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HomeMy WebLinkAboutNorthwest Alaska Coal Project Rural Power Plant Development Summary, March 1995 NORTHWEST ALASKA COAL PROJECT Rural Power Plant Development Summary March, 1995 Prepared For: Prepared By: North Slope Borough, CIPM ASCG Incorporated P.O. Box 69 301 Arctic Slope Ave. Suite 200 Barrow, AK 99723 Anchorage, AK 99518 ASCG INCORPORATED ENGINEERS ¢ ARCHITECTS © SCIENTISTS ¢ SURVEYORS aie 301 ARCTIC SLOPE AVE, SUITE 260 ¢ ANCHORAGE. ALASKA 99518-3035 TABLE OF CONTENTS Rural Power Pland Development Summary ................cccseceeceececceceececeecesceeceecs Page 1 Appendix A Ie Nome Electrical Load Forecast, SFT Incorporated, Toledo, OH 2. Unalaska Power Production, Alaska Energy Authority, Anchorage, AK 3: Technical Memorandum; Power Plant Evaluation for Northwest Alaska Coal Project, SFT Incorporated, Toledo, OH 4. Phase II, Technical Memorandum; Power Plant Evaluation for Northwest Alaska Coal Project, SFT Incorporated, Toledo, OH ay Electric Transmission Lines Study for the Northwest Coal Project, J. W. A., Anchorage, AK 6. Economic Analysis of Coal-Fired Power Plant to serve Nome, Kotzebue, and Red Dog Mine, Analysis North, Anchorage, AK Appendix B Vendor information on Micronized Coal ie 2. TCS Incorporated Fuller Corporation NORTHWEST ALASKA COAL PROJECT Rural Power Plant Development Summary I. INTRODUCTION The Northwest Alaska Coal Project was charged with development of a large scale Arctic coal mine and related infrastructure along with identifying the potential markets for the coal produced. Previous studies have shown that such a mine offers the most potential as an economically viable alternative energy source for western Alaska. A portion of the 1992 Phase II effort was to assess the technical and economic feasibility of coal-fired generation in tural western Alaska fueled by Northwest Arctic coal. This report presents the results of the rural power plant development efforts. Electric power in rural Alaska is generated almost exclusively by diesel driven generators. The majority of space heating needs is oil fired. Oil price volatility has made energy an overwhelming component of the cost of living in rural Alaska. The shipment of oil to remote locations and subsequent storage has become a large liability for the state, both economically and environmentally. By being the state's most abundant energy resource, coal offers an obvious alternative to the use of oil. The high energy, low sulfur content coal of Northwest Alaska, coupled with the proper combustion techniques, has the potential for an environmentally suitable substitute. This study targeted locations for which Northwest Alaskan coal has been shown to be a potentially viable alternative energy source. Communities on the navigable waters of western Alaska with large electrically and thermal heating loads were selected. The locations identified were Kotzebue, Nome, Red Dog Mine, St. Paul, and Unalaska. Other potential sites were the military bases at Adak and Shemya. Limited success at collecting data was realized at the military sites however due to low interest. For each targeted community, engineering and economic studies were conducted to quantify the cost difference between coal and oil use for power and heat generation. This report epitomized the results of a number of specialized contractors whose involvement is listed below. Nome Load Forecast Analysis North, Anchorage, AK Unalaska Load Study Alaska Energy Authority, Anchorage, AK Power Plant Design and Cost Estimate SFT Incorporated, Toledo, OH Transmission Line Engineering J. W. A., Anchorage, AK Economic Analysis Analysis North, Anchorage, AK II. | STUDY RESULTS The results of the individual studies commissioned as part of this effort are summarized in this section. A._LOAD FORECASTS For the locations identified, the available electrical and thermal energy consumption figures were collected. This data, along with population and economic activity growth projections, was used to predict future energy use. Coal tonnages required to meet these energy needs were calculated for those communities for which sufficient data existed. Gaps in the table reflect unavailability of data. Electrical Thermal Energy Use i Energy Use (MWh/yr) (MBTU/yr) Deadfall 22 Mine! 200 | 52 | 0000 | 53 |e 000 Red Dog The load data was used to size and cost power plants for the most promising communities. The first approach employed conventional combustion and generation technologies in the plant "| Assumes minemouth plant powering Deadfall Syncline coal mining operation and the Red Dog Mine via a transmission line. Thermal load at Red dog presently supplied by diesel waste heat recovery is replaced with electric heat. >: This data was provided by a report commissioned by the Alaska Energy Authority for the City of St. Paul: City of St. Paul Municipal Electric Utility Power plant Feasibility Study, Raj Bhargava Associates, Anchorage, Alaska, 1993. design. Alternatives were investigated to assess the impact on project feasibility. Combustion Technology A large part of the efforts by SFT, Inc. comprised a comparison of conventional combustion technologies and power plant designs. This study concluded that a conventional steam Rankine cycle is best suited for energy conversion. The currently available combustion processes which were evaluated to determine the optimum technology match for the size range of the communities studied were fluidized bed, pulverized coal, and stoker firing. A spreader stoker boiler was selected based on size and operating requirements. Reliability requirements dictated two boilers be provided. Proceeding with the technology selected, conceptual power plant designs were made for Kotzebue, Nome, Red Dog, and the Deadfall Syncline minesite. Plant capital cost estimates were made based on these designs. Capital Cost The capital cost figures estimated for conventional, stick-built, redundant boiler, coal- fired power plants are as follows. LOCATION Kotzebue Red Dog Deadfall Minesite The mine-mouth plant at the Deadfall Syncline was sized to power the local coal mining activities as well as the mining operation at Red Dog. The cost of an overhead transmission line to carry power from the Deadfall plant to Red Dog is included in the cost estimate. Operating & Maintenance Cost Interviews with utility managers and operators provided the basis for operating cost estimates. In evaluating the personnel requirements for these plants, a staffing level of 22 per plant was established. This number includes round-the-clock operator coverage, and weekday-only maintenance, clerical, and supervisory personnel coverage. Transmission Lines An alternative to building power plants in each of Kotzebue, Red Dog, and at the Deadfall Syncline mine, electrical interties between these locations with centralized generation was considered. Four options of interconnecting these locations with overhead transmission lines were costed by JWA, Inc., and are summarized below. The Red Dog port facility electrical load near Kivalina was included in the transmission line options. costes) LINE ROUTE LENGTH (miles) | 69 kV Single Pole | 138 kV H-FRAME Red Dog Mine - 60 overhead 14.4 20.9 Red Dog Port Red Dog Mine - 170 overhead 44.2 Red Dog Port - 5 submarine Kotzebue Deadfall Mine - 162 overhead infeasible Red Dog Mine - Red Dog Port Deadfall Mine - 272 overhead infeasible Red Dog Mine - 5 submarine Red Dog Port - Kotzebue C. ECONOMIC ANALYSIS The economic analysis used the results of the capital and operating and maintenance (O & M) cost estimates to evaluate the economic feasibility of stand-alone coal-fired plants in Kotzebue, Nome, Red Dog, and the Deadfall Syncline minesite. The analysis also considered the scenario of a mine-mouth coal-fired plant at the Deadfall Syncline minesite which also supplied the Red Dog mine via an 85 mile transmission line. The method used calculated the present value of costs to generate the predicted load for these locations using both a grass roots coal plant and an expanded diesel plant. These costs were then compared to determine overall project feasibility. The present value of the economic benefits of coal use in comparison to diesel generation are summarized below. Benefit Nome Kotzebue Red Dog Deadfall (1991 M$) Syncline Mine Fuel and Non- 14 15.3 44.3 59 Labor O&M D5 4. Labor and 23 -25.6 -29.2 Insurance Capital Cost 32.5 Net Economic -32.8 -34.3 -40.7 -62.9 Benefit As can be seen, the overall cost of using coal to meet the same demand is higher despite the lower energy cost component when coal is used. The staffing levels and initial capital cost of the coal-fired plant combine to negate the positive benefits of the accrued fuel savings. Sensitivity analyses were run on the assumptions used in the evaluation to determine the impact of the uncertainty in those variables. These analysis show that a break-even cost can only be realized if a number of the assumptions vary favorably. Any less optimistic scenario will result in a non viable project. Many of the variables impacting the break-even cost are market dependent and therefore beyond control of the project developer. The variables which have the greatest impact on break-even costs, and which the developer has some control of, are construction cost, plant staffing, coal price, and thermal energy sales. Preliminary investigations into reducing capital costs and increasing district heating load were reviewed to determine their impacts on project feasibility and these are summarized below. D. ALTERNATIVES TO INCREASE PROJECT VIABILITY The cost estimates generated for the economic analysis employed standard conservative designs and practices. Since these contributed to non viability of the coal option, a more innovative approach was required. New technologies and more cost effective practices were investigated in an attempt to improve the economic viability of the coal option. Capital Cost Reducti Initial plant capital cost is a larger portion of the cost side of the economic analysis. For this reason, a number of options which resulted in a lower initial plant cost were evaluated to determine their impact on the overall economics. The first of the innovations investigated was the use of micronized coal technology. Micronization is the process of grinding coal to a fine powder before combustion. The combustion characteristics of micronized coal resemble that of oil, allowing it to be used in off the shelf "packaged" type boilers. These boilers are physically smaller than conventional field erected boilers, permeating size and therefore cost savings throughout the balance of the facility. These savings are in addition to the large cost savings realized by avoiding the labor intensive process of boiler erection in the field. A second advantage offered by micronized coal use in packaged boilers is its accelerated response time. As with oil, micronized coal will adjust to load swings quickly and turndown adequately to match the load profiles of many of the targeted communities. Technical information from the two domestic vendors of this technology can be found in Appendix 2. The use of micronized coal combustion equipment in the power plant designs for Kotzebue and Nome was costed by SFT Inc. in their Interim Report II - Coal Fired Power Plants, April 20, 1992. In these designs, the plant capacities were downsized to provide baseload generation, and depend upon the existing diesel plant for peaking power. The cost effectiveness of the capital dollars expended is thereby maximized. The second capital cost reduction initiative involved a change in design philosophy as it applied to boiler redundancy. The initial conceptual design employed two 55% capacity parallel steam supply systems feeding a single turbine-generator. In their Interim Report II, a single boiler plant design was utilized in addition to employing micronized coal technology. The existing diesel plant was again retained on standby to provide the necessary peak capacity and guarantee availability of generation. In the case of Red Dog, plant size ruled out the use of micronized coal technology. A single stoker type boiler was used as in the original study. Two cases were investigated; a 16.5 MW plant sized for the Red Dog load only, and a 26 MW plant at Red Dog sized for the combined loads of the Red Dog mine and port, and Kotzebue. The last capital cost reduction concept to be included was the use of modular construction techniques. The initial SFT effort employed conventional on-site, stick- build, construction techniques in its feasibility assessment. The concept of off-site fabrication of modularized plant components followed by shipment to the site for final field assembly was summarily evaluated and preliminary cost savings calculated. The cost savings garnered by use of the techniques discussed above were inputted into the economic analysis. The results of the analysis using the revised figures demonstrate that even with the above design changes, positive benefit by switching to coal is not achieved. The reduction in capital costs shows a positive impact on the economic viability of the coal-fired option at each of the communities. As can be seen however, these initiatives alone will not generate the positive net benefits needed to guarantee success of these projects. Further, more detailed assessment of each of the proposed capital cost reduction scenarios, coupled with lower operating costs and enhancement of the revenue generated by these plants will be required for viability. Revenue Enhancement An adjunct to lowering of capital cost is increasing the revenue side to achieve project viability. The obvious method of increasing revenues from these coal-fired facilities is to employ the wasted heat in a district heating scheme, or in some other useful manner such as centralized refrigeration. The potential benefits of district heating systems in the four locations studied by SFT were calculated by Analysis North. In the base (most probable) case, recovery of thermal energy for district heating has a negative impact on the economics of the coal plant. A larger heating system displacing more on-site heating oil use improves the net benefit of a coal plant, but only if a lower capital cost for larger heating system is realized. The benefit of the heat energy sales alone does not offset the higher operating and capital costs of a district heating system. In those communities where a single substantial energy load is conceivable, hot water or steam sales may be justifiable. Large fish processing and cold storage operations could serve as single point heat loads for which the capital cost to serve the facility does not swamp the potential benefits. Such scenarios were not evaluated as part of this study however. ; ; Reducti The analysis of plant viability assumed coal from a Northwest Arctic mine producing 1 million tons/yr. A different mine production scenario, or even a different coal source could offer substantial fuel cost savings to the power plant projects. This scenario was not considered here, but future investigations should give consideration to alternative, more cost effective, fuel sources. Plant staffing level was also shown to have a large impact on viability by the economic analysis. The levels of staffing used were a result of SFT Incorporated's experience and interfaces with the target operating utilities. No investigations into reductions of these levels were made at this juncture. Synergies between the existing diesel plant and a new coal fired plant offer potential for reducing plant staffing requirements. Ill. . RECOMMENDED FUTURE ACTIONS Subsequent actions in the development of coal-fired power plants for Alaska must focus on those areas outlined above which will have the greatest impact on project economic viability. Using standard technologies and designs, bottom line returns are inadequate. Each component contributing to the success of the project must be addressed. The study undertaken here identified stoker type boilers as the preferred method of coal combustion. This technology, although simple and proven, is less efficient and construction cost intensive than what is required for the applications studied. The newer fluidized bed technology and micronization of coal should be reviewed for suitability to the target locations. A search-comparison study to identify the most suitable technology for this application is recommended. Following selection of an appropriate combustion technology, plant assembly using construction practices which will further cut the initial capital cost must be employed. Pre- fabrication and modularization of large plants with minimal field erection has proved very successful in many remote areas, including Alaska. Employing the combustion technology selected above plan design and construction should incorporate the concept of modularization to its fullest extent. A preliminary design using the results of the combustion technology study should be made and from this an initial capital cost figure can be estimated. As part of the preliminary design effort, particular attention must be paid to the overall plant energy conversion efficiency. Despite the lower raw energy cost advantage coal has over diesel fuel, it is quickly lost when electrical energy is produced. As Figure 1, which uses data estimated for None shows, a low pressure saturated steam plant using Northwest Arctic coal produces electrical energy which is more costly than diesel generated power. Standard plant designs resulting in plant efficiencies in the low 20's cannot compete with diesel powered plant with efficiencies of upward to 36%. A coal plant will most likely be built adjacent to the existing diesel plant. The diesels will be retained for peaking and backup power. The same staff can be trained to run the new coal- fired plant, with only a few additional personnel with coal expertise required to supplement that staff. In this manner substantial savings in the areas of staffing level can be realized. An accurate determination of the requirements to run a combine coal and diesel fired plant will need to be made to determine feasibility. Previous studies have shown that a centralized western Arctic coal mine is the best source for power plants located in western Alaska. This is based on a large scale mine in the two to three million tons per year production range producing cost competitive coal to these power plants. In the absence of such a mine, the most economic coal available should be employed as the fuel source if economic feasibility of the coal plant is of concern. With one coal mine presently in operation in Alaska, and potential existing for a second mine to open, in state coal which is potentially more cost effective than coal from a low volume Arctic coal is available. In the interest of developing cost effective power generation for Alaska, these, as well as other non-Alaskan coal sources should be considered as fuel sources for these plants. A study of potential sources and transportation consideration is required to determine the fuel cost component to the economic equation. Sales of heat from a coal-fired plant offers potential as a source of additional revenue. Numerous preliminary studies of district heating systems have been carried out over the years for most of these target locations. A review of these studies, along with an investigation into the latest techniques for using rejected heat should be made to determine if such a system is justifiable in these locations. IV. CONCLUSION Coal-fired power generation in western Alaska using Northwest Arctic coal using conventional technologies is not cost competitive with diesel fired generation. Newer, proven methods of combustion and construction with the potential to reduce plant capital cost exist which have yet to be applied to power generation. Potential savings in operating costs and increases in revenue generated have been identified. While coal-fired generation has not proven to be more cost effective than diesel fired generation, substantial incentives still warrant further investigation into the use of coal. The technical obstacles to making coal viable are not insurmountable. Coal resources in Alaska are enormous. Oil cost is variable and supply is tenuous. Efforts to replace oil fired generation with coal should continue in the direction identified above. 10 October 26, 1990 Nome Electrical Load Forecast Prepared for: Arctic Slope Consulting Group P.O. Box 650 Barrow, AK 99723 Prepared by: Alan Mitchell Analysis North 911 West 8th Avenue, Suite 204 Anchorage, AK 99501 and Steve Colt EMI Consulting 1408 P Street #A Anchorage, AK 99501 Nome Electrical Load Forecast CCNTENTS Je. Entroduction . . . © + 3.2 Load Forecasting Methods ..... 3.2.1 Residential Model . . 3.2.2 Commercial/Other Model ....... 3.2.3 Gold Mining Model... . . =... .... a 3.2.4 Forecasting Uncertainty ......... 3.2.5 Losses and Peak Generation Requirements 3.3 Employment and Population Projections ..... 3.3.1 Background .....+..e««e 3.3.2 Historical Employment and Population Data . 3.3.3 Economic Projection Methodology and Assumptions 3.3.4 Economic Projections Results .. . 3 3.4 Residential Load Forecast .. ec tsnonetene 3 3.4.1 People per Customer Trend oe ew ew we 3 3.4.2 Use Per Customer Trend ..... . 3 3.4.3 Summary of Residential Forecast . 5 3 3.5 Commercial/Other Forecast ....:.....-. 3 3.5.1 Use per Employee ......... . 3 3.6 Non-Mining Summary ............. S 3 3.7 Mining Forecast .. . ee ee ee er ee 2 3.7.1 General Background ncn noone 3 3.7.2 Recent Mine Operators and Potential Future Operators." 2"... Cen ononere . 3 3.7.3 Low, Mid, and High Mining Assumptions, and Forecast Summary oe . : 3 3.7.4 Likelihood of NJUS supplying Mining Loads 3 3.8 Combined Peak Generation Requirement for Non-Mining and Mining Loads . . .. 2. 2. 1 2 2s © s+ © 2 se we ee s 3 3.9 Forecast Summary .........+.4+6+4+e4e88-s 3 SLO pe ROL OLeNCSS ele ele) co eiloll isc oie ie ; 3 WWWWW Ww Ww WWWwW BE 32 33 34 40 42 48 49 59 LIST OF TABLES Table 3.1 - Historical Employment and Population Data: Of Meee ss 1 «es 2s eh «ee wk 2 wo 2 2 Table 3.2 - Statewide Economic Assumptions by Case.. Table 3.3 - State Spending Assumptions.. . “ Table 3.4 - Projected Employment and Population. Table 3.5 - Adjustments to NJUS Historical Data oe Table 3.6 - End Use Forecast Results for Fairbanks .. Table 3.7 - Residential Forecast Assumptions by Case Table 3.8 - Assumptions for Commercial/Other Forecast. Table 3.9 - Assumptions for the Mining Forecast by Case Table 3.10 - Relative Monthly Peak Demands ...... Table 3.11 - Growth Rates of Total Net Generation Requirements and Table 3.12 - Mid Case Table 3.13 - Mid Case Totals .... Table 3.14 - Low case Table 3.15 - Low Case Totals .. Table 3.16 - High Case Forecast Results, “Non-Mining Loads Table 3.17 - High Case Forecast Results, Mining Loads and Totals ..... Peak Generation Requirements. Forecast Results, Non-Mining Loads Forecast Results, Mining Loads and Forecast Results, Non-Mining Loads Forecast Results, meee Loads and oe oe 8 ee LIST OF FIGURES Figure 3.1 - Indoor Employment Projections ...... Figure 3.2 - Nome Population Forecast ......... Figure 3.3 - People per Residential Customer ..... Figure 3.4 - Use per Residential Customer oem onnre Figure 3.5 - Income per Nome Residential Customer . . Figure 3.6 - Nome Residential Electric Rates .. ane Figure 3.7 - Residential Energy Sales Forecast .... Figure 3.8 - Use per Employee ........4-++4+e4e-. Figure 3.9 - Commercial/Other kWh Sales Forecast. ... Figure 3.10 - Non-Mining Net Generation Requirements. . Figure 3.11 - Historical Load Factor for Nome Non-Mining Loads .... . Figure 3.12 - Historical Gold Production in the Nome District Figure 3.13 - US “Wholesale Gold Prices te . Figure 3.14 - Gold Operators in the Nome District, 1989 Figure 3.15 - Gold Mining Production Forecast ..... Figure 3.16 - Mining Net Generation Forecast . . Figure 3.17 - Total Net Generation Requirements, Non- “Mining and Mining Loads. Figure 3.18 - Total Peak Generation Requirenents, Non-Mining and Mining. .. Figure 3.19 - Total Net Generation Requirements, Mid Case ee eo 8 © © eo we ew ee City Ww WW WW WW ww Www WwW WWWWWWWWwWw w WWWWW 3 a 3 - 54 =195 = 56 7, melds — 72 = 13 aro - 16 Ly, - 26 = 27 sa. S32 - 34 - 38 - 36 - 43 - 44 atl 3.0 NOME ELECTRICAL LOAD FORECAST 3.1 Introduction This report presents a 25-year forecast (1990-2014) cf electric loads in the vicinity of Nome, Alaska. Both the total annual electrical energy use (kilowatt-hours) and the annual peak demand (megawatts) were forecast over the analysis period. Because of the uncertainty present in any forecasting effort, a Low, Mid, and High forecast are provided. These forecasts were selected so that there is approximately an 80% probability that the actual load in future years will fall between the Low and High forecasts. 3.2 Load Forecasting Methods We utilized relatively simple models to forecast the electrical load in Nome. We believe that the level of sophistication present in the models matches the type and quality of historical data available and is appropriate given the level of unavoidable uncertainty present in a long-term forecasting effort. Electrical use in the Nome area was forecast separately for the following 3 customer classes: + Residential + Commercial, Community Facilities, and Street Lighting + Mining 3.2.1 Residential Model The model used for residential electrical use was: Residential Use and (# of customers) was modeled as: # of Customers = Population / (people per customer) (# of customers) * (use per customer) Using this model, three variables need to be forecast: population, people per customer, and use per customer. We utilized the Rural Alaska Model (RAM), a regional economic and demographic model developed at the University of Alaska, Institute of Social and Economic Research (ISER), to forecast population for the Nome area (Knapp, 1990). "People per customer" is essentially a measure of household size. We forecast this household size variable by examining statewide forecasts developed by ISER (Goldsmith, 1990). Finally, we forecast use per customer by examining historical trends in this variable for Nome, estimating the impacts from probable changes in Nome electric use patterns, and examining other statewide and national forecasts that have relevance to the Nome situation. 3.2.2 Commercial/Other Model All non-residential use except for mining electric consumption was grouped together in one category. Commercial use, community facility use, and street lighting are the main uses in this category. The model used for this type of electric use was: Commercial/Other Use = (Indoor Employment) * (Use/Employee) Indoor employment is a measure of the number of employees working in-.buildings and was calculated as total employment minus mining employment and minus a portion of construction employment. The indoor employment forecast is provided by the RAM model referred to above. Use per employee is forecast by examining historical Nome data and investigating other forecasts concerning the energy intensity of commercial activities. ~~ Some electricity uses in the commercial/other category, such as street lighting, are not closely related to the number of indoor employees. Street lighting use is more closely related to the total population of Nome. However, the total use associated with street lighting is not large. We did not complicate the forecasting effort by separating out such uses. In addition, indoor employment is closely correlated with population, so forecasting street lighting use from indoor employment will not result in significant errors. 3.2.3 Gold Mining Model The final category of electric use is gold mining use. The electrical use of gold mining operations is a large fraction of the total electrical requirements in the Nome area. Further, total mine electrical use is dependent on factors different from factors determining the level of other electrical uses. Thus, a separate forecast of mining electrical use was prepared. Gold mining was divided into three different types of mining operations: onshore mining that occurs during the summer only, onshore mining that occurs year-round, and offshore mining. This division was made because the seasonal distribution of power requirements and the total power requirements vary substantially among these different types of operations. For offshore mining, we only considered the wintertime (off- season) power requirements. These are the power requirements that occur while the dredges are docked at the Nome causeway between mining seasons. For the onshore mining operations, we only included operations and potential operations that would have economical access to the Nome Joint Utilities System (NJUS) transmission and distribution grid. The electrical use of each different type of mining was forecast using the following model structure: Mining Use = (Ounces of Gold Mined) * (Electric Use per Ounce) For each type of use, we forecast the amount of gold mined by consulting with state mining experts and interviewing mine operators and potential operators. To forecast electric use per ounce of gold mined for the different types of operations, we gathered such data from existing operations and utilized mine operator estimates for potential future operations. 3.2.4 Forecasting Uncertainty For each type of use, three scenarios were projected--a mid case, a low case, and a high case. The mid case was chosen such that there is a 50% chance that the actual load will be higher than the mid case and a 50% chance that it will be lower. The low case represents a combination of forecast assumptions that result in a low growth rate in electric use, and the high case represents assumptions that result in rate of growth higher than the mid case. We attempted to chose the assumptions for the low and high cases such that the likelihood of the actual electrical load being somewhere between those cases is roughly 80%, i.e. there is a 10% chance that the actual electrical load will exceed our high scenario projection and a 10% chance that the actual load will be less than our low scenario projection. However, these probability figures themselves are substantially uncertain. The range of assumptions chosen for an individual variable may seem small. For example, there is probably more than a 10% probability that gold production will exceed our high case estimate. However, the High gold assumption was combined with the High population growth assumption and the High use per customer assumption to determine the High load growth projection. Because of the unlikelihood of all of these variables assuming high values simultaneously, we restrained a & —=_ as 3.3 the high estimates for the individual variables. Likewise, the low estimates were restrained. 3.2.5 Losses and Peak Generation Requirements Since the objective of the overall study is to evaluate alternative generation options, the consumption figures were converted to a generation requirement by adding the transmission and distribution losses associated with serving the loads with off-site generation. In section 3.7.4 we discuss the likelihood of various loads being served from the NJUS generation system. As well as forecasting annual generation requirements in kilowatt-hours, we also forecast the peak generation requirements in megawatts based on typical load factors for each load. Since mining loads do not necessarily peak at the same time as non-mining loads, the combined peak generation requirement of the loads is less than the simple addition of their individual peaks. We account for this non-coincidence in calculating a Nome area peak electrical demand. Employment and Population Projections 3.3.1 Background The city of Nome is the regional hub of about 15 Inupiaq villages surrounding Norton Sound. Nome was founded in the 1898 gold rush and briefly enjoyed the status of Alaska’s largest community at the turn of the century (Waring 1988, p. i). Since that time, its cash economy has been driven by military spending, continued mining, and, especially during the 1980s, public spending for government services, public works construction, education and health care. 3.3.2 Historical Employment and Population Data Table 3.1 shows historical average annual employment by sector for the City of Nome during the 1980s. These data are from the Alaska Department of Labor’s ES-202 reports, with two substantial adjustments* made to better represent employment actually occurring within the city. Total "Adjusted DOL Employment" grew at an average annual rate of 3.3 percent between 1980 and 1989. As Knapp (1990) points out, ES-202 data undercounts some actual employment because it does not include proprietors or workers working in Nome for firms headquartered in other cities. On the other hand, the data erroneously includes workers working outside of Nome for firms headquartered in Nome. Even with these limitations, the ES- 202 data are excellent for reviewing trends in employment. Because they are based on monthly reporting, they accurately reflect the highly seasonal nature of many rural Alaskan jobs. An alternative employment data set, generated by a 1986 survey of employers, exists for the period 1980-1986 (Impact Assessment 1987). These data are somewhat more detailed and are theoretically free of the defects noted above. However, they are biased downward for earlier years because it is likely that there are several firms which were in business during the early part of the decade but no longer in business when the survey was conducted. In order to combine the best attributes of each data source, we further adjusted the entire DOL data series so that total "benchmarked" DOL non-mining employment was equal to Impact Assessment measured non-mining employment in the year 1986. ‘These are: (1) Removing estimated Bering Straits School District employment since the district is actually located in Unalakleet; (2) Removing one-time CETA program summer employment from 1980 and 1981 services employment. > 6 Table 3.1 -— Historical Employment and Population Data: City of Nome. Avg Growth) 198019811982 19631984 19SS_ 1986 _19S7__:198S__1989 $0-89 EMPLOYMENT (AK Dept of Labor) Mining (1) 98 131 107 131 106 57 os 143 269 238 10.4% | Construction 18 18 61 75 50 41 31 19 2s 3s 1.9% Trans/Comm/Util 120 120 120 124 100 74 77 105 129 132 1.0% Trade 148 4=«:17%) «61% = 195 00 202 - 28 211 22 35% FIRE. x» 3%6 37 47 45 61 40 31 0 26 “14% Services (2) 540 517 406 432 446 471 455 464 449 501 0.8% Fed Government 8 89 79 83 a 98 93 89 90 73 0.7% State Government 172 186 213 2% 236 240 2% 29211 a 3.0% Local Government 3% 389 435 511 575 604 598 580 628 623 T1% Total DOL Empieyment 1,568 1,671 1,666 1,804 1,860 1858 1,847 1.853 2045 2081 32% Less: Bering Sts School Dist 178 194 241 237 374 429 372 400 400 400 94% Less: CETA workers 1400117 Adjusted DOL Employment 1250 1360 1,425 1517 1,486 1429 1475 1.453 1.645 1,681 33% Less: Mining 98 131 107 131 106 57 65 143 269 28 Less: 1/2 Construction 9 9 31 37 23 21 16 9 14 18 Less: Benchmarking to LAI (3) 97 97 7 97 7 97 97 97 97 97 Benchmarked Indoor Employment 1,046 1.123 1.190 1.252 1.258 1.254 1.297 1.204 1265 1.328 27% POPULATION City of Nome 3.000 3,039 3430 3,620 3,791 3.876 AK Dept. of Labor (4) 2430 3,039 3.420 3,102 3,146 3,236 3.208 3,306 3403 3,499 4.1% Sources: Minerais Mgmt Service 1990 (employment): Waring 1989 (population): Personal Communication Judy Hallanger. ADOL. 10/15/90 (population 1987-89). Notes: (1) Mining is partially suppressed in years 1980-86. Estimated during those years as a residual, using total and sum of all other industries. (2) When CETA service workers (1980-1981) are removed, average growth rate is 2.6%. (3) Data collected in a survey by Impact Assessment, Inc. (1987) are believed by Knapp (1990) to be best single year snapshot of employment and are used in the RAM forecasting model. Benchmarking adjustment forces DOL data series to be equal to LA] series in 1986. (4) Figure for 1980 is US Census, believed to be a significant undercount. Average growth rate for 1981-89 is 1.8%. Further removal of one half of the construction employment yields a data series labeled Benchmarked Indoor Employment which is most useful for looking at trends in electricity use per employee. A single definitive data series for population is not available. There are two population series available, from the City of Nome and from the State Demographer through the Department of Labor. These two series are also shown in 3-7 Table 3.1. The two series are in agreement for the years 1981 and 1982. For the period 1983-1986, they diverge substantially, with the city estimates growing more rapidly. Waring (1989) discusses the probable accuracy of these two series at length and concludes: We conclude that the City’s post-1982 population estimates overstate the City’s true population. The City’s 1982-1985 population estimates were based on an annual count of housing units multiplied by the vacancy rates and average household size that prevailed at the time of the City’s 1981 population count. We believe this method is prone to yield increasingly inflated population estimates under the housing market conditions that prevailed at Nome [in 1981]. Specifically, in the following four years, a residential construction boom enlarged the housing stock by 331 units (34 percent). Under these changing market conditions, we believe it is unrealistic to hold vacancy rates and average household sizes fixed at 1981 levels, as the city did in its estimation technology... All things considered, we are persuaded to accept the Alaska Department of Labor’s 1983-1986 population estimates over the City of Nome’s official estimates as more consistent with other available population indicators. (page 55) Based on this logic, we agree with Waring that the DOL population series is more plausible for the period 1981-89. We have therefore projected population using a 1989 starting point consistent with DOL data. It is important to remember that either series could be used as a basis for projection, since it is the relative growth in population that is relevant to the electric load forecast. 3.3.3 Economic Projection Methodology and Assumptions We used the Rural Alaska Model (RAM) developed by Knapp (1990) and adjusted to reflect 1988 and 1989 data in order to project 36 City of Nome employment and population under various sets of driving assumptions. The RAM model relies on assumptions about the following driving variables: + future basic sector employment - future levels of state spending (operating and capital) + future growth in "exogenous" support employment (serving tourist and out-of-region demand) Future basic sector employment consists almost entirely of offshore and onshore mining. Scenarios for Low, Mid, and High case mining employment levels are discussed in section 3.7.3 of this report. Other basic employment (about three full time equivalent fishermen) is assumed to remain constant. Table 3.2 - Statewide Economic Assumptions by Case. Source: Goldsmith (1990). Peet ee eRe eee Oil Prices } in 1989 $ 1990 $18 $18 | 2000 $14 $19 | $14 $21 | | Tourism } 3% per year 3% per year | Growth : | Petroleum West Sak, West Sak, Production after 2000 Fishing | Constant at Constant at Employment | 15,700 15,700 ne Three scenarios for future levels of state spending have been taken from recent econometric projections prepared by the Institute of Social and Economic Research using the MAP model (Goldsmith 1990). Table 3.2 shows the key assumptions used by Goldsmith to develop these projections. More detailed assumptions are contained in Goldsmith (1990). Sino Table 3.3 - State Spending Assumptions. Results of MAP Model Projections. Source: Goldsmith (1990). Average Annual Growth Rate, 1990-2010 Constant 1989 Dollars panceyee Expenditures Capital Expenditures Table 3.3 shows the projected annual growth rates in state operating and capital spending which result from the MAP model runs. These are used as inputs to the RAM model to place realistic limits on the number of future state-supported jobs in Nome. Future growth in exogenous support employment is assumed to be 2.0 percent annually. This is Knapp’s best guess for the Nome region and is consistent with the 3.0 percent growth rate in tourist visits assumed by Goldsmith in the MAP statewide model projections. Because it is highly unlikely that low mining employment, low state spending, and low tourism growth will all occur at the same time, we have chosen not to vary this assumption across cases. 3.3.4 Economic Projections Results Table 3.4 summarizes the results of the RAM model runs. Population grows at between 1.3 and 2.3 percent annually, while indoor employment grows at between 0.7 and 1.6 percent.’ ?These growth rates do not exactly correspond to the growth rates in the final forecast summary tables. This is because the electric forecast extends to the year 2014 while RAM only projects SLO) Table 3.4 - Projected Employment and Population. Source: RAM Model. 1990-2010 Variable | Mid % Total Employment 1.0 1. 1.68 Indoor Employment eal Population 1.3% 1.7% ___(DOL Series) = 2,500 Average Annual Growth Rate, — 2,000 Employees a 8 g 981 1986 1991 1996 2001 2006 2011 Year —= Historical -— Mid — Low —= High Figure 3.1 - Indoor Employment Projections Population grows faster than employment due to the effects of natural increase. Natural increase in population is not dependent on employment growth. Figure 3.1 and Figure 3.2 to the year 2010. We extended the RAM results to 2014 for use in the electric forecast by using the 2000-2010 growth rate. Spoon graphically depict the indoor employment and population projections. Nome Population 7,0007 6,000 5,0007 981 1986 1991 1996 2001 2006 2011 Year —® Historical —— Mid = Low —= High Figure 3.2 - Nome Population Forecast 3.4 Residential Load Forecast As stated in section 3.2.1 our model requires that three variables be forecast to project residential sales: population, people per residential customer, and use per residential customer. The population forecast is an output of the economic/demographic forecast discussed in previous section. The forecast of the remaining two variables will be addressed in this section. 3.4.1 People per Customer Trend Figure 3.3 shows the history of the people per customer variable, a measure of household size, for the 1981 through Samae “A 1989 period, based on Alaska Department of Labor population data, and NJUS residential customer counts adjusted for misclassified customers. Prior to 1988, a number of apartment units were classified by NJUS as commercial customers. An estimate of these misclassified customers was made, and pre- 1988 customer counts were adjusted. Table 3.5 shows these adjustments, the associated kWh sales adjustments, and the separation of mining electrical use from the NJUS sales data (relevant in subsequent sections of the report). People per Residential Customer Nome 3.5 3 2.5 2 -3.1% / year 1.5 People/Customer 0.5 1981 1982 1983 1984 1985 1986 1987 1988 1989 Year Figure 3.3 — People per Residential Customer. Population data from Alaska Department of Labor. Residential customer data from NJUS, adjusted for misclassified residential customers. The graph shows that the people per customer variable drops sharply between 1981 and 1983, and then remains nearly constant for the remaining years of the historical period. A housing boom occurred in Nome during the early 80s. The housing stock increased faster than population, resulting in Soils Table 3.5 - Adjustments to NJUS Historical Data. Residential customers erroneously classified as commercial are added back to residential customer counts and sales. Also, mining sales are separated from commercial sales. 1981__1982__1983 9851986 __1987__ 1988 1989 | a) Total Sales, MWh 19,024 20,379 20,785 Kb) Residential Class Sales, MWh 6,257 6,492 6,995 Kc) Residential Customers 1,160 1,151 1,197 Kd) Use/Resid. Cust., kWh, b * 1000/c 5,394 5,640 5,844 K€) Resid. Cust. classified as Commercial] 130 129 134 K Sales to Misciass. Cust., MWh, d xe 700727 783 g) Adj. Residential Sales, MWh, b + f h) Adj. Residential Customers, c + ¢ i) Adj. Use/Resid. Cust., kWh, g * 1000 kj) Mining Company Sales. MWh k) Net Commercial, Commun. Facil., & Street Lighting Sales, MWh, a - g - j a reduction in the average household size during this period. The stability shown in the 1983 through 1989 period is consistent with more general evidence concerning long-term household size trends. The variable does change over time but in a slow manner. For our forecast of this variable, we rely on the forecast of Alaskan household size used in the ISER MAP forecast (Goldsmith, 1990). In this forecast, household size was projected to decline 0.25%/year through the year 2010. Because of its minor effect on load relative to other variables, the household size trend is assumed to be the same in all three residential forecasts--mid, low, and high. 3.4.2 Use Per Customer Trend Figure 3.4 shows the history of residential use per customer for Nome, Alaska, and the US. Use per customer in Nome has trended upward at a rate of 0.8% per year for the period 1981 through 1989. 