROEN Engineers, Inc. Page 34 Preliminary Site Assessment Bethel Utility Corporation September 1991 e the increase in oxides of nitrogen (NOx) emissions subjected the facility modifications to PSD provisions, ° and that BUC did not request that the Department impose operational restrictions to prevent the increase in emissions. As a result, ADEC required the PSD provisions or the request of operating restrictions for PSD avoidance. In addition, BUC was prohibited from operating generators No. 3 and No. 5 until the permit application was received. BUC responded to ADEC in a letter dated January 3, 1991. Ed Tilbury of BUC indicated that he understood that "facilities existing prior to August 7, 1977 are automatically “grandfathered in" with regard to the acceptability of their level of maximum installed emissions potential as of that date and are therefore allowed entitlement to those levels into perpetuity". He also believed that additions to such a facility are not subject to PSD provisions unless the total emissions of the facility exceed the maximum installed emission potential originally "grandfathered in". Using that reasoning, Mr. Tilbury stated that the BUC power plant was entitled to "grandfather rights for maximum potential emissions computed for the installed equipment as of August 7, 1977". Following ADEC and BUC discussions BUC requested a PSD avoidance Air Quality Control Permit to Operate on February 4, 1991. ADEC subsequently issued the BUC power plant a five year permit on March 13, 1991. BUC was not required to provide the information for the PSD determination since they requested limitations on operations to reduce emissions to levels below those specified in 18 AAC 50, resulting in PSD avoidance. Conditions in the permit include limitations on the total power generated, the gallons of diesel fuel burned, and the sulfur content of the fuel; source testing of one of source Nos. 1 - 4 for nitrogen oxides and carbon monoxide emissions; continuous emission and process monitoring; and routine analysis of fuel oil. During the preparation of this report Ed Tilbury with BUC indicated that a contract for the required air emission test had been developed and was currently being completed. No significant additional costs to comply with 18 AAC 50 are expected within the next five years, aside from the routine monitoring and fuel testing required in the permit. This assumes that emissions are not increased to more than the maximum level stated in the permit, 250 tons per year, therefore requiring a PSD determination. Also assumed is that the results of the stack tests show actual emission levels are less than the assumed levels stated in the permit. FPE/ROEN Engineers, Inc. Page 35 Preliminary Site Assessment Bethel Utility Corporation September 1991 As part of the scope of work, FPE/Roen Engineers reviewed current consultant estimates to complete the PSD requirements. As noted above the final cost associated with completing a PSD is highly dependent on site specific conditions and operating requirements. At a minimum a limited PSD effort for remote facility similar to BUC is estimated to require $10,000-20,000. Depending on the specific level of effort required and the consultant utilized these preliminary costs could be on the order of $50,000-75,000. If preliminary results indicate the necessity for long term preconstruction meteorological and ambient air quality monitoring, these expenses are estimated to be $80,000-$150,000. 9.3. Survey of Environmental Costs Environmental budget expenses associated with power plant facilities similar to Bethel were reviewed. The six power plants in Alaska identified to be surveyed were in Nome, Kotzebue, Barrow, Dillingham, King Cove, and Unalaska. Survey participants were contacted by telephone and responded to questions about the number of generators at the facility, age and manufacturer of the generators, type of fuel used, capacity of generators, and total energy production. Additionally, personnel were questioned about the total budget for the power plant, budget for and management of environmental items, and anticipated changes in environmental costs to the power plant in the future. At the time of the survey, phone service to Kotzebue was not available due to an equipment failure, so no information was available. Information from the following personnel at the powerplants contacted is summarized below: Nome - Joe Murphy Barrow - Sheldon Tinklin Dillingham - Dave Bouker King Cove - John Gehrmain Unalaska - Jim Fitch Like Bethel, all of the communities surveyed are located in rural Alaska and use diesel generators, except Barrow, which uses natural gas turbines. The power plants range in size from 1.1 Megawatts at Kind Cove to 13 Megawatts at Nome. Nome, with the largest power plant, spent about $10,000 in 1990 on environmental items out of a total budget of $2.8 million, with most of that environmental cost for the oil spill contingency plan for the bulk fuel facility. Some of their generators on line were installed as FPE/ROEN Engineers, Inc. Page 36 Preliminary Site Assessment Bethel Utility Corporation September 1991 early as the 1950’s. In King Cove, the smallest facility, had a $392,000 budget. The individual interviewed could not recall the facility spending any money for environmental items. Waste oil is disposed of by the City of King Cove Harbor Department, at no cost to the utility. Nushagak Electric in Dillingham has seven generators and a total capacity of 5.4 Megawatts. Dave Bouker didn’t know the budget amount, but he did indicate they spend $26,000 per year on oil spill insurance. The City of Unalaska Electric Utilities pays ChemPro to dispose of their hazardous wastes and some waste oil. The employee at Unalaska indicated that less than $1000 plus another $3000 to $4000 in labor goes to environmental items, out of a budget of approximately $2.5 million (which includes power lines, transformers, etc...). The Barrow Utilities Electric Cooperative has a capacity of 7.5 Megawatts and a budget of $992,000. Of the ‘91 budget, $10,000 was spent to dispose of PCB transformers and waste oil. None of the facilities currently have air quality control permits, however it is possible that they may be