3° 14 Use per Residential Customer 0 9,000 8,000- 7,000- 6,000+ Coe erreerrr tities 5,0005 0.8% / year 4,000+ 3,0004 2,0004 1,0004 0 ee — ooo 1981 1982 1983 1984 1985 1986 1987 1988 1989 Year 1.1% / year -2.4% / year kWh/year —* Nome —— US — Alaska Figure 3.4 - Use per Residential Customer. Sources: Nome - adjusted NJUS data (adjustments shown in Table 3.5); Alaska - Penny Haldane, Alaska Energy Authority; US - US Statistical Abstract, 1989. Use per customer can be thought of as the amount of electric services used by a customer multiplied by the energy intensity of providing those services. An example of an "electrical service" is food refrigeration or residential lighting. The "energy intensity" of providing a service indicates the amount of electricity required per unit of service. A change in use per customer can be explained by changes in the amount or energy intensity of electrical services used by customers. The amount of electrical services used by residential customers is affected by a number of factors. The household income affects the amount of services that can be afforded by the customer. Figure 3.5 shows how per customer income varied throughout the 1981-89 period. Per capita income rises by 3 = 15 Income per Nome Residential Customer Inflation-Adjusted -2.2% / year 1989 $ per Customer (Thousands) 1981 1982 1983 1984 1985 1986 1987 1988 1989 Year Figure 3.5 - Income per Nome Residential Customer. Sources: Income per capita - Bureau of Econ. Analysis, adjusted for differences in Census Area and Nome City incomes; Population - AK Dept. of Labor; Customer count - NJUS. about 0.9% per year throughout the period; however, the figure shows that household income declines initially because of decreasing household size. The average change in per customer income over the entire period is a decline of 2.2% per year. Such a reduction in household income would exert a downward influence on the amount of electrical services used over the period. Another factor affecting the amount of electrical services used is the price of electricity. The more expensive electricity is, the less electrical services will be used. Figure 3.6 shows the history of residential electrical rates in Nome. The rates shown are adjusted for inflation. Two data series are given; one represents the "full" residential Sp allo Nome Residential Electric Rates Inflation-Adjusted 6.7% / year -8.5% / year Cents/kWh, 1989 $ 1981 1982 1983 1984 1985 1986 1987 1988 1989 Year —#— Total Rate —— Subsidized Rate Figure 3.6 - Nome Residential Electric Rates. Source: NJUS. US Consumer Price Index used to adjust for inflation. rate and the lesser series shows the net rate after state subsidies have been deducted. The Power Cost Assistance program began subsidizing rural electric rates in 1981. This program was supplanted by the Power Cost Equalization program in 1985, which is still in existence today. For customers using less than 750 kWh per month, as do most residential customers in Nome, the rate paid by the customer for additional kilowatt-hours is the subsidized rate. Their decisions to use more or less electricity should, in theory, be influenced by this rate. The figure shows that the subsidized rate has substantially declined since 1981, both because of the higher level of assistance received under the PCE program relative to the PCA program and because of a reduction in the total electric rate. |i Lia The total electric rate has declined in inflation-adjusted terms because of a number of factors. Electric rates in the early 80s were set above electric production costs, and the surplus was used to fund other city services. This cross- subsidy has diminished in the latter part of the 80s. Also, the cost-efficiency of the utility has improved. Fuel prices have decreased and the fuel efficiency of generation has improved. Finally, sales have increased, which has caused the per kilowatt-hour impact of fixed costs to decline. The average decline of the subsidized residential electric rate over the 1981-89 period is 8.5% per year, although the rate has flattened in the latter half of the period. Such a decline would tend to have caused additional use of electrical services, since electricity became cheaper relative to other goods and services. Another factor influencing the level of electrical services used is the development of new services that use electricity. VCR’s and home computers are examples of relatively new appliances that use electricity. Even without household income increases, these new services can be attractive enough to draw away dollars from other uses of household income. However, new uses for electricity can sometimes reduce electrical usage for older electrical services. More time spent with a home computer may mean less time in front of the television. Finally, the availability and price of substitute energy sources affects the amount of electrical services used by consumers. The drop in statewide Alaskan residential use per customer in the mid 1980s is probably due to substitution of natural gas space and water heating for electrical heating. a7 oe The above discussion addresses changes in the amount of electrical services used by customers. Also important are changes in the energy intensity of those electrical services. As well as affecting the amount of electric services used, the price of electricity affects the energy intensity of how those services are provided. Consumers buy more energy-efficient lights and appliances when electricity is more expensive. The extra cost of the more efficient appliances is more quickly paid back through energy savings when electric rates are higher. Other factors affect the energy intensity of electrical services other than the electric price paid by consumers. The range of appliance energy efficiency available to consumers is often determined by the electric prices seen by United States consumers as a whole. Frequently, the spectrum of appliances does not include units optimized for the high electric rates paid in rural Alaska. Appliance energy intensities are also affected by government-mandated energy-efficiency standards. This general discussion assists in interpreting Figure 3.4 and in projecting the change in future use per residential customer. In Figure 3.4, the Nome use per customer is substantially less than the Alaska and US use per customer. This is predominantly explained by the fact that there is little use of electricity for space heating in Nome relative to Alaska and the rest of the US. The severity of the climate combined with the substantial price advantage of fuel oil give electric space heat a very small market share. A recent forecast of electrical load for the Alaskan Railbelt (Colt, 1989) concluded that about 1,800 kWh/year of the average use per Railbelt customer is due to electric heat. Although space heating requirements in Southeast Alaska are less, a higher market share for electric space heat probably compensates. 3 = 19 Another factor differentiating the Alaska and Nome use per customer curves from the US curve is lack of the air conditioning end use in Alaska. About 1,400 kWh/customer of the US figure is due to air-conditioning. Most relevant to this load forecasting effort are the changes in Nome residential use per customer over time. The growth rate over the 1981-89 period was 0.8% per year. It is useful to see if this rate corresponds to that derived from a simple econometric analysis of historical price and income data. Price during the period declined at the rate of 8.5% per year. From a cross-sectional analysis of 93 rural Alaskan communities, Yang (1989) determined a long-term residential electric price elasticity of -0.15 (t-statistic = 2.5), i.e. a 1% increase in price causes a 0.15% decline in usage.? Applying this elasticity to the 8.5%/year decline in inflation-adjusted electric price for Nome implies a 1.3%/year increase in use due to the price effect. However, an 8 year period may not be long enough to justify applying a long-term elasticity measure. Residential electricity-using appliances often have lives of 10-20 years. A large portion of today’s consumption is determined by appliance choices and prices in effect 10 years ago. *This price elasticity is very low relative to elasticities determined on total US data. Griffin and Steele (1980, p. 232) report a residential/commercial price elasticity of 0.88. One explanation is that price signals in rural Alaska do not determine the range of appliance efficiencies offered. Rural Alaskan consumers respond to higher prices by choosing a more efficient appliance from a range of appliance efficiencies determined by US electric prices. 3 - 20 Yang also determined a residential income elasticity for electricity usage of 0.31 (t-statistic =5.7).‘ Applying this to the 2.2%/year decline in income per customer over the 1981- 89 period gives an income effect of -0.7%/year. The sum of the price effect and the income effect is an increase in usage of 0.6%/year, relatively close to the actual rate of increase of 0.8%/year. This close correspondence may be somewhat coincidental. Yang found that price and income effects do not explain a large fraction of the variation in use per customer. The r-squared for his equation was 0.32. Nonetheless, it is useful to note that the historical use per customer trend is not radically inconsistent with historical prices, income, and associated elasticities. To develop a mid case projection of use per customer, we make the following assumptions. First, we assume that there will not be any substantial changes in electric price or income over the forecast period. The inflation-adjusted, subsidized electric price in Nome has stabilized since 1985. Because of the structure of the PCE formula, future variations in the unsubsidized price will be greatly dampened by the PCE program. Assuming residential rates track electric costs, a 1 cent/kWh increase in electric rate is dampened by a 0.95 cent/kWh increase in the PCE subsidy.* In the mid case, we ‘This value corresponds well with other estimates of income elasticity for electricity use. See Ross and Williams (1981), page 28. SBecause the 8.5 cent/kWh base rate in the PCE formula is not adjusted for inflation, the program actually results in a nearly constant nominal (not inflation-adjusted) subsidized price for electricity. A constant nominal price for electricity corresponds to a real (inflation-adjusted) price for electricity that declines at the rate of inflation. The eventual effect of this will be that residential consumers in some rural communities, such as Nome, will a 7 22 also assume that income effects will be negligible. In the base case of his MAP forecasts, Goldsmith (1990) projects a nearly constant per capita income for Alaska through 72010. Declining permanent fund dividends and a structural shift in the economy towards lower-paying jobs are the assumptions underlying this projection. With a 0.25%/year decrease in household size, this per capita income projection corresponds to a decline in household income of 0.25%/year. With an income elasticity of 0.31, the income effect amounts to a decline in usage of less than 0.1%/year, a trivial effect. One factor we do consider in our mid case forecast is the recently enacted National Appliance Energy Conservation Act of 1987 (NAECA). The NAECA set energy-efficiency standards for a number of different residential appliances, including refrigerators, freezers, and water heaters. A subsequent amendment set standards for fluorescent lamp ballasts, the devices that start and control power flow to fluorescent lamps. The effective dates for the requirements vary by appliance, but most requirements will be in force by 1991. As an example of the effect of this standard, Colt (1989) projected an 1.2% annual decline in the refrigerator electric use per customer in Fairbanks. The forecast period was 1988 - 2010, and the decline was largely due to the standard. The model used was a detailed end use model that explicitly accounts for the additions and replacements of appliances and associated effects on electricity use. be paying less than urban communities such as Fairbanks and Juneau for electricity. We doubt that the Alaska legislature will accept this situation for long, and expect that the 8.5 cent/kWh base rate will be adjusted upwards because of inflationary trends. An ongoing inflation adjustment to the base rate will result in nearly constant inflation-adjusted price for electricity. 3 - 22 Colt also assumed an increase over time in miscellaneous residential uses of electricity. Future development of new electricity-using appliances and equipment (that do not substitute for other electric uses) would be consistent with this projection. We use Colt’s load forecast results for Fairbanks as the basis for our Nome projections. The price and income trends for Fairbanks used in the forecast were similar to our mid case assumptions concerning Nome.‘ Also, the electrical end use structure for Fairbanks is somewhat similar to Nome’s. Thus, use per customer trends should be comparable. Table 3.6 shows the results of the end use load forecast for Fairbanks. The average use per customer is shown for each of the end uses. The bottom row in the table applies two adjustments to the Fairbanks end use results. First, the electric space heating end use is removed because we believe electric space heating is negligible in Nome. Next, 31% of the water heating use is removed to account for a lower market share of electric water heating in Nome.” The adjusted use per customer declines at a rate of 0.2% per year, and this is taken to be our mid case projection for Nome. The results show that the effect of the efficiency standard is almost canceled by a growth in miscellaneous uses of electricity. To develop a low case estimate for the use per customer trend, we make one adjustment to the mid case estimate. We assume ‘The real price of electricity in Fairbanks was projected to grow at a rate of 0.4% per year. With a 0.15 price elasticity, the effect on consumption would be a decline of only 0.06% per year. 7The initial electric water heater market share in Fairbanks was estimated to be 36%. Phil Kaluza of Arctic Energy Systems in Nome estimates that approximately 25% of Nome households have electric water heaters. 3) = 123 Table 3.6 - End Use Forecast Results for Fairbanks. Source: Colt (1989). _—— Average Use per Fairbanks Customer kWh per year Space Heating Water Heating 1,748 1,404 -0.99% Refrigerators 1723s 871 -1.21% Freezers 610 478 -1.10% Cooking 447 478 0.30% Clothes Drying 772 758 -0.08% Lighting 1,260 1,320 0.21% Miscellaneous 1,992 2,247 0.55% Total - Heat - 31% Water that the Power Cost Equalization Program is phased out by the end of the forecast period, 2014. If NJUS acquires the Alaska Gold Company load, as we believe they will, loss of the PCE subsidy will cause residential rates to rise about 40%. With a price elasticity of 0.15, this price increase will reduce consumption by the end of the period by 6%. This lowers the use per customer trend from -0.2% per year in the mid case to -0.45% per year in the low case. To develop a high case estimate for the use per customer trend, we make one adjustment to the mid case estimate. The steep drop in inflation-adjusted Nome residential electrical rates during the 1980s may not have yet realized its full impact. Electric water heaters have substantially less initial cost than oil-fired water heating systems, especially for homes with forced-air space heating systems. With a 3 = 24 greatly diminished price difference between fuel oil and electricity, electric water heaters in new construction and as replacements for existing water heaters may become more prevalent. Electric water heater consumption averages about 4,800 kWh/year. If the average market share increases by 10 percentage points, average use per customer will be 480 kWh/year higher than otherwise. This increases our mid case trend from -0.2% per year to our high case trend of +0.16% per year. 3.4.3 Summary of Residential Forecast Table 3.7 - Residential Forecast Assumptions by Case People per Customer Use per _ Customer ea eee -0.25% per -0.25% per -0.25% per year year year -0.45% per -0.2% per 0.16% per year _ year year Table 3.7 summarizes the assumptions that were used to generate the low, mid, and high residential forecasts. Figure 3.7 shows the results of the forecast in terms of sales of kilowatt-hours. The numeric values are presented at the end of the load forecast report in section 3.9. 3.5 Commercial/Other Forecast All non-residential electric use, except for mining, is forecast as one category. The category primarily includes commercial buildings, community facilities, and street lighting. Our forecasting method involves forecasting two variables: number of indoor employees (total employment - mining employees - 1/2 of 3) = 25 Nome Residential Sales 20 18 ‘el = 144 124 104 84 64 44 24 million kWh/year 1981 1986 1991 1996 2001 2006 2011 Year . —® Historical —— Mid — Low — High Figure 3.7 - Residential Energy Sales Forecast construction employees) and electric use per employee. The indoor employment forecast was described in section 3.3. The following section discusses the use per employee forecast. 3.5.1 Use per Employee Figure 3.8 shows the historical pattern of use per employee for the Nome, US, and Alaskan commercial sector. All data series show growth during the 80s of from 1.6% to 3.1% per year. The Nome and the Alaska series exhibit more growth than the US series, especially during the 1984 through 1987 period. One possible explanation for this is the addition of a large number of public buildings with relatively high electric use per employee. The state spending boom of the early 80s funded 3 - 26 Use per Commercial Employee 12 10 | | Growth Rates: Nome, 1981-89, 2.7% / yr i US, 1982-88, 1.6% / yr Alaska, 1983-89, 3.1% / yr kWh/year (Thousands) 2 1981 1982 1983 1984 1985 1986 1987 1988 1989 Year —# Nome —— US — Alaska Figure 3.8 - Use per Employee. Sources: Nome - NJUS data, US - US Statistical Abstract, 1989, Alaska - Penny Haldane, Alaska Energy Authority. the construction of a number of buildings that began consuming power during this 84 through 87 period. Because of a large amount of building floorspace per employee (e.g. recreation centers, schools), the addition of these buildings drive up the electric use per employee measure. Another important factor during this period was the economic recession beginning in late 1985. On a statewide basis, this reduced the number of employees but it did not reduce the amount of commercial floorspace.’ Although some of this ‘The Nome employment figures do not show a decrease in employment during the recession. However, the growth in employees was reduced. Because of the time required to construct buildings, the growth in commercial floorspace was probably not reduced to the degree that employment growth was reduced. (Buildings under +) ieee floorspace was left vacant by the recession, vacant floorspace still consumes electricity. The ratio of electric use to number of employees was therefore increased. In general, use per employee is determined by the type of work that is being performed, the amount of work performed per employee, and the electric intensity of the process used to perform the work. The type of work being performed is important because different activities require differing amount of electricity. As discussed before, operating and managing large public buildings requires few employees relative to the amount of electricity consumed. Structural changes in the economy that change the overall composition of the type of work being formed will have effects on average electricity use per employee. Changes in the amount of work performed per employee can have effects on electricity use. If implementing a bar code pricing and inventory system in a grocery store reduces the number of employees required to operate a 10,000 square foot store, electricity use per employee will increase. Other productivity-enhancing changes have a much less dramatic impact on electricity use per employee. Enhanced communication systems and information access systems are not very electricity intensive but can result in substantial productivity improvements. Finally, changes in the electricity intensity of the process used to perform the work will affect electricity use per employee. Approximately half of commercial electricity use is for lighting. Technological progress has produced substantial improvements in the energy-efficiency of lighting technologies, and their implementation reduces the electricity construction when the recession hit were still completed). a= 22 intensity of work processes. Other changes can cause more electricity use. Providing additional and higher quality lighting in retail spaces has been found to be an effective marketing tool in some situations. To forecast use per employee, we once again rely on the more detailed work performed by Colt (1989) for the Railbelt of Alaska. Colt utilized an end use model that projected usage levels for specific types of electric services such as lighting and ventilation. For the Fairbanks forecast, the electric price trajectory was relatively flat. Even though inflation-adjusted prices in Nome have been dropping dramatically during the previous decade, we do not expect significant further price decreases.’ As explained in section 3.4.2, much of the price decrease was due to reduction of the profit present in the electric rate, which was used to fund other non-electric utility services. Much of this profit has already been eliminated. The end use modeling for Fairbanks projects significant declines in the amount of lighting electricity use per square foot, a 23% reduction between 1988 and 2010. It also projected increases in miscellaneous electric use to account for additional uses of equipment such as personal computers. The overall change in use per square foot for Fairbanks between 1988 and 2010 was a reduction of 0.5% per year. We utilize this as our mid case estimate for Nome. However, our Nome forecast is based on use per employee. A trend in commercial electric use per square foot is not equivalent to a trend in electric use per employee if the amount of floorspace per employee is also changing. The National *In the Nome commercial sector, the price relevant for determining consumption levels is the unsubsidized price, since most commercial customers consume more than the 750 kWh/month limit present in the PCE program. om—1929 3.6 Academy of Sciences (1979) project an increase in non- residential floorspace per employee of 0.6% per year. This projected increase in floorspace per employee combined with Colt’s projected decrease in use per square foot produce our Mid case estimate of a 0.1% per year growth in use per employee. As a Low estimate for the use per employee trend, we assume that floorspace per employee grows at only 0.3% per year. Electric use per employee therefore declines at 0.2% per year in the Low case. For the High case use per employee trend, we utilize a forecast from the Edison Electric Institute (EEI), a trade association for the electric utility industry (forecast discussed in Oatman and Talbert, 1989, p.2). Some analysts claim EEI’s forecasts are consistently high (Ross and Williams, p.23). EEI projects use per square foot for commercial buildings to grow at 0.8% per year through 2000 and then remain constant from then on. The composite growth rate is 0.4% per year for the 1989 through 2014 period. Adding the 0.6% per year growth in floorspace per employee gives a use per employee growth of 1.0% per year for the High case. Table 3.8 summarizes the assumptions used in the commercial/other forecast. Figure 3.9 shows the resultant forecast of commercial/other kilowatt-hour sales, not including losses. Non-Mining Summary Net generation requirements ("net" means not including usage within the power plant) must also include transmission and distribution losses. The forecast summary tables in section 3.9 show the historical losses for 1981-89. We project future losses at 6.5%. a=—20 Table 3.8 - Assumptions for Commercial/Other Forecast. Low mia |___ign Indocr Low Mid | High Employment | Use per -0.5% per year -0.5% per 0.4% per Square Foot year year Floorspace 0.3% per 0.6% per 0.6% per per Employee year year year Use per -0.2% per 0.1% per 1.0% per Employee year year year Nome Commercial/Other Sales G o > = s x ¢ Ss € 53 1981 1986 1991 1996 2001 2006 2011 Year —® Historical —— Mid ST CON) =} High Figure 3.9 - Commercial/Other kWh Sales Forecast. Figure 3.10 shows the combined net generation requirements for residential and commercial/other loads, including losses. It is also necessary to forecast the peak generation requirement as well as the total requirement. Historical measurements of NJUS Shoes Le Non-Mining Net Generation a o = = = =< Cc 2 E 104 54 0 - 7 - - 1981 1986 1991 1996 2001 2006 2011 Year —® Historical —— Mid TT || ow Sa | ugh Figure 3.10 - Non-Mining Net Generation Requirements. peak requirements have been for the system load as a whole. No detailed analysis has been done divide the peak requirement by customer class. Because we forecasted non-mining (i.e. residential and commercial/other) and mining peak requirements separately, we needed to separate historical system peaks into non-mining and mining components. This separation was only required for the 1989 peak, when the WestGold Bima dredge contributed 1.3 MW to the system peak. Figure 3.11 shows the non-mining load factor for Nome from 1981-89. We project the future non-mining load factor to be 60%. The shape of the non-mining peak requirements forecast is similar to the net generation requirements forecast shown in the previous graph. The numeric detail of the forecast is provided in the forecast summary tables found in section 3.9. 3 - 32 Non-Mining Load Factor Nome 70% ; 60% ee a | 50% 4 40%4 30% 4 Load Factor 20% +4 1981 1982 1983 1984 1985 1986 1987 1988 1989 Year Figure 3.11 - Historical Load Factor for Nome Non-Mining Loads. Source: NJUS data adjusted for mining sales. 3.7 Mining Forecast 3.7.1 General Background A close examination of the Nome mining sector is important to the electrical load forecast because gold mining is very electricity intensive. Also, mining supports a significant fraction of the total Nome population and thus affects non- mining electricity use. Gold production in Nome over the past century has amounted to 4.6 million ounces, worth about $1.8 billion dollars at today’s prices. Figure 3.12 shows how the production has varied over the time period. Very high production levels were realized during the gold rush of the early 1900s. The other Senco Nome District Gold Production Thousands of Ounces / Year 0 — 1897 1907 1917 1927 1937 1947 1957 1967 1977 1987 Year Figure 3.12 - Historical Gold Production in the Nome District. Source: T.K. Bundtzen, Alaska Division of Geological and Geophysical Survey. significant feature of the graph is the tremendous variability of production levels. Mining in Nome was reactivated in the mid 70s after a period of very slow activity. Since then, gold prices and production have risen substantially, as shown by Figure 3.13. 3.7.2 Recent Mine Operators and Potential Future Operators Figure 3.14 shows who the major gold mining operators were during 1989. Alaska Gold Company has had the most operating history in the Nome area. They reopened their operation in 1975. They operate two onshore dredges that mine low-grade placer deposits, gold found in gravel along stream beds and beaches. Although their production in 1989 was 21,000 ounces, it has been as high as 27,000 ounces. Alaska Gold Company has 3 - 34 US Wholesale Gold Price Inflation-Adjusted $800+ _ $700/ $600+ $5004 4 $400 Vi ea $300+ A oe 8.5% / year 7 Price, 1989 $/troy oz. $200 ere 011 o-— a - : - - - 7 1971 1973 1975 1977 1979 1981 1983 1985 1987 Year Figure 3.13 - US Wholesale Gold Prices. Source: Metal Stat, Handy & Harman. Inflation-adjusted by the US Producer Price Index. very large reserves in the Nome area, which should last through the period of this forecast. Production costs are in the $300 - $350 per ounce range (not counting fixed costs), whereas current gold prices are $390 per ounce. While their financial statements do not look encouraging because of large debts to their parent corporation, variable production costs are low enough that continued operation is likely if gold prices remain above $350 per ounce. Electrical power is required for their two dredges and associated water pumps. Accurate power requirements data was available for 1989, indicating consumption of about 450 kWh per ounce of gold produced. Because they only mine from mid- June through mid-November (a 160 day season is typical), their annual load factor is low, approximately 29% for a typical 3) 135) Nome District Gold Production 1989 Windfall Mining 5,450 oz. Alaska Gold Company 21,000 oz. WestGold, Bima 30,660 oz. Figure 3.14 - Gold Operators in the Nome District, 1989. Source: Bundtzen, et al. (1990). season. However, while they are mining consumption remains relatively constant for 24 hours per day, except for equipment down-time periods. The Alaska Gold Company has historically produced their own power, except for minor wintertime needs. They have a power plant in the city of Nome and deliver power to their dredges outside of town via their own distribution system. However, as we discuss in section 3.7.4, we believe it is likely that NJUS will supply the majority of the Gold Company’s needs starting in 1991. Western Gold Exploration and Mining began operating their very large Bima offshore dredge in 1986. After a major mechanical failure in September of 1990, they announced that they would 3 = 36 cease operations in Nome and sell the Bima. They have stated that operation of the Bima has not been profitable. The Bima was expected to produce 50,000 ounces per year of gold from its Nome operations. However, mechanical difficulties and poor weather kept its maximum take to 36,700 ounces in 1987. Power requirements are substantial. Very approximate estimates indicate that power use while mining offshore during the summer amount to 240 kWh per ounce of gold mined. In addition, the dredge docked during the winters at the Nome causeway. For protection, snow was made and bermed around the dredge. Snow-making power use and on-board wintertime requirements amounted to about 80 kWh per ounce mined. Had levels of gold production closer to design levels been achieved, the fixed wintertime use would have amounted to about 60 kWh per ounce mined. The annual load factor of this wintertime use is about 22%. For the 88-89 winter and the 89-90 winter, the Bima purchased its wintertime power requirements while docked at the causeway from NJUS. While offshore, power was generated by on-board diesel generators with efficiencies of approximately 12 kWh/gallon. Offshore tin dredges in Indonesia are fed by submarine cables from onshore power plants, and there is speculation that a similar arrangement could be used in Nome if more offshore mining occurs. Windfall Mining operated in the Nome area for about 5 years ending in 1989. In 1989, they produced only 55% of what they projected for the year, and the operation shut down. Although the 1989 take was 5,450 ounces, past production peaked at about 13,000 ounces in 1987. Windfall has onsite generation, but began purchasing a portion of their needs from NJUS in 1988. No estimates were available + = 37 for their total power production needs. However, they process the same kind of material as the Alaska Gold Company, and we expect that their energy requirements are similar per ounce of gold produced. Windfall only mined during the summer season. Of the other 2,390 ounces of gold produced in 1989 in the Nome District, a significant portion was from Anvil Mining Company. The mine is still operative at the time of this report. Although they have onsite generation, they began purchasing all of their power requirements from NJUS in 1988. An approximate estimate of their power requirements is 200 kWh per ounce produced. There are a number of potential future mining operations in the Nome area. Cyprus Mining currently has employees in Nome that are investigating a strip mining operation that would utilize an electric dragline. Production estimates are 20 - 40,000 ounces of gold per year. Company officials give the operation a 50-50 chance of opening during the 1991 season.*° Power requirements estimates were very uncertain but calculated out to about 350 kWh per ounce mined. One design is based on a year-round operation that would involve stripping during the winter to avoid problems with mud, and the design would involve processing material during the summer. An alternative design utilizes a summer-only operation. The company has indicated that they would probably buy power. from NJUS, as they thought the prices were reasonable. The cost of interconnection would be very small, about $5,000, because the operation would be located near an existing transmission line to the Nome Beltz school. personal communication with Jay at Cyprus Mining in Nome, October 10, 1990. aes oS Aspen Exploration in partnership with Tenneco Minerals and other entities is conducting a lode gold exploration procran in the Rock Creek and Anvil Creek area near Nome. Reserves have been identified amounting to about 500,000 ounces of gold. If the project comes to fruition, it would be located about 8 miles north of Nome and could start as early as 1994.** The open pit mine would probably produce 50,000 ounces per year for 10 years.** TT. K. Bundtzen, Division of Geological & Geophysical Surveys, puts the probability of this mine operating at more than 10% but less than 50%. Estimates for power requirements are about 360 kWh per ounce of gold produced with a very high load factor of 80% because of year-round production. The companies have indicated a willingness to buy power from the city, citing a reasonable price and elimination of a large fuel storage system as reasons. Serving the mine from the NJUS system would require the construction of 5 miles of transmission line at a cost of $50,000 per mile.** The levelized cost (constant 1989 $) for transmission of the power calculates to about 0.8 cents/kWh.** However, the transmission of electrical power eliminates the need to transport fuel from Nome to the mine site for power generation. Fuel transport costs for onsite generation would be at least 15 cents/gallon, amounting to 1 “Personal communication with William Newlin, Tenneco Minerals, October 9, 1990. #2Personal communication with T. K. Bundtzen, Division of Geological and Geophysical Survey, October 11, 1990. Personal communication with Joe Murphy, Nome Joint Utilities System, September 27, 1990. #*§250,000 capital cost, 10 year life, 4.5% real interest rate, operation and maintenance of line at 1.5% of capital cost per year, 6.5% losses on generated power costs of 8.5 cents/kWh, and annual transmission of 18 million kWh. a | ao cent/kWh. There would be no substantial uses for the waste heat from onsite generation. Other potential mining operations in the Nome area include Coastal Hills and Coastal Plains where Aspen Exploration is currently doing exploration work. The project is more speculative than the Rock Creek project and we did not obtain production estimates. The Big Hurrah lode gold mine is another potential project about 40 miles from Nome. fT. K. Bundtzen puts the probability of production at a higher level than the Rock Creek project. Production would be 30-40,000 ounces per year, and power requirements would be similar to the Rock Creek project, 360 kWh/ounce. Because of the distance, transmission costs would be higher, about 3 cents/kWh. 3.7.3 Low, Mid, and High Mining Assumptions, and Forecast Summary For the Mid mining case, we assume that onshore gold production will consist primarily of Alaska Gold Company and some small other summertime producers, totalling 25,000 ounces per year. We assume that power requirements will be approximately 450 kWh/ounce with a 29% annual load factor. In addition, we assume that a smaller offshore dredge will begin mining in 1995 producing 17,000 ounces per year. T. K. Bundtzen indicates that the experience with Bima indicated that the appropriate size for an offshore dredge is a dredge much smaller than the Bima. He thinks it is likely that one will begin operation in the not too distant future. We only include the wintertime (off-season) power requirements in the load forecast, and we estimate these to be 60 kWh per ounce of gold mined with an annual load factor of 22%. Thus, the effect on the load forecast is small relative to the onshore operations. 3 - 40 For the Low forecast, we assume that production from summertime onshore operations declines to 12,000 ounces per year by 1992. This case is consistent with the shutdown of one of the Alaska Gold Company dredges, as occurred during 1985 and 1986. We assumed no offshore production in this scenario. For the High forecast, we assume that onshore summertime production increases from 25,000 ounces per year to 32,000 ounces per year by 1992. Also, we assume that the Cyprus strip mining operation begins in 1992 at a production level of 30,000 ounces per year. We assume that it is a year-round operation that uses 380 kWh per ounce produced, and the load factor is 80%.** We assume that 2 small offshore dredges are in service by 1993 producing 34,000 ounces of gold per year, with per ounce power requirements as in the mid case.** Table 3.9 summarizes the assumptions used in the mining forecast. Figure 3.15 shows the mining production forecast for the Low, Mid, and High cases. Figure 3.16 shows the mining net generation forecast results. 6.5% losses were assumed to calculate net generation requirements. To convert these mining production forecasts into mining employment forecasts for use in the population/employment modeling, we assumed that each 1,000 ounces per year of onshore gold production requires 2.6 annual average employees, and each 1,000 ounces per year of offshore gold production requires 1.4 annual average employees. These employment *SBecause of the uncertainty of the Cyprus power requirements estimate, 350 kWh/ounce, we use an estimate closer to the Alaska Gold Company electricity intensity, because the AK Gold Company figure is substantially more certain. sy, K. Bundtzen states that 100,000 ounces per year of offshore gold is conceivable. a7 &e Table 3.9 - Assumptions for the Mining Forecast by Case Assumption —— Onshore, Summertime Gold Mining 31% load factor. Low Mid High Rise from 25,000 Decline to 12,000 25,000 ounces/yr, | ounces/yr to 32,000 ounces/yr by 1992. 450 kWh/ounce, ounces/yr by 1992, 450 kWh/ounce, 31% load factor. 450 kWh/ounce, 31% load factor. | Cyprus starts in 1992 at 30,000 Year-Round ounces/yr, 350 Gold Mining kWh/ounce, 80% | ! | load factor. 17,000 ounce/yr Two dredges by dredge begins 1993, 34,000 Offshore operation in 1995. ounces/yr, 60 Gold Mining 60 kWh/ounce kWh/ounce, 22% onshore use, 22% load factor. | | load factor. ratios were derived from data for the Alaska Gold Company and the WestGold Bima operations. Onshore, None None None 3.7.4 Likelihood of NJUS Supplying Mining Loads load forecasting effort addresses loads that have economical access to the present NJUS transmission and distribution system. To determine whether these loads will actually be served by the NJUS generation system requires an examination of the relative costs of on-site generation versus NJUS generation. In this section we address the relative cost of onsite generation versus NJUS diesel-fired generation. We do not address the relative cost of on-site generation with alternative forms of NJUS generation, such as coal. However, use of any alternative form of NJUS generation that is more cost-effective than diesel generation will increase the This 3 = 42 Nome Gold Forecast Thousands of Ounces / Year 40+ 3 » 20} ee 104 0 - : - — 1981 1986 1991 1996 2001 2006 2011 Year —#— Historical —— Mid — Low —— High Figure 3.15 - Gold Mining Production Forecast likelihood of loads being served from the NJUS system. For small commercial and residential users, the economies of scale inherent in NJUS generation and the presence of the Power Cost Equalization subsidy clearly tilt the economics in favor of purchase from NJUS instead of on-site generation. There are no significant instances of onsite generation for small users that have access to the NJUS grid. For larger users, the economics of on-site generation improve. Historically, the mining operations in the Nome area have produced their own power. The Alaska Gold Company, the oldest mining operation in the Nome area, has always supplied their own power, except office and shop needs during the winter when mining is not occurring. Mine operators indicate that NJUS has never had the generation capacity to supply the mine’s 3. - 43 Mining Net Generation million kKWh/year as 0 - - aa 1981 1986 1991 1996 2001 2006 2011 Year —® Historical —— Mid aaa EOW: ao egh Figure 3.16 - Mining Net Generation Forecast needs. For example, Alaska Gold Company power demands peak at 4.5 MW, and the city of Nome’s needs peaked at 2.7 MW in 1977. This situation has recently changed. During the 1980s the non-mining loads in Nome grew because of the boom in the overall Alaskan economy. Non-mining loads now peak at about 4.2 MW, comparable to the mining loads in the area. Further, the new NJUS general manager, Mr. Joe Murphy, has aggressively pursued the acquisition of the mining loads since he began his position in 1988. NJUS has offered interruptible power purchase contracts to the mining operations at a rate less than average cost but still in excess of the NJUS incremental generation cost. The NJUS board has accepted this pricing policy because of its benefits for the other customers on the system. 3 - 44 Windfall Mining and Anvil Mining began purchasing NJUS power in 1988. The WestGold offshore dredge, the Bima, started buying NJUS power while docked at the Nome causeway during the 1988-89 winter season. The Bima peak demand was 1.3 MW and the dredge used about 2.7 million kWh during the winter of 1989-90. Power was sold to the Bima for 12.5 cents/kWh for the first 100,000 kWh/month, 11.9 cents/kWh for the next 100,000 kWh/month, and 10.9 cents/kWh for any additional use. The standard three-phase commercial rate in effect at the time was 12.5 cents/kWh plus a $10/kW/month demand charge. These actual power purchase decisions provide evidence that NJUS diesel generation is less expensive than on-site generation for a variety of situations. The Anvil and Windfall mining operations characterize small to medium size summertime mining operations. The WestGold Bima decision to buy power while docked at the Nome causeway is indicative of the wintertime power purchase decision of a large offshore gold mining dredge. The remaining existing load of substantial import that still self-generates is the Alaska Gold Company, a load with a 4.5 MW peak demand and an annual electricity use of about 10 million kWh. NJUS is currently negotiating with Alaska Gold to supply their total annual load (NJUS currently supplies their minimal winter load). NJUS believes a contract will be signed before the 1991 mining season. Mr. Joe Fisher, general manager of Alaska Gold, and Mr. Gary Butcher, power plant operator for Alaska Gold, also believe that a contract is likely. After examining the relative costs of generation, we concur that a contract is likely. The factors relevant to our conclusion are: + The fuel efficiency of NJUS generation is better than Alaska Gold generation. The Alaska Gold Company diesel generation has a fuel efficiency of about 13.1 kWh generated (net of station use) per gallon of fuel used. 1989 average generation efficiency for NJUS was 14.3 3 - 45 27, kWh/gallon. NJUS is currently in the process of installing a new 3.7 MW generator with a fuel efficiency at 75% load of 15.4 kWh/gallon. This unit will be base- loaded and much of its annual energy generation will be used by non-mining loads. However, the extra generation required to served mining loads will come from generators with efficiencies near 14.5 kWh/gallon. Differences in the fuel efficiency of NJUS generation and on-site generation may persist over the long-term because NJUS generation operates at higher annual capacity factors than mining generation. The extra capital cost of more efficient generation is more readily cost-justified for generation units with high utilization. NJUS has recently purchased and stored fuel at less cost than Alaska Gold. During 1989, the Alaska Gold Company paid 25 cents/gallon more for fuel than NJUS.