required in the future. As noted the majority of the current spending at those utilities surveyed is on contingency plans, insurance, disposal of waste oil and miscellaneous hazardous substances such as solvents. Waste oil disposal is managed in-house. It is usually burned with the diesel fuel in the generators or in a waste oil heater, except in Barrow, where it is transported by barge for disposal. In general, environmental operational expense budgets were negligible (0.2-0.4% of the facility budget) or nonexistent. In general, the larger the facility, the greater the percentage spent. None of the facilities surveyed had a separate line item in their budgets for environmental-type costs. Costs to each community’s power station will be affected by the age of the facility, past waste management practices, fuel used, management attitudes towards environmental protection, and current efforts. Aside from day to day environmental management measures, most of the personnel indicated that their facility has had to deal with the disposal of PCB’s in transformer oil. Costs to apply for permits and dispose of PCB transformers were not considered "routine" expenses. All of the personnel interviewed expected the amount spent on environmental protection measures to increase in the future but could not predict how much. Given the current regulatory climate, there is no doubt that it will cost the Bethel Utility Corporation an increasing amount over the next five years to comply with environmental regulations. Based on the previous information, we would recommend that BUC budget an environmental expense starting at 0.25%, increasing annually on the order of 0.25%, of its annual budget towards environmental protection and regulatory compliance to guard against future problems. FPE/ROEN Engineers, Inc. Page 37 Preliminary Site Assessment Bethel Utility Corporation September 1991 10.0 CONCLUSIONS AND RECOMMENDATIONS Based on our investigation’s findings and analysis as well as the considerations and assumptions set forth in the report, we are of the opinion that: ils With consideration of the facility’s revenue capability and analysis of the findings the investigation disclosed no significant indication of any major environmental liabilities involving the Bethel Utilities Corporation properties. 2's While it is apparent that site contamination is present, the positive management attitude, known site conditions, intermittent characteristics and small quantities reported spilled are not symptomatic of a major remediation cost or unmanageable expense for the Utility. We recommend a Phase II sampling of the site soils be completed in order to delineate the extent of contamination as well as the development of a base line of site conditions for the facility prior to the property transfer. 3. The presence of permafrost beneath the parcels will act as a restrictive layer to contaminant migration as well as contamination of the deep aquifer below the permafrost used locally for drinking water. The presence of several deep wells on-site which penetrate the restrictive permafrost layer represent potential pathways of contamination to the deep aquifer. A limited Phase || sampling of the deep aquifer groundwater did not identify any contamination and developed a groundwater quality base line for the site. 4. While double containment as well as overfill and spill protection modifications have been undertaken on the bulk fuel storage additional efforts are required with all of the facilities fuel storage. 5. Historical records indicate the PCB transformers were previously in use and may have leaked on-site. Over the past 1-2 years BUC has undertaken a significant program to eliminate all PCB contaminated transformers, dielectric oils and soils. In the process of addressing the PCB concerns the Utility has further developed their management and operational handling of hazardous materials on-site by constructing approved exterior and enclosed storage for these types of materials. FPE/ROEN Engineers, Inc. Page 38 Preliminary Site Assessment Bethel Utility Corporation September 1991 Now that BUC appears to be achieving a PCB "free" condition it is recommended that random site sampling of the surface soils be completed to provide final site closure to the PCB concern. 6. Based on the plot plans and aerial photographs reviewed that the warehouse and office may not be entirely located on BUC’s property. It is recommended that a formal boundary survey be completed prior to any property transfer. 7. While completing the environmental analysis scope of work, Bethel Utilities Corporation was directed by the Alaska Department of Environmental Conservation (ADEC) to restrict the Utility’s operation, apply for an air quality permit and submit the required information to complete the Prevention of Significant Deterioration (PSD) determination for the engine exhaust emissions. While additional air quality control expense may be required for future permits or plant modifications, on March 13, 1991 ADEC issued Bethel Utility Corporation a five year permit to operate. 8. With the ever increasing public and regulatory attention to environmental concerns, future utility management should anticipate a continuing increase in routine environmental compliance costs. In addition, the expense for those historical concerns identified in this assessment may involve notable funds to correct. In accordance with the amended scope of work, a limited survey was completed to quantify only routine environmental budget-expenses. Based on information analyzed, it is recommended that the Utility budget a minimum environmental expense starting at 0.25%, increasing annually on the order of 0.25% of its annual budget towards environmental protection and regulatory compliance. 11. LIMITATIONS FPE/ROEN Engineers, Inc. warrants that our services were performed with the usual thoroughness and competence of the engineering profession. This report is a record of observations and measurements made on the subject system as described. No other warranty or presentation, either expressed or implied is included or intended. FPE/ROEN Engineers, Inc. Page 39 Preliminary Site Assessment Bethel Utility Corporation September 1991 This report was prepared for the exclusive use of the Alaska Energy Authority. If it is made available to other, it should be for information on factual data only and not as a warranty of surface or subsurface conditions, such as those interpreted from the results presented or discussed in this report. The extent of our assessment, by definition was not of an intensity necessary to reveal all conditions with regard to environmental contamination or conformance with regulations, codes, permits of all the agencies having jurisdiction with respect to construction, operation and maintenance of an electric utility system. The work scope requested by the Alaska Energy Authority was considered adequate to identify significant indications of contamination as well as major concerns that would represent pivotal environmental issues important to a purchaser of the utility. In the preparation of this report and conclusions we have made certain assumptions about actual site conditions based on available information reviewed. No sit sampling was included in the scope of work and the schedule prohibited site inspection during a period when there would be no snow cover. While it is believed that the assumptions are reasonable for the purposes of this report actual conditions may differ from those assumed. In addition we have used and relied upon certain information provided to us by the AEA, EPA, ADEC, BUC, the City and others. While we believe the sources are reliable, we have not independently verified all of the information. To the extent that actual facts differ from those reported or provided to us by others, the actual conclusions and recommendations will vary. The principle considerations and assumptions made by us include the following: Ta Operational practices and procedures were in compliance with applicable environmental requirements and there review was not included in the scope of work. 25 The City will institute rate increases that provide the revenues as needed to cover all costs of operation and maintenance to comply with applicable regulations and a sound environmental operation. FPE/ROEN Engineers, Inc. Preliminary Site Assessment Bethel Utility Corporation September 1991 APPENDIX A Property Ownership History of Parcels APPENDIX A LEGAL DESCRIPTION AND OWNERSHIP HISTORY OF BETHEL UTILITIES GENERATING FACILITY PROPERTIES | ription and Previ Landholder: Bethel Utilities Corporation Generating Facility Properties: Ue USS 4117, Lot 6 (5 acres) Recorded: Bk 22 Pg 634 Previous Owner: Tundra Development Company Transfer: March 4, 1976 Address: 1340 State Highway 2: Lot 10D (2.569 acres in size) Recorded: Bk 33 Pg 427 Fourth Judicial Recording District, Bethel, Alaska Previous Owner: Calista Transfer: November 24, 1982 Address: 1380 State Highway 35 Lot 10E (1.7 acres in size) Recorded: Bk 33 Pg 427 Fourth Judicial Recording District, Bethel, Alaska Previous Owner: Calista Transfer: November 24, 1982 Address: 1420 State Highway 4. Lot 10F (2.2 acres in size) Recorded: Bk 33 Pg 427 Fourth Judicial Recording District, Bethel, Alaska Previous Owner: Calista Transfer: November 24, 1982 Address: 1450 State Highway Bethel Utilities Corporation Billing/Meter Office Property ue Plat 73-244, USS 870 Block 2, Lot 3 (59,999 square feet) Recorded: Bk 18 Pg 377 Previous Owner: Northern Commercial Company Transfer: July 10, 1972 Address: 160 State Highway See Figure 5 for lot dimensions and locations Bethel Utilities Corporation Lot 9 Residential Property fe Plat 82-12, USS 4117 Recorded: Bk 51 Pg 734 Previous Owner: Department of Community & Regional Affairs Transfer: September 22, 1989 Previous Owner: Gene and Mary Chaney Transfer: April 15, 1988 Record: Bk 47 Pg 835 Previous Owner: Ronnie Ritter Transfer: January 18, 1985 Record: Bk 40 Pg 305 Previous Owner: Christina Shantz Transfer: January 14, 1981 Record: Bk 29 Pg 71 From Bureau of Land Management Address: 168 Alex Hately Drive See Figure 6 for lot dimensions and location FPE/ROEN Engineers, Inc. Preliminary Site Assessment Bethel Utility Corporation September 1991 APPENDIX B FPE/ROEN Phase | Environmental Assessment Audit Form for Potential Acquisitions FPE/ROEN ENGINEERS PHASE | ENVIRONMENTAL ASSESSMENT AUDIT FORM FOR POTENTIAL ACQUISITIONS DATE OF VISIT: December 17 - 19, 1990 PERSONS INTERVIEWED: (1) Hal Borrego, President (2) Ed Tilbury, Vice President (Name, title, address P.O. Box 333 4037 Hood Court and phone) Bethel, Alaska Anchorage, Alaska 99517 (3) Rodney Rogers, General Mgr. Bethel, Alaska INTERVIEWERS: John Hargesheimer GENERAL INFORMATION 1) Company name and address. If mailing address is different than site address give both. NAME: Bethel Cogeneration, Inc. Bethel Utilities Corporation, Inc. SITE ADDRESS: Building 1340 Kwethluk Lane Bethel, Alaska 99559 MAILING ADDRESS: Box 2148 Bethel, Alaska 99559 2) Owner name and address: NAME: Hal Borrego (50%) Ed Tilburys, Frances Davidson, Elaine Tilbury (50%) ADDRESS: Box 333 4037 Hood Court Bethel, Alaska 99559 Anchorage, Alaska 99517 3) Any previous owner? YES _XX_ NO If yes, describe. List Tenants, if different from owner, and nature of business. Owner: Northern Commercial Years of Occupancy: up to 1972 Office site only previously owner/used by Northern Commercial. Tenants: None. 4) Is facility located near any schools, hospitals, residential or recreational areas? (Consider a 3 mile radius.) Describe; include direction from facility. YES _XX NO \f yes, describe. Hospital, residential, school, and recreational area. See city area and site drawings. FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 1 5) 6) 7) 8) 9) 10) 11) 12) 13) How long has this firm been in business at this location? Current site 1975 Billing/Office (previous site) 1972-1976 What is the size of the property? Office (previous power plant site) Lot 3 Block 2 of Plat 73-244 USS 870 (200 x 300) 60,000 square feet. Residential site Lot 9 Blueberry Fields Subdivision approximately 10,000 square feet. Power plant site Lots 6, 10D, 10E, 10F of the Subdivision of Lot 10 according to Plat Number 82-17 located in U.S. Survey 4117, approximately 12 acres. How many employees are on-site: 18 - 19 Are there any PCB’s on site? Have there ever been any on site? YES NO _XX YES _XX NO UNKNOWN If yes for either