*” NJUS benefits from cooperative fuel purchasing with other communities in western Alaska. The cooperative purchases approximately 6 million gallons of fuel annually (NJUS uses about 1.8 million gallons without the Alaska Gold load). The combined effect of better fuel efficiency and lower fuel prices currently gives NJUS approximately a 2.4 cent/kWh advantage over onsite generation. The seasonal load shapes of non-mining loads and mining loads are complementary. The onshore placer mining loads are present during the summer when non-mining loads are at a minimum. The NJUS generation that was needed to meet winter peaks is available to supply a portion of the summer mining loads. Serving this portion of the mining loads does not require an additional capital investment in generating capacity. In addition, the reserves necessary to back up the required generation are less on a large system than they are on an independent, on-site systen. Alaska Gold has had environmental problems with their fuel storage system that have caused examination by the EPA. _ Buying power from NJUS will greatly reduce their fuel storage needs and alleviate some of these problems. One typical advantage of self-generation is the reduction or elimination of transmission and distribution costs and losses. In the case of Alaska Gold, the dredges and water pumps that consume electricity are located outside of town, but the company’s power plant is located within town. Thus, self-generation still requires the *7Personal Communication with Mr. Joe Murphy, NJUS, September 1990. 3 - 46 transmission of power a significant distance from the power plant. If NJUS acquires the Alaska Gold load, they will simply connect to the existing Alaska Gold transmission facility, which passes directly by the NJUS Snake River power plant. Interconnection costs are minimal, and the transmission and distribution losses from the NJUS plant are similar to those from the Alaska Gold plant. - Another typical advantage of self-generation is the ability to inexpensively utilize the waste heat from generation on-site. For a self-generation situation in Nome where all of the water jacket waste heat can be utilized, the value of that heat is approximately 3 cents per kilowatt-hour produced. In the case of Alaska Gold, there are few uses for the waste heat during the summer when the bulk of the electrical consumption occurs. Thus, this advantage does not exist. + There appear to be economies of scale in the operation and maintenance of diesel generation equipment. The Alaska Gold Company employs approximately 8 power plant operators during the summer mining season. NJUS claims that they will only need to add 1 year-round employee if they acquire the Alaska Gold Company load. The net savings is about 1 cent/kWh. + NJUS has access to tax-free financing that private mining companies do not have access to. This lowers capital costs per kWh for NJUS generation relative to onsite generation. One of the largest factors acting against a power sales contract is the effect that the sale will have on Power Cost Equalization receipts. In Nome’s case, PCE will be calculated on the average cost of electricity for the utility. Because the incremental cost of generating the Alaska Gold Company load is less than the existing average cost, addition of the load will cause the utility’s average cost to drop. This drop will result in a drop in the PCE rate. We calculated the drop to be approximately 2 cents/kWh, and it will apply to the 9.8 million kWh currently subsidized by the PCE progran. To compensate for this loss of revenue, margins earned on sales to the Alaska Gold Company need to be at least 1.9 cents/kWh. Sar, It appears as though contract prices currently under discussion will provide at least this level of margin. 3.8 Combined Peak Generation Requirement for Non-Mining and Mining Loads Non-mining, onshore summertime mining, onshore year-round mining, and the winter power requirements of offshore mining have seasonal and hourly variations that are much different from each other. Thus, the total peak generation requirements for the Nome area cannot be calculated as the sum of the separate peak requirements. To calculate the Nome-area coincident peak generation requirement, we used the following technique. First, Table 3.10 was developed, which gives monthly peak generation requirements for each load component. Using the non- mining load component as an example, the 100% indicates that the non-mining loads typically peak during January. The 71% for July indicates that the July peak for the non-mining loads is 71% of the annual peak. Given an annual peak requirements estimate for non- mining, multiplying by the appropriate figure in the table gives an estimate of the peak requirement for a particular month. The table was derived from 1988-89 monthly data from NJUS for non-mining loads, from knowledge of the mining season for onshore mining loads, and from WestGold billing history for the shore-component of the offshore mining loads. We next assumed total coincidence among the monthly peaks for each load component. For example, if the non-mining peak requirement in July is 5.0 MW, the onshore mining peak is 4.0 in July, and the offshore load is 0 MW in July, we assumed that the total coincident peak in July is 5.0 + 4.0 = 9.0 MW. This assumption implies that the peak load for each individual component occurs at the same time during the month. While this obviously is not exactly correct, it suffices given the overall accuracy of this forecasting effort. 3 - 48 Table 3.10 - Relative Monthly Peak Demands Off-shore Non- Month Mining Mining JAN 0.0% 100.0% 100.0% 100.0% | FEB 0.0% 100.0% 100.0% 98.0% MAR 0.0% 100.0% 50.0% 91.8% APR 0.0% 100.0% 50.0% 85.5% MAY 0.0% 100.0% 50.0% 79.3% JUN 100.0% 100.0% 0.0% 73.0% JUL 100.0% 100.0% 0.0% 71.0% AUG 100.0% 100.0% 0.0% 73.0% SEP 100.0% 100.0% 0.0% 79.3% oct 100.0% 100.0% 0.0% 85.5% NOV 100.0% 100.0% 0.0% 91.8% DEC 100.0% | __100.0% 98.0% The hourly load variation for the non-mining loads is very constant during the daytime. Also, the mining loads tend to be quite constant when the dredging or snow-making equipment is running. The more constant the loads are, the higher the probability that peak loads will be coincident. Once total Nome-area peak requirements are calculated for each month, the annual peak requirement is simply the maximum of the monthly requirements. This technique was used for each of the years in the analysis. 3.9 Forecast Summary The tables and figures in this section summarize the results of the forecast. Figure 3.17 shows the total net generation a = 49 requirements for the non-mining and mining loads combined. The associated peak generation requirements are shown in Figure 3.18. The area chart, Figure 3.19, shows how the net generation requirements in the Mid case divide between residential, commercial/other, and mining uses. Annual average growth rates of total net generation requirements and peak generation requirements for the period 1980 through 2014 are shown in Table 3.11. Finally, Table 3.12 through Table 3.17 give the numeric detail of the forecast. There are two tables for each case--Mid, Low, and High. The first table gives the results for the residential and commercial/other forecasts for that case. The second table gives the results for the mining load forecast and gives the non-mining and mining totals. The bottom row of the table gives the annual average growth rate for the period 1989 through 2014 for each variable in the forecast. Total Net Generation Mid Case 9 er 1 SS SS SS “ — — = A 1 KS Residential HE Commercial/Other Ky Mining gur: equi Mi ab wth Ra ‘otal quirements an €s Non-Mining Forecast Case: Mid (Commerical, Commun. Facil., and Street Lighting Use per = Total Indoor Employee — Sales Employees kWh MWh Residential No fining Totals Use per Total People/ Custome Sales Cust kWh | MWh T&D TaD Net Load Peak Losses Losses General. Factor Generat. % MWh MWh % MW Popul. Customers 922 3.0 5.463 5,037 3,071 1,060 2.90 5.588 $92 3,102 1,244 2.49 5.366 = 6.676 3,146 1,294 2.43 5459 7,065 3,236 1,290 2.51 5,394 6.987 3,208 1,280 2.51 5.640 = 7,219 3,306 1,331 2.48 5844 (7,778 3,403 1,344 2.53 6.015 8,084 349 1,365 2.56 5.812 7,934 3,544 1,386 2.56 S801 ROLL 3,530 1,384 2.55 5,789 BOIL 3,515 1,382 2.54 5.778 7,982 3,535 1,393 2.54 5,766 8031 3,578 144 2.53 5755S BM 3,696 1,464 2.53 5,743 (8,406 3,811 1,513 2.52 5.732 W671 3.910 1,556 251 5,720 8.901 3,999 1,596 251 5,709 9,109 4,081 1,632 2.50 5697 9.301 4,164 1.670 249 5.686 = 9,495 4.210 1,693 2.49 5674 9.604 4,262 1,718 2.48 5,663 9,727 4,320 1,745 2.48 5,652 9,865 4,392 1,779 247 S641 10,035 4,479 1,819 2.46 5,629 10,239 4,593 1,870 2.46 5.618 — 10,504 4,716 1,925 245 5,607 10,790 4816 1,983 2.44 5.596 11,094 4945 2.024 2.44 S584 11,303 5,009 2.060 243 5,573 11,478 5,102 2,103 2.43 5,562 11,698 5,197 2,148 2.42 SSSt 11,922 5,294 2.193 241 5,540 5,393 2,240 241 5,529 1989 - 2014 Annual Average Growth Rates: 1.7% 2.0% 0.25% —-0.20% 1AM 1.1% 0.1% 1.2%. 0.1% 1.3% 14% 0.2% 1.6% 1,123 8338 9.464 1,190 8298 = 9,997 1,252 8.493 10.630 1.258 8922 11,222 1.254 9454 11.851 1,297 10,002 12,969 1,204 10,554 12,703 1,265 9,673 12,238 1,328 10,326 13,715 1,309 10.3% 13.530 1,310 10,346 13.556 1,286 10,357 13,323 1.291 10,367 13.386 1.206 10,377 13,549 1340 10,388 = 13,924 1,378 10,398 14,323 1.407 10,409 14.641 14a 10.419 14,911 1.453 10,429 15,150 1,475 10,440 15.394 1465 "10,450 15,305 1,472 10461 15,396 1,483 10,471 15,527 1,504 10,482 15,765 1,530 10.492 16,053 1,564 10,503 16,429 1,601 10,512 16,835 1641 10,524 17.270 1,659 10,534 17.472 1,662 10,545 17,521 1,6R2 10,555 17.750 1,702 10,566 17,981 1,722 10,576 18,215 1,743 10,587 18.453 8.2% 15.687 56.3% 18% 1,M7 17,266 = $6.3% 3.50 6.1% 1,124 18,430 = 58.4% 3.60 6.8% 1344 19,621 58.9% 3.80 13.1% = 2,833 21.642 61.7% 4.00 8.2% 1,791 21,979 64.3% 3.90 5.8% 1,259 21,740 61.2% 4.05 11% 1,544 21,866 = 54.7% 4.56 6.6% 1,540 23,189 63.0% 4.20 6.5% 1,499 23,070 = 60.0% 4.39 6.5% 1,498 23,066 = 6.0% 439 6.5% 1,480 22,78 = 60.0% 4.33 6.5% 1,488 22,905 = 60.0% 435 6.5% 1,507 23,190 60.0% 441 6.5% 1,552 23,882 60.0% 454 6.5% 1,598 24,592 60.0% 4.68 6.5% 1,6%6 25,178 60.0% 4.79 6.5% 1,669 25,689 = 60.0% 4.88 6.5% 1,699 26,150 60.0% 4.97 6.5% 1,729 26,619 60.0% 5.06 6.5% 1,731 26,640 60.0% 5.07 6.5% 1,746 26,868 60.0% SAL 6.5% 1,764 27,155 60.0% 5.16 6.5% 1,793 27,593 60.0% 5.25 6.5% 1,827 28119 = 60.0% 5.38 6.5% 1,871 28.803 60.0% 5.48 6.5% 1,919 29,545 60.0% 5.62 6.5% 1,971 034 600% 5.77 6.5% 1,999 3.715 600% 5.85 6.5% 2,015 31,014 §=600% 5.90 6.5% 2,046 31,494 = 60.0% 5.99 6.5% 2,078 31,980 600% 6.08 6.5% 2,110 32,475 60.0% 6.17 6.5% 2,142 32,978 «0.0% 6.27 1997 1998 1999 2000 2001 2002 2003 2004 2005 aome-OoRrv om speoyT HuUTUTH-UON ‘SQTNSeY ASeostOy eseD PTR - ZT°C eTqeL vs Mining Forecast and Totals Case: Mid B » Onshore Gold, Summer Only Onshore Gold, Year-Round Offshore Gold, Shore Elect. Req't Mining Total Aining + Non-Mining © Total Gold Total Net Peak Gold Total Net Peak Gold Onshore — Net Peak Net Peak Net Peak i Mined Use Generat. Generat.| Mincd Use Generat. Generat.| Mined Use — Generat. Gienerat.J Generat. Generat.{ Generat. Generat iS Year | 00002 = MWh_ MWh MW_| 00002 MWh MWh MW_| 00007 MWh MWh Mw_ | MWh MW MWh MW_ ' 1 1981 16.6 7,470 7,989 3.14 00 0 0 0.00 00 0 0 0.00 7,989 3.4 23,676 6.06 re S 1982 18.5 8,325 8,904, 3.50 00 0 0 0.00 0.0 0 0 0.00 8,904 3.50 26,170 6.72 be T 1983 20.5 9,225 9,866 3.88 0.0 0 0 0.00 0.0 0 0 0.00 9,866 3.88 28,296 19 Qa O 1984 21.5 9,675 10,8 4.07 00 0 0 0.00 0.0 0 0 0.00 10,348 4.07 29,969 7.56 R_ 1985 22.4 10,080 = 10,781 4.24 00 0 0 0.00 00 0 0 0.00 10,781 424 32,422 TA i 1 1986 25.7 11,565 = 12,369 4.87 00 0 0 0.00 30 0 0 0.00 12,369 487 HB 8.45 © C 1987 39.1 17,595 18,818 7.40 00 0 0 0.00 M7 2,350 2,513 141 21,332 7.40 43,072 1.12 A 1988 30.5 13,725 14,679 5.77 00 0 0 0.00 35.5 2,350 141 17,193 5.71 39,058 9% is} 1. 19897 288 12,960 13,861 5.45 00 0 0 0.00 307 2,337 141 16,360 5.45 39,549 931 8 1990} 25.0 11,250 12,032 4.73 00 0 0 0.00 24.1 2,373 141 14,570 4.73 37,640 8.76 0 1991 25.0 11,250 12,032 4.73 00 0 0 0.00 0.0 0 0 0.00 12,032 4.73 35,098 8.76 8 1992 25.0 11,250 12,032 473 00 0 0 0.00 00 0 0 0.00 12,032 4.13 34,818 871 vn 1993 25.0 11,250 12,032 473 00 0 0 0.00 00 0 0 0.00 12,032 473 4,937 8.73 ag 1994 25.0 11,250 12,032 473 00 0 0 0.00 00 0 0 0.00 12,032 473 35,222 8.78 Pe) 1995 25.0 11,250 12,032 473 00 0 0 0.00 17.0 1,020 1,091 0.57 13,123 4.73 37,005 a oO 199%} 25.0 11,250 12,032 4.73 00 0 0 0.00 170 1,020 1,091 0.57 13,123 4.73 37,715 9.03 Yu P 1997 250 11,250 12.032 4.73 00 0 0 0.00 170 1.020 1.091 0.57 13,123 4.73 38,301 9.13 any R 1998 25.0 11,250 12,032 473 00 0 0 0.00 17.0 1,020 1,091 0.57 13,123 4.73 38,812 922 ios oO 199 25.0 11,250 12,032 4.73 00 0 0 0.00 17.0 1,020 1,091 0.57 13,123 4.73 39,273 9.30 u J 2000F 25.0 11,250 12,032 473 00 0 0 0.00 17.0 1,020 1,091 0.57 13,123 4.73 39,742 9.38 FE 2001 25.0 11,250 12,032 473 00 0 0 0.0 170 1,020 1,091 0.57 13,123 473 39,763 938 x C 2002 250 11,250 12,032 4.73 00 0 0 0.00 170 1,020 1,091 0.57 13,123 4.73 39.991 942 5 T 2003 25.0 11,250 12,032 473 00 0 0 0.00 170 1,020 1,091 0.57 13,123 4.73 40,278 947 | oa E2004 250 11.250 12,032 473 00 0 0 0.00 17.0 1,020 1,091 0.57 13,123 4.73 40,716 9.55 3 D 2005 250 11,250 12,032 473 00 0 0 0.00 17.0 1.020 1,091 0.57 13,123 4.73 41,242 964 2006 25.0 11,250 12,032 473 00 0 0 0.00 17.0 1.020 1,091 0.57 13,123 4.73 41,926 976 D 2007 25.0 11,250 12,032 4.13 00 0 0 0.00 170 1,020 1,091 0.57 13,123 473 42,668 9.89 o 2008 25.0 11,250 12,032 4.73 00 0 0 0.00 170 1,020 1,091 0.57 13,123 4.73 43,457 1003 Q 2000 250 11,250 = 12,032 4.73 00 0 0 0.00 170 1,020 101 0.57 13,123 4.73 43,898 1010 a 2010 25.0 11,250 12,032 4.74 00 0 0 0.00 170 1,020 1,091 0.57 13,123 4.73 44,137 1015 2011 25.0 11,250 12,032 4.73 00 0 0 0.0 17.0 1,020 1,091 0.57 13,123 4.73 44,617 10.23 5 2012 250 11,250 = 12,032 473 0.0 0 0 0.00 170 1,020 1,091 0.57 13,123 473 45,103 1031 a. 2013 25.0 11,250 = 12,032 4.73 00 0 0 oo 170 1.020 1,091 0.57 13,123 473 45,598 10.40 | 2014 25.0 11,250 12,032 4.73 00 0 0 0.00 17.0 1,020 1,091 0.57 13,123 4.73 46,101 1049 — ° 1989 - 2014 Annual Average Growth Rates: o 0.6% 06% 0.6% 06% 2.3% -3.3% a 36% -09% 06% 06% 05% Fi Ss Non-Mining Forecast Case: Low Residential Commerical, Commun. Facil. and Street Lighting Use per — Total Employee Sales kWh MWh Non-Mining Totals Use per Total People/ Custome Sales Customers Cust kWh = MWh T&D T&D Net Load Peak Losses Losses Generat. Factor Generat % MWh MWh % MW 3,039 922 3% 5463 = §,037 3,071 1,060 2.90 5588 = §,923 3,102 1,244 2.49 5.66 6,616 3,146 1,294 243 5,459 7,065 3.2% 1,290 2.51 5,394 6,987 3,208 1,280 2.51 5.640 7,219 3,306 1,331 2.48 S844 7,778 3,403 1444 2.53 6.015 8.084 3499 1,%5 2.56 S812 7,994 3,540 1,384 2.56 5.786 BOIL 3,427 1,344 2.55 5,760 (7,741 3,364 1,322 2.54 S734 7,582 3,403 1341 2.54 5,709 7,654 3473 1,372 2.53 5.683 7,797 3,559 1,409 2.53 5.657 = 7,973 3,616 1,436 2.52 5,632 8.085 3,662 1,458 251 5,606 = 8,172 3,725 1,486 2.51 S581 8.296 3,793 1,517 2.50 5,556 8,431 3,882 1,557 2.49 5.S31 8,610 3,935 1,582 249 5.506 8711 3,994 1,610 2.48 5.481 8,823 4,059 1,640 2.48 5457 8,948 41M 1,674 2.47 $432 9,096 4,208 1,709 2.46 5408 = 9,240 4,286 1,745 2.46 5.383 9,399 4,368 1,783 2.45 5,359 9,554 4,446 1,819 244 5.335 9,704 4,517 1,852 244 5.311 9,839 4,589 1,887 2.43 5.287 = 9,975 4.666 1,923 2.43 5,263 10,123 4,745 1,961 2.42 $240 10,273 4.825 1,999 241 5,216 4,906 2,037 241 5,193 1989 - 2014 Annual Average Growth Rates: 14% 1.6% 0.25% 045% 12% 0.6% 0.2% 04% 0.1% 0.6% 0.71% 0.2% 09% 1997 1998 2001 Saaameoret W-UON ‘SQTNSeY ASedeAOT BSED MOT - FI-E STqeL TUT speoy bu Mining Forecast and Totals a Case: Low z Onshore Gold, Summer Only Onshore Gold, Year-Round Offshore Gold, Shore Elect. Req't Mining Total Mining + Non-Mining re Total Gold Total Net Peak Gold ‘Total Net Peak Gold Onshore Net Peak Net Peak Net Peak & Mined Use Generat. Generat.| Mined Use Gienerat. Generat.| Minced Use — Generat. Generat.J Generat. Generat.J Generat. Generat. 1 Year | ,0000z_ = MWh MWh MW_| 00007 MWh MWh MW_| 00 oz MWh = MWh_ = sMW_ MWh MW MWh MW 166 7,470 7,989 344 00 0 0 0.00 00 0 0 0.00 7,989 3.4 23.676 6.06 8 18.5 8,325 8,904 3.50 0.0 0 0 0.00 00 0 0 0.00 8,904 3.50 26,170 6.72 20.5 9.225 9,866 3.88 0.0 0 0 0.00 0.0 0 0 0.00 9.866 3.88 28,296 V9 2 21.5 9.675 10,348 4.07 00 0 9 0.00 00 0 0 0.00 10,348 4.07 29,%9 7.56 un 224 10.080 = 10,781 424 oo 0 0 0.00 00 0 0 0.00 10,781 4.24 32,422 7 o 25.7 11,565 12,369 487 00 0 0 0.00 a0 0 0 0.00 12,369 4.87 HMB RAS *y 39.1 17,595 18,818 7.40 00 0 0 0.00 %.7 2.350 2.513 141 21,392 7.40 43,072 be 02 oO W.5 13,725 14,679 Sa 00 0 0 0.00 35.5 2,350 2.513 141 17,193 S07 39,058 9% a 28.8 12,960 13,861 5.45 00 0 0 0.00 30.7 2,337 2.499 141 16,360 5.45 39,549 931 a 25.0 11,250 12,032 4.73 00 0 0 0.00 24.1 2.373 2,538 141 14,570 4.73 37,526 8.74 p 1991 25.0 11,250 12,032 4.73 00 0 0 0.00 00 0 0 0.00 12,032 473 33,805 8.53 a 1992 12.0 5,400 5,715 2.27 00 0 0 0.00 00 0 0 0.00 atts 2.27 27,148 6.00 1993 12.0 5,400 5,775 2.27 0.0 0 0 0.00 0.0 0 0 0.00 5,715 2.27 27,660 6.09 w 19947 120 5400 = 5,775 2.21 00 0 0 0.00 0.0 0 0 0.00 5,775 2.27 28,098 6.17 8 1995} 120 5,400 $5,775 2.27 00 0 0 0.00 0.0 0 0 0.00 5,775 2.21 28,534 6.24 c 1996 120 5,400 $,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 28,694 6.27 rf P 19977 120 5400 5,775 2.27 0.0 0 0 0.00 00 0 0 0.00 5,775 2.27 28,759 6.28 un R 198F 120 5400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 $,775 221 29,084 6M = O 199] 120 5400 $775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 29,389 6 4 J 2000 120 5,400 5.775 2.27 0.0 0 0 0.00 00 0 0 0.00 5,775 2.27 29,837 647 pte E2001 120 5,400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 29,868 6.48 ms C 2002 120 5,400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 30,081 6.51 y T 2003 12.0 5,400 $,7715 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 W337 6.56 aQ E 2004 120 5,400 $,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 227 W701 662 D 2005 12.0 5,400 5.775 2.21 00 0 0 0.00 00 0 0 0.00 5,775 227 0,969 6.67 o 2006 120 5,400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 31,308 6.73 » 2007 120 5.400 5.715 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 31,655 6.79 2008 12.0 5.400 $5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 31,910 6.43 2009 120 5,400 5.775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 32,085 6.86 5 2010 12.0 5,400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 f 32,316 6%» a 2011 12.0 5.400 5,775 2.27 0.0 0 0 0.00 0.0 0 0 000 5,775 2.27 32,580 695 2012 120 5.400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 32,847 700 3 2013 120 5.400 5,775 2.27 00 0 0 0.00 oo. 0 0 0.00 5,775 2.27 33,017 704 cr 2014 12.0 5,400 5,775 2.27 00 0 0 0.00 00 0 0 0.00 5,775 2.27 33,390 7m ee 1989 - 2014 Annual Average Growth Rates: un “34% — -34% _—-3AM_ 3AM 100.0% -1000% -100.0% -1000% -4.1% -34% 0.7% AL Zs Non-Mining Forecast Case: High (Commerical, Commun. Facil., and Street Lighting Use per = Total Indoor Employee Sales kWh MWh Residential Non-Mining Totals Use per Total People/ Custome Customers Cust kWh T&D T&D Net Load Peak Losses Losses Gencrat. Factor Generat _% MWh MWh % MW f_Popul. 3,039 922 3.30 5,463 5,037 3,071 1,060 2.90 S$88 = §,923 3,102 1,244 2.49 5,366 = 6,676 3,146 1,294 243 5,459 7,065 3,236 1,290 2.51 5,394 6,957 3,208 1,280 251 5,640 7.219 3,306 1,331 2.48 5.844 7,778 1,344 2.53 6.015 8,084 1,365 2.56 S812 7,934 3.629 1419 2.56 5.822 8,262 3,640 1,427 2.55 S831 8,322 3,193 1,491 2.54 5,840 8,706 3,913 1,542 2.54 5.850 9,018 3,966 1,567 2.53 5.859 = 9,179 4,000 1,584 2.53 5,868 9,295 4,028 1,599 2.52 5,878 9,400 4,059 1,615 251 587 9,511 4,090 1,632 251 5,897 = - 9,622 4,317 1,727 2.50 5,906 10,198 4,466 1,791 2.49 5,916 10,595 4,570 1,837 2.49 5,925 10,884 4634 1,868 2.48 5,935 11,084 4,703 1,900 2.48 5,944 11,293 4,813 1,949 247 5.954 11,605 4,940 2,006 2.46 5,963 11,961 5,097 2,075 2.46 $973 12,392 $272 2,152 2.45 5,982 12,871 5,461 2,294 244 5,992 13,387 5.581 2,289 244 6.001 = 13,738 5,670 2,331 2.43 6011 = 14,014 5,807 2,94 243 6021 14411 5,947 2,458 2.42 6,030 = 14,820 2,823 241 6,040 15,240 2,591 241 6049 15,672 1989 - 2014 Annual Average Growth Rates: 2.3% 26% 0.25% 0.16% 28% 1.7% 1.0% 28% -0.1% 2.1% 2.1% 0.2% 2.9% 8.338 ie 1,190 8.398 9.997 1.252 8,493 10.630 1,258 8,922 11,222 1,254 9,454 11,851 1,297 10,002 12,969 1,204 10,554 12,703 1,265 9,673 12.238 1,328 10,326 13,715 1,368 10,429 14.269 1,372 10,533 14,452 1,385 10,638) = 14,733 1.409 10,745 15,142 1,413 10,852 15,336 1,406 10,961 = 15.407 1,400 11,070 = 15,502 1,407 11,181 15,733 1,414 11,293 15,967 1,491 11,406 17.002 1,537 11,520 17,709 1,565 11,635 18,207 1,569 11,752 18,441 1,583 11,869 18,785 1,621 11,988 =—19.438 1,661 12,108 = 20,112 1,714 12,229 20.960 1,774 12,351 21.909 1,839 12,474 22,939 1,869 12,599 23.547 1,883 12,725 23.957 1,921 12,852 24,692 1,960 12,981 25.449 2,001 13,11) 26.230 2,042 13,242 27,035 82% 18% 1,347 17,266 = 56.3% 3.50 6.1% 1,124 18.430 = SRAM 3.60 62% 1334 19,621 58.9% 3.80 13.1% = 2,833 21,642 61.7% 4.00 8.2% 1,791 21,979 64.3% 3.90 58% 1,259 21,740 = 61.2% 4.05 1% 1,544 21,866 = 54.7% 4.56 6.6% 1,540 23,189 63.0% 4.20 6.5% 1,566 24.097 = 60.0% 4.58 6.5% 1,582 24.356 00% 463 6.5% 1,629 25,068 60.0% 4.717 6.5% 1,679 25,839 60.0% 491 6.5% 1,703 26,219 = 60.0% 4.98 6.5% 1,716 2419 = 60.0% 5.02 6.5% 1,730 26,632 600% 5.06 6.5% 1,754 698 60% 5.13 6.5% 1,778 27,%7 = 0.0% 5.20 6.5% 1,890 29.090 = 60.0% 5.53 6.5% 1,967 210 60.0% 5.76 6.5% 2,021 312 60.0% 5.92 65% 2,051 31,577 600% 6.00 6.5% 2,090 32,168 = =$60.0% 6.12 65% 2,187 33,200 60.0% 631 6.5% 2,228 41 60.0% 6.52 6.5% 2,317 35.669 600% 6.78 6.5% 2,417 37,197 = 600% 7.07 6.5% 2,524 38850 §=660.0% 7.39 65% 2,591 39875 00% 1.58 6.5% 2,638 40,608 600% InN 6.5% 2717 41,820 0.0% 7.95 6.5% 2,798 43,067 600% 8.19 6.5% 2,881 44,351 600% 843 6.5% 2,967 45674 60.0% 8.68 speoy HuTUTH-UON ‘SRINSeYy 4Asedetog aesed YHTH - 9T-€ eTqeL 8s Mining Forecast and Totals Case: High Onshore Gold, Summer Only Onshore Gold, Year-Round Offshore Gold, Shore Elect. Req't Mining Total Mining + Non-Mining Total Gold Total Net Peak Gold Total Net Peak Gold) Onshore — Net Peak Net Peak Net Peak Mined Use Generat. Generat.| Mined Use Generat. Generat.| Mined Use — Generat. Generat.J| Generat. Generat.]| Generat. Generat. Year J ,0000z | MWh MWh MW_| 00002 _MWh_ MWh MW_| 00007 MWh __ MWh MW MWh MW | MWh MW 1 1981 166 7,470 7,989 3.14 00 0 0 0.00 00 0 0 0.00 7,989 3.14 23,676 6.06 S 1982 18.5 8,325 8,904 3.50 00 0 0 0.00 00 0 0 0.00 8,904 3.50 26,170 6.72 T 1983 20.5 9,225 9,866 3.88 00 0 0 0.00 00 0 0 0.00 9,866 3.88 28,296 7A9 O 1984 215 9,675 10,348 407 00 0 0 0.00 00 0 0 0.00 10.448 407 29,969 7.56 R_ 1985 22.4 10,080 =: 10,781 4.24 00 0 0 0.00 00 0 0 0.00 10,781 424 32,422 mm 1 1986 25.7 11,565 = 12,369 4.87 00 0 0 0.00 30 0 0 0.00 12,369 487 34,348 8.45 Cc 1987 39.1 17,595 18,818 7.40 00 0 0 0.00 ™%7 2,350 2,513 141 21,332 7.40 43,072 11.12 A 1988] 305 13,725 14,679 $7 00 0 0 0.00 35.5 2,350 = 2,513 141 17,193 $5.77 39,058 9.9% 11989 288 12,960 13,861 5.45 00 0 0 0.00 7 2,337 2,499 L4l 16,360 5.45 39,549 931 1990} 250 11,250 12,032 4.73 00 0 0 0.00 241 2,373 2,538 141 14,570 4.73 38,667 8.94 1991 25.0 11,250 12,032 4.73 00 0 0 0.00 0.0 0 0 0.00 12,032 4.73 36,388 8.98 1992 32.0 14,400 15,401 6.06 30.0 11,400 12,193 1.74 17.0 1,020 1,091 0.57 28,684 7.80 53,753 12.17 1993 320 14,400 15,401 6.06 30.0 = 11,400 12.193 1.74 HO 2,040 2,182 1.13 29,775 7.80 55,614 12.31 1994] 320 14,400 15,401 6.06 3.0 11,400 12,193 1.74 MO 2.040 2,182 1.13 29,775 7.80 55,994 12.37 1995} 32.0 14,400 15,401 6.06 30 = 11,400 12,193 1.74 MO 2,040 2,182 1.13 29,775 7.80 56,194 12.41 1996} 320 14,400 15,401 6.06 3.0 11,400 12,193 1.74 HO 2.040 2,182 1.13 29,775 7.80 56,408 12.45 KH ‘SlTnsey yseoer0og eseD UHTH - LI°€ eTqeL P 1997] 320 14400 15,401 6.06 300 = =11,400 = 12,193 1.74 MO 2,040 2,182 1.13 29,775 7.80 56,773 12.51 R 1998] 320 14,400 15,401 6.06 30.0 11,400 12,193 1.74 MO 2,040 2,182 1.13 29,775 780 | 57,143 12.57 O 199] 320 14,400 15,401 6.06 0 11,400 12,193 1.74 HO 2.040 2,182 1.13 29,775 7.80 58,866 12.87 J 2000 = 32.0 14,400 15,401 6.06 3.0 11,400 12,193 1.74 MO 2,040 2,182 1.13 29,775 780 |} 60,046 13.08 5 E 2001 320 14,400 15,401 6.06 3.0 11,400 12,193 1.74 MO 2,040 2,182 1.13 29,775 7.80 60,888 13.23 B. C 2002] 320 14,400 15,401 6.06 30 11,400 12,193 1.74 MO 2.040 2,182 1.13 29,775 7.80 61,352 13.31 2 T 2003 320 14,400 15,401 6.06 30 11,400 12.193 1.74 MO 2,040 2,182 1.13 29,775 7.80 61,944 13.41 a =f 20049 320 14,400 15,401 6.06 30.0 = 11,400 12,193 1.74 M0 2,040 2,182 1.13 29,775 7.80 62,975 13.59 5 2005f 320 14,400 15,401 6.06 300 «11.400 12,193 1.74 MO 2.040 2,182 1.13 29,775 7.80 64,076 13.78 o 2006 32.0 14,400 15,401 6.06 30.0 = =11,400 12,193 1.74 Ho 2,040 2,182 1.13 29,775 7.80 65,445 14.02 p. 2007 f 32.0 14,400 15,401 6.06 300 11,400 12,193 1.74 MO 2,040 2,182 1.13 29,775 7.80 66,972 14.29 2008 f 32.0 14,400 15,401 6.06 3.0 11,400 12.193 1.74 MO 2,040 2,182 1.13 29,775 7.80 68,625 14.58 2009 f 32.0 14400 15,401 6.06 30 11,400 12,193 1.74 HO 2,040 2,182 1.13 29,775 7.80 69,651 14.76 § 2010 f 32.0 14,400 15,401 6.06 30.0 11,400 12,199 1.74 MO 2,040 2,182 1.13 29,775 7.80 70,384 14.88 a 2011 32.0 14,400 15,401 6.06 30 11,400 12,193 1.74 NO 2,040 2,182 1.13 29,775 7.80 71,595 15.10 4 2012 320 14400 15,401 6.06 0 11,400 12,193 1.74 MO 2.040 2,182 1.13 29,775 7.80 72,842 1s31 oO 2013 32.0 14,400 15,401 6.06 3.0 = 11,400 12,192 1.74 MO 2,040 2,182 1.13 29,775 7.80 14,127 15.54 f 2014 fF 32.0 14,400 15,401 6.06 30.0 11400 12,199 1.74 M0 2,010 2,182 113 29,775 7.80 75,450 15.77 bh 1989 - 2014 Annual Average Growth Rates: un 04% 04% 04% 04% 04% 05% _—-05% 0.9% 24% 14% 2.6% 21% 3.10 References Anonymous. March 20, 1989. "Northern Gold: Northern Gold Announces Exploration Continues at Nome." Business Wire. Anonymous. May 14, 1990. "Aspen Exploration: Aspen Exploration Announces Agreement with Tenneco Minerals." Business Wire. Berry, Kathi. June 1989. "Growing Pains Plague Placer Miners." Alaska Business Monthly, page 50. Bundtzen, T. K.; Swainbank, R. C.; Deagen, J. R.; and Moore, J. L. 1990. Alaska’s Mineral Industry. Alaska Division of Geological & Geophysical Surveys. Colt, Steve. 1989. Forecast of Electricity Demand in the Alaska Railbelt Region. Prepared for Alaska Power Authority (now Alaska Energy Authority). University of Alaska Institute of Social and Economic Research. Goldsmith, Scott. 1990. Economic Projections for Alaska 1988- 2010. Prepared for Alaska Housing Finance Corporation. Anchorage: Institute of Social and Economic Research. Griffin, James M., and Steele, Henry B. 1980. Energy Economics and Policy. New York: Academic Press, Inc. Henriques, Diana. October 12, 1987. "Prospects for Gold: Here’s How Timothy Green Assays Them." Barron’s, page 13. Impact Assessment, Inc. 1987. Institutional Change in Nome 1980- 1986. Social and Economic Studies Program Technical Report no. 127. Anchorage: Minerals Management Service. Knapp, Gunnar. 1990. Economic and Demographic Systems Analysis: Nome, Alaska. Social and Economic Studies Program Technical Report no. 144. Anchorage: Minerals Management Service. Minerals Management Service. 1990. Special Tabulations of Alaska Department of Labor Employment Security Reports ES-202, 1980- 1989. Provided by Kevin Banks. National Academy of Sciences. 1979. Alternative Energy Demand Futures to 2010. Special Report, Washington D.C. National Academy of Sciences. 1979. US Energy Supply Prospects to 2010. Special Report, Washington D.C. Oatman, E. N. and Talbert, T. L. 1989. Assessing Supply and Demand Uncertainties. Prepared for Electric Power Research Institute, Report EPRI P-6369. Palo Alto, California. 2 ™ | a9 Peterson, L. A.; Todd, S. K.; Weddleton, J. A.; Hanneman, K. L. 1986. The Role of Placer Mining in the Alaska Economy. Conducted for State of Alaska Department of Commerce and Economic Development, Office of Mineral Development by L. A. Peterson & Associates. Richardson, Jeffery. September 1990. "Promise and Peril Mark the Start of a Boom Decade." Alaska Business Monthly, page 40. Ross, Marc H., and Williams, Robert H. 1981. Our Energy: Regaining Control. New York: McGraw Hill Book Company. Waring, Kevin and Associates. 1988. A Demographic and Employment Analysis of Selected Alaska Rural Communities, Volume II. Social and Economic Studies Program Technical Report no. 137. Anchorage: Minerals Management Service. . Waring, Kevin and Associates. 1989. Nome Sociocultural Monitoring Study. Social and Economic Studies Program Technical Report no. 131. Anchorage: Minerals Management Service. Welling, Kathryn M. October 24, 1988. "The Prospects for Gold: Will the Precious Metal’s Glitter Ever Come Back?" Barron’s, page 8. White, Bill. September 20, 1990. "Owners Shut Down Bima Gold Dredge." Anchorage Daily News, page D-1. Yang, Xi Wei. 1989. "Regression Analysis of Rural Alaska Electric Demand." University of Alaska Institute of Social and Economic Research, unpublished spreadsheet. 3.~.60 Introduction The following report is the result of an Alaska Energy Authority initial work assignment to examine Unalaska and Dutch Harbor as a potential site for a clean coal electric generation plant to replace or significantly reduce the area's heavy dependence on diesel generating systems. In Section I, a brief description of Unalaska is followed by a discussion of the area's primary economy: seafood processing with an emphasis on bottom fish. Section II discusses energy use mix and load profiles as they relate to the task of sizing a generation system for Unalaska and items for further investigation where preliminary investigations were made. Section III discusses the Clean Air Act amendments of 1990, the process required of the Alaska Department of Environmental Conservation to implement them, the impact of the amendments, and the status of Dutch Harbor seafood processors with respect to current Clean Air Standards. Section IV contains a brief overview of Shemya Air Force Base and Adak Naval Air Station, two U.S. military facilities in the western Aleutian Islands that also are possible candidates for replacement of diesel-driven electric generation systems with Clean Coal applications. Appended to this report is a brief, layman's description of the eight technologies offered in response to AEA's request for statements of interest in participating in a joint application for the U.S. Department of Energy's Clean Coal Technology V program. SECTION I - UNALASKA The city of Unalaska is located on Unalaska and Amaknak islands in the Aleutian Chain. By air, it is about 1,100 miles south of Cape Lisburne and about 800 miles southwest of Anchorage. The name Dutch Harbor, while actually referring to a body of water, has become the name for part of the community located on Amaknak Island. A bridge, built in 1980, connects the two islands. The city has a current resident population of about 3,500. In 1990 about 73,000 people traveled in and out of the Unalaska airport, primarily to work in the commercial fishing and processing industries. About 25 domestic and 25 foreign ships visit the city dock each month for supplies, fuel and offloading or onloading freight. Local Government Unalaska is a first-class city with a council-manager form of government. The police department includes public safety officers, communication/correction officers, an animal control/sanitation officer and a narcotics K-9 dog. The ambulance service is staffed with EMT volunteers. The fire department has a chief, officers, volunteers and four fire trucks. The city sales tax is 3 percent. Transportation Three airlines, MarkAir Inc., Peninsula Airways and Reeve Aleutian Airways Inc., offer daily scheduled flights to and from Anchorage. Charter and/or scheduled services with Peninsula Airways, MarkAir Express and Aleutian Air Ltd. are available to other islands. Sea-Land Service, American President Lines, Crowley Maritime, Western Pioneer and Sunmar Shipping offer shipping via water. The Alaska Marine Highway System operates a ferry to Unalaska with four scheduled runs between May and September. In addition to Ballyhoo City Dock, Offshore Systems Inc., Crowley Maritime, American President Lines, Delta Western and Petro Marine Services maintain docking facilities. Seafood Industry Unalaska and the Port of Dutch Harbor first gained prominence as a fishing port in the 1960s with a boom in the harvest of King crab. Currently, the port is one of the busiest in the United States based on total product landed and product value. In 1991, the Port of Dutch Harbor processed 637.7 million pounds of shell and fin fish valued at $136.7 million. This compares with 455 million pounds processed in 1989 at a value of $102.7 million. Area fish processing plants handle King crab, Opilio crab, salmon, pollock, cod, halibut, herring and other species. The port was ranked second in the nation for value of fish delivered and was the No. 1 port for the number of pounds processed in both 1989 and 1990. On a value basis, crab is most significant, even though King crab stocks are only now beginning to recover from near disastrous declines in the mid to late 1980s. Crab processing can be expected to expand significantly as fishermen increasingly target Opilio crab. Currently, crab accounts for 40 percent of the ex-vessel value of product landed at Unalaska. Bottom fish, including pollock, Pacific cod, sablefish, Pacific Ocean perch, rockfish, Yellowfin sole, turbot, Arrowtooth flounder, other flat fish and Atka mackeral, contribute the most to Unalaska processing plants on a volume basis. Walleye pollock make up the largest percentage of the bottom fish catch. In 1990, pollock accounted for 1.35 million metric tons, or 82.3 percent, of the 1.64 million tons of bottomfish harvested in the eastern Bering Sea. In 1991, Dutch Harbor's land-based seafood processors processed about 267,300 metric tons of pollock, or about 20 percent of the eastern Bering Sea harvest of 1.3 million metric tons. There are three major shoreside processors engaged in the work: UniSea Inc. is a wholly-owned subsidiary of Nippon Suisan. Alyeska Seafoods Inc. and Westward Seafoods Inc. are owned by Taiyo Fisheries, also of Japan. Trident Seafood Corp.'s plant on Akutan Island processed about 8 percent of the Eastern Bering harvest. Trident is U.S.-owned. The other major Dutch Harbor processor, Icicle Seafoods Inc., also is U.S.-owned. Icicle does not have a land-based operation, processing fish on three processor boats. Icicle targets crab, herring and salmon and processes no pollock or other bottom fish. Other seafood processors located at Dutch Harbor include East Point Seafood Co., Marine Management Inc., Northern Victor Management and Royal Aleutian Seafoods. Fishing Seasons The pollock fishery begins Jan. 1 with the first half of the season, the "A" season, which lasts six to eight weeks. Pollock roe is targeted, and about one-third of the pollock quota will be taken during the A season. This year, the season opening was delayed 20 days. The second half, or "B" season, typically begins June 1 and lasts between three and four months. The remaining two-thirds of the pollock quota will be taken during the B season. This year, the B season was delayed on a voluntary basis by the trawl fleet because initial fishing efforts caught too much herring and because the pollock taken were considered too small. The season is closed down for the year sometime between late August and mid-September. The Pacific trawl cod season begins Jan..1 with most of the catch taken during the first quarter of the year. It is the amount of halibut allocated to each fishery as a bycatch that regulates when a particular fishery will be closed. The halibut bycatch quota is allocated on a quarterly basis. As soon as the quota for the quarter is reached, the fishery is closed. About two thirds of the cod quota will be caught during the first quarter before the halibut bycatch quota is reached. The remaining one-third of the cod quota is taken early during the second quarter. The hook-and-line cod fishery traditionally had been 12 months. However, this year the season is forecast to close in August because of an increase in the number of vessels in the fishery and because of the addition of a halibut bycatch quota of 750 metric tons. The Yellowfin sole fishery typically starts in the spring and lasts about three months. The crab season begins in July in Norton Sound and closes between Nov. 1 and the end of the year. The vessels first target King crab, then Bairdi crab, and finally Opilio crab. Crab processed in Dutch Harbor is primarily Opilio. That Opilio season starts at the beginning of the year and runs about four months. Pollock Although some of the pollock is processed into fillets, most of the resource is made into surimi, a high-protein fish paste used to make imitation crab and other products. The U.S. surimi industry has seen phenomenal growth. In 1985, the only operational surimi plant in Alaska was a demonstration effort in Kodiak sponsored by the Alaska Fisheries Development Foundation. The longevity of the bottom fish processing industry at Unalaska is closely linked to a healthy pollock resource that can be harvested at sustainable levels for years to come. The industry, the regulatory agency and the scientific community agree the probability of maintaining current harvest levels of bottom fish in general and pollock specifically remains high. From 1954 to 1963, pollock were harvested at low levels in the eastern Bering Sea. Fishing directed at pollock began in 1964. Catches increased rapidly during the late 1960s and reached a peak in 1970-1975 when catches ranged from 1.3 million to 1.9 million tons annually. Following a peak catch of 1.9 million tons in 1972, catches were steadily reduced through bilateral agreements with Japan and the former Soviet Union. Since implementation of the Magnuson Fishery Conservation and Management Act in 1977, catch quotas set by the regulatory agency, the North Pacific Fishery Management Council (Council), have ranged from 950,000 tons to 1.3 million tons. In 1980, U.S. vessels began harvesting pollock and by 1987 were able to take 99 percent of the quota. Since 1988, the harvest has been taken exclusively by U.S. vessels. The quota for pollock harvest in 1992 in the eastern Bering Sea has been set at 1.3 million metric tons. It is the policy of the Council to manage the pollock resource in such a way as to maintain an average annual catch of about 1.4 million tons in the eastern Bering Sea. The National Marine Fishery Service's Alaska Fisheries Science Center compiles the scientific data on which the Council bases its management plan and catch quotas. The Center has indicated the maximum sustained yield of all bottom fish in the eastern Bering Sea, Aleutian Islands and Bogoslof Island areas is about 3 million tons. Under the current management regime, however, a cap has been set of 2 million tons for the total bottom fish harvest, a figure which could remain stable for decades. Should the pollock component of the bottom fish resource fluctuate, the Service believes other species would fill the gap, ecologically and commercially. Over the past 50 years of data accumulation of eastern Bering Sea fish stocks, the most abundant species have varied. At one time, herring was the most abundant species. Herring was succeeded in abundance by flat fish such as Yellowfin sole. Flat fish were succeeded by rock fish which were succeeded by the cod family, including Pacific cod, Black cod or Sable fish and Walleye pollock. The current time period could be called the era of pollock. Flatfish are abundance but herring or shrimp levels have declined. If pollock stocks were to drop significantly, the scientific community believes the most likely candidate for succession is herring because of feeding requirements. Pollock, early in its life cycle, feeds heavily on planktom before becoming a more opportunistic feeder. Herring feeds almost exclusively on plankton. The Council has produced three scenarios for future exploitation of the pollock biomass in the eastern Bering Sea through 1996. One scenario contemplates a constant annual catch of 1.2 million tons. Under this, the total exploitable biomass of pollock would gradually increase from 6.18 million tons in 1992 to about 7.5 million tons in 1996. The percentage of pollock that would have to be harvested to maintain an annual 1.2 million catch level would decline from about 19 percent in 1992 to 16 percent in 1996. A second scenario would also promote an increase over time in the total exploitable biomass of pollock but not as fast. This estimate indicates the exploitable biomass would increase from 6.18 million tons in 1992 to 6.68 million tons in 1996. The projected catch level would increase from a possible 1.49 million tons in 1992 to 1.67 million tons in 1996. The harvest level would remain steady at between 23 percent and 24 percent. The third scenario is based on maximum sustained yield and would maintain the total exploitable biomass at just over 6 million tons. The annual catch of pollock would range between 1.61 million tons and 1.77 million tons. The harvest level would remain stable at between 28 percent and 29 percent. The processing industry as represented by both the onshore processors and factory trawler ships believe the pollock resource is healthy. The industry views a cap for total annual harvest of bottom fish of 2 million tons as a built in conservation measure in view of the 3 million tons that could be harvested at maximum sustained yield levels. The industry states the Council's conservative approach also reflects an effort to make sure the over fishing in the 1980s that, in part, lead to a precipitous decline in the King crab resource is not repeated. Northern sea Lion The industry indicates the only problematic or unknown factor facing it is a sharp decline in Alaska northern sea lion numbers. The declines were sufficient to lead to a final listing on Nov. 26, 1990 of the species as threatened throughout its range under the Endangered Species Act. Regulatory measures included the designation of 3 nautical mile no-entry zones around all major sea lion rookeries west of 150 degrees west longitude. Subsequent regulations prohibited trawling within 10 nautical miles in the Gulf of Alaska and eastern Aleutian Islands. In addition, the Gulf of Alaska pollock allowable catch was split in half to minimize potential localized depletion of pollock stocks, which comprise part of the sea lion's diet. A draft recovery plan for the northern sea lion is currently under review by the National Marine Fishery Service in Washington, D.C. Counts in 1991 of sea lion pups at 13 rookeries from Southeast Alaska through the eastern Aleutian Islands and Bering Sea showed a decrease at Outer and Marmot islands in the central Gulf of Alaska. Counts at other sites remained relatively stable or increased. Should the sea lion subsequently be declared an endangered species, fishing would be further curtailed. However, the industry believes sea lion populations have stabilized, albeit at low levels, and that there is no immediate need to declare the species endangered. Donut Hole The so-called donut hole is a roughly triangular, 50,000-square-mile area in the central Bering Sea that lies outside of the 200-mile exclusive economic zone (EEZ) of the United States and the former Soviet Union. It is in the donut hole area where the international fishery for pollock by Japan, Republic of Korea, Poland, Peoples Republic of China and the USSR is reported to take place. Exploitation of donut hole pollock began a significant increase when the catch went from 363,400 metric tons in 1985 to 1.45 million metric tons in 1989. In the ensuing two years, however, catches have dropped as pollock stocks were depleted. The donut hole pollock fishery is important to U.S. onshore and offshore processors because there is no self-sustaining stock of pollock in the area. The fish found in the donut hole area are part of the broader Aleutian Basin stock that migrates through or resides in the donut hole area. Donut hole pollock catches are down because the catch rate is no longer economic. Fishing vessels that had targeted the area in the past have left to pursue more lucrative arrangements, such as joint venture agreements with the former Soviet Union in its exclusive economic zone. Diplomatic efforts at reaching agreements on donut hole pollock exploitation are in progress. Recent summits between the U.S. and USSR have resulted in statements on the donut hole and the Bering Sea fisheries. Japan, China, Korea and Poland have participated in meetings, symposia and work groups on the subject with the U.S. and the USSR. The six nations are scheduled to meet in mid-August in Moscow to address fishing cut backs. A draft treaty on management of the donut hole resource also is under preparation, although it may take years