or both, describe: 1989-90: completed removal and transfer of material to certified disposal facility; awaiting certificate of destruction. Jackie and Rodney Rogers handled PCB disposal. EPA inspection reported PCB soil contamination. Interviews indicated that contaminated soils ‘were removed with transformers. Shipping manifests provided. No follow soil sampling reported. Are there any transformers, capacitors, old fluorescent fixtures, or mechanical hydraulic systems on this site? YES _XX NO Was the facility ever inspected or will it be inspected for presence of asbestos material? YES NO _XX UNKNOWN If the answer is no, why not? None of the interviews believed there was any in the facility. Both Mr. Borrego and Mr. Tilbury mentioned the suspended ceiling tile as the only possibility. Insulation around the exhaust boilers had been removed. Mr. Borrego thought that the SBA loan requirements used to rebuild after the fire and the design effort by Cruise Maginnis and Hoffman considered the asbestos issue. Ed Tilbury was not aware that asbestos had been addressed during the rebuild. Is asbestos present anywhere on site? YES NO _XX UNKNOWN If yes, describe. Visual inspection, no sampling, did not identify any apparent asbestos materials. Obtain a plot plan. Plan obtained: _XX Plan to be sent: FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 2 14) 15) 16) 17) 1) 2) 3) 4) 5) 6) Describe any industrial process or processes that are done on site. None. Obtain aerial photographs. Photos obtained: ___ Photos ordered: _XX_ List the names of adjoining property owners and nature of business. A. Bethel Native Corporation Years of Occupancy: Unknown north and west Business Function: Native Corporation vacant land; see area drawings. B. Calista Corporation Years of Occupancy: east and south Business Function: Native Corporation 40 Unit Apartment; see area drawings. General Comments: Mark Earnest, City Manager to provide property ownership records. AIR What is the name and address and phone number of the agency person who is responsible for your facility for air quality regulations? NAME: ADEC - Bill Lamoreaux TITLE: Regional Supervisor ADDRESS: SCRO 3601 C Street, Suite 1334 Anchorage, Alaska 99503 PHONE: (907) 563-6529 NAME: Bethel ADEC Representative Gary Saupe PHONE: (907) 543-3216 FAX (907) 543-3215 Is there a specific plan to cover air quality events? (This includes emergency releases and adverse weather conditions.) YES NO _XX If yes, describe. Are there any monitoring devices used to determine air contaminant emissions to the environment? YES NO _XX If yes, describe. Have there ever been any odor complaints from the neighbors? YES NO _XxX lf yes, what was the source of the complaint? Were steps taken to abate this odor concern? YES NO If yes, describe. FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 3 7) Is there a strong odor anywhere in or around the facility? YES NO _XX \f yes, describe odor and intensity. 8) Have any past major air releases occurred? YES NO _XX__ If yes, explain. 9) Have any notice of air violations been issued? YES NO _XX__If yes, describe. By whom, when. Current correspondence between ADEC and BUC regarding issuance of air permit. See copies of correspondence and general comments. 10) Are there any compliance orders that have been issued? YES NO _XX If yes, describe. See comments and current correspondence. 11) Have fines been assessed for air problems, lack of permits, or permit compliance? YES NO _XX If yes, describe. See comments and current correspondence. 12) Obtain list of raw materials used and/or stored at this facility. Fuel Oil Lube Oil 13) Obtain a list of all chemicals that could be released or are released to the air. (Includes finished products and by-products). List Obtained List Ordered _ XX 14) What sources are there for VOC, particulate, or other air emissions? (Specify if point source or fugitive.) SOURCE DEFINE DEFINE DEFINE POLLUTANT POINT FUGITIVE SOURCE SOURCE Five General Motors EMD 2100 kw diesel generator sets visible particulate SOo NO, (eo) exhaust " Waste Oil Burner visible particulate FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 4 15) Are any of these sources in need of control? YES __.= NO _XX_ SOURCE CONTROLS IN CONTROLS CONTROL NEED OR IN PLACE _PLACE =| NOTINPLACE | CSPECIFY) NOT IN PLACE (SPECIFY) Are air permits required, have they been obtained, and are they up to date? Review and comment. PERMITTED | NO PERMIT | NO PERMIT PERMIT EXPIRES REQUIRED | APPLIED FOR Requirements are control and monitoring Currently an issue with ADEC (see comments and current correspondence). a) Exhaust 17) Has an annual emission inventory been made? YES NO _XX__ If yes, review. Obtain a copy, if possible. Annual emission inventory estimate has been completed and is included in correspondence with ADEC regarding permit requirements. 18) Submit a copy of the annual report. 19) Comments: See copies of current correspondence between ADEC and BUC regarding issuance of air quality permit. BUC’s position is that facility does not require air quality controls/monitoring and should receive permit under grandfather provisions. WATER 1) ‘What is the name, address and phone number of the agency person who is responsible for your facility for water regulations? NAME: ADEC - Bill Lamoreaux TITLE: Regional Supervisor ADDRESS: SCRO 3601 C Street, Suite 1334 Anchorage, Alaska 99503 PHONE: (907) 563-6529 NAME: Bethel ADEC Representative Gary Saupe PHONE: (907) 543-3216 FAX (907) 543-3215 2) Is there any type of on-site waste water treatment done here? YES __ NO _XX If yes, describe. 3) How is the residue from this process handled? N/A FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 5 4) Where is the water discharged? Holding tank and picked up by septic hauler or connected to community wastewater collection system. 5) What are the characteristics of this wastewater? Domestic sewage from facility employees. 6) What is the flow volume through the system? _200 - 300 _ GPD OR-GRW 7) Do you have any pits, ponds, or lagoons? YES NO _XX_ If yes, describe. Natural lake on site. 8) ls any water discharged to surface waters? YES ___ NO _XX_ If yes, describe. Cooling waters were previously discharged to natural lake on site. 9) Does the firm have a NPDES permit? YES __. 1+ NO _XX_ 10) If yes, complete the following for that NPDES permit. Permit No.: Discharge conditions: 11) How are storm water discharges handled? Site drainage. 12) Any storm water discharged to the sanitary sewer? YES NO _XX 13) Is a permit required for this discharge? YES NO _XX 14) Has a permit been obtained? YES NO N/A _XX 15) | What is the permit number and name of issuing agency? Permit No.: Expiration Date: 16) For any water discharged to a Publicly Owned Treatment Works (POTW), what is the nature of that discharge? Wastewater is discharged to a holding tank with a lift pump that discharges to the community wastewater collection system. 17) What is the name, address and phone number for that PPTW? NAME: City of Bethel ADDRESS: _ Bethel, Alaska PHONE: 543-2297 FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 6 18) Is there a tank farm? YES _XX NO 19) If yes, is that tank farm properly diked? YES _XX NO No diking required for double walled fuel oil day tanks. No diking currently around lube oil and vehicle fuel storage; upgrade is planned. 20) What is the composition of the containment walls and floor? Two new fuel oil day tanks are double walled. Walls: None Floor: Native site soils. 21) ~~ Are the dike floor, joints and walls impervious? YES __= NO _XX_ Owners indicated diking around lube oil storage was in the process of being implemented. 22) | What are the size and number of these tanks? Obtain a tank list. This list should include tank size (diameter and height), tank capacity (gallons), tank usage (product stored) and material of construction. GASOLINE/VEHICLE <500 GALLON ABOVE GROUND | 5-6 COMPANY VEHICLES DIESEL/VEHICLE <500 GALLON ABOVE GROUND | MINIMAL - CAT & BUCKET TRUCK WASTE OIL TANK IN 300 GALLON ABOVE FEED FOR WASTE OIL BURNER SHOP BUILDING (SINCE 1977-78) | GROUND/INSIDE | FOR BLDG. HEAT ENGINE/GENERATOR 2-20,000 ABOVE GROUND | DOUBLE WALL TANKS. FUEL OIL DAY TANKS GALLONS INSTALLED IN CURRENTLY INSTALLING A 1989-90 TANK MINDER AND OVERFILL PROTECTION LUBE OIL 2-10,000 ABOVE GROUND | INSULATED TANKS GALLON INSTALLED 1984-86 ADDITIONAL SKID MOUNTED LUBE OIL BULK STORAGE WAS TEMPORARILY ON SITE 23) Is there any storage of containers outside? YES _XX NO If yes, describe. Barrel storage in fence enclosed area adjacent to PCB storage/trailer area - miscellaneous liquids and waste oil. 24) What is the condition of these containers? Type, material, labeling. General condition of barrels visible was good. Barrels were labeled and segregated by type. FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 7 25) 26) 27) 28) 29) 30) 31) 32) 33) 34) 35) 36) 37) 38) 39) Are there any wells around or near the facility (within 1,000 feet)? YES _XX NO See site drawing with well locations. Multiple wells are located on site. Only one in use as raw water source allowed to run continuously to prevent freezing (not insulated). Bypass amounts reinjected down a second existing well. Majority of wells installed by TRW as initial phase of aquifer thermal energy storage system. Is there a current groundwater monitoring program in place? YES __. NO _XX If yes, explain. Describe why the program is in place. If the answer is no, is there one planned in the future? Describe. No. Are there any underground storage tanks on site? YES __. NO _XX_ Where are they located? (Also specify on plot plan.) N/A If yes, what do they contain, what is there condition, and how old are they? N/A Were they ever tested for leakage? YES ___ + NO _XX_ Specify details: N/A Has a Discharge Monitoring Report (DMR) been filed? YES __» + NO ___ If yes, obtain a copy. Are there any streams, lakes, or rivers within a one mile radius. Assess whether they could experience some potential contamination from spills from this facility. YES _XX NO If yes, describe. Natural lake on site. See site drawing. There exists a potential for contamination from across the surface and subsurface depending on contour of site surface and permafrost respectively. Is there any know groundwater contamination? YES NO _XX If yes, what is the extent and location of the contamination? Is the groundwater elevation known. YES _XX NO What is the elevation? 400-600 _ feet below grade Is there a usable aquifer? YES _XX NO UNKNOWN What is the location of the aquifer? FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 8 40) Is the aquifer used for process water by this facility? YES _XX NO} an If yes, describe. Make up cooling water and general utility. 41) Is there any known contamination of the aquifer? YES NO _XX 42) | What has been the frequency and size of spills? Mr. Borrego reported minor overfills and spills due to bulk storage filling and vehicle fuel dispensing. He estimated that the maximum spill amount was probably no greater than 100-200 gallons. 43) Were those spills cleaned up in a timely fashion? YES __.» +9=NO _XX_ Standard procedure was to clean up spills in a timely fashion. However Mr. Borrego indicated that due to weather and other reasons beyond their control, did not always permit timely clean ups. 44) Is there any evidence of any past spills that may have not been properly cleaned up? YES _XX NO Site soils visible (without snow cover) beneath engine/generator fuel oil day tanks were visibly contaminated. 45) Has any remedial action taken place for past spills not properly cleaned up at the time of the spill? YES NO _XX 46) Have any facilities located upstream of the property been cited for illegally discharging contaminants? YES NO _XX_ If yes, explain. 47) Do any facilities located upstream pose a risk to the quality of the property waters? YES NO _XX_ If yes, explain. 