to reach a final version. Unalaska's Bottom Fish Future Bottom fish processing at Unalaska plants can be expected to increase both because of its proximity to the eastern Bering Sea stocks and because of efforts to provide a specific shoreside allocation of the resource. On March 5, 1991, John Knauss, U.S. Department of Commerce undersecretary of oceans and atmosphere, signed a North Pacific Fishery Management Council amendment which assigned shoreside allocations for the eastern Bering Sea. In 1991, shoreside processors handled 28 percent of all pollock caught that year in the eastern Bering Sea. Under the amendment, shoreside processors were to be allocated 35 percent of the resource in 1992. The percentage was to increase to 40 percent in 1993 and 45 percent for 1994 and 99 5)5 The allocations were challenged in U.S. District Court in Seattle May 29 by the American Independent Fishermen, the American Factory Trawler Association, North Pacific Longline Association and Royal Seafoods Inc. of Seattle. On July 24, the judge refused to overturn the allocations but noted questions remain in the suit that must be decided at trial. The plaintiffs have indicated they will appeal the ruling. The Council and the scientific community believe the most likely outcome is a flat 35 percent shoreside allocation with no future increases. Even if the offshore processors eventually win the case, it is believed the amount of pollock available for onshore processing will increase. Unalaska processors processed about 20 percent of the eastern Bering Sea harvest in 1991. If a 35 percent shoreside allocation does become the rule and Unalaska processors maintain their market share at current levels, the 20 percent figure could be expected to increase to 25 percent. On a volume basis, that would mean the 267,300 metric tons of pollock processed by Unalaska processors in 1991 could increase to 334,125 metric tons, an increase of 66,825 metric tons or 25 percent. Unalaska pollock processors are expected to respond to an increased amount of pollock available for onshore processing this year by running their plants at full capacity rather than by expansion. Efforts by the Alaska Department of Environmental Conservation to enforce provisions of the U.S. Clean Air Act and the impacts of 1990 amendments to the act have had a "definite chilling effect" on expansion efforts of existing companies in Unalaska, according to the industry. SECTION II - LOAD STUDY To properly size a generation station for the Dutch Harbor/Unalaska load and ensure an adequate turndown capability, historic load data was collected and load profile curves plotted. These plots are shown as Figures 1 through 7. Figure 1 shows recent monthly diesel fuel use for electric generation by the largest consumers in the Dutch Harbor area. This plot displays the variation in electrical load during the year: the peak electical use occurs during the summer and mid-winter fishing seasons. Comparison of the February, 1992 use with that of the year before demonstrates that the new Opilio crab season has had a positive impact on electrical use. To give a better perspective on the actual load variations to be expected by a generation plant, weekly load profiles are plotted as Figures 2 through 6. These plots show actual kilowatt (kW) load for an entire week at the Alyeska Seafood plant. Data was obtained for the highest (July-August) and lowest (December) timeframes. Review of these plots shows the variation in load magnitude which can be expected from a seafood processing plant. For example, Figure 6 shows the extreme example of a day (Sunday) where little processing was done followed by a six days of nearly level load. Figure 7 attempts to predict the overall load profile that a centralized plant could expect if all the processors happened to have synchronized work schedules. Since the processors process the same species within the same timeframes into similar products, this is entirely probable. The same shape load profiles as that of Alyeska Seafoods was assumed for the other two processors, the magnitude was obtained by ratioing their energy consumption used for electric generation to that of Alyeska's. A significant portion of the area load is that of the City of Unalaska. A daily load profile for the city was needed for inclusion in the area load. No hourly data for the city's load is recorded, so a load profile had to be assummed. The City of Unalska records peak kW and kWh on a daily basis. The highest and lowest peak kW in each month for the past two years were made available. The highest peak kW values for December,1990 and August, 1991 were used to scale Alyeska's load profile to model a profile for the city. GALLONS OF DIESEL (000's) 700 600 un So o 400 300 200 100 Jun-91 Jul-91 Aug-91 FUEL USE FOR ELECTRIC GENERATION DUTCH HARBOR, ALASKA City of Unalaska Sep-91 Oct-91 Nov-91 Dec-91 MONTH FIGURE 1 Jan-92 Pollock Season "A" Pacific Cod Opilio Crab Feb-92 Mar-92 KILOWATTS 1200 1000 800 600 400 200 0 SUNDAY ALYESKA SEAFOODS LOAD PROFILE: WEEK OF 12/9/90 - 12/15/90 MONDAY TUESDAY WEDNESDAY THURSDAY FRIDAY DAY OF THE WEEK FIGURE 2 SATURDAY KILOWATTS 1400 1200 1000 800 600 400 200 SUNDAY ALYESKA SEAFOODS LOAD PROFILE: WEEK OF 12/16/90 - 12/22/90 MONDAY TUESDAY WEDNESDAY THURSDAY FRIDAY DAY OF THE WEEK FIGURE 3 SATURDAY KILOWATTS 1600 1400 1200 1000 800 600 400 200 SUNDAY ALYESKA SEAFOODS LOAD PROFILE: WEK OF 12/23/90 - 12/28/90 MONDAY TUESDAY WEDNESDAY THURSDAY FRIDAY DAY OF THE WEEK FIGURE 4 SATURDAY 3000 2500 2000 1500 KILOWATTS 1000 500 SUNDAY MONDAY ALYESKA SEAFOODS LOAD PROFILE: WEEK OF 7/28/91 - 8/3/91 TUESDAY WEDNESDAY DAY OF THE WEEK FIGURE 5 THURSDAY FRIDAY SATURDAY KILOWATTS 3000 2500 2000 8 1000 500 SUNDAY ALYESKA SEAFOODS LOAD PROFILE: WEEK OF 8/4/91 - 8/10/91 MONDAY TUESDAY WEDNESDAY THURSDAY FRIDAY DAY OF THE WEEK FIGURE 6 SATURDAY 18000 16000 14000 12000 KILOWATTS s oS Oo 8000 6000 4000 2000 SUNDAY PROJECTED WEEKLY LOAD PROFILE MONDAY DUTCH HARBOR, ALASKA AUGUST LOAD TUESDAY WEDNESDAY DAY OF THE WEEK FIGURE 7 DECEMBER LOAD THURSDAY FRIDAY SATURDAY Analysis The overall load profile for the Dutch Harbor area (Figure 7) shows a ratio between peak and minimum load which can reach up to 3.5:1 over a short period of time. This ratio exceeds the practical turndown ratios for most coal fuel technologies. Some form of energy storage or load shifting would be required to level the area load to meet the load following capability of a coal based generation plant. Potential energy storage technologies such as compressed air storage, refrigerated water, batteries, and methanol or synthetic oil production could be used. Additional uses for the non-peak capacity such as an off-peak steam load or new customers could also be used to allow load following. While sizing the generation plant for the base load and using other means for peaking is possible in theory, it tends to work against the original driving force for the project. Other forms of generation used for peaking, such as diesel engines, will prolong the dependence on oil and fail to solve the air quality problem. Decreasing the unit size of a coal plant into increments which can be dispatched as needed will increase capital cost and may still not be adequate to meet the turndown requirements. Energy Use The use of a coal fueled plant to supply all the energy (steam and electric) needs of the Dutch Harbor area was investigated as a way to reduce overall emissions. A single energy source using the proper coal technology could theoretically eliminate a majority of the scattered sources in use today, lowering the total amount of pollutants emitted in the area. The burden of compliance with the provisions of the Act could also be lifted from individual users and consolidated in one central coal fueled electic generating facility. The dominant pollutants in Dutch Harbor, of concern to the Department of Environmental Conservation, are oxides of nitrogen (NOx) produced in the combustion process. In Dutch Harbor the main source of NOx is the burning of diesel fuel and fish oil to generate electricity, produce steam for process use, and for product drying. Most NOx is produced for the generation of electricity (see Figure 8). Any attempt to control NOx production on the part of the seafood processors should therefore target the diesel generators. Figures 9 and 10 give a percentage breakdown of the energy used for electricity, process steam, and drying. These energy uses are further divided acording to the type 10 Percentage Permitted NOx Contribution by Source for Dutch Harbor Seafood Processors Alyeska 7% 89% HM Electric O1 Steam I Drying Unisea 6% 4% 90% FIGURE 8 Westward 6% 94% 2nd H 90 1st H 91 2nd H 91 1st H 92 Percentage Diesel Fuel Use By Seafood Processors, Dutch Harbor, Alaska Electric Steam Drying Total Total gals. Electric Steam Drying Total Total gals. Electric Steam Drying Total Total gals. Electric Steam Drying Total Total gals. Notes: ALYESKA SEAFOODS Total Energy Diesel Fish Oil 52.9 52.9 0 29.7 18.6 11.1 114 0.8 16.6 100 Ta3 27.7 911,170 47 47 0 38.9 37 1.9 14.1 0.9 13.2 100 84.9 15.1 969,949 §2.2 §2.2 0 35.7 17.1 18.6 12.1 14 10.7 101 70.7 29.3 875,277 er Pe UNISEA Total Energy Diesel Fish Oil 57.4 57.4 0 426 31.4 11.2 o 0 o 100 88.8 11.2 1,161,422 60.6 60.6 0 21.3 19.4 1.9 18.1 2.7 15.4 100 82.7 17.3 2,156,282 63.8 63.8 0 22.4 16.1 6.3 13.8 13 12.5 100 81.2 18.8 1,593,584 60.6 60.6 0 26 25.3 0.7 13.4 2.6 10.8 100 88.5 11. 1,740,708 Note 3 Data unavailable for Alyeska (1st H 92) and Westward (2nd H 90). Two months of data only. Five months of data only. Four months of data only. Gallons are diesel fuel or equivalent on a BTU basis (1 gallon fish oil = .88 gallons of diesel). FIGURE 9 WESTWARD SEAFOODS Total Energy Diesel Fish Oil 37.6 37.6 0 62.4 57 5.4 0 0 0 100 94.6 5.4 51.3 48.7 100 34.9 65.1 0 100 211,704 Note 2 51.3 0 19.2 29.5 o 0 70.5 29.5 551,876 34.9 0 33.8 31.3 0 Q 68.7 31.3 710,081 Note 4 Gallons of diesel equivalent 1990 2nd half 2,500,000 2,000,000 1,500,000 1,000,000 AN 500,000 Alyeska 1,161,422 MI Westward No Data 1991 1st half 2,500,000 2,156,282 OT 2,000,000 Drying (fish oil) Drying (diesel) Steam (fish oil) 1,500,000 | 1,000,000 +—268.948 | Steam (diesel) BEHEEE@O Electricity (diesel) One gallon of fish oil is equivalent to 0.88 gallons of diesel. 500,000 Alyeska Unisea Westward May - June only FIGURE 10 Page 1 of 2 2,500,000 2,000,000 1,500,000 1,000,000 500,000 Gallons of diesel equivalent 1991 2nd half 875,278 ini Alyeska 1,593,585 I Unisea 551,875 Zz Westward 1992 1st half 2,500,000 2,000,000 Drying (fish oil) 1,740,707 Drying (diesel) Steam (fish oil) 1,500,000 Steam (diesel) BHEEED Electricity (diesel) 1,000,000 710,080 One gallon of fish oil is equivalent to 0.88 gallons | ose 500,000 | | Alyeska Unisea Westward No Data Jan-May only Jan-April only FIGURE 10 Page 2 of 2 of fuel consumed. The gallons of fish oil consumed was converted to equivalent gallons of diesel fuel on an energy content basis of 1 gallon of fish oil = .88 gallons of diesel. Analysis The two processors with dryers burn primarily fish oil in this equipment. Fish oil in excess of their drying needs is burned in the boilers, thereby reducing the amount of diesel used. The processor without drying equipment (Westward), fires all their fish oil in their boilers for steam production. Electrical power generation accounts for 50% to 60% of the total energy used by the processors. Only diesel fuel has been used to generate electricity. The remainder of the energy used by the processors is for steam production and product drying. Westward has no drying equipment, so the balance of their total energy use is for steam production. Between one quarter and one third of the energy needs of Alyeska and Unisea is for steam production. The remainder of their needs is for drying. Fish oil has been used to replace up to 60% of the diesel required for steam production. Assuming that different uses will not be found for fish oil and it will continue to be disposed of by burning for process heat and steam, the steam which will be produced by burning diesel fuel will continue to be a relatively small portion of the total energy. A rough estimate of potential revenues from steam sales to the largest user is $400,000 per year. Given the additional capital investment which would be required to supply this quantity of steam, the sale of steam could not be economically justified. The physical distances which seperate the seafood processors and any potential steam users within the city make a central steam plant concept uneconomical. Stand-alone steam sales to generate revenues in Dutch Harbor are unjustified. Locating the coal fueled plant near a potential steam load to allow ancillary steam sales to level the plant's load profile should be evaluated. Items Requiring Further Investigation The following is not an exhaustive list of items needing resolution, but a highlight of the areas in which ll only a preliminary investigation could be made and more thorough work needs to be done. ¢ city of Unalaska electrical load profile: The city power plant has recording capability to capture only peak kW and kWh. No data of the magnitude of daily load swings or minimum load exists. A load profile based on that of one seafood processor was used in the above evaluation for a worst case estimate. ¢ Unisea and Westward load profiles: As with the city, data for the load profiles of these plants were not available. Some of this data may have already been collected in previous studies and be in possesion of the contractor who performed the study. Since these plants have had recent expansions, more timely data should be collected. The load profiles used in this evaluation assumed the load shape of the one processor for which data was obtained. e Other Dutch Harbor area loads: The city and the three seafood processors represent the majority of the electrical load in the area. There are a number of other self generators in the area who will be covered by the new Clean Air regulations and whose loads will have an impact on a central facility. These loads have never been rigourisly quantified. ¢ Load leveling: The Dutch Harbor area load profile will make application of a typical coal fueled plant difficult. In order to use coal as a fuel, a process which can handle the load swings as estimated must be found, or the load the plant sees has to be leveled in some manner. Load leveling could involve: serving load presently self generated, finding an economically justifiable steam buyer, interim storage of the energy, or attracting a new facility and load which will compliment that which already exists. e Plant optimization: The generation capability of the plant needs to be determined considering the technology chosen, the actual load to be followed and the availability of peaking generation. The turndown ratios, availability, and response times will factor into the size and number of units best suited. 12 Location: A suitable location for the plant needs to be chosen considering the size of the plant, availability of space, and cost of interconnection. Price of power: Changes in air quality regulations have not forced the major loads into purchased, rather than self generated, power. Power produced must therefore compete with diesel generated electricity, and a target price should be set to guage project viability and dictate capital expenditure. Purchase commitment: A purchase power agreement which is acceptable to both parties needs to be assembled for project viability. Past studies have met with non-commitment from the major potential power purchasers. 13 SECTION III - CLEAN AIR ACT AMENDMENTS OF 1990 The recently signed U.S. Clean Air Act amendments of 1990 lower the threshold limits for requiring a permit for all criteria air pollutants from 250 tons per year to 100 tons per year. A plant emitting less than 100 tons per year of a pollutant per year would not require a permit. Air pollutants covered are: particulate, particulate matter of 10 microns or less (PM 10), carbon monoxide, oxides of nitrogen (NOx), oxides of sulfur (SO2) and ammonia. For deisel engines, for example, the criteria pollutant is NOx. Translating this to a kilowatt basis, the amendments lower the size of generators which will require a permit from 1,750 kW to 550 kW. The 550 kW limit is an approximation. This could vary by 10 kW either way and depends on the emission rate for a particular engine. It also should be noted the emission rates are calculated by "name plate." Diesel engines of a certain size are assumed to emit a certain level of NOx whether the diesel is run at capacity, less than capacity or intermittently such as for a standby generator. A goal of the Clean Air Act is for each state to develop a program to issue the permits rather than the federal government (Environmental Protection Agency). The Air Quality Management Section of the Alaska Department of Environmental Conservation's (ADEC) Division of Environmental Quality currently is working to develop such a program. The Act states permitting agencies must collect sufficient revenue to cover the cost of operating the program. The 1990 amendments provide for a test charge of $25 per ton of emissions for each permit. The permit fee for a plant emitting 100 tons of NOx per year, for example, would be $2,500. For a plant emitting 250 tons per year, the permit fee would be $6,250. The fee system is to assure the states will have the resources to administer their programs. The $25/ton figure is neither a maximum nor a minimun, but a test mark to help EPA determine if an agency is collecting enough revenue. ADEC has developed several scenarios to help determine the fee level, but at this point has no idea of what the fee will be. The fee structure will be the subject of negotiations between ADEC and public and private entities which will be required to get permits. If the emissions of all facilities emitting 100 tons or more per year of pollutants were lumped together and divided by the expected cost to operate the permit program, ADEC speculates the fee level would be between $15 and $18 per ton. The Act gives states considerable flexibility in devising permit fee levels. Some states have set different permit fees for different pollutants. Once states have their programs implemented, it is believed EPA will probably 14 discontinue some of the funding it previously had allocated to the states to enforce the Clean Air Act. ADEC believes it will be able to implement its program in mid-1995. Writing regulations for the program cannot begin until ADEC has the statutory authority to do so. The Alaska legislature defeated clean air statutes during the last sesson. New statutes will be offered to the next session of the legislature in January 1993. It is expected the statutes will win approval because the state faces the sanction of losing $200 million in federal highway funds if they are not approved. ADEC has a Nov. 15, 1993 deadline to submit its program to EPA for review, but is not likely to meet the deadline. If the program is not ready for submission by the due date, EPA has 18 months during which it can either invoke the loss of highway funding sanction or allow ADEC more time to complete its program. In past such instances, EPA has not invoked sanctions if the agency responsible for submitting a program is acting in good faith and making reasonable progress. At the end of the 18 months, EPA must invoke sanctions. If ADEC has its statutory authority by the end of May 1993 with the close of the legislative session, the agency can begin the seven-month-long process of writing the regulations. That makes January 1994 the earliest ADEC could have its program back to EPA for review. EPA has one year to approve the state's program, but ADEC believes EPA will want changes made, further delaying the implementation date. Assuming another six months to comply with EPA requests, ADEC believes July 1, 1995 is a reasonable date to begin implementation. The Clean Air Act amendments will not function to reduce emisssions. ADEC is not changing its ambient air standards. There will be no requirements for changes in emission rates for virtually all of those entities required to have a permit. The permit fees are not expected to be of a magnitude sufficient to force facilities to curtail emissions or use enhanced technology to reduce emissions. ADEC estimates the fee would have to be on the order of $220 per ton of emissions to be an economic compelling motive. With no means to force Dutch Harbor diesel users to reduce or eliminate their NOx emissions, ADEC has expressed interest and support for the use of different generation systems, such as clean coal applications, to eliminate emissions by replacing the diesel engines. Alaska also is exempt from Title IV of the Act which deals with acid rain and sulfur emissions. In the Lower 48, Title IV sets up allocations for facilities on the number of tons of sulfur each facility can emit. These allocations can be bartered, sold and traded. However Phase 2 of this 15 program calls for a reduction in the allocations, thereby bringing about a reduction in emissions. In Alaska, a reduction of emissions could come about if a company signed an agreement with the ADEC to restrict diesel operations, for example. This would result in lowering emissions by a measurable amount which would, therefore, also lower the company's permit fee. Currently EPA can levy criminal fines of up to $10,000 per day for violations of the act, and can collect an additional $10,000 per day up to a maximum of $200,000 in administrative fines. ADEC has no authority to assess a fine without a court order. The agency is seeking the statutory authority to levy criminal fines of up to $5,000 per day for violations, as well as the ability to collect administrative fines. With the ability to assess both such fines, ADEC believes it could preclude the EPA from overfiling on a Clean Air Act violation. Current Status in Dutch Harbor Seafood processors at Dutch Harbor use diesel engines to generate electricity. Increased availability of pollock for shoreside processing prompted many processors to expand their plant's capacity. The expansions placed processors in violation of air quality standards. ADEC fined the offenders and placed them on a schedule for a PSD (prevent serious deterioration) air quality review and required them to gather meteorological data to assess the impact of the increased emissions. After ADEC has received an application for a PSD review from a processor, the agency has 30 days to decide if the application is complete or deficient. Once the application is complete, the permit must be issued within one year. However, ADEC typically has been able to complete the process within six to nine months. During that time, a technical analysis report must be written and a draft permit made available for public review. The processors currently are operating under individual compliance orders negotiated with ADEC. One criterion of the PSD review is the use of best available technology whenever a new or expanded plant will exceed emission limits. ADEC has determined best available technology for diesel engines includes engine designs that result in lower emissions. However, engine design for lowest emission rates is not the criteria on which processors made their decisions in the purchase of diesel engines. Cost was the main factor. Best available technology will therefore be retrofitting the diesels to lower emissions. ADEC indicates there are two viable and economic retrofit technologies available: exhaust gas recirculation, which is a manufacturer retrofit, and retarding the injection timing, a 16 task which can be performed on site. Timing retard is estimated to reduce NOx by 10 percent to 20 percent. ADEC is in the PSD review process with one processor, Westward Seafoods Inc. Timing retard will be recommended to Westward as the best available technology. That technology also will be recommended for the other processors when they begin their PSD review. 17 SECTION IV - SHEMYA AND ADAK In addition to Unalaska/Dutch Harbor, some research effort was put into a brief overview of Shemya Air Force Base and Adak Naval Air Station. Shemya Air Force Base By air, Shemya AFB is about 1,325 miles southwest of Cape Lisburne and 1,530 miles southwest of Anchorage. The base, sometimes referred to as the "Black Pearl of the Pacific" or "the rock," is the most westerly of the Eleventh Air Force's bases. The 683rd Air Base Group provides support to various associate units assigned to other Air Force commands, primarily the Air Combat Command. Shemya is best known to the public in Alaska as a base from which aircraft were and are dispatched to intercept and shadow surveillance aircraft, most notably long range "Bear" bombers, from the former Soviet Union. The base has a compliment of 38 officers and 501 enlisted personnel. At any one time, between 40 and 60 contractors may be working at the base, giving a total population of 600 or less. Shemya receives scheduled air service on a contracted basis by MarkAir twice a week (Tuesday and Thursday) and by the U.S. Military Airlift Command. There is no scheduled surface transportation to the island, however barges resupply the base during summer months. There are no civilian dependents on the base. Personnel serve a one year unaccompanied tour of duty. Shemya's power generation system is capable of 18 MW at maximum production. The peak load reached has been 16 MW, and 6 MW is the average load. The generators are driven by diesel engines. The once uninhabited island was first occupied by military forces on May 28, 1943 during the final days of the battle to take nearby Attu from the Japanese during World War II. The present day 10,000-foot runway and accompanying facilities were constructed to accommodate the 28th Bomber Group whose B-24s flew bombing and photo reconnaissance missions agains the northern Kurile Islands. Air Force activities were reduced following the war. The base served as a refueling stop during the Korean War and was home to the 5021st Air Base Squadron. The base was inactivated July 1, 1954 after the Korean War. The facilities were turned over to the then U.S. Civil Aeronautics Authority in 1955, and subsequently leased to Northwest Orient Airlines which remained on the island until 1961. The Air Force resumed operations on Shemya in support of various Air Force and Army strategic intelligence collection activities, and the 5040th Air Base Squadron was 18 activated July 15, 1958 to provide base support. The base's operational status was redesignated and upgraded several times during ensuing years. It was transferred from the Aerospace Defense Command to the Strategic Air Command when the former was inactivated Oct. 1, 1979. The base currently is part of the Alaskan Air Command which is based at Elmendorf Air Force Base just north of Anchorage. Adak Naval Air Station By air, Adak NAS is located 1,290 miles southwest of Cape Lisburne and about 1,250 miles southwest of Anchorage. The air station is a part of the Naval Air Force Pacific Command. Its mission is to support the U.S. Navy's Pacific fleet, most notably in the area of anti-submarine warfare. Adak has a compliment of 2,200 active duty military personnel. Dependents and contractors bring the total population to about 5,000 persons, which would make it Alaska's sixth largest city were it in civilian hands, according to a station spokesman. During winter months, the station's population declines by about 500. Adak is served on a scheduled basis by Reeve Aleutian Airways and MarkAir, and by the Military Airlift Command. Samson Tug and Barge Co. of Seattle is under contract to provide scheduled (every 17 days) barge service from Seattle. Adak has a peak power demand of 10.75 MW. The generators are driven by diesels which use JP 5 jet fuel. Both the diesels and generators have been characterized as "very old." Plans exist for replacing the diesel engines with turbines, but funding has not been made available. The island was occupied by the U.S. Army when it landed 3,500 troops on Aug. 30, 1942. Adak served as a staging area for efforts to retake Kiska during WWII, and at one time there were 100,000 personnel on the island. Adak's military population declined to about 1,000 following the end of the war. In July 1950, the Army base on Adak was turned over to the U.S. Navy. The naval air station underwent a steady build up in the 1960s and 1970s to reach its current staff level. 19 REFERENCES Tom Chappel, project manager, Air Quality Management Section, Division of Environmental Quality, Alaska Department of Environmental Conservation, Juneau, personal communication. Albert Bohn, Air Quality Management Section, Division of Environmental Quality, Alaska Department of Environmental Conservation, Juneau, personal communication. Bill McClarence, Air Quality Program, South Central Regional Office, Alaska Department of Environmental Conservation, Anchorage. Roe Sturgulewski, public works director, and Jim Taylor, City of Unalaska, personal communication. R.W. Beck and Associates Inc., Preliminary Report: Unalaska Geothermal Project, Nov. 13, 1991, Anchorage. Shemya, Tech. Sgt. Holbrook, Elmendorf Air Force Base public affairs office. Adak, Capt. Ellis Caldwell, command office, Adak Naval Air Station. North Pacific Fishery Management Council, "Stock assessment and fishery evaluation report for the groundfish resources of the Bering Sea/Aleutian Islands region as projected for 1992," November 1991. National Fisherman, West Coast Focus, pp. 1 & 4, pp. 18-19, February 1992, Vol. 72, No. 10. National Fisherman, pp. 11 & 71, May 1992, Vol. 73, No. 1. Alaska Fisherman's Journal, pp. 11, 34 & 36, August 1991. Richard Lauber, chairman of North Pacific Fishery Management Council and lobbyist for Pacific Seafood Processors Association, Juneau, personal communication. Bruce Buls, spokesman for American Factory Trawlers Association, Seattle, personal communication. Loh-Lee Low, Alaska Fisheries Science Center, National Marine Fisheries Service, Seattle, personal communication. Brent C. Paine, fishery biologist, North Pacific Fishery Management Council, Anchorage, personal communication. Unalaska/Dutch Harbor Chamber of Commerce, 1992 Business Directory and Information Guide. 20 Appendices PROPOSED COAL FUEL TECHNOLOGIES Eight companies responded favorably to the Alaska Energy Authority’s request for statements of interest in joint application for the U.S. Department of Energy’s (USDOE) Clean Coal V program. Responding firms were required to offer pre- commercial technology that would meet the minimum requirements of the proposed USDOE solicitation that is also applicable to Alaska remote utility needs. Size range of potential units could vary from 200 kw to 25 MW. The eight companies were: Detroit Diesel Corp. of Detroit, Mich., Air Products and Chemicals Inc. of Allentown, Penn., Southern Engineering and Equipment Co. of Graysville, Ala., Cooper Industries of Grove City, Penn., The M.W. Kellogg Co. of Houston, Texas, Energy and Environmental Research Corp. of Orrville, Ohio, Hague International of South Portland, Maine and SGI International of La Jolla, Calif. Detroit Diesel Detroit, Mich. Richard Winsor, manager - combustion and emissions 313 592-7190, fax 313 592-7888 Detroit Diesel proposed a joint application to develop two- stroke diesel engines which would operate on coal-derived methanol to generate electricity in rural Alaska areas. The company proposes to further develop its Series 92 and 149 heavy-duty diesel engines which have horsepower outputs ranging from 276 hp to 1,232 hp (Series 92) and between 1,155 hp and 2,340 hp (Series 149). The engines can power a range of Detroit Diesel generator sets with outputs ranging from 200 kw to 1.5 MW per engine. Series 92 methanol diesel engines have been used to power urban buses since 1983. This engine was the first alternate fuel heavy-duty engine in the United States to win certification by the U.S. Environmental Protection Agency. Benefits Detroit Diesel believes can be accrued by the use of methanol-fueld diesel engines to generate electricity in rural Alaska include local fuel source, lower emissions and potentially lower fuel cost. A number of Detroit Diesel engines are in use throughout Alaska, including rural villages where they are used to generate electricity. Existing engines could be retrofitted to run on methanol, or could be replaced with the new methanol-burning engines. The company, in its expression of interest, did not specify how the methanol would be produced from coal or what the by products would be. But the company does have a relationship with Air Products and Chemicals under a USDOE Clean Coal III program to test methanol as a diesel fuel in buses on the West Coast. This is in conjunction with an Air Products Clean Coal program to demonstrate its proprietary process to produce methanol from coal-derived synthesis gas on a commercial scale at a facility located in Daggett, Calif. There is no relationship between Detroit Diesel and Air Products for an application under Clean Coal Vv. In a coal-to-methanol system, the coal is first crushed and pulverized before being fed into a gasifier. During gasification, the carbon in the coal reacts with oxygen and steam to form carbon oxides, methane and hydrogen. The raw gas is delivered to the synthesis gas upgrading section for production of a gas suitable for methanol synthesis. During this process the hydrogen and sulfur join to form hydrogen sulfide which is removed in a sulfur recovery unit. The other by product is virtually pure carbon dioxide. The carbon dioxide is either vented or collected for future sale. In the final stage, the synthesis gas is compressed to the level required for methanol synthesis (1,390 psia). Centrifugal type compressors are used. The methanol is produced from a distillation column. Air Products Allentown, Penn. David J. Taylor, manager - business development 215 481-7440, fax 215 481-5444 Air Products proposed a joint application for the development, design, construction and operation of a pressurized fluidized bed boiler independent power plant. The plant would use Alaska coal and sell power to a utility targeted by AEA under a long term contract. A pressurized fluidized bed boiler is a container in which the combustion process occurs. Because of its pressurized operation, the container is considerably smaller than a conventional boiler of equal generating capacity. The process begins when a mixture of crushed coal and limestone or dolomite is injected, along with a uniform flow of air, through the bottom portion of the container. When the air velocity inside the container reaches a certain level, the solid particles of coal and limestone appear to float or "fluidize." During this process the coal is burned and the limestone absorbs more than 95 percent of the sulfur oxides that are produced, thus requiring no additional flue gas desulfurization. The sulfur-laden limestone forms a dry, solid waste product which is removed through the bottom of the container or captured as fly ash in dust collectors. The combustion temperature ranges from about 1,600 degrees F to 1,800 defrees F, or about half that encountered in a conventional boiler and well below the heat level needed to form nitrous oxides. The heat from the combustor is used to make hot water, hot air or steam to drive a generating systen. In the Air Products combined cycle proposal, the coal and limestone are first fed into a pressurized carbonizer which produces a low-Btu fuel gas and char. The fuel gas, after having the particulate fly ash removed, is burned to produce the energy required to drive a gas turbine which, in turn, drives a generator to produce electricity. After exiting the carbonizer the char is then fed into the fluidized bed combustor. Steam generated in a heat-recovery steam generator associated with the fluidized bed drives a steam turbine generator that furnishes the balance of electric power delivered by the plant. The steam turbine generates about 80 percent of the plant’s total gross electrical output, and the gas turbine produces the rest. Air Products, a company with annual sales exceeding $3 billion, has a history of involvement with USDOE in Clean Coal I, II and III and with other non-coal related projects. The company operates fluidized bed power plants in Stockton, Calif., and Ebensburg, Penn. Southern Engineering & Equipment Co. Graysville, Ala. Neil Turner sr. 20S 674-5626, fax 205 674-5630 Southern Engineering has expressed an interest in participating in a Clean Coal V application as a provider of steam turbines and generators. The company designs, builds and installs small and medium size cogeneration systems using back pressure or condensing steam turbines and induction or synchronous generators. Southern Engineering currently has 30 installations in operation in the 35 kw to 4 MW range with the majority in the less than 500 kw range. The steam turbines and generators are assembled in Southern Engineering’s Graysville, Ala., shop, and personnel are available for re-erection at a chosen site. Size of the components to be used in an Alaska Clean Coal application would depend on the type of turbines and generators selected. Services of the company include feasibility analysis, complete engineered drawings and written material for system manufacture, field installation supervision and maintenance. The equipment is designed to operate without an attendant. Cooper Industries Grove City, Penn. A.K. Rao, project manager 412 458-3550, fax 412-458-3525 Cooper Industries (Cooper-Bessemer Reciprocating Products Division) is looking for a host site and a potential partner to join it in bidding for a USDOE Clean Coal V project to demonstrate the company’s coal water slurry (CWS) fueled diesel engine. Cooper-Bessemer developed the engine under the sponsorship of USDOE’s Morgantown Energy Technology Center, and has successfully operated both a research engine and a production engine on CWS with under 2 percent ash production. Test results indicate power output and operating efficiencies comparable to diesel fuel operation. The slurry underwent almost complete combustion without leaving deposits inside the engine. A full scale emissions control system has been constructed and is scheduled to be demonstrated in 1993. Offered for demonstration are a six-cylinder engine capable of producing 1.8 MW and a 20-cylinder engine capable of producing 6 MW of electricity. A coal cleaning and slurrying plant would be installed at the site with the engines. The plant would produce engine grade slurry with less than 2 percent ash and a boiler grade cleaned coal for use in boilers in Alaska and/or for export. Coal pulverized to an optimum 10 to 13 micron size with 98 percent less than 88 microns in size would comprize 50 percent of the slurry by weight. Electricity generated by this system could be used to power the coal preparation plant as well as meet the energy requirements of a coal mining operation. The size of the CWS plant would depend on the fuel demand of the engines, whether the plant were to be run year-round or on a seasonal basis and the nature of other AEA requirements. Components for the CWS plant are available off-the-shelf. Representatives of the Alaska Energy Authority and the Rural Alaska Power Association visited the Cooper-Bessemer research center in February 1992 where they were briefed on the technology involved and witnessed a demonstration of the coal-fueled engine. M.W. Kellogg Co. Houston, Texas William M. Campbell, manager, clean coal technologies 713-753-2184, fax 713 753-6609 M.W. Kellogg has piloted an atmospheric circulating fluidized bed combustor which could be adapted to the range of generating capacities called for in AEA’s request for statements of interest for Clean Coal V. The process was piloted under a cooperative agreement with the USDOE in a one-ton-per-day facility which consumes coal, petroleum coke, lignite or other similar fuel. The process operates at atmospheric pressure, and uses limestone as the sulfur sorbent. The technology is pre-commercial, and Kellogg is seeking an industrial or governmental partner to commercialize the technology. The system uses a "transport-phase" combustor which uses coal pulverized to about the size of pencil eraser heads and limestone. Velocity of the air being pumped into the combustor is relatively high, in excess of 30 feet per second. The test program, in which both bituminous coal and petroleum coke feeds were used, resulted in essentially complete conversion of carbon and greater than 98 percent capture of sulfur. The transport reactor of the combustor operates in stages to minimize production of nitrous oxide. Heat from the combustor is used to generate steam for a steam turbine which drives the generator. In low capacity units, the combustor would be operated at near atmospheric pressure and power would be produced only from steam in a simple cycle. For higher capacities, the combustor would be operated at moderate pressure and the flue gas would be expanded to generate power and compress the combustion air in a combined cycle system. The low capacity unit could be transported in C-130 cargo aircraft. M.W. Kellogg currently is under contract to the USDOE to build a pressurized version of the combustor at Wilsonville, Ala., which will consume about 40 tons per day of coal. Energy and Environmental Research Corp. Orrville, Ohio Robert A. Ashworth, process manager 216 682-4007, fax 216 684-2110 EER has expressed an interest in working with AEA to develop and commercialize its atmospheric fluidized bed cumbustor for use in burning Alaska coal and waste wood to generate electricity. Heat from the combustor could drive either a hot air turbine or create steam for a steam-driven turbine/generator system. The system also could provide hot water, steam and/or hot air for use in AEA’s patented ammonia chiller to make ice. In this fluidized bed system, air and recirculated flue gas are blown up through the bottom of the combuster and the coal fuel is fed into the unit via a side port. Hot combustion gases are transmitted to a shell-and-tube heat exchanger where either water is heated or steam is created. After exiting the heat exchanger the combustion gas is filtered to remove the ash and sulfur sorbent. Combustible flue gas is then recirculated to the air blower. The remaining flue gas is sent to the exhaust stack. EER currently has a fluidized bed combustor development program underway with the USDOE. An EER representative has indicated he will recommend to the USDOE that the demonstration phase of the program be completed in Alaska in a cooperative effort with AEA. Also under discussion is a test of four Alaska coals as part of the demonstration phase. EER’s commercialization partner, which fabricates the fluidized bed combustors, has been advised of the discussions and the possibility of assembling the components in Alaska. This effort would not entail an application under Clean Coal V. Funding from DOE for demonstration phase is already in place. This would significantly shorten the time needed to initiate a test of this technology in Alaska. Hague International South Portland, Maine Gwynne F. Briggs, program manager 207 799-7346, fax 207 799-6743 Hague International is interested in joining with AEA to submit a proposal to USDOE for the design, constrution, installation and start-up of an air transportable electric power generation plant for rural areas. Hague currently is developing an emerging technology for a solid fuel power cycle based on an externally or indirect-fired gas turbine and low pressure (atmospheric) ceramic heat exchangers. The program is sponsored by USDOE’s Morgantown Energy Technology Center, the Pittsburgh Energy Technology Center and a consortium of electric utilities, utility organizations, industrial equipment manufacturers, state agencies and foreign government entities. Hague is constructing a test facility power plant that includes all of the key components in the cycle at a test site in Kennebunk, Maine. The rated heat input of 7.3 MW is based on a Garret 831 gas turbine. Hague also is studying the application of the General Electric LM 2500 turbine for coal and bio-mass fired power plants, covering a range of 500 kw to 50 MW. The Kennebunk test facility is scheduled to go into operation on natural gas during the last quarter of 1992 for initial pressure testing, and on coal during the first quarter of 1993. Data from the tests will be available for submittal with the Clean Coal solicitation. In the company’s Externally-Fired Combined Cycle (EFCC) system, clean air enters an open cycle gas turbine for compression to a pressure of 10 to 20 atmospheres. The compressed air flows through the tubes from the turbine and receives heat from the higher temperature coal combustion gases generated by a low NOX pulverized coal combustor. The heated air is sent back to the turbine through tubes to its expander section, which produces about 45 percent of the new combined cycle electricity. The exhaust air from the gas turbine becomes the combustion air for the coal combustion system. The resulting coal gases pass through a slag screen and enter the ceramic heat exchanger. The heat is then used for the bottom half of the power cycle to produce steam to generate electricity, or for injection into the the compressed air systen. SGI International La Jolla, Calif. Richard McPherson, director of development 619 551-1090, fax 619 551-0247 SGI has expressed an interest in AEA’s efforts on an application for Clean Coal V, but believes it may be excluded from participating because the request for statements of interest specified coal-fired electrical generation technology. The company’s Liquids From Coal (LFC) refining process takes lower rank coal and converts it to more valuable co-products of a natural gas substitute, a liquid similar to No. 6 fuel oil anda higher heat content coal with low sulfur and moisture. The LCF process could be part of a package which includes use of the upgraded coal in advanced boiler technology such as fluidized bed combustion. The gas could be used to fuel the LFC refinery or in a combined cycle to drive a gas turbine to generate additional electricity such as that proposed by Air Products and Chemicals Inc. The liquid fuel could be used for powering plants and industrial boilers, as transportation fuel or as a feedstock in the production of specialty chemicals currently derived from crude oil. In 1989, SGI and its partner ENCOAL Corp., a subsidiary of Shell Mining Co., submitted a proposal in USDOE’s Clean Coal III round which resulted in an agreement to construct and operate the first commercial LFC plant. The plant is located near Gillette, Wyo. The LFC process first uses a proprietary control system to analyze the coal which is then dried. From there, the coal goes into a pyrolyzer where heat is used to to remove the liquid and gas constituents including sulfur. NORTHWEST ALASKA COAL PROJECT POWER PLANT EVALUATION FA Ree rat September, 1991 Prepared For: Prepared By: Arctic Slope Consulting Group, Inc. Shia iines P.O. Box 650 6629 West Central Avenue Barrow, Alaska 99723 Toledo, Ohio 43617 ARCTIC SLOPE CONSULTING GROUP, INC. Engineers « Architects * Scientists * Surveyors TECHNICAL MEMORANDUM ON POWER PLANT EVALUATION FOR NORTHWEST ALASKA COAL PROJECT ENGINEERING FEASIBILITY STUDY SFT Sta, Inc. 6629 West Central Avenue Toledo, Ohio 43617 (419) 843-8200 TABLE OF CONTENTS Execucd vel Summary aceiiersislolefeisie cverels}eterere> efelelelebercheversrcnsions efenetereere 1.0 2.0 3.0 4.0 5.0 ENCE OGUCT LOM elelelerelelalevere tate fs a eb wo ler sete ecnee Introduction: --)./- seloielslelsicleieketslevolevalccieie elerelelslelsielelc)s Plant Configuration...........