48) General comments: HAZARDOUS WASTE 1) What is the name, address, and phone number of the agency person who is responsible for your facility for hazardous waste regulations? NAME: ADEC - Bill Lamoreaux TCE: Regional Supervisor ADDRESS: SCRO 3601 C Street, Suite 1334 Anchorage, Alaska 99503 PHONE: (907) 563-6529 NAME: Bethel ADEC Representative Gary Saupe PHONE: (907) 543-3216 FAX (907) 543-3215 FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 9 2) 3) 4) 5) 6) 7) 8) 9) NAME: US EPA Region X TITLE: Waste Management Branch ADDRESS: 1200 Sixth Avenue, MS HW 112 Seattle, WA 98101 PHONE: (206) 442-0151 Are hazardous wastes stored on the property? YES NO _XX_ (If no, the Real Estate Assessment is completed.) What form of RCRA hazardous waste permit do you have? PartA_NO Part B__ PCB Generator with on-site storage. What is the U.S. EPA identification number? _AKD 980834162 Review the following plans and comments on same: Contingency including SPCC plan: None available. Personnel Safety and Response Training: None available. Waste Analysis: None available. Identify the status of the facility; check all that apply. XX_ Conditionally exempt generator: Less than 100 kg/month (200 Ibs/month) hazardous waste generation, and on-site accumulations of less than 1,000 kg (2,200 Ibs). Small quantity generator: 100 to 1,000 kg/month (200 to 2,200 Ibs/month) hazardous waste generation, or on-site accumulation of over 1,000 kg (2,200 Ibs) but less than 6,000 kg (13,200 Ibs) from lower generation rates. Generator: Greater than 1,000 kg/month (2,200 Ibs) hazardous waste generation or generate acutely hazardous waste in excess of the limits. Hazardous waste treatment on-site. Hazardous waste storage on-site. Hazardous waste disposal on-site. Transporter. Is the site presently in compliance with all local, state, and federal statutes and regulations? YES _XX NO If no, describe the discrepancies. Yes according to interviewers. Are the labels on the containers properly filled out? YES NO Inspect several labels at random. Look for proper wording and accumulation date. All PCB waste and transformers have been shipped and accepted at disposal facility. Awaiting certificates of destruction. See copies of correspondence and shipping manifests. Are there any past or present lawsuits involved with environmental liability? YES __ NO _XX_ If yes, describe. FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 10 10) 11) 12) 13) 14) 15) 16) 17) 18) 19) 20) 21) During the last lawsuit environmental inspection, were there any violations brought to the attention of this facility or any fines issued? When was the last inspection? Violations: YES _XX NO ___ Fines: YES __. + NO _XX_ Describe. PCB Notice of Violation with possible fines. Consent agreement is in existence. Currently all PCB transformers and waste are reported to have been shipped and received by disposal facility awaiting certificate of destruction. See copies of complaint, consent agreement, and current correspondence. Does this facility currently have any outstanding Notices of Violations or fines for hazardous waste activity? YES _XX NO PCB consent agreement outstanding. What is the routing of materials to major highways or railways? Not applicable; only air and water routing capable. For hazardous waste tank storage, what is stored and are the daily tank inspections documented? Waste oil. Inspected daily. Review the EPA waste permit and hazardous waste manifests. Completed. Are the manifests properly prepared? YES _XX_ NO ___ Describe. PCB shipping manifests were reviewed. Are the proper landfill ban notifications completed for each shipment? YES _XX_ NO ___ How are hazardous wastes managed at this facility? While preparing and storing PCB transformers and waste, a properly constructed PCB storage facility was constructed and is available for any additional small quantities of hazardous materials on-site or generated. ls there adequate containment for all hazardous waste? YES _XX NO If no, describe. Is any type of on-site treatment done to any of the hazardous waste generated (e.g. neutralization, etc.)? YES NO _XX_. Describe. Is this treatment permitted by the local, state, or federal authorities? YES NO N/A If no, describe. Is any waste exported? YES _XX NO If yes, describe. All hazardous waste generated is exported according to applicable requirements. FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 11 22) Do they receive any hazardous waste from any affiliates, customers, or other outside sources? YES NO _XX_ If yes, describe. 23) Has there ever been or is there now any disposal on-site of hazardous waste? If yes, comment. This includes landfills, injection wells, incinerators and other treatment processes. YES NO _XX Not to the interviewer’s knowledge. 24) How does the facility handle its non-hazardous waste? Observe this area. Solid waste is collected in a contractor provided container which is hauled away by contract. 25) Any disposal of on-site non-hazardous waste? YES _XX NO If yes, describe. Bypass well water, to prevent freezing, is disposed of an injection well. 26) Is this facility affiliated either on-site or off-site with a superfund site? YES NO _XX_ If yes, where? 27) Is there any type of waste minimization program in place or currently being formulated? YES _XX NO Owners indicated that over the years all waste streams have been examined specifically to minimize or eliminate, i.e. cooling water -- all recycled Waste oil Quantity reduced; remainder incinerated PCB Eliminated 28) General comments: None. FPE/ROEN ENGINEERS Environmental Assessment Audit Form Page 12 FPE/ROEN Engineers, Inc. Preliminary Site Assessment Bethel Utility Corporation September 1991 APPENDIX C Laboratory Results CHEMICAL & GEOLOGICAL LABORATORY A DIVISION OF COMMERCIAL TESTING & ENGINEERING ANALYSIS REPORT BY SAMPLE for WORKorder# 33906 Date Report Printed: MAY 21 91 @ 10:11 Client Sample ID:DISCHARGE WELL #1 Client Name :FPE - ROEN INC PWSID :UA Client Acct :FPEROEN Collected APR 30 91 @ 16:00 hrs. BPO # PO # 90083-1 Received MAY 391 @ 10:00 hrs. Req # Preserved with :AS REQUIRED Ordered By :JOHN HARGESHEIMER Analysis Completed :MAY 17 91 Send Reports to: Laboratory Superyisor :STEPHEN C. EDE 1)FPE - ROBN IWC Released By : a Li — 2) Chemlab Ref #: 911791 Lab Smpl ID: 1 Matrix: WATER Allowable Parameter Tested Result Units Method Limits IWORGAMIC CHEMICALS/TITLE 18 n/a na n/a ARSENIC 0.014 g/l ASTM D2972 0.05 maximu BARIUM 0.21 ag/1 EPA 200.7 1.0 maximum CADMIUM ND(0.0005) 1/1 EPA 213.2 0.010 maxim CHROMIUM wD(0.005) ng/1 EPA 218.2 0.05 maximu FLUORIDE wD(0.10) g/l EPA 340.3 2.4 maximum LEAD 0.0057 1/1 EPA 239.2 0.05 maximu MERCURY wp(0.001) ng/1 SM14 301AVI 0.002 maxim WITRATE-N wD(0.10) g/l EPA 353.2 10 maximum SELENIUM wD(0.0005) ng/1 ASTM D3859 0.01 maxima SILVER wD(0.001) ag/1 EPA 