- alererelelelels miehercletelererene Environmental Issues........cccceee cle| al ohetlorel eles) els (cls Available Boiler Technology..........-- aielevetolstcletens Plant Size and Technology Selection.............. 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Dog (Mines... 3 scsiee « clere aieletclellors ieleliovellelekelerel eer Deadfall Syncline Coal Mine.........cccecccsoces 5 Conclusions... sloletelsiclelelsl cisieleloneroleielereisleleletorerelsleictele WW Www Ww AUP WNH Plant Description and Cost Estimate......eeeceeeseeces Introduetion.......... slalevelelololololeleoleloheioleloielelsieiolsyelelc Deseription of Contracts. ......cccccccccsccvccecs Plant Stating, oo. 6 cise ccvccicle s slsicvicieiels cleicicc celle Arrangement DrawingsS.....cccccccccccccccccsccssce Water) Supply. 6)... ccc ee clc wcccls acsic tices aeehes Sewer FACLLIty. 2... .ccccccccecscecccccccccscscccs Schedules crc sic c/ciol elec sioleliele ols late slalonshelelel elelslclelcvenerelol« PPh bP PP oe © © © ow NHDUPWNHE ConeLusiongieieclcie1e creole DO COOOSOOIOO DOO CUCU BD UOUOOOGGO UD TECHNICAL MEMORANDUM ON POWER PLANT EVALUATION FOR NORTHWEST ALASKA COAL PROJECT ENGINEERING FEASIBILITY STUDY EXECUTIVE SUMMARY A review has been made of the potential of utilizing Alaskan coal for generation of electrical power and district heating in northwest Alaska. The study has reviewed this potential at the City of Nome, the City of Kotzebue, the Red Dog Mine site and the Deadfall Syncline Mine site with transmission to Red Dog. A technology assessment has been performed which assumed use of a conventional Rankine cycle for power production. Results of this assessment indicate that the selection of spreader stoker steam generating equipment coupled with a conventional steam turbine-generator is the best choice. Should sulfur dioxide scrubbing be required at Nome and Kotzebue, consideration should be given to fluidized bed combustion technologies. Dry scrubbers have been selected at the mine sites. Selection of an air cooled condenser in lieu of a conventional condenser - cooling tower arrangement is based upon minimal water availability without significant performance degradation. A review of the present systems at Nome, Kotzebue, and Red Dog was performed. © From that information, forecasts of load requirements through the year 2004 were made. Included in these forecasts was the first phase of district heating. In Nome, the first phase would displace 126,000 gallons of fuel oil a year and in Kotzebue, 214,000 gallons. Red Dog presently heats from waste heat produced by the diesel generators. On the basis of this review, the following sizing criteria was developed: ii @ Nome: 10.5 MW electrical plus 5 million BTU/Hr district heating requiring 2 - 65,000 Lbs/Hr boilers, 28,100 tons per year of coal. @ Kotzebue: 5.7 MW electrical plus 5.3 million BTU/Hr district heating requiring 2 - 40,000 Lbs/Hr boilers, 18,100 tons per year of coal. @ Red Dog Mine: 16.5 MW electrical plus 40 million BTU/Hr district heating requiring 2 - 120,000 Lb/Hr boilers, 87,000 tons per year of coal. @ Deadfall Syncline Mine: 22 MW electrical requiring 2 - 120,000 Lb/Hr boilers, 87,000 tons’ per year of coal. Estimates were prepared for each of the plant sites. Pricing was solicited from various vendors for major equipment. The remainder of the estimates were prepared by SFT, Inc. Following are the estimated prices for the plants including district heating at Nome, Kotzebue, and Red Dog, sulfur dioxide scrubbing at Red Dog and Deadfall Syncline, and a 90 mile transmission line in the Deadfall Syncline estimate: @ City of Kotzebue: $32,520,000 @® City of Nome: $39,120,000 @ Red Dog Mine: $61,490,000 @ Deadfall Syncline Mine: $70,130,000 It is estimated that the period of construction would be 24 months for Nome and Kotzebue, and 30 months for the Red Dog and Deadfall Syncline mine sites. anil Manpower requirements were reviewed. It is expected that these plants will require staffing of 22 persons total, for alu shifts. iv 1.0 INTRODUCTION SFT, Inc. of Toledo, Ohio was retained by the Arctic Slope Consulting Group to develop information regarding the potential of burning Alaskan coal for power generation at various communities in northwest Alaska. This report presents the results of the study. The objective of the study is to develop sufficient information such that the Arctic Slope Consulting Group can make prudent decisions regarding the economic viability of use of coal as a fuel for power generation in northwest Alaska. The procedures used in performing the study follow: be Review status of existing generation, transmission and distribution systems at Nome, Kotzebue, and Red Dog Mine. 2. Review environmental issues. 3. Review applicable power generation technology. 4. Forecast future system electrical demand. Sie Size first phase of district heating. 6. Determine optimum equipment sizing for Nome, Kotzebue, Red Dog Mine, and Deadfall Syncline Mine 7. Estimate construction costs for each of the four (4) potential power plant sites. 8. Prepare the report. The report is arranged as follows: 1B The report proper which presents the essential results of the study in the following sections: @ Section 2 describes the technology assessment. @ Section 3 determines proper equipment sizing. @ Section 4 describes the plant descriptions and subsequent cost estimates. @ Final conclusions are presented in Section 5. The Appendix which contains supporting documentation. 2.0 TECHNOLOGY ASSESSMENT 2-1 Introduction SFT has reviewed the coal and ash analyses performed on the Deadfall Syncline coal by Commercial Testing and Engineering and by Idemutsi Kosan. Both these analyses indicate a reasonably good quality very low sulfur coal with a low ash content. The fuel appears to be similar to coals found in Utah and is classified as a high volatile bituminous coal. The ash analysis indicates a lignite-type ash classification, generally indicating a "younger" coal. Battelle, in a report dated March 16, 1989, reviewed the coal analyses and ran combustion tests in their facility. It was found that the coal burns well in both fluid bed combustors and in suspension. Mass burn, or stoker tests were not run. There were no problems with clinkering or slagging. Battelle ultimately recommended fluid bed combustion as the preferred technology and indicated that the coal is suitable for use in a suspension-fired furnace. Battelle, however, did not rule out burning this fuel on a stoker but did indicate that use of a stoker may result in clinker formation due to the low ash fusion temperature. SFT elected to review all technologies, particularly considering the fact that the combustion tests showed no evidence of clinkering or slagging. 2.2 Plant Configuration The requirements of this study are to review the available technologies assuming a conventional Rankine cycle, whereby steam is generated in a boiler by the combustion process, the steam then passing through a turbine-generator where electricity is generated and the steam then being condensed to water in a condenser unit and returned to the boiler to begin the process again. Steam turbine-generator technology does not vary in the size ranges being studied. There are several alternatives regarding boiler technology and condensers that need to be reviewed in order to make a proper selection. 2.3 Environmental Issues Today, technology selection for a project of this type is usually not only based on what is best based upon fuel, but is also based on what product can meet the environmental regulations in effect. Amendments to the Clean Air Act were promulgated into law in late October 1990. The amendments define the area for which the laws are applicable as the "States". States are defined as "State means one of the 48 contiguous states and the District of Columbia." It has, therefore, been determined that these amendments which include “acid rain" legislation do not apply to the State of Alaska. Discussions with the Alaskan Department of Environmental Conservation (DEC) indicate that the areas under consideration have achieved the National Ambient Air Quality Standards and that the areas are classified as Class II. Class II areas do not require any special consideration. It will be necessary to obtain a Permit to Install from DEC which generally takes 4 - 6 weeks. Should the facility generate relatively large amounts of regulated pollutants, a Prevention of Significant Deterioration (PSD) review would be required and Federal EPA review of the permit application would occur. A PSD permit will take more than a year to obtain according to DEC. Whenever a PSD review occurs, the facility plans must demonstrate meeting Best Available Control Technology (BACT). BACT requires a review of all similar installations and a determination of what is being done in those installations to reduce poilutants. PSD is triggered when emissions of any regulated pollutant exceed 250 tons per year for "grass roots" sites or the following increment above present levels (based upon actual emissions over the prior two (2) years) for modified existing sites: Increment Pollutant Tons/Yr Particulate LS) Nox 40 co 100 voc 40 SO, 40 It is our opinion that we can conclude that these power plants being considered are not a modification to an existing plant but are indeed grass roots. Of course, in order to do so, it will be necessary to locate the new coal plants physically away from any existing plants. Based upon our review of potential sites, this is certainly feasible and probable. In order to avoid PSD review, it will be necessary to limit the operation of the equipment such that the 250 ton per year limit is not exceeded. This should not be a significant problem for the Nome and Kotzebue sites because the demand for electricity and district heating is seasonal during the day, or, in other words, the equipment does not have to operate at full capacity 24 hours per day, 365 days per year. The situation at the Red Dog Mine is potentially a bit different. While the heating load is seasonal, the electrical load is not, typical for any heavy industry. The installation at Red Dog (or at the coal mine with transmission to Red Dog) may require PSD review. A PSD review, as previously stated, will require that the site install Best Available Control Technology. In the case of the smaller units that would be located in Nome and Kotzebue, should they be subject to PSD review, this would require meeting an SO, emission standard of 1.2 Lbs/million BTU which can be met because of the sulfur content of the coal under consideration. Should SO, reduction be required under any new law, this can be accomplished by either use of an SO, scrubber or fluid bed technology. For the larger equipment to be located at Red Dog or the coal mine, 90% reduction of SO, would be required. A review of recent permits issued indicates that essentially all units installed in the capacity range being reviewed for Nome and Kotzebue are using low sulfur coal as BACT for emissions. 2.4 Available Boiler Technology The generally accepted means for combusting coal for power generation today considering the conventional Rankine cycle are fluid bed (both bubbling and circulating), pulverized firing and stoker firing. Each offers advantages and disadvantages. The fluid bed boiler industry in the U.S. has been an outgrowth of use of the technology in Europe. The technology was developed to be able to utilize the poor quality coals readily available in Europe. The U.S. industry accepted the technology generally out of frustration with poor operating characteristics of wet scrubbers and limited success with dry scrubbers; both for sulfur dioxide removal. It should be noted that minimal work was done in Europe on sulfur dioxide reduction in fluid bed units. Acceptance in the U.S. has been slow, with about 150 units sold in the past 7 - 10 years and approximately 50 in operation, the majority of the smaller units without SO, reduction. Present U.S. experience on fluid bed boilers has been poor to fair; with significant problems in the areas of fuel handling, erosion and other areas. It is expected that the next generation of fluid bed units will perform better. The advantages of using fluid bed boilers are as follows. The fluid bed has the capability of calcining limestone, whereupon the calcium oxide reacts with the sulfur dioxide being formed and becomes calcium sulfate, a solid. The solid can then be removed by conventional means. In addition, due to relatively low combustion temperatures, nitrous oxides, as well as slag are not formed. Typical nitrous oxide emissions are guaranteed to not exceed 0.4 Lbs. per million BTU input, which will meet the New Source Performance Standards. Properly designed fluid bed units have demonstrated an ability to handle various waste fuels, including wood, municipal refuse, agricultural wastes, tires and others. Disadvantages of fluid bed boiler include the following. The fluid bed is sensitive to fuel sizing. Large amounts of fines tend to increase carbon carryover and therefore reduce efficiency. Fluid bed units typically cannot turn down (reach low loads) due to the air requirements of keeping the bed fluidized and in addition, are slow following load swings. Fluid beds have relatively complex fuel and material feed systems which complicate operations. There is insufficient data available regarding reliability and maintenance costs in order to be able to accurately estimate life cycle costs. Fluid bed units have also shown themselves to be high auxiliary power users. A survey of several fluid bed boiler manufacturers in the U.S. indicates that generally, the size range being considered for Nome and Kotzebue is smaller than the majority of U.S. and European installations. Competitiveness, with other technologies, would be poor. There is one (1) manufacturer of bubbling fluid bed type units who claims competitiveness in the size range being considered for Nome and Kotzebue. This manufacturer has limited experience burning coal and limited experience with SO, reduction. However, should it be necessary to meet significant SO, reduction (90%+), all manufacturers will be examined further. Concerning Red Dog, however, which will require SO, reduction and is to be a larger installation than the villages, fluid bed technology is an option that should be considered to a greater degree than Nome and Kotzebue. Pulverized coal (PC) boilers have been in service in all types of plant for many years. Several thousand have been installed in the U.S. with several more thousand installed throughout the world. PC units are used in all major coal fired power generation facilities in the world. PC units can be found burning a variety of coals, from lignite to anthracite. PC units offer several advantages. A PC boiler will have an excellent load response with an acceptable turndown rate. While a PC boiler can burn a wide range of fuels, it must be designed for the types of fuels expected otherwise slagging and fouling will occur. PC units typically have high availability and are considered quite reliable and as indicated above, PC firing is a demonstrated technology. Certain disadvantages also exist with PC fired boilers. An auxiliary fuel, such as oil or gas, is required to start the unit. PC units generally have medium to high (but not as high as fluid beds) auxiliary power use. Generally, PC units get very expensive as size of the unit decreases. The PC unit generates more NOx than other technologies and does require auxiliary equipment in order to reduce SO,emissions. Typical NOx emissions are 0.6 Lbs. per million BTU input which will meet New Source Performance Standards. The manufacturers of pulverized coal units in the U.S. do not recommend this technology in smaller capacities. Small (under 100,000 pph or 10 MW) PC units are very difficult to find. Use of PC technology would be better suited at Red Dog than at Kotzebue or Nome. The third type of unit being reviewed is a stoker fired boiler. Stoker units have been in service for many years, being the oldest technology for coal burning. Stoker themselves, however, have seen significant improvements over the years. There are several thousand new as well as old stoker fired boilers throughout the U.S. as well as the world. Stoker units can be found burning a wide variety of fuels, including all types of coal, wood, refuse, waste materials, and others. This can be done as long as the stoker itself and the boiler are properly designed for the fuel to be encountered. The stoker unit can be considered to be reliable with very good availability. Stokers do have a reasonably good load response, somewhere between fluid beds and PC units. Stoker units are the simplest and most forgiving, of the three (3) technologies being reviewed, to operate. Generally, one can expect low maintenance costs and low auxiliary horsepower requirements on stoker fired boilers. Stoker units are to be considered demonstrated technology. Stoker units do generate less NOx than PC units. Typical NOx emissions are 0.5 Lbs. per million BTU input which will meet the New Source Performance Standards. Along with advantages of stoker boilers come some disadvantages. The major disadvantage of stoker units is that they are, like fluid bed units, sensitive to coal sizing. Generally, coal must be double screened to remove both large and small particles prior to burning in a stoker unit. Like the PC unit, there is no inherent capture of SO, and therefore, auxiliary equipment would be required for SO, reduction. All manufacturers surveyed indicated stoker firing would be the technology of choice for the scenarios being reviewed. While there is some concern regarding clinkering and slagging potential, proper design and selection of equipment would overcome these problems. The manufacturers indicated that the products would be highly competitive and relatively easy to install. In some instances, complete shop assembly could be accomplished. A table summarizing the three (3) technologies reviewed follows: —waeaeses=————a———————eooqS=So ESS BOILER TECHNOLOGY nm RR Stoker PC CFB NOx Generation Medium High Low (0.5 Lb/MMBTU) | (0.6 Lb/MMBTU) | (0.4 Lb/MMBTU) Inherent SO, No No Yes Capture Auxiliary Power Low Medium High Usage Sensitivity to Yes No Yes est Size | Complexity of Simple Average Complex Operation a Experience in Yes Limited Limited Units less than | 100,000 pph | Maintenance Low Medium High Cost Load Response Fair Good Poor : Turndown Fair Good Fair Boiler 85% 87% 85 - 86% Efficiency It should be noted that if lower NOx levels (below those shown in the table) are required due to local restrictions, a non- selective catalytic reduction system would be required. It has been assumed that this is not the case. 2.5 Plant Size and Technology Selection Plant electrical generation is to be detailed elsewhere in this report. A summary of the requirements is listed below on a location basis. Along with the requirements is a discussion of the technologies suitable for the size range and a recommendation of the best selection. The selection is generally based upon ability to meet environmental regulations, estimated installed cost, reliability, operational costs including performance ease of operations and size and weight. District heating requirements are to be detailed elsewhere in this report. As a summary, district heating requirements are based on a phased approach. Plant sizing requirements would increase dramatically if it were necessary to provide sufficient capability for an entire city such as Nome or Kotzebue. This large load would not match well with the present electric load, and in essence, the plants would become heating plant with electricity as a byproduct which, because there presently are no or minimal heating customers, may make financing difficult. 2.5.1 Nome The projected median electrical load growth for Nome shows a growth rate of 0.6% on energy and 0.5% on peak electrical demand after the acquisition of the gold Mines’ electrical requirements. Looking at a 10 year window from a 1995 startup, it is expected that Nome will have an electrical peak of 9.55 MW and net generation requirements of 40,716 MWH in the year 2004. Regarding district heating, it is reasonable to assume a phased approach as will be discussed elsewhere. For purposes of equipment sizing, the first phase would be expected to displace approximately 125,900 gallons of oil per year. On the basis of the above, approximately 115,000 pounds of steam per hour would be required to meet the maximum electrical and district heating loads. In order to assure reasonable reliability, normally two (2) 55% capacity boilers would be recommended driving one (1) steam turbine. It is recommended that the primary technology be stoker firing, or more particularly, spreader stoker. Should SO, scrubbing be required, either a dry scrubber utilizing lime or a venturi scrubber utilizing alkali technology could be utilized. 2.5.2 Kotzebue Projected electrical load growth for Kotzebue indicates that by the year 2004, peak electrical requirements will be approximately 5.2 MW with net generation of 25,500 MWH. District heating would be phased as it would be at Nome. Presently, it is expected that the first phase would displace 214,000 gallons of oil per year. On the basis of the above, it is expected that approximately 70,000 pounds of steam per hour would be 2 2 Alf) required to meet the maximum electrical and district heating loads through the ten (10) year planning period ending in 2004. Again, in order to assure reasonable reliability, two (2) 55 percent capacity boilers would be recommended driving one (1) steam turbine. It is recommended that the primary technology be spreader stoker firing. However, because availability of water is a serious problem in Kotzebue, should SO, major reduction be required, fluid bed technology may be the only viable solution. Should process water become available, a stoker unit with either a dry or alkali scrubber would be preferred. 2.5.3 Red Dog A power plant located either at the Red Dog mine or at the coal mine with transmission to Red Dog would be required to meet all load requirements of the present diesel plant installed at the Red Dog facility. Present installed capacity at Red Dog is 25 MW of diesel generation and approximately 40 MMBTU/Hr of waste heat recovery. At times of high power use, no more than three (3) of the five (5) diesels are presently used, one (1) being held as backup and one (1) considered as under repair. It is expected that approximately 215,000 Lbs/Hr of steam generation will be required to meet peak load. PSD review will be required in this instance, and we can expect that 90% SO, reduction will be necessary. Zed It is recommended that the technology considered here be spreader stoker firing based upon two (2) 55% capacity boilers with SO, reduction by dry scrubber in order to be similar to Kotzebue and Nome such that spare parts and operator training would be simplified and based upon sufficient process water available in the area. Should process water not be available (25 - 35 gallons per minute), then circulating or bubbling fluid bed technology would be preferred. 2.6 Condensers There are several means for providing the cooling media necessary to remove heat from the low pressure steam exhausting from the turbine. Water and air, and in some instances a combination of both, are the mediums used for this purpose. Most conventional power generation plants utilize water as the cooling medium. The water circulates through tubes in a heat exchanger while the hotter steam circulates around the tubes. The steam is condensed and collected. The circulating water is either sent to a cooling tower where it is cooled and re- used or sent back to the source such as a river or large lake. Water loss is significant with a cooling tower and it must be made up by local sources. In the case of Nome, expected cooling tower losses would be approximately 600 gpm. In regard to Kotzebue, 300 gpm and Red Dog, 1,000 gpm. Another method of cooling is by the use of air. This would seem to be most appropriate for the climate conditions encountered in Northwest Alaska. The exhaust steam from the turbine flows through a series of finned tubes exposed to air. The air is forced around tubes by multispeed fans and cools and condenses the steam. There is no water loss and therefore 2) =) 12 no makeup water requirements. The only concern regarding air cooled condensers would be freezing during harsh weather, however, this can be avoided by proper design. Hot weather would degradate performance, which would not occur in Northwest Alaska. Generally, a rankine cycle power plant can improve cycle efficiency by lowering the pressure at the exhaust of the steam turbine. However, this exhaust pressure is a function of the temperature of the cooling media utilized to condense the steam; the lower the cooling media temperature, the lower the exhaust pressure and the cycle efficiency improves. A plant that has the capability of utilizing once through cooling by use of a river or large lake usually has a fairly constant cooling water temperature that typically does not exceed 70 F. A turbine backpressure range for this situation would be 1-1/2" Hg to 3" Hg. A plant that utilizes circulating cooling water where the water is subsequently cooled in a cooling tower, cool make-up added and then returned, generally has a turbine backpressure in the 2-1/2" - 4" Hg range. Plants that utilize air cooled condensers are affected much more by ambient temperatures. Utilizing the ambient temperatures expected at the sites under discussion, turbine backpressure will range from 2-1/2" to 5" Hg, with the higher backpressures occurring in the summer. Yearly average backpressure is expected to be 3-1/4" Hg. As can be seen, it is expected that use of an air cooled condenser will result in slight degradation of average yearly cycle efficiency. However, the significant losses will occur Zaha Ls) in the summer, when the unit is lightly loaded, thereby mitigating the loss. Both air and water cooled systems utilize multiple fans, typically dual speed, to assist in control of backpressure. In addition, sections of an air cooled condenser or a cooling tower can be isolated in order to assure proper control can be maintained under any climate condition. The air cooled condenser is more versatile in that it has several more fans than a cooling tower and therefore, is easier to control A condenser - cooling tower system would include the condenser, condenser foundations, hotwell, condensate pumps, circulating water piping, circulating water pumps, cooling tower, cooling tower foundation, cooling tower fans and controls. An air cooled condenser system would include the steam line to the condenser, condenser foundations, hotwell, condensate pumps, condenser, condenser fans and control. It is expected that the air cooled condenser system would be less costly on an installed basis. However, there would be slightly higher parasitic power use to the number of fans, thereby resulting in an increase in operating costs. Based on the above and the high cost of water, it is our recommendation to proceed on the basis of use of air cooled condensing at all plants. 2.7 Conclusion A review has been performed of technologies available for production of electricity and district heating utilizing a conventional Rankine cycle. Present environmental regulations 2110 Le have a major impact on the technology selection. The recent Clean Air Act amendments do not apply to the State of Alaska. Various vendors have been surveyed and it has been determined that minimal experience exists regarding fluid bed boiler technology in this size range. Pulverized coal firing is a non-competitive technology in the boiler capacities required. All vendors who manufacture stoker fired boilers indicate that this is the technology most suited and most competitive in the capacities necessary for Nome and Kotzebue. SFT, assuming conservative boiler sizing and grate release rates, concurs. Should sulfur dioxide reduction be required, small dry scrubbers as well as alkali venturi scrubbers are available. It should be noted that it will be necessary to process the coal at the mine site prior to shipment. The processing for stoker units will involve crushing and double screening of coal to remove large pieces and small fines. The processing for fluid bed units, should they be selected, would involve crushing and single screening to remove small fines. Pulverized coal units would require no processing. The balance of plant equipment, including the turbine- generator would be of conventional design, with the exception of the condenser - cooling tower system. Rather then use of a water cooled condenser with circulating water then cooled in a cooling tower, it is recommended that an air cooled condenser be utilized. An air cooled condenser requires minimal makeup water as compared to a conventional condenser - cooling tower arrangement. 2-15 3.0 EQUIPMENT SIZING 3.1 Introduction Power plants of this nature typically take several years from initial conception to final commercial operation. Construction alone, from time of purchase of the major equipment such as boiler and turbine-generator to construction completion typically amounts to over 20 months. When considering the time required for review of the various studies and preliminary plans, as well as the time required for arrangement of financing, it is reasonable to assume that initial operation of the various plants under consideration will occur in 1995. Typically, it is prudent to incorporate into the design of major capital equipment the ability to meet present and future needs such that the needs can be met for a reasonable period, generally ten (10) years. For that reason, plant sizing should be based on meeting the electrical needs as forecast for the year 2004, including any known expansion and growth. District heating, in deference to the above, requires a different method of analysis. In order to provide equivalent heat from a central heating plant capable of meeting the district heating needs of an entire town would require a very large increase in the initial investment in capital equipment. For example, the City of Nome utilizes on the order of 2,000,000 gallons of fuel oil per year for heating. This is approximately 30,000 MMBTU per year of energy or an average of 34 million BTU per hour, which would be expected to peak at about 60 million BTU per hour. This is equivalent of being able to produce approximately 5,500 KW of electrical power, which amounts to, in essence, a 50% increase in plant size due Soe to district heating over the requirements of electrical production. To be considered is the fact that the residents must be convinced of the viability of district heating particularly in regard to reliability. Due to these reasons, most district heating systems have been based upon a phased approach, with the first phase typically including buildings and residences physically near the power plant and also possibly potential major users. Once reliability and decreased cost is demonstrated, additional phases are constructed. It is recommended that plant size be based upon a phased approach to district heating. Generally, rankine cycle equipment ranges in pressure and temperature of the steam produced. The actual choice of a pressure and temperature is dependent upon several factors. This includes such items as size, cost, complexity, and efficiency. While higher pressures and temperatures generally result ina better cycle efficiency, availability becomes more difficult and cost increases as does complexity. It is for these reasons that units under 50 MW in size typically do not exceed 1,250 psig and 950 F, units under 25 MW in size generally do not exceed 900 psig and 900 F and units 15 MW and under are usually either 600 psig, 750 F or 425 psig, 750 F. These generalizations should then be examined based upon the particular situation. One significant concern is boiler water quality. As boiler operating pressure increases, the requirements for higher guality also increase. There is a break point at 900 psig where units at or above this pressure typically require mixed Sae2 bed demineralized quality water while units below this pressure utilize water quality associated with the simpler and less costly sodium zeolite system. Another concern is materials and associated labor. Temperatures exceeding 750 F require a piping material change to alloy. The higher the temperature, the more alloy used until stainless steels are reached. Higher alloy content piping and valving are more difficult to obtain, cost more and are much more difficult to weld, requiring heat soak periods and stress relief which in turn means better labor skills and more equipment. It is recommended that all units at all locations being examined be designed for production of steam at 600 psig and 750 F. The potential increase in cycle efficiency to increase pressure or temperature is outweighed by cost complexity and availability as described above. 3.2 Nome 3.2.1 Present System The City of Nome owns and operates its own electrical system under the auspices of the Nome Joint Utility System (NJUS). The NJUS operates two (2) power plants, one (1) located adjacent to the Snake River and west of town the second smaller plant located at Beltz High School which generally operates unattended. There are seven (7) diesel generator sets located at the main power plant as follows: GENERATOR SIZE (KW) General Motors GMD 2,800 General Motors GMD 1,500 Fairbanks Morse 1,000 Cooper Bessemer 1,200 Cooper Bessemer (3) 600 (each) Jacket cooling water is utilized to heat the City’s potable circulating water loop. The plant was built in the mid-1950s and has been added to throughout the intervening years. NJUS is in the process of installing a new 3,700 KW diesel generator to augment existing capacity and possibly retire some of the older units. The Beltz High School plant consists of a single unattended diesel generator set manufactured by Mitsubishi at 600 KW capacity. The heat rejected from this engine is utilized to heat the Beltz school. 3.2.2 Electrical Sizing Electrical load has grown steadily in Nome for many years. The past ten (10) years data is shown below and graphically in Figure 1. ee HISTORICAL ELECTRICAL LOAD - NOME YEAR ENERGY (KWH) DEMAND (KW) 1980 15,738,600 3,150 1981 16,254,600 3,180 1982 18,090,400 3,500 1983 19,257,300 3,600 1984 20,478,100 34 700 1985 21,818,000 3,950 1986 22,491,600 3,900 1987 22,748,500 4,050 24,056,200 27,459,400 The analysis of this data indicates an average energy growth rate of 6.4%, well above the U.S. norm. Nome’s electrical use peaks in winter. Also, there is a significant decrease in requirements in the summertime, a bit unusual as compared to most U.S. cities. Monthly generation for 1989 is shown in Figure 2. In the past few years, Nome has been assuming portions of the load of the various gold mining companies in the area, which has partially accounted for the high average growth rate of over 6%. Presently, the majority of the gold mining companies generation is by in-house diesels owned and operated by each of the mining companies. Based upon discussions with the NJUS management, it is reasonable to assume that the NJUS will serve the electrical needs of the gold mining companies within the next few years. Should the cost of NJUS generated electricity decrease due to use of coal as a fuel, then it becomes even more probable that the gold mining loads will be served by the NJUS. This conclusion has been supported at length in a recent report outlined "Nome Electrical Load Forecast" dated October 26, 1990. This report does predict load growth for Nome on the basis of non-mining generation, mining generation, and a combined total. Sufficient work was done studying the demographics of the area such that a conclusion was reached that shows three (3) cases, a low forecast, a mid-forecast, and high forecast. The report indicates that there is a 50% probability that the mid-forecast will indeed become the actual load. The three (3) forecasts are shown below for reference. It should be noted that the growth rate decreases significantly, to 0.6% on energy and 0.5% on demand, after the acquisition of the gold mine company’s load. ace te AMER SEN AN AMAR MINING + NON-MINING LOAD GROWTH PLETED IO INTE ELL IDET TELE DBOE LE IDEA SaaS sss Year Low Mid High (MWH) 1995 28,534 37),065 56,194 1996 28,694 Siipits 56,408 1997 28,759 38,301 56,773 1998 29,084 38,812 57,143 | 1999 29,389 39,273 58,866 2000 29,837 39,742 60,046 2001 29,868 39,763 60,888 2002 30,081 39,991 61,352 2003 SOR So, 40,278 61,994 2004 30,701 40,716 62,975 Fig It is our belief that the mid-forecast does represent a reasonable expectation of the Nome load requirements in the future. It would, therefore, be recommend that the electric plant output be sized for 40,716 MWH with a peak load of 9.55 MW as predicted for the year 2004. 3.2.3 District Heating Presently, the NJUS does recover heat from diesel jacket water and heats the City’s circulating water loop. In addition, the Beltz High School installation’ also recovers heat from diesel jacket water in order to heat the school. There is no other district heating or supplemental heating from power plant operations. All other heating in Nome is done with diesel fuel in local heaters amounting to over 2,000,000 gallons per year of use or 300,000 million BTU per year. Since this equates to approximately 5,500 KW or 58% of the electrical requirements, it seems prudent to size the district heating to meet the requirements of Nome in a phased approach. The first phase would show the feasibility as well as the cost saving of the system. The first phase, therefore, should be well planned and should service major heat users near the power plant and be capable of future expansion. Proposed, therefore, is sizing such that the following Bering Street buildings would be serviced. Bonanza Auto Hanson Trading Company Police/Fire Station Public Works Garage Lutheran Church Professional Building N.S.H.C. Hospital Community Health Services Hospital Warehouse The above buildings require 125,900 gallons of fuel oil, per year or 17,626 million BTU per year. Peak hourly requirements amount to approximately 5 million BTU per hour including losses which is what the district heating system would be required to produce. It is not expected that the heating load for these buildings will vary over the next fifteen (15) years. Domestic water heating is expected to continue by use of stack heat recovery or condenser heat recovery adding an additional 10,640 million BTU per year or 1.2 million BTU per hour to the above figures. Future phases would continue on a route on the north side of Nome to include the Community Center, apartment building and elementary school as well as a route along Front Street in order to service the commercial establishments and businesses located there. In addition, other phases would be intended to service the various residences throughout Nome. The district heating system design would be similar to that proposed in various other studies and reports on this subject, the latest being the "Nome Waste Heat Recovery Report and Concept Design" as prepared by Fryer/Pressley Engineering, Inc. 3.2.4 Summary On the basis of the above information, it is necessary for the coal fired power plant to produce a peak electrical load of 9.55 MW (winter load) which could be coincident with a peak district heating load of 5 million BTU per hour. Production of a net 9.55 MW would require a fuel input of approximately 135 million BTU per hour. Projected demand, electrical consumption, and coal use is shown in the following table. PROJECTED ELECTRICAL AND COAL USE CITY OF NOME | TALE TES RS: Ge li Ne LA TT TCT TE TT, ee 2003 9.5 Demand Energy Coal Use Year (MW) (MWH) (Tons/Yr) 1995 8.9 37,005 25,000 1996 9.0 Sas 25,900 1997 Sel 38,301 26,300 1998 9.2 38,812 26,700 1999 9.3 39,273 27,000 2000 9.4 | 39,742 27,200 40,278 27,700 2004 | 9.5 40,716 28,100 See The district heating energy requirement, which would be serviced from a turbine extraction, would improve the overall cycle efficiency due to less steam flow to the condenser. Therefore, while we would normally expect to provide fuel energy to the boiler higher than the district heating load to account for losses, we do not need to due to the cycle efficiency gains. It is recommended that the Nome coal fired power plant be sized such that total maximum fuel input be 140 million BTU per hour. This is equivalent to a boiler(s) 3))—1) LO Sea producing 115,000 pounds per hour (pph) of steam and a steam turbine-generator capable of generating 10.5 MW gross electrical generation. A cycle diagram is shown in Figure 5. Kotzebue 3.3.1 Present System The Kotzebue Electric Association (KEA) provides electrical service to the area at the tip of the Baldwin Peninsula. This fully encompasses the City of Kotzebue. The KEA is a Rural Electric Administration (REA) cooperative not subject to the administration of the municipal government as is Nome. The KEA operates one (1) power plant located within the confines if the City of Kotzebue. There are five (5) diesel generators and one (1) combustion turbine-generator located at the plant as follows: KW Generator Size White Superior (ay 500 (each) General Motors GMD 2,500 General Motors GMD 1,700 Caterpillar LlsS Ie Solar (combustion turbine) 900 ao ae ® While several waste heat recovery system have been designed and installed in Kotzebue, presently, minimal waste heat recovery from the equipment at the power plant is occurring. 