272.2 0.05 maximu TURBIDITY 0.72 WU EPA 180.1 1.0 maximum VOLATILE ORGANIC CHEMICALS n/a n/a _—s&EPA $02.2/524.2 n/a 1,1,1 TRICHLOROBTHANE wD(0.0010) mg/L —sEPA $02.2/524.2 0.200 1,1 DICHLOROBTEYLENE wD(0.0010) mg/L —sEPA $02.2/$24.2 0.0070 1,2 DICHLOROBTHANE wD(0.0010) ng/L —sEPA $02.2/524.2 0.0050 CARBON TETRACHLORIDE wD(0.0010) mg/L —«sEPA $02.2/S24.2 0.0050 VINIL CHLORIDE wD(0.0010) mg/L —sEPA $02.2/524.2 0.0010 BENZENE wD(0.0010) mg/L —_—sEPA $02.2/524.2 0.0050 1, 4-DICHLOROBENZ ENE wD(0.0010) mg/L —sEPA $02.2/524.2 0.075 TRICHLOROBTHYLENE wD(0.0010) mg/L —sEPA $02.2/524.2 0.0050 TTEM wD(0.0010) mg/L —sOEPA $02..2/524.2 0.100 BROMOBENZ ENE wD(0.0010) mg/l —sEPA $02.2/524.2 BROMOCHL OROME THANE wD(0.0010) mg/L —sEPA $02.2/524.2 BROMODICELOROME THANE wD(0.0010) mg/l —sEPA $02.2/524.2 BROMOFORM wD(0.0010) mg/L —sEPA $02.2/524.2 BROMOMETHANE wD(0.0010) ng/L —sEPA $02.2/524.2 n-BUTYLBENZENE wD(0.0010) mg/L —sEPA $02.2/524.2 SEC-BUTILBENZENE wD(0.0010) mg/L —_—sEPA $02.2/524.2 TERT-BUTILBEMZENE wD(0.0010) mg/L —sBPA $02.2/524.2 CHLOROBENZ ENE wD(0.0010) mg/L —sEPA $02.2/524.2 CHLORODIBROMOME THANE wWD(0.0010) mg/L —«BPA $02.2/524.2 CHLOROE THAME wD(0.0010) mg/L —sEPA $02.2/524.2 CHLOROFORM wp(0.0010) mg/L EPA S02.2/524.2 CHLOROMETHANE WD(0.0010) ng/L EPA S02.2/524.2 CHEMICAL & GEOLOGICAL LABORATORY A DIVISION OF COMMERCIAL TESTING & ENGINEERING { "\xeonatony 5633 BSTREET ANCHORAGE, ALASKA 99518 TELEPHONE (907) 562-2343 FAX: (907) 561-5301 AMALYSIS REPORT BY SAMPLE for WORKorder# 33906 Date Report Printed: MAY 21 91 @ 10:11 Client Sample ID:DISCHARGE WELL #1 Client Wame :FPE - ROEW INC PWSID :UA Client Acct :FPEROEN Collected APR 30 91 @ 16:00 hrs. BPO # PO # 90083-1 Received MAY 3.91 @ 10:00 hrs. Req ¢ Preserved with :AS REQUIRED Ordered By :JOHM HARGESHEIMER Analysis Completed :MAY 17 91 Send Reports to: Laboratory Supe: or STBPHEN C. EDE 1)FPE - ROEM INC Released By : Ce a 2) Chemlab Ref #: 911791 Lab Smpl ID: 1 Matrix: WATER Allowable Parameter Tested . Result Units Method Limits 1,2 DIBROMO-3-CHLOROPROPANE wD(0.0010) ng/L EPA 502.2/524.2 o-CHLOROTOLUENE wD(0.0010) ng/L EPA $02.2/524.2 p-CHLOROTOLUBNE w0(0.0010) ng/L EPA $02.2/524.2 DIBROMOME THANE w0(0.0010) ng/L EPA 502.2/524.2 m-DICHLOROBENZ EME wD(0.0010) ng/L EPA $02.2/524.2 o-DICHLOROBENZENE w(0.0010) ng/L EPA $02.2/524.2 DICHLORODIFLUOROMETHAME wD(0.0010) ng/L EPA $02.2/524.2 1, 1-DICHLOROBTHANE wD(0.0010) ng/L EPA $02.2/524.2 cis-1, 2-DICHLOROBTHYLEME WD(0.0010) ng/L EPA $02.2/524.2 trans-1,2-DICHLOROBTHYLEME wD(0.0010) ng/L EPA $02.2/524.2 DICHLOROMETHANE wD(0.0010) ng/L EPA $02.2/524.2 1,2-DICHLOROPROPANE WD(0.0010) ng/L EPA 502.2/524.2 1, 3-DICHLOROPROPANE WD(0.0010) ng/L EPA 502.2/524.2 2,2-DICHLOROPROPANE WD(0.0010) ng/L EPA 502.2/524.2 1, 1-DICHLOROPROPENE wD(0.0010) ng/L EPA 502.2/524.2 1, 3-DICHLOROPROPENE wD(0.0010) ng/L EPA $02.2/524.2 ETHYLBEMZEME WD(0.0010) ng/L EPA $02.2/524.2 ETHYLEME DIBROMIDE (EDB) wD(0.0010) ng/L EPA $02.2/524.2 FLUOROTRICHLOROME THANE wD(0.0010) ng/L EPA $02.2/524.2 HEXACHLOROBUTADIENE WD(0.0010) ng/L EPA 502.2/524.2 ISOPROPYLBENZEME WD(0.0010) ng/L EPA $02.2/524.2 p-ISOPROPYLTOLUENE wD(0.0010) ng/L EPA S02.2/524.2 WAPTHALENE w0(0.0010) ng/L EPA 502.2/524.2 n-PROPYLBENZENE wD(0.0010) g/L EPA $02.2/524.2 STYRENE wD(0.0010) mg/L EPA $02.2/524.2 1,1,1,2-TETRACHLOROE THANE wD(0.0010) ng/L EPA 502.2/524.2 1,1,2,2-TBTRACHLOROE THANE w0(0.0010) ng/L EPA $02.2/524.2 TETRACHLOROETHYLENE wD(0.0010) ng/L EPA 502.2/524.2 TOLUENE wD(0.0010) g/L EPA $02.2/524.2 1,2, 3-TRICLOROBENZ ENE wW(0.0010) ng/L EPA 502.2/524.2 1,2,4-TRICHLOROBENZENE wD(0.0010) ng/L EPA 502.2/524.2 1,1, 2-TRICHLOROZ THANE W0(0.0010) ng/L EPA $02.2/524.2 1,2, 3-TRICHLOROPROPANE wD(0.0010) ng/L EPA $02.2/524.2 1,2,4-TRIMETHYLBEMZENE w0(0.0010) ng/L EPA 502.2/524.2 1,3, S-TRIMETHYLBEMZENE wD(0.0010) ng/L EPA $02.2/524.2 CHEMICAL & GEOLOGICAL LABORATORY A DIVISION OF COMMERCIAL TESTING & ENGINEERING [Ow xeonarony 5633 B STREET ANCHORAGE, ALASKA 99518 TELEPHONE (907) 562-2343 FAX: (907) 561-5301 AMALYSIS REPORT BY SAMPLE for WORKorder# 33906 Date Report Printed: MAY 21 91 @ 10:12 Client Sample ID:DISCHARGE WELL #1 Client Name :FPE - ROEW INC PWSID :UA Client Acct :FPEROEN Collected APR 30 91 @ 16:00 hrs. BPO PO # 90083-1 Received MAY 391 @ 10:00 hrs. Req # Preserved with :AS REQUIRED Ordered By :JOHN HARGESHEIMER Analysis Completed :MAY 17 91 Send Reports to: Laboratory Supervigor :STEPHEN C. EDE 1)FPE - ROBN IWC Released By : Le Yo 2) Chemlab Ref #: 911791 Lab Smpl ID: 1 Matrix: WATER Allowable Parameter Tested Result Units Method Limits p & m XYLEM wD(0.0010) ng/L BPA 502.2/524.2 o-XTLEME wD(0.0010) ng/L EPA 502.2/524.2 POLYCHLORIMATED BIPHEWYLS-H20 W0(0.002) ng/L EPA 8080 ooa—an| ‘AROCLOR --- SECOMD COMTAMIMANTS-TITLE 18 n/a n/a n/a CHLORIDE 4.7 ag/l SML6ED407A 250 TRUE COLOR $s PCcU SM16ED204A 15 units COPPER wD(0.05) ng/1 EPA200.7A 1 LANGLIER INDEX @ 40 degrees F -0.13 SM14ED203 LAMGLIER INDEX @ 140 degrees F +0.95 SM14ED203 FLUORIDE w0(0.10) g/l EPA340.3 4.0 FOAMING AGENT, MBAS wD(0.50) ng/1 SML6EDS12B3 0.5 TROW iE) ag/l BPA200.7A 0.3 MANGANESE 0.023 ag/l EPA200.7A 0.05 ODOR WO ODOR TOW SM16ED207 3 pH 8.03 units BPAISO.1 6.5 - 8.5 SODIUM 23 mg/l BPA200.7A 250 SULFATE wo(i) ng/1 EPA37S.4 250 TOTAL DISSOLVED SOLIDS 175 ag/1 EPA160.1 $00 TIN wD(0.05) mg/l EPA200.7A 5 Sample § SAMPLE COLLECTED BY: JOHN HARGESHEIMER. BETHEL UTILITIES. Remarks: LANGLIER INDEX: WATER EXHIBITS VERY SLIGHT CORROSIVE TEMDEMCY AT 40 DEREE F. 90 Tests Performed * See Special Instructions Above Ua-Unavailable WD- Hone Detected ** See Sample Remarks Above WA Wot Analyzed LT-Less Than, GT-Greater Than CHEMICAL & GEOLOGICAL LABORATORY A DIVISION OF COMMERCIAL TESTING & ENGINEERING | Aronson NN 5633 BSTREET ANCHORAGE, ALASKA 99518 TELEPHONE (907) 562-2343 FAX: (907) 561-5301 AMALYSIS REPORT BY SAMPLE for WORKorder# 33906 Date Report Printed: MAY 21 91 @ 09:34 Client Sample ID: INJECTION WELL PURGED Client Wame :FPE - ROEN IWC PWSID :UA Client Acct :FPEROEN Collected MAY 291 @ 11:30 hrs. BPO ¢ PO # 90083-1 Received MAY 3.91 @ 10:00 hrs. Req # Preserved with :AS REQUIRED Ordered By : JOHN HARGESHEIMER Analysis Completed :MAY 16 91 Send Reports to: Laboratory Supervisor :STEPHEN C. EDE 1)FPB - ROBN INC Released By : <x. LK — 2) Chemlab Ref #: 911791 Lab Smpl ID: 2 Matrix: WATER Allowable Parameter Tested Result Units Method Limits IWORGAMIC CHEMICALS/TITLE 18 n/a n/a n/a ARSENIC 0.025 g/l ASTM D2972 0.05 maximu BARIUM 0.25 ag/l EPA 200.7 1.0 meximun CADMIUM wD(0.0005) ng/l EPA 213.2 0.010 maxim CHROMIUM 0.0068 wg/l EPA 218.2 0.05 maximu FLUORIDE wD(0.10) mg/l EPA 340.3 2.4 maximum LEAD 0.045 g/l EPA 239.2 0.05 maximu MERCURY wD(0.0002) wg/l SM14 301AV1 0.002 maxim WITRATE-¥ wD(0. 10) ng/1 EPA 353.2 10 maximum SELENIUM WD(0.0005) ng/l ASTM D3859 0.01 maximu SILVER wD(0.001) wg/l EPA 272.2 0.05 maximu TURBIDITY 18 wIU BPA 180.1 1.0 maximum VOLATILE ORGANIC CHEMICALS n/a n/a EPA S02.2/524.2 n/a 1,1,1 TRICHLOROZTHANE wD(0.0010) ng/L EPA $02.2/524.2 0.200 1,1 DICHLOROETHYLEWE wD(0.0010) ng/L BPA S02.2/524.2 0.0070 1,2 DICHLOROBTHANE w(0.0010) ng/L EPA 502.2/524.2 0.0050 CARBON TETRACHLORIDE wD(0.0010) ng/L EPA $02.2/524.2 0.0050 VINYL CHLORIDE WD(0.0010) ng/L EPA 502.2/524.2 0.0010 BENZENE wD(0.0010) ng/L EPA $02.2/524.2 0.0050 1,4-DICHLOROBENZ BNE wD(0.0010) ng/L BPA S02.2/524.2 0.075 TRICHLOROETHYLEME W0(0.0010) ng/L EPA S02.2/524.2 0.0050 TT wD(0.0010) ng/L EPA $02.2/524.2 0.100 BROMOBENZ EME wD(0.0010) wg/l EPA S02.2/524.2 BROMOCHL OROME THANE WD(0.0010) ng/L BPA S02.2/524.2 BROMODICHLOROME THANE wD(0.0010) ag/1 BPA S02.2/524.2 BROMOFORM WD(0..0010) ng/L EPA $02.2/S24.2 BROMOME THANE WD(0.0010) ng/L EPA S02.2/S24.2 n-BOTILBENZEME m(0.0010) ng/L BPA S02.2/524.2 SEC-BUTILBEMZEME wD(0.0010) ng/L BPA S02.2/524.2 TERT-BUTILBENZEME wD(0.0010) g/L EPA 502.2/524.2 CHLOROBEMZ ENE WD(0.0010) ng/L EPA S02.2/524.2 CHLORODI BROMOME THAME w0(0.0010) ng/L BPA 502.2/524.2 CHLOROEZ THAME W(0.0010) mg/L EPA S02.2/524.2 CHLOROFORM w0(0.0010) mg/L . BPA S02.2/524.2 CHLOROME THANE (0.0010) ug/L EPA S02.2/524.2 CHEMICAL & GEOLOGICAL LABORATORY A DIVISION OF COMMERCIAL TESTING & ENGINEERING i [_~"xconstony 5633 B STREET ANCHORAGE, ALASKA 99518 TELEPHONE (907) 562-2343 FAX: (907) 561-5301 AMALYSIS REPORT BY SAMPLE for WORKorder# 33906 Date Report Printed: MAY 21 91 @ 09:35 Client Sample ID: INJECTION WELL PURGED Client Mame :FPE - ROEW IWC PWSID :UA Client Acct :FPEROEW Collected MAY 2 91 @ 11:30 hrs. BPO PO # 90083-1 Received MAY 391 @ 10:00 hrs. Req # Preserved with :AS REQUIRED Ordered By :JOHN HARCESHEIMER Analysis Completed :WAY 16 91 Send Reports to: Laboratory Supervisor ;STEPHEN C. EDE 1)FPE - ROEM INC Released By : Com Za_— 2) Chemlab Ref #: 911791 Lab Smpl ID: 2 Matrix: WATER Allowable Units Method Limits Parameter Tested 1,2 DIBROMO-3-CHLOROPROPANE wD(0.0010) g/L EPA $02.2/524.2 o-CHLOROTOLUENE wD(0.0010) ng/L EPA $02.2/524.2 p-CHLOROTOLUENE wD(0.0010) ng/L EPA S02.2/524.2 DIBROMOME THANE wD(0.0010) ng/L EPA S02.2/524.2 m-DICHLOROBEMZEME WD(0.0010) ng/L EPA S02.2/524.2 o-DICHLOROBEMZEME wD(0.0010) ng/L EPA 502.2/524.2 DICHLORODIFLOOR OME THANE wD(0.0010) ng/L BPA 502.2/524.2 1, 1-DICHLOROETHAME wD(0.0010) ng/L EPA S02.2/524.2 cis-1,2-DICHLOROBTHILENE wD(0.0010) ng/L EPA S02.2/S24.2 trane-1,2-DICHLOROETHYLEWE WD(0.0010) ng/L EPA 502.2/524.2 DICHLOROME THANE wD(0.0010) ng/L EPA S02.2/524.2 1, 2-DICHLOROPROPANE wD(0.0010) ng/L EPA S02.2/524.2 1, 3-DICHLOROPROPANE wD(0.0010) ng/L EPA $02.2/524.2 2, 2-DICHLOROPROPAME wD(0.0010) ng/L EPA 502.2/524.2 1, 1-DICHLOROPROPEME WD(0.0010) g/L EPA 502.2/S24.2 1, 3-DICHLOROPROPENE W(0.0010) ng/L EPA 502.2/524.2 ETHYLBEMZEWE WD(0.0010) ng/L EPA S02.2/524.2 ETHYLENE DIBROMIDE (EDB) W(0.0010) ng/L EPA $02.2/524.2 FLUOROTRICHLOROME THANE WD(0.0010) ng/L EPA S02.2/524.2 HEXACHLOROBUTADIEME wD(0.0010) ng/L EPA $02.2/524.2 ISOPROPYLBEMZENE wD(0.0010) ng/L EPA S02.2/524.2 p-ISOPROPYLTOLUEME w0(0.0010) ng/L EPA 502.2/524.2 MAPTHALEWE WD(0.0010) ng/L BPA S02.2/524.2 n-PROPYLBENZENE W0(0.0010) ng/L EPA S02.2/524.2 STYREWE wD(0.0010) ng/L EPA $02.2/524.2 1,1,1,2-TBTRACHLOROB THAME WD(0.0010) g/L EPA $02.2/524.2 1,1,2,2-TETRACHLOROB THANE wD(0.0010) ng/L EPA S02.2/524.2 TETRACHLOROBTHYLENE WD(0.0010) ng/L EPA S02.2/524.2 TOLUENE wD(0.0010) ng/L EPA S02.2/S24.2 1,2, 3-TRICLOROBEMZEME w(0.0010) ug/L EPA S02.2/524.2 1,2,4-TRICHLOROBENZ EME WD(0.0010) g/L EPA 502.2/524.2 1,1,2-TRICHLORORTHANE wD(0.0010) ng/L BPA S02.2/524.2 1,2, 3-TRICHLOROPROPAME wD(0.0010) ng/L EPA $02.2/524.2 1,2,4-TRIMETHYLBEMZENE wD(0.0010) ng/L BPA S02.2/524.2 1,3,S-TRIMBTHYLBEMZEME WD(0.0010) mg/L © ‘EPA $02.2/524.2 CHEMICAL & GEOLOGICAL LABORATORY A DIVISION OF COMMERCIAL TESTING & ENGINEERING fl ~"xeonstony 5633 BSTREET ANCHORAGE, ALASKA 99518 TELEPHONE (907) 562-2343. FAX: (907) 561-5301 AMALYSIS REPORT BY SAMPLE for WORKorder# 33906 Date Report Printed: MAY 21 91 @ 09:35 Client Sample ID:INJECTION WELL PURGED Client Wame :FPE - ROEW INC PWSID :UA Client Acct :FPEROEN Collected MAY 2 91 @ 11:30 hrs. BPO ¢ PO # 90083-1 Received MAY 391 @ 10:00 hrs. Req # Preserved with :AS REQUIRED Ordered By :JOHM HARCESHEIMER Analysis Completed :MAYT 16 91 Send Reports to: Laboratory Supervisor ; STEPHEN C. EDE 1)FPE - ROEM IWC Released By : * 7 2) See eceee sess nenennsesessnasessseesesersesessessenssenessseesssessanesecssnesescesesasessseessesessessessessssassssnssscssessssessens Chemlab Ref #: 911791 Lab Smpl ID: 2 Matrix: WATER Allowable Parameter Tested Result Units Method Limits p & m XYLENE wD(0.0010) ng/L EPA 502.2/524.2 o- XYLENE WD(0.0010) ng/L EPA S02.2/524.2 POLYCHLORIMATED BIPHENYLS-H20 w0(0.002) ng/L EPA 8080 soceee| AROCLOR --- SECOMD COMTAMIMANTS-TITLE 18 n/a na n/a CHLORIDE 4.9 g/l SM16ED407A 250 TRUE COLOR 10 PCU SML6BD204A 1S units COPPER wo(0.05) ng/1 EPA200.7A 1 LAMGLIER INDEX @ 40 degrees F -.037 SM14BD203 LAMGLIER INDEX @ 140 degrees F +0.71 SM14ED203 FLUORIDE wD(0.10) ng/1 EPA340.3 4.0 FOAMING AGENT, MBAS wD(0.50) g/l SM16BD512B3 0.5 TROW 18.1 mg/l EPA200.7A 0.3 MANGANESE 0.082 g/l EPA200.7A 0.05 ODOR WO ODOR TON SM16ED207 3 pH 7.83 units EPA1SO.1 6.5 - 8.5 SODIUM 23 g/l EPA200.7A 250 SULFATE w(1) ng/1 EPA378.4 250 TOTAL DISSOLVED SOLIDS 188 g/l BPA160.1 $00 TIN 0.44 ng/l EPA200.7A $s Sample § SAMPLE COLLECTED BY: JOHN HARGESHEIMER. BETHEL UTILITIES. Remarks: LANGLIER INDEX: WATER EXHIBITS VERY SLIGHT CORROSIVE TENDENCY AT 40 DEGREE F. 90 Tests Performed * See Special Instructions Above UA-Unavailable WD- None Detected ** See Sample Remarks Above MA- Wot Analyzed LT-Less Than, GI-Greater Than