3-11 Electrical load growth in Kotzebue has been fairly steady over the past ten (10) years. The data is shown below and in Figure 3. et mnmeanaee arettansiion ae nnraenirennennnteanneenemnantenane HISTORICAL ELECTRICAL LOAD - KOTZEBUE YEAR ENERGY (KWH) DEMAND ( KW) BEN OSEGCEL 1980 10,626,900 2,105 fe 1981 11,530,600 2,150 1982 12,249,300 2,240 1983 13,668,400 2,668 1984 14,703,000 2,662 1985 15,999,200 2,665 1986 16,101,400 3,005 1987 16,222,900 3,455 1988 16,235,000 3,005 \ IN y v 1989 16,981,000 3,425 ee The average energy growth rate over the past ten (10) years is 5.4% which is also well above the U.S. norm for the same period. Kotzebue, like Nome, has its electrical peak in the winter, with significant decreases during the summertime. Monthly generation for 1989 is shown in Figure 4. soos Recent projections performed by KEA (Power Requirements Study - March 1989) indicates that a growth rate of 2.7% in electrical use is expected through the year 1997. The reason the growth rate is less than the historical growth is that it is expected that both small and large commercial use will not increase significantly over the planning period. This is evidenced by the past five (5) year’s data which shows a growth rate significantly below the ten (10) year average. It is, therefore, reasonable to assume that the growth rate as predicted in the Power Requirement Study is acceptable and can be extrapolated through the year 2004 even though the study only predicted growth through 1999. On that basis, plant capability should be 26,345,000 KWH per year with a peak of 5,200 KW. 3.3.2 District Heating Presently, the KEA does minimal heat recovery from power plant operations but does intend on reactivating a heating system which will assist in heating domestic potable water in the wintertime. All heating in Kotzebue is done with diesel fuel in local heaters amounts to well over 1,000,000 gallons per year of fuel use. As previously stated, a district heating system should be designed such that a phased approach is taken in order to prove feasibility and reliability and also not have a major impact on the capital costs of the power plant project. It is recommended that the system be sized to meet the needs of major users near the power plant and also be sized such that expansion can occur in the future. s0— 3 Proposed, therefore, is sizing such that the following buildings would be serviced: New Hospital A.C. Company Store KIC Apartments Senior Center Public Works Water Treatment The above buildings and water system require 214,200 gallons of fuel oil per year or 29,988 million BTU per year. Peak hourly requirements are 5.3 million BTU per hour. The water system would not be able to be heated from stack or condenser waste heat because the water treatment plant is located far from the proposed coal fired power plant location. Future phases would include a southerly loop to incorporate the NANA Museum, KIC apartment building and various airport buildings. Northerly phases would incorporate the various schools, armory, recreation center, buildings on Shore Avenue and ultimately residences. The district heating system design would be similar to that proposed in various other studies and reports, the latest being "Kotzebue Waste Heat Recovery Report and Concept Design" as prepared by Fryer/Pressley Engineering, Inc. 3.3.3 Summary Based upon the above information, the proposed coal fired power plant would need to produce a peak electrical load of 5,200 KW which could be coincident with the peak district heating load of 5.3 million BTU per hour. As 3-14 previously indicated, district heating energy would improve overall cycle efficiency by reducing losses from the condenser. It is recommended that the Kotzebue coal fired facility be sized such that total maximum fuel input be 88 million BTU per hour. This is equivalent to a steam production of 70,000 pph and a steam turbine-generator producing 5.7 MW gross electrical generation. Projected demand, electrical consumption, and coal use is shown in the following table. PROJECTED ELECTRICAL AND COAL USE CITY OF KOTZEBUE Demand Energy Coal Use | Year (MW) (MWH) (Tons/Yr) 1995 4.2 | 20,730 14,250 1996 4.3 21,296 14,600 1997 4.4 21,863 15,000 1998 4.5 22,453 15,400 1999 4.6 23,059 15,850 2000 4.7 23,682 16,300 2001 4.9 24,321. 16,700 2002 5.0 24,978 17,260 2003 Sal 25,1052 17,600 2004 Se2 26,345 18,100 - ) ae eee: A cycle diagram is shown in Figure 6. 3.4 Red Dog Mine The present installed capacity at the Red Dog Mine is 25 MW of diesel generation, made up of five (5) Wartsila 5 MW diesel generators. Significant waste heat is recovered from jacket water, turbocharge cooling, and exhaust gases amounting to 40 million BTU per hour. Generally, the electric load at Red Dog does not exceed 9 MW, but when full production is reached, 12 - 15 MW will be required. It is not expected that this will change through the planning period; the year 2004. This is equivalent to boiler production of 215,000 pph of steam which will meet the heating and electrical load needs and a steam turbine-generator capable of generating 16.5 MW gross electrical generation. This would require approximately 65,000 tons per year of 12,000 BTU coal. A cycle diagram is shown in Figure 7. 3.5 Deadfall Syncline Coal Mine Another possible power plant location would be at the Deadfall Syncline coal mine site. This plant would generate sufficient electricity to service the Red Dog Mine at its maximum requirements of 15 MW. Transmission from the Syncline to Red Dog would be by 138 KV overhead transmission line. Preliminary routing indicates that approximately 85 miles of line would be required. Generation would occur at voltage of 13.8 KV (which is typical for this size of generator), be stepped up to 138 KV for Si) 6 transmission and then be stepped down at the Red Dog site to the voltages required for plant operation. The losses associated with the transformation and transmission are expected to be approximately 500 KW. Therefore, boiler production would be 220,000 pph of steam with electrical production of 22 MW assuming that Red Dog converts to electrical heating. Boiler production would be 170,000 pph of steam and with 17 MW of electrical production should Red Dog convert to some other method of heating. The larger unit would require approximately 87,000 tons per year of coal and the smaller unit approximately 65,000 ton per year. A cycle diagram is shown in Figure 8. 3.6 Conclusion Based upon various projections of growth, it is recommended that the coal fired power plants be sized to produce the following: @ Nome: 10,500 KW gross plus 5 million BTU per hour district heating energy. @ Kotzebue: 5,700 KW gross plus 5.3 million BTU per hour of district heating energy. @ Red Dog Mine: 16,500 KW gross plus 40 million BTU per hour of district heating energy. @ Deadfall Syncline Mine: 22,000 KW gross including sufficient electrical production for plant heating. Sew <Qnarae 30000000 25000000 20000000 15000000 10000000 1980 1981 1982 MME MISTOMA. ELECT LON) 1963 Me SS —= 1964 1985 ENCRGY 1986 1987 19869 6000 5500 5000 4500 0 4000 3500 3000 Pigure 1 3100 4000 2900 DEMAND —_ | - a 3500 ( 0 E 2500 ! [ 3000 {4 R A Y 2300 D 2500 M2200 ENERGY u kK H 1900 ~ 1700 1500 1500 1000 JAN FEB MAR APR MAY JUN JUL AUG SEP ocT Nov DEC Figure 2 KOLILUE HISTOMC LLECTIUCAL LOAD 17000000 3600 16G00000 CNERGY __ = 3200 [ 15000000 N D [ jooo [ R 14000000 M c A ; 2800 13000000 a i K ~~DEMAND 2600 . kK H 12000000 " 2400 11000000 2200 10000000 eses 1980 1981 1982 1983 1984 19865 1986 1987 1968 19869 Pigure 3 LIED CLMELATION-KOLL 2000 2600 1900 2400 ae DLMAND 2200 £ 1700 0 N ( E 1600 2000 ‘ N : 1500 1s00 = [) jy 2400 K 1600 W W H 1300 ~ 1200 i ———-_- TMERCY aoe 1200 1100 1000 1000 JAN FED MAR APR MAY JuN JUL AUG SEP ocT NOV DEC Figure 4 GENERATOR FROM = J Ee wn > wn oO = e <= uw < EXCHANGER BOILER AIR COOLED CONDENSER i DEAERATOR | Own 5 LOW PRESSURE g TN HEATER HIGH i , BOILER PRESSURE HEATER PULP pe i store emai cr pele tek pega red opens arbor mS 102-0501 FIGURE 7 tear, ner cannot be coplea or repreauced [OWRD Jf [04-09-91 CYCLE DIAGRAM eee express written permission o| a le : RED DOG MINE DOG MINE jaro: Prt |04- SCALE: PROJ. /CONTRACT NO.] ORANING NO. SFT, Inc. Consuing Ie ngins ess GFT NONE 9058-00-00 | _905800-mrP-001 THN GAG AANN aly GENERATOR FROM DISTRICT HEATING SYSTEM HEAT EXCHANGER BOILER CONDENSER TO DISTRICT HEATING SYSTEM BLOWDOWN BOILER FEED PUMP ARCTIC SLOPE CONSULTING GROUP NOTICE: thie deowing ond ot Information con- Toman: SMR [02-05-91 FIGURE 5 lolned thereon le contidentlol ond proprietory to SFT, Inc. It connot be copled or reproduces {cKO FPP 104-09-91 CYCLE DIAGRAM shneul the express written permiesion of rcu'xo: Be 104-09-91] : fare"0: rex JO4-09-9T MRE ALASKA SCALE: PROJ. /CONTHACE NO.) ORANWING NO. SFT, Inc. Consulting Eosineces GFT) NONE 3058-00-00 | 905800-MxP-002 D:\905800\ M002 GENERATOR ROM DISTRIC HEATING SYSTEM HEAT EXCHANGER TO DISTRICT HEATING SYSTEM BOILER CONDENSER i DEAERATOR } BOILER FEED PUMP EP =p NOTICE: This drowing ond oll Informotion con- toined thereon le contidentiot ond proprietory BLOWDOWN ARCTIC SLOPE CONSULTING GROUP a ee FIGURE 6 CYCLE DIAGRAM -KOTZEBUE+ ALASKA. SCALE? PROJ./CONIRACT HO.) DRANING NO. NONE 9058-00-00 905800-MRP-003 raat 9P—Joa-03-31 SFT, Inc. Consulting Engineers GFT lo SFT, Inc. It connot be copled or reproduced without the expreas written permission of SFT, Inc. BOILER BLOWDOWN HIGH HEATER PRESSURE GENERATOR AIR COOLED CONDENSER LOW RESSURE HEATER BOILER FEED PUMP ARCTIC SLOPE CONSULTING GROUP NOTICE: This drowing ond oll Informotion con- toined thereon Is contidentio! ond proprietory FIGURE 8 to SFT, Inc." connot be copled or reproduced CYCLE DIAGRAM without the express written permission of am ia Seknacae We aaer™ SFT, Inc. DEADFALL_SYNCLINE MINE SCALE: PROJ. /CONTIRACT NO.] DRAWING ND. SFT, Inc. Consulting Eooines:s NONE 9058-00-00 | 905800-MRP-004 D:\ansAnn\ unos 4.0 PLANT DESCRIPTION AND COST ESTIMATE 4.1 Introduction In accordance with the recommendations of this report, the plants for Nome, Kotzebue, Red Dog Mine, and the Deadfall Syncline Mine cost estimates have been prepared on the basis of installing spreader stoker fired boilers with associated equipment required for a complete power plant. Arrangement drawings were prepared for the Nome and Kotzebue plants and site plans for the Red Dog Mine and Deadfall Syncline Mines as listed in paragraph 4.4. The cost estimate results for each plant are tabulated and shown on separate pages in this section. In order to complete the cost estimates, pricing was obtained from various vendors for major equipment including boilers, turbine-generators, air cooled condensers, and feed pumps. The remainder of equipment costs were based on recent experience and adjusted as required for the plant requirements. Construction costs including materials and labor costs were estimated on the basis of the drawings prepared for the four (4) plants. Freight costs to Seattle and from Seattle to the Alaskan ports have been included. 4.2 Description of Contracts 4.2.1 General Each of the line items listed on the cost estimate is generally considered to be one (1) contract. Certain of them are on a delivered and erected basis and others are for equipment only delivered to nearest Alaskan port. In general, the contents of each plant is the same except for capacity and size of equipment required to meet the plant output as recommended in this report. 4.2.2 Steam Generators The steam generator contracts for each plant include two (2) stoker fired boilers with furnaces, superheaters, economizers, attemperator, coal feeders, forced draft fans, induced draft fans, flues, ducts, one (1) stack, sootblowers, boiler support steel, baghouse, refractory, insulation and lagging. In addition, a cost for the dry scrubbers have been added to the Red Dog and Deadfall Syncline Mine installations. Each of the steam generators would be sized to produce 55% of the total steam requirements of the plant at the pressure and temperature conditions recommended in this report. The size of the steam generators for the Kotzebue plant would allow complete shop assembly while the others can be partially assembled in the shop, shipped to Seattle, then assembled into larger modules for shipment to the appropriate Alaskan port by barge. The amount of assembly would be limited to the weight capacity of lift equipment at the Alaskan port and any clearance limits. The intent is that this contract scope be on a delivered and erected basis to provide for a single responsibility to meet the guarantee which would be written into the contract. Budget prices were obtained for the equipment from the following: Foster Wheeler Energy Corporation ® Babcock & Wilcox Company @ Energy Products of Idaho @ Tampella Keeler 4.2.3 Turbine-Generators One (1) turbine-generator would be installed with a capacity rating as recommended for the plants. The cost is based on a condensing type turbine with a controlled extraction point for process steam and supply to the deaerators. The generator would be a _ synchronous machine. Accessories include one (1) turbine-generator combined control and lubrication oil system, speed reducing gear, supervisory controls, instrumentation, and baseplates. The estimated costs include installation of the equipment. Budget prices for the equipment were obtained from the following: @ Turbodyne @ Elliott Company @ General Electric Company 4.2.4 Deaerator/Feedwater Heaters The cost estimate is for the equipment delivered to the port. Construction of this equipment is included in the piping and mechanical contract. The budget cost was obtained from Cochrane Environmental Systems. The deaerator is required for removing air from the water and also heats the water. All the plants would have a deaerator and the plant at the Red Dog Mine and Deadfall Syncline Mine would have additional feedwater heaters as indicated on the flow diagrams. 4.2.5 Boiler Feed Pumps Three (3) boiler feed pumps, two (2) motor driven and one (1) steam driven, with drives and shipping costs to Alaska port are included in the estimate. Budget prices were obtained from Goulds, Inc. Installation cost is included in the piping and mechanical contracts. These pumps are required for supplying water to the boiler at the pressures needed. 4.2.6 Air Cooled Condenser The estimated cost includes the air cooled condenser, delivered and installed, with a galvanized steel support structure, fan with drive and geared speed reduction, condenser isolation valve and other accessories. Budget prices were obtained from the following: @ GEA Power Cooling Systems, Inc. @ Zurn Balcke-Durr, Inc. 4.2.7 Water Treatment The estimated cost includes a sodium zeolite water treatment system delivered and installed. ae This equipment is required to provide water to the boilers at the quality required for the design pressure of the system. 4.2.8 Instruments and Controls The estimated cost is based on a microprocessor based system delivered to the Alaskan port. It would control the two (2) stoker fired boilers, district heating (where applicable) and the balance of plant auxiliaries. Installation is included in the contracts for mechanical and electrical work. A budget price was obtained from Bailey Controls for system. 4.2.9 Ash Handling The estimated cost includes the necessary equipment delivered to Alaska for installation by the mechanical contractor. The system would be a pneumatic type with mechanical exhauster, air filtering equipment, transport pipe, air intakes, bottom ash crushers, ash silo and rotary unloader. It would be designed to collect ash at the various boiler and baghouse hopper discharges and transport the ash to the silo. It is expected that the silo storage would be for about two (2) days. Trucks would be required to take the ash from the silo to the City landfills or the mines for disposal. 4.2.10 Coal Handling The cost for the coal handling system includes the equipment delivered and erected at the plant. Each system will require a coal crusher, magnetic separator, controls, conveyor with motor drives, and equipment structural supports. The arrangement drawings indicate an indoor storage facility in which coal would be dumped from truck. An operator with a front end loader would load coal into a hopper from where it would be conveyed to the power house coal bunker. 4.2.11 Site Preparation and Substructure This contract includes labor and materials for the site preparation and substructure installation. 4.2.12 Structural Steel and Building Enclosures Costs for all structural steel materials and labor required for platforms, building support, walls, roofing, hoppers, coal silos, and miscellaneous steel are included in this estimate. Boiler support steel was included in the steam generator estimate. 4.2.13 Building and Site Finishes This contract estimate includes all costs for materials and labor required for concrete floors, partitions for offices and rooms, underground sewer and water lines to site boundary lines and roads located within the plant boundary. 4.2.14 Piping and Mechanical Equipment All materials and labor required for the installation of steam, water, and air piping to the boiler and plant auxiliaries would be included in this contract. This contract would also include the supply and/or installation of mechanical equipment not included in the other contracts. 4.2.15 Major Electrical Equipment This cost estimate is for the transformers, switchgear, and motor control centers that are shown in the single line diagrams prepared for each of the plants and listed under paragraph 4.4. Cost includes the shipment and delivery to the Alaskan port. Installation costs are in the station wiring estimate. 4.2.16 Painting The contract would be for the finish painting of shop primed coated surfaces including structural steel, platforms, uninsulated piping, rooms, and touch up of shop finished equipment. 4.2.17 District Heating District heating is for the Nome, Kotzebue, and Red Dog Mine plants and hot water heating of the coal storage buildings. All materials, heat exchangers, and miscellaneous equipment costs are included on a delivered and installed basis. 4.2.18 Overhead Circuits This estimate is for the finishing of all materials and labor required for delivery and installation of the transmission lines between the Deadfall Syncline Mine power plant and the Red Dog Mine. Certain design assumptions were to use H-frame wood pole structures, span lengths of 500 feet, foundations of direct embedment type and a transmission line length of 92 miles. Wood poles for cost estimate included 75 foot Class 1 Douglas Fir. 4.2.19 Total Project Costs A 15% engineering and contingency cost has been added to the total construction costs and 7% escalation has been assumed to provide for 1992 and 1993 cost increases. 4.3 Plant Staffing The power plants would require a full time, 24-hour per day staffing. Three (3) daily shifts, one of eight (8) hours each plus a rotating shift for weekends, requiring a total of four (4) shifts is proposed. This will account for continuous staffing, with allowances for sickness and vacations. The plant would have to be staffed with the following operating personnel as a minimum. Plant Superintendent: Power Plant Operator: Assistant Operator: Laborers: Responsible for overall management of the plant, shift and maintenance scheduling, ordering of fuel and supplies, hiring of personnel, record keeping, etc. Usually this position is held by a person with at least ten (10) years of power plant operating experience and preferably some formal college training. Responsible for the day to day control and operation of the equipment within the power plant. This position is held by a person with at least five (5) years of heavy equipment operating experience. Familiarity with a power plant would be helpful. Reports to the Plant Superintendent. Responsible for removal of ash from the system and the receipt of coal and filling of coal bunkers. Assisted as necessary by the power plant operator. This position is held by a person who has familiarity with mechanical and electrical equipment. Reports to the Plant Superintendent. Responsible to assist all others within the plant as_ necessary. General cleaning and stocking of supplies. No experience is required and reports to the power Plant Superintendent. The plant would also require certain maintenance personnel although it is expected that major maintenance would be performed on a contracted basis by an outside company. Maintenance personnel would include: Mechanical Maintenance: Responsible for oiling and greasing, minor valve repair, minor equipment repair and non-code welding. A person with experience in heavy equipment maintenance would be required. Reports to the power Plant Superintendent. Electrical Maintenance: Responsible for minor repair to electrical devices within the plant. Also responsible for tuning and calibration of instruments = and controls, assisted by mechanical maintenance. This position requires a person with experience in Maintenance of electrical devices and instrument and control calibration and repair. Reports to the power Plant Superintendent. In addition to the above, a clerk would be required. The clerk’s responsibilities would include bookkeeping, payroll and general typing. A person with three (3) to five (5) years bookkeeping/typing experience would suffice. Typical shift operation would be: Days: 7:00 a.m. to 3:30 p.m. Evenings: 3:00 p.m. to 11:30 p.m. Nights: 11:00 p.m. to 7:30 a.m. Overall plant staffing would be as follows: Number Required Number of Total Number Title Plant Superintendent Shift Operator Assistant Operator Laborers Mechanical Maintenance Electrical Maintenance Clerk Subtotal per Shift Shifts Required Zz Days Only dL 2 All 8 2 All 8 al Days Only 1 2 Days Only 2 a Days Only i i Days Only 1 22 4 - 10 4.4 Arrangement Drawings Arrangement drawings, site Plans, and electrical single line diagrams have been prepared and used as a basis for the cost estimating. These drawings are located in the Appendix of this report with numbers and titles as follows: Drawing No. 905800-MPR-005 905800-MPR-006 905800-MPR-007 905800-MPR-008 905800-MPR-009 905800-MPR-010 905800-ERP-001 905800-ERP-002 905800-ERP-003 905800-ERP-004 4.5 Water Supply Rev. Rev. Rev. Rev. Rev. Rev. Rev. Rev. Rev. Rev. Title Site Plan - 10.5 MW Plant - Nome, Alaska General Arrangement - 10.5 MW Plant - Nome, Alaska Site Plan - 5.7 MW Plant - Kotzebue, Alaska General Arrangement - 5.7 MW Plant - Kotzebue, Alaska Site Plan - 16.5 MW Plant - Red Dog Mine, Alaska Site Plan - 17.5 MW Plant - Deadfall Syncline Mine, Alaska Single Line Diagram - Kotzebue, Alaska Generation Single Line Diagram - Nome, Alaska Generation Single Line Diagram - Red Dog Mine, Alaska Generation Single Line Diagram - Deadfall Syncline Mine Generation It has been assumed that City water supply will be made available to the Nome and Kotzebue plants and that the Red Dog and Syncline Mines water supply will be adequate for the boilers. After the boilers are filled with water and are operating, approximately 5% makeup water will be required for a el. blowdown and miscellaneous uses. In addition, water for the dry scrubbers will be required for the Red Dog Mine and Deadfall Syncline Mine plants. On this basis, the following approximate quantities would be required: e Kotzebue 7 gpm @ Nome 12 gpm @ Red Dog Mine 55 gpm @ Syncline Mine 55 gpm 4.6 Sewer Facility It is assumed that the boiler drains blowdown and wastewater can be discharged into the City sewer systems for the Nome and Kotzebue plants. Sewer facilities for the mine plants would also have to be made available for the plant discharges. 4.7 Schedule The critical path item for power plant construction is normally the procurement, fabrication, shipment, and construction of the steam generating equipment. The steam generator manufacturers have quoted 10 to 12 months for shipment to Seattle while the turbine-generator vendors have quoted 65 weeks. An additional 4 to 6 weeks will be required for shipment to the Alaskan port. Shipments from Seattle to Alaska have to be accomplished between May and September. It will take approximately 12 to 18 months for installation of the equipment, piping, and wiring depending on manpower availability and climate conditions. In regard to the transmission line, it is assumed that this would be started and built in the same period of time. 4 - 12 5.7 MW POWER PLANT CITY OF KOTZEBUE COST ESTIMATE TT NL STL Se ee Steam Generators SialSiy Turbine-Generator 25 Deaerator Boiler Feed Pumps Air Cooled Condenser 1, Water Treatment Instruments and Controls ue Ash Handling Coal Handling l, Site Preparation and Substructure 2, Structural Steel and Building Enclosure 4, Building and Site Finishes abr Piping and Mechanical Equipment 2, Major Electrical Equipment Station Wiring 2, Painting District Heating l, Total Construction $26, Engineering and Contingency Sly Escalation 2, Total Project $32, 740,000 380,000 60,000 160,000 460,000 50,000 200,000 620,000 220,000 370,000 460,000 100,000 600,000 570,000 420,000 30,000 990,000 430,000 960,000 130,000 520,000 -o¢7ee = 4- 13 10.5 MW POWER PLANT CITY OF NOME COST ESTIMATE TL A ETS TE eae SSS ___0 Steam Generators $ 4,430,000 Turbine-Generator 3,120,000 Deaerator 70,000 Boiler Feed Pumps 170,000 Air Cooled Condenser 2,190,000 Water Treatment 60,000 Instruments and Controls 1,250,000 Ash Handling 620,000 Coal Handling 1,080,000 Site Preparation and Substructure 2,790,000 Structural Steel and Building Enclosure 5,160,000 Building and Site Finishes 1,100,000 Piping and Mechanical Equipment 2,690,000 Major Electrical Equipment 500,000 Station Wiring 2,400,000 Painting 50,000 District Heating 4,200,000 Total Construction $31,880,000 Engineering and Contingency 4,780,000 Escalation 2,560,000 Total Project $39,120,000 mation "29 _— 4 - 14 16.5 MW POWER PLANT RED DOG MINE COST ESTIMATE RT ROT REE i TT TORT TAN AT i EET EE eee Steam Generators $ 13, Turbine-Generator 4, Deaerator Boiler Feed Pumps Air Cooled Condenser ar Water Treatment Instruments and Controls 1, Ash Handling Coal Handling 1, Site Preparation and Substructure 5, Structural Steel and Building Enclosure 8, Building and Site Finishes l, Piping and Mechanical Equipment 3, Major Electrical Equipment Station Wiring 2, Painting District Heating 1, Total Construction $ 49, Engineering and Contingency 7, Escalation 4, Total Project $ 61, 4-15 750,000 900,000 150,000 250,000 010,000 80,000 500,000 700,000 400,000 800,000 330,000 270,000 820,000 900,000 860,000 80,000 170,000 970,000 500,000 020,000 490,000 22 MW POWER PLANT DEADFALL SYNCLINE COAL MINE COST ESTIMATE LT TE LT TT ET I TTT TT TE TIS SSS eee Steam Generators $ 13, Turbine-Generator 5, Deaerator Boiler Feed Pumps Air Cooled Condenser 3, Water Treatment Instruments and Controls l, Ash Handling Coal Handling l, Site Preparation and Substructure 1, Structural Steel and Building Enclosure 4, Building and Site Finishes 1, Piping and Mechanical Equipment a7 Major Electrical Equipment l, Station Wiring 3, Painting Overhead Circuits 14, Total Construction $ 56, Engineering and Contingency 8, Escalation 4, Total Project $ 70, 4- 16 750,000 060,000 150,000 250,000 080,000 80,000 500,000 700,000 400,000 790,000 000,000 270,000 590,000 930,000 510,000 80,000 850,000 990,000 550,000 590,000 130,000 5.0 CONCLUSIONS On the basis of use of a conventional Rankine cycle for power generation, a technology assessment was performed based upon the potential of utilizing Alaskan coal for power generation. Technology selection is based primarily on the environmental requirements and that the Clean Air Act amendments of 1990 do not apply to Alaska. Review of environmental aspects indicate that there is minimal potential for sulfur dioxide scrubbing requirements at Nome and Kotzebue. The mine sites will require scrubbing. Other environmental requirements can be met with proper equipment selection. Review of the fuel indicates that essentially any coal burning technology would be suitable. This includes stoker firing, pulverized coal firing, fluid bed firing. The least costly method is stoker firing. If scrubbing is required at Nome and Kotzebue, consideration should be given to fluid bed boilers. Stoker firing provides good reliability and simple operation. Review of various methods for the condensing portion of the cycle has resulted in the selection of air cooled condensers. The primary reason is the shortage of water in the areas of study. Projections of Nome plant loads indicate a need to meet an electrical load of 9.5 MW and 40,716 MWH in the year 2004. This would require 28,100 tons of coal per year. A first phase of district heating would displace approximately 126,000 gallons of fuel oil on a year basis and additional phases can be added as required. At Kotzebue, it is estimated that electrical needs will be 5.2 MW and 26,345 MWH in the year 2004, requiring 18,100 tons of coal yearly. The first phase of district heating would displace 214,000 gallons of fuel oil a year. Placing a power plant at the Red Dog Mine would require a need to meet maximum plant load which is estimated to be 15 MW plus heating requirements of the plant. Should the power plant be placed at the Deadfall Syncline Mine, with transmission to Red Dog, an additional 500 KW is required due to line losses plus additional electrical generation for heating of the Red Dog Mine, assumed to be converted to electric heat. This would require approximately 22 MW of electrical production. Either plant requires 87,000 tons of coal per year. Estimates have been prepared for each of the four (4) potential power plant sites. Total costs for each of the sites is as follows, including escalation through 1993: @ City of Kotzebue, 5.7 MW Plant $32,520,000 @ City of Nome, 10.5 MW Plant $39,120,000 @ Red Dog Mine, 16.5 MW Plant $61,490,000 @ Deadfall Syncline Mine, 22 MW Plant $70,130,000 The estimates have been prepared based upon solicitation of quotations for major pieces of equipment. Other portions of the estimate were developed by SFT, Inc. based upon prior experience and the arrangement drawings prepared for each of the plants. Plant construction scheduling is based primarily upon the procurement, fabrication, shipment, and construction of the boilers. It is estimated that the overall construction schedule will be 24 - 30 months, the shorter schedule applying to two (2) smaller plants and the longer schedule applying to the mine sites. rn Recaeee Plant staffing has also been determined. It will be necessary to have 22 persons on staff to operate the plant during all shifts. UTR A 1 ARCTIC SLOPE CONSULTING GROUP NOTICE: ie crewing ow att inrermarion Se Flows wots mm it err wane SPIRAL won| rerennes wee we caren witten OO OO S ARCTIC SLOPE CONSULTING GROUP ——— IONE: mie ewig nt ernie S| os 3 « 7” ewweiras waren le ovlouttet ww pre: [en mint Bie 1) eoes1 SFT, Ine. seat prietery 12 St, im, tt cover os emion few 30 Barnes | cena | onems woong tc PEE ZT eee | Lat lS ———————— eee EE emcee | eon] SS i ann [Ses ene | eee | CTs | Sn [| ca = CT aes 1.Seu Abt = Es MASEL OT — ee ee ae vis oefe ss a ~ 6 5 a = 1 AIR como 3 coeenser LAKE STREET LAGOON STREET ARCTIC SLOPE CONSULTING GROUP ANDY ONILTNSNOD 3007S ILLIUY y s Poyeme oe ema 61 ows 1 Os Lae 24 Re iO1umDiAEe 9] wemE peTORED e1mant 1m ne bow ON EOIN RY 3 ~0-,01 ¢ “AI DOU © 0-08 + *AZ13 KOU > on) A3ZIA Yd ~ | Hit hy heb oS ros roo 1 1 ; =e = ~T one an bs \ iS sla ( 1 7% anes , Soe ony ugino Woiula: +O T ae 7 rons "DALI ie ‘ ae ! wud | ae & TR TD, eens 0 | wives: ; +0 = —— = = | ~~ gy _ atin ' —— ——— 1 ga — | 8 ~ 4 wma MIRREN \ \ | | 1 0, S1h WIG vIY DL AST: o oo oo 6 20 SE +9 | __ sion Tan | Sunwanuncurae Naw pees | wrierey 101. in it ever te ewion MIP AZ prone _| eB (Paes erences owas we ewes witien CMLL MC EO him sa Uy Loe Ss) ‘SUBSTATION AIR COMED (CONDENSER $00’ -0" sts’ L a ARCTIC SLOPE CONSULTING GROUP Ee [sear [en oss ; ~ NOTICE! mie eevieg are ott intermetion eee | seat Say eewh wa. tema eee payee Th hee Coe eee cece emen fae ee | omnes aoe Se ese on] ase | ee | Seca [Sf] Se ene [econ a [hacen peers aeisincensioniomnnlin ts Shanta’ SITE at = 11 0ny MT NORTH PLANT SOUTH PLANT OUTDOOR —_—_—_—_—_—— ——— 5 GEN. GEN. GEN. GEN. GEN. GEN. SUBSTATION NO.3 NO.4 HOUSE FOR. NO.8 NO.7 HOUSE. NO.6 NO.9 500KW 5OOKW SERVICE NO.3 BOOKW 1135KW SERVICE 2500KW 1700KW 12.47/4-16KV 12.47/4.16KV 3000KVA 3000KVA 12.47KV 1200A BUS FOR. FDR. FOR. NO. 1 NO.2 =-NO.4 r 12.47/4.16KV 1 NOTE: | AN ALTERNATE ARRANGEMENT WOULD BE TO HAVE , 4.16KV BUS THE NEW GENERATOR RATED 12.47KV WHICH WOULD ELIMINATE THE NEED FOR THE 12.47/4.16KV [ TRANSFORMER. 4.16KV/480V 5. 7MW 480V SWGR. BUS Nn LARGE 480V AUX. COAL _HDLG. M.C.C. LEGEND EXISTING PROPOSED BOILER AUX. M.C.C. TURBINE AUX. N.C.C. =z PB OE ARCTIC SLOPE CONSULTING GROUP fb} —p hb — i Siena tae TITLE: eriepacoet kant tnt03“26-91 SINGLE LINE DIAGRAM sree tT KOTZEBUE ALASKA GENERATION NOTICE: Tris growing ong all Information con- teined thereon is confidential and proprietory to SFT, inc. It connot be copied or reprocuced without the expreas written permission of SFT, inc. PROJ. /CONTRACT NO.} DRAWING NO. ; SFT, Inc. Consulting Engineers =e = 9058-00-00 905800-ERP-001 = D:\905800\EM01 BASE SCALE: = 4.16KV» 3000A, 250MVA BUS rH 2 H a a i fd fa ia fg ia H on e3 [1 3000A I FDR. FOR. FOR. t FOR. STATION FOR. FDR. FDR. GROUNDING perm (G) (c) (6) (6) (c) (G) SERVICE TRANSFORMER GEN. GEN. FUTURE GEN. GEN. GEN NO.i NO.2 GEN. NO.3 -NOe4 NOLS SMW SW SMW SMW SMW 16.5MW & 4.16KV BUS —__ > 4.16V AUX. 4.16KV/480V 480V SWGR. BUS —————————————— LARGE 480V AUX. COAL HDLG. M.C.C. BOILER AUX. M.C.C. TURBINE AUX. M.C.C. LEGEND EXISTING PROPOSED iT oO Ass. ARCTIC SLOPE CONSULTING GROUP ue ted TITLE: [ORAWN idan eet) 3-26-9 1} SINGLE LINE DIAGRAM prareed Sree OF RED DOG MINE GENERATION — NOTICE: This growing ond all information con- telned thereon is confidential ond proprietory to SFT, Inc. It cannot be copied or reproduced without the express written permiasion of SFT, inc. “CONTRACT NO.} ORAWING NO- SFT, Inc. Consulting Engineers em [= 9058-00 905800-ERP-003 DNSOSBOO\EMOD BASE SCALE: TWO (2) 4.16KV CIRCUITS CONNECTED TO NOME’S DISTRIBUTION SYSTEM OR DEDICATED CIRCUITS TO NOME’S EXISTING POWER PLANT. (Cauapimaiaaaicasi Siena. 4.16KV BUS 4.16KV/480V 5. 7MW 480V SWGR. BUS ice ehaielatalalaealstatobst tela LARGE 480V AUX. COAL_HDLG. M.C.C. BOILER AUX. M.C.C. TURBINE AUX. M.C.C. peeks eid eb eth aR eevee Eel erie el si Pa [—siewarure bate | TIvues feng naraon ie conticente! cna proprsary , frm cette S 21 FT to SFT, inc. it cannot be copied or reprocuced without the express written permission of sree paaO I= O8=5T SFT, ine. APP’ Din Fe GFT | SFT, Inc. Consulting Engineers GFD [ove | ARCTIC SLOPE CONSULTING GROUP NOTICE: This drawing ond olf Informotion con- SINGLE LINE DIAGRAM NOME ALASKA GENERATION PROJ./CONTRACT NO.] DRAWING NO. 9058-00-00 905800-ERP-002 0:\905800\EMO5 BASE SCALE: * = =O 138KV TRANSMISSION CIRCUIT (APPROX. 92 MILES) FUTURE CIRC. FUTURE 138KV A CIRCUIT aH id ' FUTURE 138KV BUS -----}---------- - 4138/4. 16K’ 12/16/20M\ 138/13-8KV 12/16/20MVA 4.16KV. 3000A, 250MVA BUS 13.8KV BUS FDR. STATION FDR. FDR. FDR. GROUNDING 13.8/4.16KV SERVICE TRANSFORMER GEN. FUTURE GEN. GEN. GEN. 4.16KV BUS NO.1 NO.2 GEN. NO.3 NO.4 NOLS 5MW SMW 5MW 5MW SMW FS RED DOG MINE 4.16KV/480V ae a 480V SWGR. BUS SS ~ LARGE 480V AUX. LEGEND. EXISTING COAL _HDLG. M.C.C. PROPOSED ------- FUTURE BOILER AUX. M.C.C. TURBINE AUX. M.C.C. ee oe ee ee oe NOTICE: Tris crewing ond oll informetion con- toined thereon Is confidential ond proprietory te SFT, Inc. It connot be copies or reprocuced without the express written permission of SFT, inc. SFT, Inc. Consulting Engineers ARCTIC SLOPE CONSULTING GROUP DEADFALL SYNCL INE. COAL _MINE SINGLE LINE DIAGRAM DEADFALL SYNCLINE GENERATION PROJ./CONTRACT NO.] ORAWING NO- 9058-00-01 905800-ERP—-004 O:\90 pace Crarce “- INTERIM REPORT II ARCTIC SLOPE CONSULTING GROUP COAL FIRED POWER PLANTS SFT PROJECT NO. 9058 AUGUST 1992 SFT SFT, Inc. 6629 West Central Avenue Toledo, Ohio 43617 419) 531-8200 ( 443 INTERIM REPORT II ARCTIC SLOPE CONSULTING GROUP COAL FIRED POWER PLANTS SFT PROJECT NO. 9058 APRIL 20 1992 SFT, Inc. was retained by the Arctic Slope Consulting Group to continue investigations regarding the burning of Alaskan coal in Alaska for power generation purposes. The intent of this work was to perform the following tasks. 1. Reduce redundancy of the previously sized power plants at Nome and Kotzebue and therefore utilize the existing diesel generators for backup should the coal plant trip off line. Increase district heating thereby reducing heating oil use since heating oil is more expensive than oil utilized for power generation. Review and utilize micronized coal fired package boilers to further reduce cost where possible. Provide updated pricing for a single 16.5 MW unit to service the Red Dog Mine only. Increase the capabilities of the proposed Red Dog power plant such that the plant could service the mine, the Red Dog port and Kotzebue. Transmission lines would be included to provide the electrical power to these other locations. SFT utilized information previously received from both Nome and Kotzebue regarding electrical load demand. After review of the data received, and utilizing some in-house information, plant capacities were set at 8,400 KW net generation at Nome and 4,600 KW net generation at Kotzebue for the coal fired power plant. This would result in the use of diesel generation beginning in 1995 at Nome (dependent on when the various gold mine loads are placed on the system) and in 1999 at Kotzebue. It is expected that, at Nome, 1,000 KW of diesel generation would be required for approximately 170 hours per year beginning in 1995. The remainder of the generation would be from coal. The 1,000 KW of generation would increase at about 1.1% per year. The hours of diesel generation would also increase on a yearly basis, however, this amount is more difficult to determine. We would suggest using a 5% per year figure as a reasonable value. It is expected that, at Kotzebue, approximately 200 KW of diesel generation would be required beginning in 1999, also for a period of 170 hours per year with the balance of generation from coal. The 200 KW would increase at a 2% per year rate. Again, a 5% increase in hours should also be utilized for analysis. At Nome, the district heating system was kept at the same levels as our previous work which included the following buildings: Bonanza Auto NSHC Hospital Hansen Trading Community Health Services Police/Fire Station Hospital Warehouse Public Works Garage Community Center Lutheran Church 8-Plex Apartments Professional Building Elementary School Supplying all these buildings with hot water generated at the power plant would result in a yearly displacement of approximately 220,000 gallons of heating oil. In so doing, however, the electrical generation due to the conversion of energy to district heating rather than power generation would have to be increased by approximately 1,300 KW during the peak heating season, December through March. In addition, during the rest of the year, an additional 210 million BTUs of fuel (coal) would be required to supply the district heating system, based upon 140,000 BTU/gallon fuel oil and 82% boiler efficiency. At Kotzebue, the district heating system would include the following: Hospital Water Treatment Building A.C. Store Elementary School KIC Apartments Middle School Public Works Armory Recreation Center A yearly displacement of approximately 264,000 gallons of heating oil would occur. This would require that the power plant produce the equivalent of an additional 2,300 KW of electricity during the peak heating season, December through March. Also, during the rest of the year, an additional 165 million BTUs of fuel (coal) would be required to supply the district heating system based upon . fuel oil at 140,000 BTU per gallon and on 82% boiler efficiency. Micronized coal is coal that has been ground to a very fine powder, typically 95% through a 200 mesh sieve. Because the fuel is so fine, it burns rapidly. This rapid combustion allows for a smaller combustion chamber (furnace) with less residence time. In addition, the resultant ash is also extremely fine. This allows for boiler heat transfer surfaces to be placed closer together without adverse ash deposition. This reasoning results in the ability to use shop assembled package boilers for micronized coal firing. Each of the Nome and Kotzebue plants utilizes a single package boiler and a single turbine-generator. Expected availability of these plants would be 90%, or in other words, the plant would be available to produce power 90% of the time it is required to produce power. An estimate of cost for the Nome and Kotzebue plants has also been prepared and is attached. A review was made as to the potential of modularization of the micronized coal power plants for both Nome and Kotzebue. Checking dock facilities indicates that at Nome the port can handle a modularized power plant while at Kotzebue the module would have to be beached and then transported to the power plant site. However, it has been determined that the concept of modularization is sound. The plants can be constructed in the Puget Sound area as single units and then shipped to the two (2) sites. Experience in the Puget Sound area exists for both the construction and transportation of these modules. A preliminary estimate indicates a potential savings of approximately $4 Million at Nome and approximately $3.9 Million at Kotzebue. Further detailed study would be required to determine a more accurate value of potential savings. Two (2) options have been considered for the Red Dog Mine power plant. The first is a plant sized to produce electrical power for the Red Dog Mine, the Red Dog port, and Kotzebue. In order to provide power to the port and Kotzebue, transmission lines are included. This study work was performed by JWA, Inc. of Anchorage in May of 1992. This plant has been sized to produce approximately 26 MW gross. The boiler would be pulverized coal fired as the unit is too large for micronized coal firing. The second option is to provide a single boiler plant to serve the Red Dog Mine site only. This would also be a pulverized coal fired unit of approximately 16.5 MW capacity which is too large for consideration of micronized coal. Both options have been estimated. The overall costs are shown in the attachment. In regard to design of all these plants, consideration for sulfur dioxide (SO,) reduction has not been taken into account. While the State of Alaska would need to follow the Federal Clean Air Act of 1977, it is exempt from the Clear Air Act amendments of 1990. This results in an unclear situation regarding SO, reduction. Since no coal fired units have been permitted in Alaska recently, there is no precedent. Also, the coal to be burned in the plants under discussion has an extremely low sulfur content, on the order of 0.3%, which in itself may result in minimal SO, reduction requirements. In the case of Nome and Kotzebue, it is possible to mix limestone with the coal prior to micronization. The various reactions in the furnace would result in some SO, reduction which may meet any potential of SO, reduction requirements in Alaska. Minimal cost impact would be incurred. Should SO, reduction be required for either of the Red Dog sites, either a dry SO, scrubber or a circulating fluid bed boiler should be considered. Either choice will have a significant impact on the cost estimate. Recently, lower nitrous oxide (NOx) emission levels have been imposed on units being permitted in the lower 48, resulting in use of ammonia injection for NOx reduction. Again, due to the unclear situation in Alaska, no equipment has been included in the estimates for NOx reduction. MICRONIZED COAL FIRED POWER PLANT CITY OF KOTZEBUE COST ESTIMATE Steam Generator Turbine-Generator Deaerator Boiler Feed Pumps Air Cooled Condenser Water Treatment Instruments and Controls Ash Handling Coal Handling Site Preparation and Substructure Structural Steel and Building Enclosure Building and Site Finishes Piping and Mechanical Equipment Major Electrical Equipment Station Wiring Painting Total Construction Engineering and Contingency Escalation Total Project Addition for District Heating $ 2,450,000 2,350,000 60,000 160,000 1,000,000 45,000 950,000 500,000 900,000 2,100,000 2,000,000 950,000 1,950,000 450,000 1,800,000 30,000 $17,695,000 3,000,000 1,250,000 $21,945,000 $ 3,100,000 MICRONIZED COAL FIRED POWER PLANT CITY OF NOME COST ESTIMATE Steam Generator $ 3,950,000 Turbine-Generator 3,120,000 Deaerator 70,000 Boiler Feed Pumps 170,000 Air Cooled Condenser 1,670,000 Water Treatment 45,000 Instruments and Controls 950,000 Ash Handling 500,000 Coal Handling 900,000 Site Preparation and Substructure 2,300,000 Structural Steel and Building Enclosure 2,150,000 Building and Site Finishes 1,000,000 Piping and Mechanical Equipment 2,000,000 Major Electrical Equipment 475,000 Station Wiring 1,950,000 Painting 40,000 Total Construction $21,290,000 Engineering and Contingency 3,300,000 Escalation 1,400,000 Total Project $25,990,000 Addition for District Heating $ 5,620,000 PULVERIZED COAL FIRED POWER PLANT RED DOG MINE - 26 MW COST ESTIMATE Steam Generator Turbine-Generator Deaerator Boiler Feed Pumps Air Cooled Condenser Water Treatment Instruments and Controls Ash Handling Coal Handling Site Preparation and Substructure Structural Steel and Building Enclosure Building and Site Finishes Piping and Mechanical Equipment Major Electrical Equipment Station Wiring Painting Subtotal Switchyards Red Dog Port Kotzebue Transmission Lines (by JWA, Inc.) Subtotal Engineering and Contingency Escalation Total Project $ 13,800,000 5,030,000 130,000 280,000 3,300,000 200,000 1,350,000 550,000 1,250,000 3,500,000 3,100,000 1,800,000 5,200,000 990,000 3,150,000 200,000 $ 43,830,000 $ 2,900,000 2,100,000 1,800,000 44,200,000 $ 94,830,000 7,600,000 3,000,000 $105,430,000 PULVERIZED COAL FIRED POWER PLANT RED DOG MINE - 16.5 MW COST ESTIMATE Steam Generator $ 9, Turbine-Generator 4, Deaerator Boiler Feed Pumps Air Cooled Condenser 2; Water Treatment Instruments and Controls 1, Ash Handling Coal Handling l, Site Preparation and Substructure 3, Structural Steel and Building Enclosure 2, Building and Site Finishes 1, Piping and Mechanical Equipment 4, Major Electrical Equipment Station Wiring 2, Painting Total Construction $35, Engineering and Contingency 5, Escalation 2, Total Project $42, 800,000 200,000 100,000 250,000 450,000 200,000 300,000 550,000 100,000 000,000 650,000 500,000 300,000 800,000 750,000 150,000 100,000 500,000 300,000 900,000 AUG-13-92 THU 7:52 SFT TOLEDO FAX NO. 4198438020 90s8s P01 SFT, Ine. 6629 W. Central Avenue Toledo, Ohio 43617 (419) 843-8200 FAX (419) 843-8020 noon [rasan | rom August 12, 1992 ASCG, Inc. 301 Arctic Slope Avenue Anchorage, Alaska 99518 Attention: Ms. Teresa Imm Dear Mrs. Imm: Attached please find a copy of our cost estimate for the electrical plants at Kotzebue, Nome, and Red Dog. These estimates are based upon a single boiler installation as per our discussion with Kent Grinage. The capacity at Kotzebue is 5,700 KW, at Nome 10,500 KW, and at Red Dog 25,000 KW. It is the intent that the Red Dog plant provide power to the Red Dog port and Kotzebue. We will be following up shortly with a write up describing the scope and the basis of the estimate. Please advise if you have any questions. Very truly yours, L.S//Joachim, P.E, ProYect Manager LSJ/081292PL.E05 Attach. cc: Mr. D.J. Herforth - SFT, Inc. Consulting Engineers AUG-13-92 THU 7:52 SFT TOLEDO FAX NO. 4198438020 P. 02 es ee [Boiler | 2,450 |g 3,950 | $13,800 |Tarbine-Generator | __2,350_| 3,120 Deaerator 70 130 170 1,670 Feed Pumps 160 Condenser Water Treatment 1,350 Ash Handling Coal Handling Site Prep/Foundations Steel Building Piping and Mechanical Electrical Equipment Station Wiring Painting 2,100 3,100 1,800 1,000 1,800 $43,830 i] i Subtotal Switchyards: $17,695 $21,290 Red Dog Port Kotzebue ae w [| C™~“‘;*~sSCSCSt7,695 | $2,290 | $50,630 Engineering & Contingenc 7,600 Escalation 1,250 1,400 | 3,000 | [moter 52,045 081292PL.R02 $25,990 $61,230 =mMS ov Iue ud OCT-22-92 THU 13:22 SFT TOLEDO FAX NO. 4198438020 P. 01 SFT, Ine. 6629 W. Central Avenve Toledo, Ohio 43617 (419) 843-8200 FAX (419) 843-8020 October 22, 1992 ASCG, Inc. 301 Arctic Slope Avenue Anchorage, Alaska 99518 resesa Zan Attention: Ms. Teresa Imm Subject: Cost Estimate SFT Project No. 9058 Dear Mrs. Imm: Attached please find a copy of our cost estimate for the electrical plants at Kotzebue and Nome. These estimates are based upon a single boiler installation at average load for the year 1996. This works out to 4305 KW for Nome and 2430 KW for Kotzebue. Please note that sizing the plants in this manner will require a substantial increase in fuel oil use. At Nome, 1,147,000 gallons will be required to be burned in 1996 and 465,100 gallons at Kotzebue in 1996. We will be following up shortly with a write up describing the scope and the basis of the estimate. Please advise if you have any questions. Very truly vy Project ae LSJ/102292PL.E01 Attach. cc: Mr. D.J. Herforth - SFT, Inc. Consulting Engineers OCT-22-82 THU 13:23 SFT TOLEDO FAX NO. 4198438020 P, 02 UTED TUS TET ales 12) sei jmoiter ts asco | § 2,480 [nurbine-cenerater [2,050 | _2,880_| empemestoe LU LIL Lge) gL al [Feed pums | tn. | aa [condenser | 700200 [Water treatment | 35 | 38 emg EEE ese EEE EE ze [Ash Handling | 80 | 350 [coal Handling | sso. 00 [steon, | tts | 00 [pudding | sso S| | Piping and Mechanical | 1,600__| 1,600 _ [Electrical Equipment | 410 | 440. [station Wiring | a,4o0._ | 3450 Petre tt subtotal | si3,205 | 14,685 __| Engineering & Contingency Escalation |e eee | [| moter | tc aes | $27,985 102292PL.E02 JACK WEST PROFESSIONAL JWA, INC. Sizseer* 3605 ARCTIC BOULEVARD, SUITE BB ANCHORAGE, ALASKA 99503 Mr. Kent M. Grinage Vice President Resources, Permitting, Project Services ASCG, Incorporated 301 Arctic Slope Suite 200 Anchorage, Alaska 99518-3035 Subject: Transmittal of the JWA, Inc. Planning Report Electric Transmission Lines for the Northwest Coal Project Mr. Grinage: Transmitted here is the subject report in fulfillment of our engineering services contract agreement. The report follows the outline of the "Deliverables" paragraph of our agreement and, I hope, achieves the desired objectives of technical feasibility and cost estimate analysis for the ASCG, Inc. selected four specific line cases to be considered. These line cases are called "LINE ROUTES" 1) through 4) in this report. With this report I am also submitting pencil mark-up USGS quadrangles for the line corridors selected to assist in the final CAD map preparations by ASCG, Inc. per our contract agreement. I will be available to assist your technicians in developing the final maps for inclusion in the larger documents by ASCG, Inc. of which this report is only a portion. Thanks for the work and please contact me for any questions through my Anchorage message center. Jack West aot President, JWA, Inc. Alaska Corp. P.C. License C-490 JACK WEST PROFESSIONAL JWA, INC, siexerine 3605 ARCTIC BOULEVARD, SUITE BB ANCHORAGE, ALASKA 99503 PLANNING REPORT ELECTRIC TRANSMISSION LINES for the NORTHWEST COAL PROJECT Prepared by JWA, Inc. Professional Engineering Alaska May 1992 PLANNING REPORT ELECTRIC TRANSMISSION LINES for the NORTHWEST COAL PROJECT (May 1992) TABLE OF CONTENTS PAGE ¢ EXECUTIVE SUMMARY .............. cece cece cece cence eeeeeecues 1 ¢ COST ESTIMATES BY ELEMENTS: LINE ROUTES 1) through 4) .......... 3 ¢ METHODOLOGY: COST ESTIMATES ................ 0c ce eeeceececees 7 ¢ BASE COST ESTIMATE: ARCTIC H-FRAME, 138kV, O/H LINE ........... 9 ¢ DERIVED COST ESTIMATE: ARCTIC SINGLE-POLE, 69kV, O/H LINE .... 10 ¢ COST ESTIMATE: SUBMARINE CABLE CROSSING (KOTZEBUE ONLY) . 11 ¢ MAPS: FOUR LINE ROUTES/CORRIDOR DETAILS .............220005 12 e ANALYSIS: BASIC CRITERIA ........... 0.00. ccc e eee 13 e ANALYSIS: LINE ROUTE ALTERNATIVES .............000eeeeeeeees 14 e ANALYSIS: SYSTEMS VOLTAGE SELECTION ................-..---- 15 * ANALYSIS: LINE ROUTE STRUCTURE SELECTION ...............05: 16 e ANALYSIS: LINE CONDUCTOR SELECTIONS ..............00000000% a ¢ APPENDICES e ABBREVIATIONS/SYMBOLS ............ 00. cece cece eee eee eees Al * DATA SOURCES USED FOR THIS REPORT .............ceeceeeeees A2 ¢ LOAD DISTRIBUTION ESTIMATES BY LINE ROUTE ................ A3 « ARCTIC BARGE FREIGHT ESTIMATES: MATERIALS & EQUIPMENT . A4 e SUBSTATION COST ESTIMATES: MVA BASIS ............20000 000s AS ¢ REMOTE CAMP COST ESTIMATES: LINE ROUTE SPECIFIC .......... A6 ¢ COST ESTIMATE TABLES: VARIATIONS OF LINE MILES/LOAD/VOLTAGE .......... cece cece cect cece cece eeeeeee A7 ¢ LINE ROUTE CHARGING REQUIREMENTS ..............--00eeeee A8 © LINE LOSS| CONSIDERATION) -J57- 0 rlocls) 0 ilies eee eens: A9 e LOAD AMPERES TABLE ............ 0.2 c cece eees A10 * CONDUCTOR SELECTION TABLE ............. cece eee eeeee All ¢ RELEVANT ENGINEERING STANDARDS .............0ceeeeeeees Al2 EXECUTIVE SUMMARY R Objecti The scope of this report was established by paragraph 4. "Deliverables" of the ASCG Inc./JWA, Inc. contract (see APPENDICES). The objectives were to analyze the four LINE ROUTES chosen by ASCG, Inc. and select line structures, line conductors and system voltages for each route at various load capacities ranging from 10-40 MVA. It was assumed by JWA, Inc. that both Cape Krusenstern National Monument and the Noatak National Preserve and Wilderness were to be avoided. A prime objective of this report was to establish LINE ROUTE construction costs. These are direct costs and do not include special environmental mitigations or permitting costs and/or right-of-way acquisitions. Only 3 phase, conventional design, standard voltage lines were considered for this report. The cost summary appears on page 2. 5 + Four T ission LINE ROUTE C The construction cost estimates reached in this report for the four LINE ROUTES considered are: LINE ROUTE 1 60 Miles O/H LINE ROUTE 2 170 Miles O/H plus 5 Miles submarine LINE ROUTE 3 162 Miles O/H LINE ROUTE 4 272 Miles O/H plus 5 Miles submarine Note: The LINE ROUTE straight-line milages have been multiplied by 120% (1.2 multiplier) to allow for route contingencies not identified at the level of this report when no field survey or right-of-way work has been accomplished. This is the only Millions Dollars 69kV, 138kV, 1POLL H-FRAME Red Dog Mine to Red Dog Port (10 MVA) 14.4 20.9 Red Dog Mine to Red Dog Port to Kotzebue (30 MVA) 33.0 44.2 (10 MVA-each to Mine, Port, Ktz) Deadfall-Syncline Mine to Red Dog Mine to Red Dog Port (30 MVA) (10 MVA-Each to Mine, Port, Ktz) (Not Feasible) 58.1 Deadfall-Syncline Mine site Red Dog Mine to Red Dog Port to Kotzebue (40 MVA) (20 MVA-Port/Mine, 20 MVA-KTZ) (Not Feasible) 100.3 "contingency" factor in this report. COST ESTIMATE BY ELEMENTS LINE ROUTE 1: RED DOG MINE TO RED DOG PORT Criteri O/H Line Length: (50 miles) (120%) = 60 miles Line Capacity: 10 MVA Line Voltage: 138kV/69kV, 3 phase Line Type: 138kV H-Frame, 69kV Single Pole Conductor Selected: 1/0 ACSR Both Voltages Submarine Cable Req’d: None Substations Req’d: 2 @ 20 MVA Total (1 - 10 MVA each end) Remote Camps Req’d: None C ion Cost Esti Millions Doll El —_— 138kV B 69kV Derived 60 Mi O/H @ 260K/169K 15.6 10.1 Substations, 20MVA (includes freight) 2.8 22 Remote Camps Os Loo Submarine Cable Crossing -0- -0- Arctic Barge and Handling, Materials (60 Mi O/H @ 35K/28K) 21 ey Arctic Barge, Heavy Equipment 0.4 0.4 138kV Base Cost Total: 20.9 69kV Derived Cost Total: 14.4 COST ESTIMATE BY ELEMENTS LINE ROUTE 2: RED DOG MINE TO RED DOG PORT TO KOTZEBUE Criteri O/H Line Length: (142 miles) (120%) = 170 miles Line Capacity: 30 MVA Line Voltage: 138kV/69kV*, 3 phase Line Type: 138kV H-Frame/ 69kV Single Pole Conductor Selected: 138kV-4/O ACSR, 69kV-336.4MCM/ACSR Submarine Cable Req’d: 5 miles, 138kV, Solid Dielectric Substations Req'd: 3 @ 60 MVA Total (1-30 MVA, 1-10 MVA, 1-20 MVA) Remote Camps Req’d: 1 C ion Cost Esti Millions Dollars Element Description 138kV Base 69kV Derived 170 Mi O/H @ 260K/169K (1.15) 44.2 33.0 Substations, 30 MVA (includes freight) 4.2 3.4 Remote Camps (1) 5 1.5 Submarine Cable Crossing (5 miles) 5.5 5.0 Arctic Barge and Handling, Materials 170 miles O/H @ 35K/28K 6.0 4.8 Arctic Barge, Heavy Equipment 0.4 0.4 138kV Base Cost Total: 61.8 69kV Derived Cost Total: 48.1 *69kV line has marginal performance at 30 MVA but is adequate at 10 MVA Red Dog Mine to Red Dog Port and 20 MVA Red Dog Mine to Kotzebue. COST ESTIMATE BY ELEMENTS LINE ROUTE 3: DEADFALL SYNCLINE MINE TO RED DOG MINE TO RED DOG PORT Criteria O/H Line Length: (135 miles) (120%) = 162 miles Line Capacity: 30 MVA Line Voltage: 138kV, 3 Phase Line Type: H-Frame Conductor Selected: 4/0 ACSR Submarine Cable Req’d: None Substations Req’d: 3 @ 60 MVA Total (1-30 MVA, 1-20 MVA, 1-10 MVA) Remote Camps Req’d: 2 ct st Est: Millions Doll Element Description 138kV Base 69kV Derived 162 Miles O/H @ 260K 42.1 Not feasible Substations, 60 MVA (includes freight) 8.4 due to line Remote Camps (1) 15 Teactance and Submarine Cable Crossing -0- losses. Arctic Barge and Handling, Materials (162 miles O/H @ 35K) Sei, Arctic Barge, Heavy Equipment 0.4 138kV Base Cost Total: 58.1 69kV Derived Cost Total: (69kV Not feasible) COST ESTIMATE BY ELEMENTS LINE ROUTE 4: DEADFALL SYNCLINE MINE SITE TO RED DOG MINE TO RED DOG PORT TO KOTZEBUE Criteri O/H Line Length: (227 miles) (120%) = 272 miles Line Capacity: 40 MVA* Line Voltage: 138kV, 3 Phase Line Type: H-Frame Conductor Selected: 4/0 ACSR Submarine Cable Req’d: 5 miles, 138kV, Solid Dielectric Substations Req’d: 4 @ 80 MVA Total (1-40 MVA, 1-20 MVA, 1-10 MVA, 1-10 MVA) Remote Camps Req’d: 3 C ion Cost Esti Millions Doll 272 Miles O/H @ 260K 70.7 Not feasible Substations, 80 MVA (includes freight) 11.2 due to line Remote Camps (2) 3.0 reactance and Submarine Cable Crossing (5 miles) 5) losses. Arctic Barge and Handling, Materials (272 miles O/H @ 35K) 9.5 Arctic Barge, Heavy Equipment 0.4 138kV Base Cost Total: 100.3 69kV Derived Cost Total: (69kV Not feasible) *Note 40 MVA capacity may be marginal for 5-10% line loss depending on the load distribution along the route. If the load is distributed as 20 MVA @ Red Dog Mine, 10 MVA @ Red Dog Port and 10 MVA @ Kotzebue then the 272 mile line "average" loading is 18 MVA/miles which is 138kV feasible. 6. METHODOLOGY: COST ESTIMATES The cost estimates of this report have been developed from the following line item criteria: 1) 2) 3) 4) 5) 6) The "base" overhead-line construction cost estimate is for 138kV, H-Frame, suspension insulator configuration projected to 1994 construction. The "derived" overhead-line construction cost estimate is for 69kV, single-pole, offset post insulator configuration projected to 1994 construction. Four only LINE ROUTE cost estimates have been developed completely including overhead line, substation, remote camp, submarine cable crossings and arctic freight cost elements. The "base" overhead line cost is the mean of two historical previous arctic line costs in earlier reports (which have been adjusted for arctic regions construction and 6.0%/annum to 1994 escalation since the year of each report) plus a third actual cost record for a 1991/92 completed 138kV H-Frame line at Homer, Alaska. This HEA line cost has also been escalated at 6.0%/annum to 1994 construction. The submarine cable crossing cost estimate (only at Kotzebue) is based on review of actual costs incurred in the last twenty years in Alaska by the engineers involved (including the engineer preparing this report with extensive knowledge and experience in this area since the mid 1960’s). Submarine cable costs are expensive. For this level of report 138kV and 69kV submarine crossing costs are assumed approximately equal. Substation costs estimates have been developed on a unitized basis per/MVA of installed capacity along the LINE ROUTE considered with "best judgement" as to load distribution at this preliminary planning level. METHODOLOGY: COST ESTIMATES 1) 8) 9) (Continued) Arctic freight (see APPENDICES) costs have been added as a compounding penalty to the multiplier assigned to the per mile overhead line cost estimates due to the remote logistics requirements. Lightening and handling costs are included. These costs have been developed on a unitized basis per mile of line construction for each line route. Adjustment factors developed and used in this report for cost estimates are: A) Base O/H line cost estimate: 138kV, H-Frame ........ No Factor B) Derived O/H line cost and estimate: 69kV, 1-Pole ...... 0.65X (A) C) Base line conductor cost estimate: 1/0 ACSR .......... No Factor D) Derived line conductor cost estimate: 4/0 ACSR ....... 1.05X (C) E) Derived line conductor cost estimate: 336.4MCM/ACSR .. 1.15X (C) Where only one type of line construction configuration has been cost estimated for a particular LINE ROUTE the other type has been excluded for technical considerations. 10) Remote camp costs are LINE ROUTE specific (see Appendices). 11) LINE ROUTE mileages used for the cost estimates are reasonable straight line routes taken from USGS 1:250,000 scale topography maps (Noatak, Delong Mountains, Point Lay) and adjusted uniformly by a multiplier of (1.20) or 120% as no field survey, right-of-way acquisition or soil and foundation analysis is available at this report level. This multiplier is the only "contingency" factor used in the cost estimates in order to avoid repetitive compounding and unrealistic inflation of actual direct construction costs. BASE COST ESTIMATE: ARCTIC H-FRAME, 138kV, O/H LINE Estimate A) From telecon with HEA, Homer Alaska 1992 completed "Fritz Creek" Line "H" Frame Wood Role, 183 kV Including clearing and R.O.W. costs 60 miles @ $14.4 Million Dollars (elimination of clearing offset by Arctic conditions) ................... $240K/mile Escalating @ 6.0%/year to 1994 construction ................-2-00e- $270K/mile Estimate B) From JWA/IECC/HGA 1981 Transmission Line Cost estimates extract the "arctic adjusted" (1.63 multiplier) cost estimate for 138kV and escalate this cost @ 6.0% year from 1981 to) L994" comstruction sce cierslaleiciets teres ole sicie ole ste tee eee ea aee $249K/Mile Estimate C) Hawley Resource Group 1986 Report (100K/mile) with 1.63 multiplier adjustment from JWA/IECC/HGA 1981 report (to $163K/mile) then escalates @ 6.0%/year from 1986 to}1994\consteuction files asierlcleiicrelerdereilarclersietsleraierersveusysteue rovers $260K/mile Estimates A,B,C Mean Value (270 + 249 + 260) +3 ................. $260K/mile " al iy ‘V Formula for specific LINE ROUTE cost estimates (138kV & H-Frame): (Route milage) x (Base Cost) + Remote Camp cost + Equipment Freight (See Appendices) + Substation costs + submarine cable crossing (where required). -9- DERIVED COST ESTIMATES: ARCTIC SINGLE-POLE, 69kV, O/H LINER 69kV Construction Cost For this report the 69kV-Single Pole line constructions is estimated @ 65% of the 138kV H-Frame construction BASE COST ESTIMATE detailed previously. The logic for this is that logistics of construction are not reduced more than 35%. Arctic freight tonnage is only reduced by 20%. The remote camp requirements and heavy equipment arctic freight costs are essentially unchanged for either a 69kV-Single Pole or 138kV H-Frame O/H line. The 69kV derived O/H line cost is then: DERIVED SINGLE POLE, 69kV PER MILE COST ......... 169K/Mile Line Goad Variati The BASE COST for 138kV line assumes a minimum conductor size of 1/0 ACSR with a 138kV capacity of 4OMVA without exceeding the 50% ampacity limit of the conductor at 25°C ambient air temperature. For increasing the conductor size for 1/0 ACSR to 4/0 ACSR for either 69kV or 138kV construction type the base or derived cost estimate is increased by 5% for 4/0 ACSR and by 15% for the much heavier "Linnet" 336.4 MCM/ACSR. The logic for this is that line voltage and construction type effect the field construction effort far more than conductor stringing difficulty while logistics equipment and freight are essentially unchanged. The line items following summarize BASE COST and DERIVED COST estimates used in this report. A) Base O/H line cost estimate: 138kV, H-Frame ........ No Factor B) Derived O/H line cost and estimate: 69kV, 1-Pole ...... 0.65X (A) C) Base line conductor cost estimate: 1/0 ACSR .......... No Factor D) Derived line conductor cost estimate: 4/0 ACSR ....... 1.05X (C) E) Derived line conductor cost estimate: 336.4MCM/ACSR .. 1.15X (C) Cost Estimates for the four specific LINE ROUTES have been presented in the EXECUTIVE SUMMARY of this report and are detailed on single page summaries by elements.. COST ESTIMATE SUBMARINE CABLE CROSSING (KOTZEBUE ONLY) Di : For purposes of this report only a single cable crossing, at the narrows of Hotham Inlet to the Kotzebue electric distribution grid, is anticipated. Other submarine cable use may have advantages in lieu of overhead circuits at specific segments of some of the LINE ROUTES but are not identified at this preliminary planning report level. Submarine cable installations are expensive on a per mile basis and should be chosen judicially. The shortest route of submarine crossing to Kotzebue is approximately 5 miles. Alternate routes may be considered which could increase the submarine cable length. For example avoiding the Noatak River delta to cross at Sheshalik Spit would increase submarine cable to at least 8 miles but possibly reduce overhead line by 10-12 miles. The submarine cable has a much higher per mile cost and other considerations are required to determine the most technical and economic advantages of cable/overhead line trade off. For this report a 5 mile crossing is selected and costed as follows: Submari ile route Millions Dollars 138kV, Wire Armored Jacksfed, Solid Dielectric ..............200cceeeees 2.5 Special Cable Barge Loading and 30 Days Ops. ..............eeeeeeeeeee 1.0 Route Survey and' Controlled Laying Ops. oe eee ee ree ava eae ata lala 0.5 Cable Terminals and Protection Construction ..............ceeeeccceeees 1.0 Unforseen and contingencies @ planning level ................00 2-00 e eee 0.5. 138kV BASE 5 MILE CROSSING TOTAL ....... 35 Note: 69kV Submarine cable has identical cost at this report level. -]1- MAPS: FOUR LINE ROUTES/CORRIDOR DETAILS Here ASCG, Inc. will insert CAD work maps for each LINE ROUTE of some appropriate scale and a series of 1:250,000 scale line corridor detail maps can be included here or as Appendices items. JWA, Inc. has provided straight line 1:250,000 pencil mark-up maps as a guide (USGS Quadrangles: NOATAK, DELONG MOUNTAINS, POINT LAY). JWA, Inc. will provide supervision assistance to ASCG, Inc. CAD technicians to this end. -12- ANALYSIS: BASIC CRITERIA For purposes of planning at this level the basic analysis criteria used were: A) B) 1) D) E) G) 1) Jd That LINE ROUTES avoid Cape Krusenstern National Monument and Noatak National Preserve and Wilderness, that realistic arctic construction costs be developed, that minimum line voltage and minimum line cost for each LINE ROUTE would be identified, that line losses would be kept minimum and not exceed 5-6% of the expected transmitted energy, that the electrical loading range and distribution for the considered LINE ROUTES would be "realistic" for 35-40 year line life and within the boundaries of 10 MVA - 40 MVA, that the cost of remote construction camps and arctic barge freight would be considered where appropriate, that "light, medium and heavy" conductor alternatives would be identified, that both single-pole-offset-post-insulator and H-Frame suspension insulator designs would be considered, that LINE ROUTE corridors would be identified and approximate straight-line milages determined with a 120% increase allowance for rerouting based on future field survey and right-of-way acquisition, that the line structural features would be planned for arctic conditions and nominal 35-40 year life. -13- ANALYSIS: LINE ROUTE ALTERNATIVES The four basic LINE ROUTE cases examined in this report were selected by ASCG, Inc. for technical feasibility and cost estimate analysis by JWA, Inc. It was assumed by JWA, Inc. that both Cape Krusenstern National Monument and the Noatak National Preserve and Wilderness were to be avoided. As this report is prepared prior to field survey and permitting efforts beginning in 1992 it is not possible to establish detail line routing here but merely use straight line routings through logical corridors with some appropriate multiplier to allow for rerouting related to soils, right-of-way or other considerations developing with this field work. The LINE ROUTE multiplier used in this report is (1.20) or 120% applied to reasonable straight-line routings chosen from 1:250,000 scale USGS quadrangles. The specific line loadings for the four LINE ROUTES examined were selected by JWA, Inc. based on technical considerations of feasible power transmission for each case. These four LINE ROUTE cases and related transmitted electrical capacity are presented in the EXECUTIVE SUMMARY of this report and range from 10 MVA (Red Dog Port only maximum utilization estimate) to 40 MVA (Red Dog Mine and Port and Kotzebue maximum utilization estimates). The distribution of the load considered for each case is a best judgement estimate by JWA, Inc. and also has been coordinated with technical considerations as to line losses, reactance and conductor electrical leading at the two voltages considered. Only 138kV (H-Frame) and 69kV (Single-Pole) configurations are considered in this report for these same technical considerations. For the selected LOAD ESTIMATES for LINE ROUTES see the Appendices. ANALYSIS: SYSTEM VOLTAGE SELECTION The system voltage selected for each LINE ROUTE is based on: A) The total MVA of LINE ROUTE load. B) The total mileage of the LINE ROUTE. C) The load distribution along the LINE ROUTE. D) Limiting line losses to an estimated 5-6% maximum. E) Line reactive and charging considerations. F) Best economic compromise between all factors of system voltage, ruling span limitations, conductor selection and structural limitations. For the 10-40 MVA load range considered for all LINE ROUTES only two voltages are necessary to cover this spread over the LINE ROUTES distances determined. These are 69kV and 138kV. Intermediate voltage of 115kV was discarded as being generally obsolete by industry standards and 230kV was discarded as unnecessary for the MVA-MILES transmission requirements range and excessive in construction cost. The conclusions of this report are that 69kV is technically satisfactory for both LINE ROUTES 1) and 2) and 138kV is satisfactory for all four LINE ROUTES. The appropriate conductor has been selected for each voltage in the EXECUTIVE SUMMARY of this report. While there may be some cost saving merit to considering 69kV for the Red Dog Port (60 miles) line segment of LINE ROUTES 3) and 4) this is not done at this planning report level where "mixing" of the two disparate voltages cannot be benefit/cost analyzed with any assurance. -15- ANALYSIS: LINE ROUTE STRUCTURE SELECTION Following the selection of feasible line voltages as 69kV (LINE ROUTES 1 and 2) and 138kV (LINE ROUTE 1, 2, 3, and 4) line structure configurations were considered. Using a nominal ruling span of 500 feet and probable maximum spans of 600-700 feet leads to limiting the 69kV to single pole, offset post insulator construction while the 138kV requires greater structural loading and more suitable as H-Frame construction. This also follows general industry convention of matching these respective construction types to these voltages. The 69kV, Single-Pole construction is particularly suited to the 10 MVA interconnect of Red Dog Mine to Red Dog Port. Even the lighter conductor selection will handle the 600 MVA- MILES line loss and reactance consideration and any increase in line out-of-service time resulting from worst case Arctic storms is economically justified over the line 35 year life by the initial capital cost savings estimated at 6.5 million dollars. Additionally existing prime power generation at the Red Dog Port could provide adequate life-line standby service during line repairs. Summarizing overhead line structure feasibilities: LINE ROUTE 1 (60Mi, 10 MVA) 69kV,1Pole or 138kV, H-Frame LINE ROUTE 2 (170Mi, 30 MVA) 69kV,1Pole or 138kV, H-Frame LINE ROUTE 3 (162Mi, 30 MVA) only 138kV, H-Frame LINE ROUTE 4 (272Mi, 40 MVA) only 138kV, H-Frame Both line structures are capable of the full range of conductors (Light, Medium, Heavy) examined in this report within the 500 foot ruling span limitation and simultaneous wind and radial ice conditions. ANALYSIS: LINE CONDUCTOR SELECTION Line conductors have been selected on the basis of MVA loading, length and system voltage to keep losses to a nominal maximum of 5-6%. Westinghouse T and D standard charts and tables have been the primary guide. The conductors selected will all meet the structural requirements of 400-500 feet ruling spans and the expected simultaneous wind and radial ice loadings. Only three conductors are considered in this report, which are: "Heavy" "Medium" "Light" 336.4MCM/ACSR (Linnet) 2,442 Ibs/mile weight 14,050 Ibs. UTS 530 AMPS @ 25°C Ambient 4/0 ACSR 1,542 Ibs/mile weight 8,420 Ibs. UTS 340 AMPS @ 25°C Ambient 1/0 ACSR 769 Ibs/mile weight 4,280 Ibs UTS 230 AMPS @ 25°C Ambient Limiting the line losses to 5-6% the conductors selected are: 69kV @10MVA 69kV @30MVA 138kV @ 30 MVA 138kV @ 40 MVA 1/0 ACSR 336.4 MCM/ACSR 4/0 ACSR 4/0 ACSR -17- APPENDICES ABBREVIATIONS/SYMBOLS ........... 00. cece cece eee teen eees Al DATA SOURCES USED FOR THIS REPORT ..............-0000000: A2 LOAD DISTRIBUTION ESTIMATES BY LINE ROUTE ............... A3 ARCTIC BARGE FREIGHT ESTIMATES: MATERIALS & EQUIPMENT . A4 SUBSTATION COST ESTIMATES: MVA BASIS ............0.0ee0008 AS REMOTE CAMP COST ESTIMATES: LINE ROUTE SPECIFIC ......... A6 COST ESTIMATE TABLES: VARIATIONS OF LINE MILES/LOAD/VOLTAGE, ae cree) slalele) clelelorerelefelelore) sielersieys1eiea)ateyalerelerersiete A7 LINE ROUTE CHARGING REQUIREMENTS ..............-.eeeees A8 LINE LOSS CONSIDERATION ......... 02. ccceccecceccscccccceces A9 LOAD AMPERES TABLE Wa ciliereloclerleieie sereriocieiacieiieicieoeiereiereeictc A10 CONDUCTOR SELECTION TABLE .............. cece cee ec cece All RELEVANT ENGINEERING STANDARDS ..............22-000 00 Al2 ABBREVIATIONS/SYMBOLS USED IN THIS REPORT A AMPERES ACSR ALUMINUM CONDUCTOR, STEEL-REINFORCED DFS DEADFALL SYNCLINE (MINE SITE) °C DEGREES CELSIUS FT FEET FT? SQUARE FEET ‘ H-FRAME TWO VERTICAL POLES AND CROSS ARM STRUCTURE WITH SUSPENSION INSULATORS Hp HORSEPOWER In. INCHES K PREFIX MULTIPLIER (x1000) - METRIC kV KILOVOLTS Kw KILOWATTS kVA KILOVOLTAMPERES Ib. POUNDS LF LINEAR FEET MCM THOUSAND CIRCULAR MILS Max. MAXIMUM Min. MINIMUM Mi. MILES MVA MEGAVOLT - AMPERES MW MEGAWATTS O/H OVERHEAD (LINE) OcB OIL CIRCUIT BREAKER OCR OIL CIRCUIT RECLOSER 1-POLE SINGLE POLE STRUCTURE WITH OFFSET POST INSULATORS PSI POUNDS PRE SQUARE INCH REA RURAL ELECTRIFICATION ADMINISTRATION Sq. In. SQUARE INCHES UTS ULTIMATE TENSILE STRENGTH Yr YEAR Al DATA SOURCES FOR THIS REPORT The following sources were used in developing this report: ¢ "NWCP, POWER PLANT EVALUATION, FINAL REPORT" September 1991 for ASCG, Inc. by SFT, Inc. of Toledo, Ohio. ¢ "PRELIMINARY FEASIBILITY STUDY OF A COAL MINE AT CHICAGO CREEK, SUMMARY REPORT," March 1986 for State of Alaska, Division of Geologic and Geophysical Surveys, by Hawley Resource Group. ¢ "PROJECT PLANNING REPORT, BARROW-ATQASUK-WAINWRIGHT TRANSMISSION LINE," September 1981, for the North Slope Borough, by JWA/RWRA/IECO/HGA. ¢ "TRANSMISSION and DISTRIBUTION, WESTINGHOUSE" (Engineering standard volume with tables and charts for preliminary T-line planning). LOAD DISTRIBUTION ESTIMATES BY LINE ROUTE Based on previous report data and the technical and economic limitations of feasible transmission lines the load estimates used for this report were as follows: Utilization RB (1995-2030) Red Dog Mine 15-20 MVA Red Dog Port 5-10-15 MVA (Not known at this report) Kotzebue 5-20 MVA For purposes of this planning report the estimated load distribution considered to establish the electric capacity of each LINE ROUTE over its projected 35-40 year life was then: LINE ROUTE 1 LINE ROUTE 2 LINE ROUTE 3 LINE ROUTE 4 10 MVA all at Red Dog Port 10 MVA at Red Dog Port 20 MVA at Kotzebue 20 MVA at Red Dog Mine 10 MVA at Red Dog Port 20 MVA at Red Dog Mine 10 MVA at Red Dog Port 10 MVA at Kotzebue Note: These are maximum peak demand figures and do not represent average leads. Lines must be designed for peak demand performance. ARCTIC BARGE FREIGHT ESTIMATES: MATERIALS AND EQUIPMENT C, Lo Nate ried TONS/MILE "EH" STRUCTURES, CLASS' 1 AND 2: POLES 28 oo ele ses 5 cles os 13 (500’ RULING SPANS THIS ESTIMATE) CONDUCTOR (HERE CONSIDER ONLY HEAVIEST, "LINNET") ..... 9 (3 CONDUCTORS @ 2,442 LBS/MILE PLUS REELS) INSULATORS (USE 138kV THIS ESTIMATE) ...........----+-00-- 7. (33/MILE X 200LBS EACH W/CRATE) GUY WIRE AND ANCHORS 2.0.5 ccs cee desc ccc cncsresssces 2 ARMOR ROD AND MISCELLANEOUS HARDWARE .............- 1 SUBTOW AG oes cielo ae callers ec alers erottetepenaterorenetayet 32 Tons/Mile EST. @ $1,100/TON BARGE TO RED DOG PORT AND LIGHTER AND HANDLE ............... cece ee eeeeeee $35K/Mile Above est. of 138kV, H-Frame: For 69kV Single Pole use 80% ........... $28K/Mile TONS TRACK MOUNTED HEAVY EQUIPMENT (5-20 TON UNITS)......-. 100 ROAD VEHICLES AND TRUCKS (5-3 TON, 5-10 TON UNITS) ....... 65 LIGHT SNOW TRACK VEHICLES (10-1 TON UNITS) .............-. 10 SUBTOTAL rrrerleletstesictelolete teterneielo ckerercrere 175 TONS ESTIMATE @ $1,100/TON AGAIN -FIXED COST EACH LINE ROUTE . $192,500 FOR ESTIMATING PURPOSES "SAY" ....... $200,00 Since must also remove equipment (200X2) ...........-2e cece eee eeee $400,000 A4 SUBSTATION COST ESTIMATES: MVA BASIS This report uses a base 1994 purchase cost of $130K/MVA of 138kV substation capacity. It is assumed substation transformers will be purchased in minimum 5 MVA units and maximum 10 MVA units. The $130K/MVA includes necessary associated minimal yard- switching and adequate relay protection systems. A lump-sum arctic freight and overland hauling estimates of $10K/MVA brings the in place substation estimate to $140K/MVA. The following substation costs have been appropriately added to the LINE ROUTE costs in the EXECUTIVE SUMMARY of this report: 138kV Substation C . In Place Cost (Millions Dollars) 5 MVA 0.7 10 MVA 1.4 20 MVA 2.8 30 MVA 4.2 40 MVA 5.6 Note: 69kV Substation Costs are derived by multiplying the 138kV costs by 80%. Substation savings is not directly proportional to voltage ratios due to many practical considerations of unit weights, logistics, labor and switchyard layouts. REMOTE CAMP COST ESTIMATES: LINE ROUTE SPECIFIC The cost of establishing a remote line construction support camp is fixed cost to be assigned to each 40 miles* of line construction regardless of the LINE ROUTE or voltage level selected. This cost is incurred for all cases except for LINE ROUTE 1 (Red Dog Mine to Red Dog Port) where the total air route is nominally 60 miles and some support infrastructure is located at each terminal of the line. On this basis the requirements for remote camps are: LINE ROUTE 1 Red Dog Mine Site to Red Dog Port ......... 0 Remote Camp LINE ROUTE 2 Red Dog Mine to Red Dog Port to Kotzebue .. 1 Remote Camp LINE ROUTE 3 DFS Mine Site to Red Dog Mine to RES PO ERT Eel orotic oder ctcl cvateyel aierelvereveiicielsterelerercreneienecier 1 Remote Camp LINE ROUTE 4 DFS Mine Site to Red Dog Mine and POCt ANd tO MOReODUS |irerelor yee) crete olelcleteyareiererexclievereesteic’ > 2 Remote Camps The best estimate possible for a remote camp cost is: $1,500,000 / Remote Camp (total for two construction seasons) This is a 1981 estimate escalated for inflation at 5%/annum from 1981 to 1994 (as first year of construction). The 1981 estimate is based on work done in a project planning report for another arctic transmission line concept by JWA/IECO/HGA cited in the APPENDICES of this report. The "Fixed" cost for remote camp requirements for each LINE CASE which are added to the computed variations of line mileage and voltage level are then: LINE ROUTE 1) -0- (60 Miles LINE ROUTE) LINE ROUTE 2) $1,500,000 (120 Miles LINE ROUTE + Submarine Cable Crossing) LINE ROUTE 3) $3,000,000 (140 Miles LINE ROUTE) LINE ROUTE 4) $4,500,000 (200 Miles LINE ROUTE + Submarine Cable Crossing) These figures are included in the overhead line cost totals for each LINE ROUTE in the EXECUTIVE SUMMARY of this report. *40 miles is the practical limit of "crew-spread" using helicopters and winter overland construction support equipment. A6 COST ESTIMATE TABLES VARIATIONS OF LINE MILES/LOAD/VOLTAGE The following table is provided for considering other O/H line costs than the four LINE ROUTES considered in this report. s9kV-Single Pole C . 10 MVA-1/0 ACSR 20 MVA-4/0 ACSR 30 MVA-LINNET 40 MVA-LINNET 10 MVA-1/0 ACSR 20 MVA-1/0 ACSR 30 MVA-4/0 ACSR 40 MVA-4/0 ACSR 40 MVA-LINNET Note: These are base O/H line direct construction costs only. Substations, arctic barge freight, remote camps and submarine crossings (where required) must be added for specific LINE ROUTES considered. (See examples: COST ESTIMATES BY ELEMENTS this report). No permitting, right-of-way acquisition or environmental mitigation costs are included in the direct construction costs above. Where there are no entries in the tables line loss and reactance considerations preclude feasibility at that voltage, distance and loading combination. A7 LINE ROUTE CHARGING REQUIREMENTS The capacitive line charging requirement for each LINE ROUTE is the reactive capacity necessary to energize an open circuit line prior to load flow. 1/0 ACSR 4/0 ACSR LINNET* 138kV 138kV *LINNET: 336.4 MCM ACSR Note: For LINE ROUTES longer than 60 miles line-segment-switching (for sequential energization) would be used to reduce reactive sudden loading of generation plants when "picking-up" a deenergized system. Substation transformer reactances are not included in the table above. Line electrical stability analysis is beyond the scope of this preliminary planning report. LINE LOSS CONSIDERATION For this report the objective has been to match load flow (MVA) with line voltage and conductor selection so that losses will not exceed 5-6% for each LINE ROUTE examined. This necessarily eliminates the use of 69kV lines beyond routes over 120 miles (i.e. limits 69kV to LINE ROUTES 1 and 2, for consideration). The analysis yields the following preliminary feasibility findings: LINE ROUTE/MILES FEASIBLE VOLTAGES AND CONDUCTORS LOAD LIMIT LR. 1/60 miles 69kV-1/0 ACSR or 138kV-1/0 ACSR 10 or 20 MVA LR. 2/170 miles *69kV-336.4 MCM ACSR or 138kV-4/0 ACSR 30 MVA LR. 3 / 162 miles 138kV - 4/0 ACSR 30 MVA LR. 4 / 272 miles **138kV - 4/0 ACSR or 336.4 MCM ACSR 40 MVA * Denotes marginal case where either higher losses of approximately 10% or the cost penalty of large conductors or both conditions must be accepted. Reducing the load by 10 MVA may be required to avoid these penalties. ** May be marginal at 40 MVA depending on the load distribution along the LINE ROUTE. Utilizing a voltage of 230kV is an option that solves the line loss for the LINE ROUTE 4 marginal case at a cost penalty of 30-40% over 138kV cost estimates. At this report level loads are not sufficiently determined to justify the merits of increasing line voltage to 230kV. LOAD AMPERES TABLES Load Amperes LINE VOLTS 10 MVA 20 MVA 30 MVA 40 MVA 69kV 84 167 251 335 115kV 50 100 150 200 138kV 42 84 126 168 230kV 25 50 75 100 Conductor Ratings "Heavy" 336.4 MCM/ACSR 530 Amps @ 25°C Ambient "Medium" 4/0 ACSR 340 Amps @ 25°C Ambient "Light" 1/0 ACSR 230 Amps @ 25°C Ambient A10 CONDUCTOR SELECTION TABLE lection 5-6% Line Loss (% Ampere Rating @ 25°C) LINEVOLTS 10MVA 20 MVA 30 MVA 40 MVA 69kV 10 ACSR 4/0 ACSR 336.4MCM/ACSR — (37%) (49%) (47%) —_—— 115kV 1/0 ACSR 1/0 ACSR 4/0 ACSR 336.4MCM/ACSR (22%) (44%) (44%) (38%) 138kV 1/0 ACSR 1/0 ACSR 4/0 ACSR 4/0 ACSR (18%) (37%) (37%) (49%) 230kV 1/0 ACSR 1/0 ACSR 1/0 ACSR 1/0 ACSR (11%) (22%) (33%) (44%) Conductor Ratings "Heavy" 336.4 MCM/ACSR 530 Amps @ 25°C Ambient "Medium" 4/0 ACSR 340 Amps @ 25°C Ambient "Light" 1/0 ACSR 230 Amps @ 25°C Ambient All RELEVANT ENGINEERING STANDARDS Al2 RECOMMENDED MINIMUM VERTICAL CLEARANCES (IN FEET) ABOVE GROUND OR RAILS FOR SPOTTING STRUCTURES ON PLAN OR PROFILE SHEETS (120°F, No Wind, Final Sag or 32°F, No Wind, Radial Ice Thickness, Final Sag, Whichever is Greater) Nature if Surface Nominal Valtage kV L-L Underneath Conductors 34.5 46 69 115 138 161 230 Track rails of railroads (REA) 31 31 31 «31.7 32.1 32.6 34.0 Track rails of railroads (NESC) 30 30 30 30.7 31.1 31.6 33.0 Public streets and highways (REA) 23) 23 23 23.7 24.1 24.6 26.0 Public streets and highways (NESC) 22 22 22 22.7 23.1 23.6 25.0 Areas accessible to pedestrains only (REA) 18 #18 18 18.7 19.1 19.6 21.0 Areas accessible to pedestrians . only (NESC) 17, ««17:«217':=COo 117.7 «18.1 «18.6 20.0 Cultivated fields (REA) 23. 23 23 23.7 24.1 24.6 26.0 Cultivated fields (NESC) 22 22 22 22.7 23.1 23.6 25.0 Along roads in rural districts (REA) 21. 21 21 21.7 22.1 22.6 24.0 Along roads in rural districts (NESC) 20 20 20 20.7 21.1 21.6 23.0 Residential driveways and commercial areas not subject to truck traffic (REA)3 23. 23 23 «23.7 24.1 24.6 26.0 Residential driveways and commercial areas not subject to truck traffic (NESC) 22 22 22 22.7 23.1 23.6 25.0 Water areas not suitable for sail- boating or where sailboating is prohibited (REA)3 18 18 18 18.7 19.1 19.6 21.0 Water areas not suitable for sail- boating or where sailboating is prohibited (NESC) 17. «17:«:17:«217.7:» «18.1 18.6 20.0 NOTES ° Sag templates should be cut to allow one foot greater clearance than shown above. ° The above data is taken from REA Bulletin 62-1, © NESC clearance is based on maximum operating voltage, equal to 1.05 times the nominal voltage line to line per REA Bulletin © CROSSING CLEARANCES (IN FEET) OF WIRES CARRIED ON DIFFERENT SUPPORTS (120°F, No Wind, Final Sag or 32°F, No Wind, Radial Ice Thickness, Final Sag, Whichever is Greater) Nominal Voltage kV_L-L Nature of Wires Crossed Over 4.5 46 69 4115 138 161 230 Communication lines (REA) 7.0 TOP 1601 701 (O65 1 e761 1tO.0 Communication lines (NESC) 6.0 62077 6.0rr Gea tia set 66 9.0 Supply lines up to 50 kV phase to ground (REA) 5.0 SLO osOM Sys mOatiinGso 8.0 Supply lines up to 50 kV phase to ground (NESC) 4.0 4201 4-01 4.0 oa toce 70) NOTES ° Where crossing occurs at midspan in the upper conductor, NESC re- quires that the upper conductor at 120°F, unloaded final sag or 32°F, no wind, radial ice, final sag, whichever is greater, clears the lower wires when at 60°F, no wind, no ice, initial sag. For a crossing which is not at midspan see Section 23, Rule 233, ° The above data is taken from REA Bulletin 62-1, © NESC clearance is based on maximum operating voltage equal to 1.05 times the nominal voltage line to line per REA Bulletin 62-1 CONDUCTOR CHARACTERISTICS Resis- Strength tance Code Dia. Weight Area (Sq.in.) Ultimate @ 68°F Word Mat'l Size Strand (in. ) (Ibs/L. F.) Total AL (lbs) | Ohms/Mi cinnet ACSR 336.4 26/7 0.721 0.463 0.3072 0.2642 14,100 0.2737 MCM RULING SPAN DATA - SAG AND TENSION 500 Ft. Ruling Span Temp Loading Conditions oF Ice Wind o° 1/2" 4# (40 mph) -30° None 31# (110 mph) 10° None None -30° None None -60° None None 80° None None UTS = Ultimate Tensile Strength Sag (ft) Final 8.64 9.38 5.11 3.8 3.11 8.13 Tension (ibs) ' Final 5,986 6,410 2,830 3,790 4,650 1,783 % UTS Final 42.4 45.4 20.0 26.8 32.9 12.6 OVERLOAD CAPACITY FACTORS FOR WOOD STRUCTURES (NESC - Grade B)* Grade B When At Installed Replacement Transverse (wind) and Vertical strength At Crossings 4.0 2.67 Elsewhere 4.0 2.67 Transverse (wire tension load) strength At Crossings Elsewhere et oo os w w Longitudinal Strength In General less 1.00 At Dead-ends y ° S _ w w NOTES Where structures are built for temporary service the overload cap- acity factors at replacement may be used provided that the desig- nated fiber stress is not exceeded during the life of the structure. ° The factors in this table apply for the loading conditions of Rule 250B. For extreme wind loading conditions, see Rule 260C. * From National Electrical Safety Code CONDUCTOR LOADING AND TENSION. DATA Vertical Transverse "K" Design Loading Ibs/ft Ibs/ft Ibs/ft "Linnet" 500 ft. Ruling Span a. NESC Heavy Loading (" 1.2222 0.5737 0.3 ice, 4ibs/ft? wind, 0°F) b. 10°F, Final Sag, Unloaded 0.463 0 0 c. -60°F, Final Sag, Unloaded 0.463 0 0 d. 80°F, Final Sag, Unloaded 0. 463 0 0 e. Extreme wind (110 mph) 0.463 1.8631 0 (No ice, 31 Ibs/ft?, -30°F) NOTE Constant "K": From National Electrical Safety Code, Perceni Resultant Tension Ultimat Ibs/ft 1.6501 0.463 0.463 0.463 1.919 “Constant Added to Resultant Loading to Obtain Total Load". Ibs. 5985 2830 4650 1783 6410 Streng' 43% 20% 33% 13% 45% CLEARANCES (IN INCHES) IN ANY DIRECTON FROM LINE CONDUCTORS TO SUPPORTS AND GUY WIRES ATTACHED TO THE SAME SUPPORT 34.5 Number of suspension insulator units (REA)? 3 Weight of suspension insulator (Ibs) 38 Normal clearance to support (REA) 19 Minimum clearance to support 6 Ibs/ft? wind (REA) 12 Minimum clearance to surface of support arms (NESC) 9 Minimum clearance to structure at extreme wind or other extreme conditions (REA) 3 Minimum clearance to span and guy wires attached to the same structure: When parallel to line (NESC) 23 Anchor guys (NESC) 13 Anchor guys (REA) 13 All other (NESC) 17 NOTES: ° The above data is taken from REA Bulletin 62-1, ° Average conditions for a tangent structure. 38 19 12 11 27 16 16 21 48 25 16 15 37 21 31 ay — uw ~ | 78 42 26 24 10 55 33 35 49 138 88 48 30 29 12 38 41 55 161 10 108 60 35 34 14 73 44 47 67 230 12-14 138 71-83 50-56 47 20 101 61 65 95 TOSS 07S Cay ate | dae NY: (4 See AL ABA JWA INC. Northwestern Alaska NW Alaska Coal Project - Phase Il PROPOSED POWERLINE CORRIDOR eso ROSA LORAIN EDO IES, LPS ECE NOOSE ORE SSN BG By hY LLVES GY ORF Ke AGIs KCNA Tene SAE SER op K ISL y AKA CUS ade IOS RINE OF NIP EV EES ; Z | Rao SE Za Oey SIA Spo Ne i j CW OL SIS N CN nee AZ, Wf MDS CMSA ‘ XC NI Ihe wt R421 ‘ Ages SCALE: 1"=6_MILES DATE: 12/92 DRAWN BY: RSA/MI CHECKED BY: TI FILE NAME: 2094FIG2.dwg JOB NUMBER: 1141-2115 JWA INC. Northwestern Alaska NW Alaska Coal Project - Phase Il INCORPORATED cs oe one Ss PROPOSED POWERLINE CORRIDOR Map Location > go ALASKA 42 KOTZ Oe Cc (Y, 7 0 oY Ja 0 BUE VIN Northwest Alaska Coal Project Economic Analysis of Coal-Fired Power Plants to Serve Nome, Kotzebue, and the Red Dog Mine September 19, 1991 Submitted by: Analysis North 911 West 8th Avenue, Suite 204 Anchorage, Alaska 99501 (907) 272-3425 “ Authors: Alan Mitchell Steve Colt, Subcontractor Submitted to: Arctic Slope Consulting Group 5.7 CONTENTS Objective of the Study... Summary of Results ..... Sensitivity Analyses . . Break-Even Analyses .... Economic Analysis Methods . 5.551 5.5.2 Costs Accounted For ....... 5.5.3 Variable Electricity Production Costs 5.5.4 Fixed Operation and Maintenance Costs 5.5.5 New Power Plant Investment Costs 5.5.6 Credit for Power Plant Heat Recovery Input Assumptions for the Economic Model 5.6.1 Coal Plant Characteristics .. 5.6.2 Diesel Plant Characteristics . 5.6.3 Heat Recovery Assumptions oie 5.6.4 Electric Load Forecasts enire 5.6.5 Fuel Price Forecasts .. ee 5.6.6 General Assumptions . . Meelis Model Runs ...... . . * “ References ......++.-. ‘ . Analysis Period and Discounting oe eo ew ew we . on Uaanunnuwn Nunnaunn uo S§-1 5 =)|2 5-5 - 20 = 4.20 cola: - 22 =25 - 26 — 27 - 36 9) - 40 - 42 - @5 - 46 = $3 Table 5.1 - Net Benefit of Coal-Fired Power Plants Relative LIST OF TABLES Co Diesel; Powar|PlLantaire ell oiieiicielancea one Table 5.2 - Sensitivity Analysis: Nome Power Plant Table 5.3 - Sensitivity Analysis: Kotzebue Power Plant Table 5.4 - Sensitivity Analysis: Red Dog Power Plant Table 5.5 - ei Analysis: Deadfall Syncline Power Plant Table 5.6 - Break- Even. Coal Prices, Construction Costs, and Coal Plant Staffing .. Milled iiitoall fell ell lel elilil Table 5.7 - Base Case Input Assumptions ae me TTT ear aati Table 5.8 - Projected Crude Oil Prices .. Table 5.9 - Retail Diesel Prices and Margins for 1000+ gal/month Table 5.10 - Summary of Assumed Margins Between Crude oil Prices and Avoidable Diesel Costs Table 5.11 - Delivered Diesel Prices Figure 5.1 - Break-Even Figure 5.2 - Break-Even Figure 5.3 - Break-Even Figure 5.4 - Break-Even Power Plant... Figure 5.5 - Comparison for) Nome! eis Figure 5.6 - Comparison for Kotzebue . . LIST OF FIGURES Analysis, Nome Power Plant . Analysis, Kotzebue Power Plant Analysis, Red Dog Power Plant . Analysis, Deadfall Syncline of Two District Heating Studies of Two District Heating Studies aw ann aun uNaunun ou @OrnNnw wo 15 S17, 48 50 52 53 16 17 18 19 33 36 5.0 Economic Analysis of Coal-Fired Power Plants to Serve Nome, Kotzebue, and the Red Dog Mine 5.1 Objective of the Study This study is an economic analysis of coal-fired power plants that would serve portions of the electrical and heat loads of Nome, Kotzebue, and the Red Dog mine. The analysis compares the capital and operating costs of the proposed coal plants with the costs of serving those loads from systems that utilize diesel and fuel oil. The coal-fired plants will use coal from a proposed coal mine at the Deadfall Syncline site. Four separate coal-fired power plants were considered in this analysis. Separate plants in Nome and Kotzebue to serve the local electrical and heat loads in those communities were analyzed. Two alternative power plants for serving the energy needs of the Red Dog mine were analyzed. One alternative is a plant located at the Red Dog mine. The other alternative analyzed is a plant located at the Deadfall Syncline coal mine, serving the Red Dog mine through use of a proposed 85 mile transmission line. Estimates for the costs and operating characteristics of the power plants were developed by SFT.! Because costs occur at different points in time, an economic comparison must consider the time-value of money. In this analysis, the present-value of costs were calculated so that future costs could be compared and added to present-day costs. The present value of a $1 cost occurring in the future is less than $1, because a sum less than $1 can be set aside now to pay for that '"Technical Memorandum on Power Plant Evaluation for Northwest Alaska Coal Project Engineering Feasibility Study," SFT, Inc., Preliminary. future $1 expenditure. The invested sum earns interest and grows to $1 by the future expenditure date. The analysis considered costs and benefits that are expected to occur over a 35 year time period. All dollar figures presented in this report are constant 1991 dollars. 5.2 Summary of Results A summary of the results of the analysis is presented in Table 5.1. The results presented in the table were derived from a set of "Base Case" assumptions concerning fuel prices, construction costs, operating costs, and other assumptions that affect the economic costs and benefits of each power plant. The base case assumptions represent our best estimate of the values for these variables. Numerous sensitivity tests were done on these assump- tions and are presented in the next section. Each of the four rightmost columns presents the results for a different power plant. Each number in the table represents the benefit or cost resulting from use of a coal-fired power plant relative to use of a diesel-based system. A positive value indicates that the coal plant has a cost advantage relative to the diesel system. A negative value indicates that the coal plant has a cost disadvantage relative the diesel alternative for the type of economic benefit indicated. All benefits are expressed as the present value sum of the benefits occurring during the 35 year analysis period. Four categories of benefit for each coal-fired power plant are identified: e Fuel and Non-Labor Operation and Maintenance - This category addresses the differences between coal and diesel plants as to fuel costs, and any non-labor maintenance costs (e.g., spare parts, lube oil, water consumption). Table 5.1 - Net Benefit of Coal-Fired Power Plants Relative to Diesel Power Plants. Base Case Assumptions. Figures are present vaiue, millions of 1991 $. Positive numbers indicate a cost advantage for the coal plant. Negative vaiues indicate a cost disadvantage for the coal plant. The Red Dog plant and the Deadfall Syncline Minemouth plant are alternatives for serving the Red Dog mine energy needs. oo Location of Coal Power Plant ----- Deadfall Syncline Type of Benefit Nome Kotzebue Red Dog Minemouth Fuel and Non-Labor Operation 14.0 15:3 44.3 59.0 and Maintenance Power Plant Labor and -19.9 -23.0 -25.6 -29.2 Property Insurance New Power Plant Investment -26.9 -25.6 -53.0 -60.1 Credit for Recovered Power 0.0 -1.0 -6.4 -32.5 Plant Heat Net Economic Benefit -32.8 -34.3 -40.7 -62.9 e Power Plant Labor and Property Insurance - This category accounts for differences in the labor costs and property insurance costs associated with coal and diesel power plants. e New Power Plant Investment - This category accounts for differences in capital investment in electrical generation capacity for the coal and diesel alternatives. e Credit for Recovered Power Plant Heat - This category address- es any differences between coal and diesel plants as to cost or value of heat recovered from the power plant to serve heating demands such as water heating, space heating, or industrial process heating. The final row in the table, "Net Economic Benefit", adds together the four benefit categories to determine the overall economic merit of the project. A net economic benefit value of $0 indicates a break-even project; i.e., any cost advantages of the project are just balanced by cost disadvantages. All net economic benefit figures are negative, indicating that none of the coal- fired power plants were estimated to produce net economic benefit when using the base case assumptions. All coal plants showed an advantage relative to the diesel alternatives in the Fuel and Non-Labor Operation and Maintenance category, but this advantage was more than cancelled primarily by higher Power Plant Labor and Property Insurance costs and higher capital costs in the New Power Plant Investment category. Each coal plant requires a staff of 22 to operate the plant during all shifts. A typical diesel plant in these locations requires a staff of 9 to operate the plant.’ The capital costs range from $3,300 to $5,400 per kilowatt of capacity for these four coal plants. Diesel capacity costs approximately $740 per kilowatt to install and comes in smaller capacity increments. The Fuel and Non-Labor Operation and Maintenance cost advantage of the coal plant is higher in Kotzebue than in Nome, despite lower electrical loads in Kotzebue. This result is due to higher diesel oil prices in Kotzebue relative to Nome and worse diesel plant efficiencies in Kotzebue relative to Nome. For the coal power plant alternative sited at the Deadfall Syncline mine, an additional cost disadvantage is the inability of that plant to supply the heating needs of the Red Dog mine through recovered power plant heat. Extensive waste heat recovery is employed at the existing diesel plant, and that heat recovery provides approximately $36 million of present value benefit to the Red Dog facility.’ The waste heat recovery benefit is lost with a *Kotzebue’s diesel plant currently has a staff of only 6. [The estimate of annual heating load at the Red Dog mine is relatively uncertain because of lack of heat flow metering. This results in substantial uncertainty in the estimate of heat recovery benefit. remotely-sited power plant, except during periods when the remote plant is down for maintenance and the local diesels are operated. Because of less expensive coal, the Deadfall Syncline coal plant does have a $15 million fuel cost advantage relative to the coal plant sited at the Red Dog mine. However, the heat recovery penalty and the higher capital cost of the Deadfall Syncline power plant more than cancel the fuel cost advantage. The superiority of the Red Dog coal plant relative to the Deadfall Syncline coal plant is maintained across all of the various sensitivity tests that were performed and discussed in the following section. 5.3 Sensitivity Analyses The results of this analysis depend on a number of uncertain input assumptions. Different estimates for the values of these input assumptions would produce different estimates of the net economic benefit of these projects. In order to investigate this uncertainty, a number of sensitivity tests were conducted by varying the values for critical input assumptions and recalculating the net economic benefit of the projects. The results of the sensitivity tests are presented in Tables 5.2 through 5.5. Each table corresponds to a different coal power plant. Each row in the table identifies an important input assumption in the analysis. The middle diamond in the row marks the net economic benefit of the project using Base Case assumptions for the identified variable and all other variables. The other diamonds in the row mark the calculated net economic benefit of the project assuming other values for the identified variable. Consider the first row of the Nome sensitivity analysis, Table 5.2. The sensitivity test examines the effect of varying the Table 5.2 - Sensitivity Analysis: Nome Power Plant Base Case: Mid Electrical Load, Mid Oil Prices Net Present Value Benefit of Coal Plant Relative to Diesel, $ million variable unit -50 -45 -40 -35 -30 mao -20 -15 -10 -§ oO t ' { { ' t ! ! ! ! Electrical Load Case Low Mid High QcnaskeuwOsSeineyeneeus Brefereiere © Oil Prices Case Low Mid High Omrerciaice Seeekves SUC Ei eeeewnnueeeues 4 Electrical Load Case Low Mid High Oil Prices Case Low Mid High Oararererere sYofelerololererelelerelels\ O tororotevelelsforslelerererclerels eololefeiciols\ elo oleteisloreloreleloleteerelererere M7 Average Coal $/MMBtu $3.95 $3.29 $2.63 Price Prsusenees Oeneewavasse® Grants for Coal Yes/No No Yes Mine Oreeerr 4 Coal Plant Heat Btu/kWh 17875 16250 14625 Rate ©. .2.0....4 Construction % of 120% 100% 80% Cost Base Wu ccicecccccPiccccccces® Coal Plant # of 27 22 17 Staffing Staff WanessdeeeeSsaneweqeae® District Heat- Type Small None Large/Cheap ing System Oi ci dicwoyensnes ‘ Discount Rate %/year, 6 4.5 3 real 44.4 Table 5.3 - Sensitivity Analysis: Kotzebue Power Plant Base Case: Mid Electrical Load, Mid Oil Prices Variable Unit Electrical Load Oil Prices Electrical Load Oil Prices Average Coal Price Grants for Coal Mine Coal Plant Heat Rate Construction Cost Coal Plant Staffing District Heat- ing System Discount Rate Case Case Case Case $/MMBtu Yes/No Btu/kWh % of Base # of Staff Type %/year, real Net Present Value Benefit of Coal Plant Relative to Diesel, § million -45 -40 -35 -30 -25 -20 -15 -10 -5 t ! ! ! { Low Mid High OC cisieicicle eo cic @ Low Mid High Po ccicccccccMecccccccee® Low Mid Low Mid High @reiaieiiaciclel*) elelolololare Oares\c cielelelelrsleie aie 4 $3.95 $3.29 $2.63 17875 16250 @...6..4 14625 120% 100% 80% Wn ccccccccGecccceee® Large/Cheap Table 5.4 - Sensitivity Analysis: Red Dog Power Plant Base Case: Mid Electrical Load, Mid Oil Prices Net Present Value Benefit of Coal Plant Variable Unit -100 ' Relative to Diesel, $ million -10 -60 -50 -40 -30 -20 -10 0 ' ' t ' ' { ' i Electrical Load Case Low Mid High Orr 3.0 one) Oil Prices Case Low Mid High Oarelololoveloloiottelstoreioleicieieiarer @cretererer siejersiclolelo wleleleleiwie's’s 4 Electrical Load Case Low Mid High Oil Prices Case Low Mid High Oielororelololelerelorstercieierereierele SFoKAG aioe ie foleieraiotoleselelalelorsieletorelerorers aoleerein® Average Coal $/MMBtu $3.38 $2.82 $2.26 Price Orrorcirelecreeeers Orrcreicrerererarconae Grants for Coal Yes/No No Yes Mine Oniiwicle coo Coal Plant Heat Btu/kWh 17,875 16,250 14,625 Rate GOOG boca.) Construction % of 120% 100% 80% Cost Base Oxtereree es Orrercrorecrrre 4 Coal Plant # of 27 22 Lid! Staffing Staff Rimcuns Vancce® Discount Rate %/year, 6 4.5 3 real Table 5.5 - Sensitivity Analysis: Deadfall Syncline Power Plant Base Case: Mid Electrical Load, Mid Oil Prices Net Present Value Benefit of Coal Plant Relative to Diesel, §$ million -100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 Variable Unit ! { ' ! ! ! ! ! ! { i Electrical Load Case Low Mid High @...0. 2 5¢ Oil Prices Case Low Mid High GN DOOUOOUCOK hw arolaralote(siateaiel sce ste 4 Electrical Load Case Low Mid High Oil Prices Case Low Mid High Cae aloiavoiplancielciotersi ol Olcvelotstotcleleisia sicielstoe ie aieier ota 4 Average Coal $/MMBtu $2.66 $2.22 $1.78 Price Cre cies falelctei Welolelotelercia © Grants for Coal Yes/No No Yes Mine @...¢ Coal Plant Heat Btu/kWh 17,875 16,250 14,625 Rate Qe cosBeaesD Construction % of 120% 100% 80% Cost Base arte lelareiere a aieleloveloiste rele ¢ Coal Plant # of 27 22 a7 Staffing Staff Co nccec Pcs ence Electric Heat Yes/No Yes No for Mill 4..¢ Discount Rate %/year, 6 4.5 3 real 4.0.4 ee assumption concerning future electrical load in Nome. The Mid case load forecast, developed by us in a separate report‘, is the 3asecase assumption. The net economic benefit of the Nome coal olant with all variables set to their base case values is -$33 aillion, present value (i.e. a net loss of $33 million), as shown vy the middle diamond of the sensitivity test in Table 5.2 and also mn Table 5.1. The sensitivity test then shows that in the Low :lectrical load forecast for Nome, the net economic benefit of the rroject drops to -$39 million, the left diamond in the row. In the ligh electrical load growth scenario, the net economic benefit ncreases to -$21 million, the right diamond in the row. The sensitivity analyses indicate that the economic benefits f the coal plants are quite sensitive to oil prices. In the case f high future oil prices, the attractiveness of coal plants ncreases substantially, since the fuel cost advantage of coal mproves. The sensitivity analysis also shows the effect of ombining High oil prices with High electrical loads. Such a ombination almost results in break-even economics for the Nome and 2d Dog coal power plants. Because of substantial uncertainty in the amount of future ining load that will be connected to the Nome electric utility, ere is a large difference between the Low and High Nome electri- 1l load forecast. This large difference has a substantial impact 1 the economic merit of the Nome coal plant, as shown in the mnsitivity table. The variation in economic net benefit between ie Low and High electric load scenarios for the other three coal ants is less significant because of tighter estimates of electri- .1 load in the those locations. ‘"Nome Electrical Load Forecast," Prepared by Analysis North r Arctic Slope Consulting Group, October 26, 1990. Se) L0 Assumptions concerning the size and cost of a district heating system are critical in the Nome and Kotzebue analysis. The base case assumption for Nome was that no district heating system will be installed for the diesel or coal power plants (although use of waste heat to heat city water is assumed). Costs and fuel-saving benefits indicated in the SFT technical coal plant report’ and a recent analysis of Nome district heating potential by Fry- er/Pressley Engineers® imply that a district heating system is not cost-effective (this issue is discussed in more detail on page 5) || (sabre The base case assumption for Kotzebue was that a relatively small district heating system will be installed, as designed in the SFT report. The economic benefits of such a system appear to be favorable. The prior analysis of coal plants for Nome and Kotzebue’ differed substantially from the recent reports concerning the potential size and cost of district heating systems for Nome and Kotzebue. The previous report concluded that larger systems could be built at a relatively low cost per saved gallon of fuel. We performed a sensitivity test to see how such an assumption would affect the economics of coal plants for Nome and Kotzebue. Because these larger district heating system designs could outstrip the available waste heat from the diesel power plants, yet do not surpass the heat potentially recovered from the coal plants, the economics of both the Nome and Kotzebue coal plants improved by $13 million and $11 million, respectively. SSFT, p. 3-8, 4-14. SwuNome Waste Heat Recovery Report and Concept Design," Prepared by Fryer/Pressley Engineering, Inc. for the Alaska Energy Authori- ty, May 1, 1990. ™Kotzebue and Nome Coal Study," Prepared by Arctic Slope Consulting Group and Mechanical Technology, Inc. for Alaska Native Foundation, January 1990. Ey etal The "Grants for Coal Mine" sensitivity test examines a scenario where the Deadfall Syncline coal mine receives grants for a number of infrastructure components, receives a waiver for local taxes for three years, and prices so as to eliminate profits. This scenario and the resulting coal price are described in a July 5, 1991 memo from Northern Economics to Kent Grinage of the Arctic Slope Consulting Group. The "Coal Plant Heat Rate" is the amount of fuel required to generate one kilowatt-hour of electricity (one net kilowatt-hour, after deducting electric consumption within the plant). The heat rate is inversely related to the efficiency of the plant; a higher heat rate corresponds to a lower efficiency. The construction cost of the coal plant and the number of people required to staff it are both critical factors in the economic analysis. As the sensitivity tests show, a 20% reduction in the construction cost of the Nome and Kotzebue plants produces about the same improvement in the economic net benefit of the coal plants as a 5 person reduction (23% reduction) in the plant staffing. For the Red Dog and Deadfall Syncline plants, the 20% construction cost reduction is more significant than a 5 person staffing reduction, because of the higher capital cost of those plants. The "Discount Rate" is used to calculate the present value of future costs and is related to interest rates for borrowing or investing money.* To use a high discount rate in the present value calculation causes less value or emphasis to be put on future cost ’Because costs are expressed in constant, inflation-adjusted dollars in this analysis, a "real" or inflation-adjusted discount rate must be used. An interest rate of 9% along with an inflation assumption of 4.5% results in a real interest rate of about 4.5% 9% - 4.5%. (Actually, the exact calculation is 1.09/1.045 - 1 4.3%.) 5 = 22 savings or increases. A high discount rate usually penalizes capital-intensive projects such as coal plants because these projects rely on future fuel savings to pay back large up-front investments in the coal plant. The sensitivity tests show that changes in the discount rate do not have large effects on the net economic benefit of the plants. This is because the future fuel savings from the coal plants are cancelled to a large degree by the increased future labor costs required to operate the coal plants. A high discount rate diminishes the importance of the fuel savings, but it also diminishes the importance of the higher future labor costs. In high oil price scenarios, the net economic benefit of the plants would be more sensitive to the discount rate. For the Deadfall Syncline coal plant, the base case assumes that the Red Dog mine does not convert to electric heating, because electric heat conversion appears not to be cost-effective. Therefore the Deadfall Syncline plant is assumed to be a 15.5 MW (net) plant, not the 20 MW (net) plant required to supply electric heat at the Red Dog mine. A sensitivity test was done to determine the net benefit realized from converting the Red Dog mine to electric heat if a coal plant is built at Deadfall Syncline. Comparing the fuel cost of electric heat (additional coal burned at the power plant) with the fuel cost of the oil heat alternative leads to the conclusion that there is a net economic cost of about $4 million (present value) associated with converting to electric heat in the Mid Oil price scenario. This is shown in the sensitiv- ity chart, Table 5.5. Electric heat is about $4 million superior to oil heat on a fuel cost comparison (capital costs were not compared) for the High Oil Price scenario. Overall, the sensitivity analyses indicate that the Kotzebue and the Deadfall Syncline plants have a very low probability of producing net economic benefit. More than three variables would have to assume favorable values in order for those plants to show economic merit. Seas The Red Dog plant has the highest probability of demonstrating yomic benefit. High oil prices along with a favorable construc- 1 cost could result in net economic benefit from that plant. Nome plant would require high oil prices, high electrical load, one other variable such as construction cost or plant staffing \ssume a favorable value in order for the plant to show economic a Break-Even Analyses In addition to the sensitivity analysis, a break-even analysis performed on three variables: the construction cost of the coal r plant, the staffing of the coal power plant, and the average vered price of coal to the coal power plant. These factors are critical in determining the economic benefits of the coal ts and are factors that can be affected by the design and ncing of the coal power plants and the Deadfall Syncline coal » The break-even analysis determines the value of a particular able that will cause the coal plant to have $0 net economic Fit. For example, the break-even delivered coal price is the > that coal needs to be delivered to the coal plant in order the coal plant to produce electricity for the same cost as a :l plant. If coal is delivered for less than the break-even price, the coal plant will demonstrate net economic benefit compared against the diesel alternative. Table 5.6 shows the break-even values for each of the three bles. The analysis was done for each of the four power s. All other assumptions are held at their base case values determining the break-even value for a variable. For example, the break-even delivered coal price for Nome is being lated, the construction cost, plant staffing, electrical load, cices, etc. are all set to their base case values. The break- coal price for the Nome plant is $0.05/MMBtu, very low 3 =) 14 relative to the best estimate of the average Nome coal price of $3.29/MMBtu.?° Table 5.6 - Break-Even Coal Prices, Construction Costs, and Coal Plant Staffing. All other assumptions are set to their Base Case vaiues when caiculating break-even amounts. Capital costs for the Nome and Kotzebue plants do not include District Heating construction costs. ------- Location of Power Plant ------- Deadfall Variable Unit Nome _ Kotzebue Red Dog Syncline Average Delivered $/MMBtu $0.05 -$1.86 $1.41 -$0.10 Coal Price ; Construction Cost $ million $1.1 -$4.0 $19.5 $5.8 Coal Plant Staffing #of Staff -2.1 -4.2 -2.5 -15.9 A more general break-even analysis is presented in Figures 5.1 through 5.4. These graphs allow one to determine the break-even value for a variable given any values for the other two key variables. For example, the break-even delivered coal price in Nome can be determined assuming the coal plant costs $20 million to construct and can be staffed with only 17 persons. The notes on Figure 5.1 explain how to use the figure, and the dotted lines show how to solve the above example problem. The break-even delivered coal price for the Nome plant is approximately $2/MMBtu with a construction cost of $20 million and a plant staffing of 17. The large arrows on each break-even graph indicate the Base Case values for each of the three variables. For example, the Base °‘The estimates for the delivered price of coal in Nome vary from year to year over the analysis period. The "average" values presented here are actually weighted-average prices that use the discount rate to weight early-year prices more heavily. S = 15) 9tT - S Figure 5.1 - Break-Even Analysis Nome Power Plant Average Coal Price, $/MMBtu $5 Bul To determine a break-even coal price for a particular coal plant capital cost and staffing level We 1 Find the capital cost on the horizontal axis $4 i ier 2 Move vertically upward until intersecting the line corresponding to the plant stattling level PN 3. Then move horizontally to the left to read of! the bees break-even coal price from the vertical axis eel il a The graph can also be used in reverse to determine the i eal rw break-even capital cost given a coal price and stalling i pee fi The large arrows indicate the Base Case assumptions for re inc each of the variables $2 PL eee : : ww Coal Plant . << . $1} Ul Rene Level ed ne ~ i ~ ~ mate -$1 el| ns | feo mT $0 $10 $20 saa $40 $50 Coal Plant Capital Cost, $ million 4t-S& (6: Figure 5.2 - Break-Even Analysis $6 Kotzebue Power Plant Average Coal Price, $/MMBtu |, ——_ . $2 —— $1} $0 — a — ; Coal Plant -git = SS $27 = a7 ~ $3} 2 2 \ —<— = 1 ——— "0 » $10 “$20 | 4530 $40 Coal Plant Capital Cost, $ million 4 / \ itd land wbey rs — { F nh get oil (iy st- Ss riyuice 0. - Break-Even Analysis Red Dog Power Plant Average Coal Price, $/MMBtu $57 $4 i —— a = : PF a : a <a _ $2} rT —S eoegeea al =. a = oo ~ 12 $1} ie 17 ~ 22 $0 '—— ees je 2 Ll | $0 $20 $40 ts60 $80 Coal Plant Capital Cost, $ million 6T - & Figure 5.4 - Break-Even Analysis Deadfall Syncline Power Plant Average Coal Price, 1991 $/MMBtu $4 $3 —s — — = — N $2 i = = re NN : —— $1 > Se Coal Plant NO Staffing Level $0 SST? = = 17 -$1 am ! 1 —— , > 22, $0 $20 $40 $60 t $80 $100 Coal Plant Capital Cost, 1991 $ million Case coal plant construction cost for Nome is $31.8 million (1991 $ and not including district heat), the Base Case plant staffing is 22, and the base case delivered coal price is $3.29/MMBtu. Of the four plants analyzed, the Red Dog plant exhibits the most realistic break-even combinations. 5.5 Economic Analysis Methods To determine the economic benefit of a coal-fired power plant, the costs of serving the electrical load with the coal plant are compared with the costs of serving the electrical load without the coal plant (i.e. with diesel generation). The difference between these two cost scenarios is the net economic benefit of the coal plant. Therefore, the primary task in evaluating the economic benefit of a coal plant is to develop a model that estimates those future costs that might change from use of the plant. A personal computer spreadsheet model (using Quattro Pro) was developed for this purpose. The net economic benefit calculation involves running the model twice: once with the coal plant and once without. The following subsections describe the structure of that model. The actual input assumptions that were used in the net benefit calculations are described in section 5.6. 5.5.1 Analysis Period and Discounting The economic model estimates costs on a year-by-year basis for 20 years from the expected operation date of the coal plant. However, the coal plant is expected to last 35 years, and costs and benefits should be accounted for over its entire life. Because of the uncertainty involved in forecast- ing for such a long period of time, costs in year 20 were extended without change through year 35. Thus, no load growth or fuel prices changes were accounted for from year 20 through 5 - 20 year 35. This technique has been common practice in past Alaskan energy project analyses. As discussed earlier, all comparisons that involve costs occurring during different time periods utilize present value amounts. The present value calculation discounts future costs at a rate of 4.5%/year more than general inflation. 5.5.2 Costs Accounted For This analysis examines costs from the perspective of Alaska as a whole. It is an economic analysis of "social" costs, similar to economic analyses performed by the Alaska Energy Authority for other energy projects. Only cost changes that are due to changes in the consumption of economic resources within Alaska (labor, fuel, materials, etc.) are counted in this analysis. Some payments that appear to be costs to particular entities within Alaska are actually transfers of money that do not involve the consumption of any additional resources. For example, property tax payments on a power plant are a transfer of money from the plant owner to an Alaskan govern- mental entity. Although a coal plant may incur higher property taxes than a diesel plant due to its higher capital cost, it does not consume any more governmental services due to its higher capital cost. Therefore, any changes in property tax payments due to use of a coal plant are not counted in this analysis. Similarly, payments towards the fixed cost of existing long-lived capital facilities that have unused capacity, such as the Nome and Red Dog ports, are not counted in this analysis. The increased or decreased use of those facilities does not result in changes in the amount of economic resources consumed. Siaaia. The categories of costs that are addressed in the analysis include: e Variable Electricity Production Costs: fuel costs, and non-labor operation and maintenance costs. e Fixed Operation and Maintenance Costs: power plant labor costs, and property insurance costs. e New Power Plant Investment Costs: capital costs of addi- tional generation capacity or replacement of existing generation capacity. e credit for Recovered Power Plant Heat: net benefit derived from recovering heat from power production. Costs other than these are frequently assigned to power production for accounting purposes. For example, a portion of general overhead may be assigned to power production expenses. However, these overhead costs are not changed by the presence of a coal plant so are not addressed in this analysis. The sections below discuss the methods used to account for costs in each of the above categories. It is helpful to reference the model output presented in section 5.7 while reading the following sections. 5.5.3 Variable Electricity Production Costs The costs in this category are assumed to be related to the number of kilowatt-hours generated by the power plant. The load forecast provides the number of kilowatt-hours generated in each year. The model assumes that those require- ments are be produced from "Baseload" and "Peak" units. The Baseload unit has the lowest variable cost per kilowatt-hour and is the coal plant in the runs including a coal plant. In the diesel scenarios, the most efficient diesel unit is entered into the model as the Baseload unit. Sisi22 Since the Baseload unit has a limited capacity and is down for maintenance during a portion of the year, not all of the energy requirements can be produced from that unit. The model utilizes a load duration curve” and the availability figure for the baseload unit to determine how much of the energy requirements are met by the unit. The remaining energy requirements are served from the Peak unit. The characteris- tics of the Peak unit in the model are intended to represent the average characteristics of the generation units that typically meet load beyond the most efficient unit’s contribu- tion. This is a two-unit model; the actual utility plant may have many more generation units, but this model simplifies the analysis by characterizing the plant as two generation units. Once the division of annual load is made between the Baseload unit and the Peak unit, the heat rate (Btu/kWh) and variable operation and maintenance figure (mills/kWh) for each unit is applied (adjusting for transmission losses) to determine the total fuel used (MMBtu) and total variable O&M costs ($). Fuel prices are used to translate the MMBtus of fuel use into total dollars of fuel costs. The heat rate used at this stage of the analysis is the heat rate of the generation unit assuming no heat recovery is taking place. The coal plants analyzed in this study utilize Rankine steam cycles to produce mechanical power. When heat recovery occurs by extracting steam prior to the final turbine stages of a Rankine steam cycle, additional fuel must be burned in order to maintain power output (also the capacity rating of the unit decreases). In this model, the extra fuel consumption associated with this type of heat recovery is not accounted for in the variable electricity production costs. oad duration curves were estimated from the load factor and the minimum load for each area served. 5 = 23 It is accounted for in the "Credit for Recovered Power Plant Heat" category discussed in a subsequent section. For a diesel engine, recovering heat from the water jacket does not cause significant extra fuel consumption. For a cogeneration plant, dividing fuel use between electricity production and heat production is an arbitrary decision. From the perspective of the economic analysis, what is important is that the proper total amount of fuel use is calculated. Our convention here is to consider electricity production to be the basic product and to calculate the fuel necessary to produce that product alone. Then, any additional fuel required to supply heating needs is assigned to heat production. We assumed that all non-labor power plant operation and maintenance expenses (e.g. spare parts, lube oil, water consumption, ash disposal) are proportional to kilowatt-hours produced. These costs were included in a variable O&M factor (mills/kWh). We examined cost records for these items for the Nome and Kotzebue diesel power plants. Nome generation in 1990 was 80% more than Kotzebue generation. Non-labor operation and maintenance expenses were about 54% higher for Nome, indicating approximate proportionality with annual generation. Rules of thumb used by coal plant designers appear to indicate that non-labor expenses for coal plants also vary with the number of kilowatt-hours generated. SFT, Inc. estimates the amount of non-labor expenses for the coal plants in this study on a dollar per ton of coal basis. This method indicates that these expenses are largely proportional to generated kilowatt-hours. 5 - 24 5.5.4 Fixed Operation and Maintenance Costs Some operation and maintenance costs do not vary signifi- cantly with the number of kilowatt-hours generated. Our interviews with SFT, utility engineers, and utility managers suggest that power plant labor expenses are not particularly sensitive to load. The 4 coal plants in this study are estimated to have the same staffing requirements despite serving loads that are different by as much as a factor of 5 (Red Dog vs. Kotzebue load). The Nome and Red Dog diesel plants currently serve loads different by a factor of 4, yet these plants have approximately the same staffing require- ments. For the purposes of our modeling, we treated plant labor costs as being unrelated to amount of kilowatt-hours produced. Labor costs vary by plant type, and these critical differences were accounted for in the model. Total plant labor costs are included in the model, as opposed to only presenting the incremental plant labor cost associated with new investment. The other fixed operation and maintenance cost accounted for in the model is property insurance. Because property insurance costs are proportional to the replacement cost of the property and coal plants cost significantly more than diesel plants to construct, there are significant differences in property insurance costs if coal plants are utilized. Total plant property insurance costs are presented in the model. For example, in the runs assuming the existence of a coal plant, the property insurance costs for both the coal plant and the standby diesel generators are presented. 5§ = 25 5.5.5 New Power Plant Investment Costs New investments in generating capacity occur when insufficient capacity exists to reliably meet peak electrical demand, or when generating technology becomes available that is more cost-efficient than existing generation units. The model accounts for differences in new investment in generation units between the coal and diesel scenarios. The model ignores investment that occurs before the study period, since such investment is irretrievable and common to both scenarios. Since the length of the analysis period is equal to the life of the coal plant, the coal plant capital cost is entered as a one time cost occurring at the beginning of year 1. In scenarios including a coal plant, no other investments in generating capacity are assumed to occur. Utility managers and power plant operators stated that the capacity provided by the coal plant would meet peak requirements for the entire study period without further generation investments. Without a coal plant, additional investments in diesel generation capacity will need to made in all study locations. In order to avoid the need to incorporate salvage values into the analysis, and in order to account for investment costs through the year 20 through 35 extension period, diesel capacity costs were entered as levelized amounts, based on a 20 year life and a 4.5% real discount rate. The analysis distinguishes between replacements of existing generation units that retire and the addition of new units requiring a new building, switchgear, etc. Replacements are less expensive per kilowatt than new additions of capacity ($500/kW versus $740/kW) . 5 = 26 5.5.6 Credit for Power Plant Heat Recovery As well as producing electricity, thermal power plants can provide heat for space, water, or process heating uses. If supplying that heat from the power plant is less expensive than the next best alternative source of heat, then net economic benefit results from recovering power plant heat. The net benefit associated with recovered heat can differ across thermal power plants. Three significant reasons why the benefit can differ are: 1) The cost of the equipment required to transfer heat from the power plant to the heat load may differ between plants. 2) Recovering heat from the power plant may cause additional fuel consumption (e.g. extraction of steam from a Rankine cycle plant). That additional fuel consumption may differ between plants. 3) One plant may have more waste or low-cost heat available than another. If that additional heat can be cost- effectively used, it will provide additional net economic benefit. Consider issue 1) first. If the main heat load being served by the power plant heat is a district heating system, the main portion of that heat distribution system will cost the same for heat recovery from a diesel plant or a coal plant. However, the location of the power plant may affect the cost of the initial run of pipe that connects the power plant with distribution piping supplying the buildings. Such is the case in Nome where the capital cost of the district heating for a coal plant is estimated to be about $2 million more expensive than the capital cost of a district heating system connected to the existing Snake River diesel 5 - 27 plant, because of their locations relative to the town.!! ” In Kotzebue, there is no substantial cost difference between the diesel and coal plants in connecting to a district heating distribution system. For the Red Dog mine, a connection already exists from the diesel plant to the heating loads at the mine, so is effectively free for purposes of an economic analysis. Making the connection from a coal plant is estimat- ed to cost $1.3 million.” These differences in connection costs are not large relative to the overall plant economics but were accounted for in the recovered power plant heat analysis. Issue 2) above generally lowers the net benefit of recovered heat from a coal plant relative to a diesel plant. Recovering heat from the cooling water jacket of a diesel engine does not result in significant extra fuel consumption by the engine. However, recovering heat from a coal plant utilizing a Rankine cycle usually involves extracting steam from the turbine configuration prior to its final stages. This steam extraction reduces the power output of the turbine unit; additional steam must be delivered to the turbine to make up for the lost power. Fuel consumption is increased. The increase typically amounts to about 0.6 of a Btu of fuel per Btu of steam extracted. Since average coal prices are about $3/MMBtu, this extra fuel consumption amounts to only $1.80 per MMBtu of steam extracted, far less than the $18 per MMBtu cost of heat from a conventional oil boiler using retail "This figure comes from comparing the district heating system cost in the SFT coal plant engineering feasibility study to the cost of a comparable system discussed in the 1990 Fryer/Pressley Nome Waste Heat study. "However, the Base Case assumption is that no district heating system is installed in Nome; plant heat recovery is only used for city water heating. BSFT, C ant Engineeri easibility Study, p. 4-15. S28 fuel oil. However, the cost does count as a disadvantage for coal plants relative to diesel plants with regards to heat recovery. An alternative method for recovering heat from a coal plant is to recover heat from the condenser. Recovery of heat from the condenser does not result in additional power plant fuel consumption. However, this heat recovery can only produce low temperature heat, too cool for a district heating system designed for supplying building space and water heating needs. The temperature of this heat is sufficient to provide heat to the city water system in Nome. SFT believes that a system can be engineered to allow waste heat from the coal plant condenser to heat Nome city water. Thus, the coal plant has no disadvantage relative to the diesel plant for supplying this heat load. As discussed later, this is the only heat load assumed to be served from recovered power plant heat in Nome in the base case. Issue 3) above can give coal plants a substantial heat recovery advantage relative to diesel plants. With maximum steam extraction occurring, Rankine-cycle coal Plants can produce about 15,000 Btus of low-cost heat (~$1.80/MMBtu according to above calculation) per kilowatt-hour of electric- ity produced.’ The Fryer/Pressley estimates for the Nome and Kozzebue diesel plants are that 2,700 and 2,450 Btus of waste heat per kilowatt-hour are available, respectively. These recovery rates assume that no heat is recovered from the stack gas of the diesel plant, only from the cooling water jacket. “However, the capacity rating of the plant is decreased substantially when this level of steam extraction occurs. For example, the 9.6 MW Nome plant de-rates to about 6.5 MW if 90% of the steam is extracted for heating needs. In models runs where high heating demands were assumed, this capacity derating was accounted for. Sia eo) The coal plant can provide considerably more low-cost heat than the diesel plant. If heat loads in excess of 15,000 Btu per kWh can be inexpensively connected to the power plant, the coal plant offers a further advantage. These loads can be supplied directly from the relatively efficient coal boiler that utilizes low cost coal (assuming boiler capacity is available). Heat from a supplemental oil boiler in the diesel plant would be substantially more expensive. Before discussing how issues 2) and 3) play out for the coal plants addressed in this study, two general conclusions can be stated: e When the heat loads that can be cost-effectively connect- ed to a power plant heat recovery system are less than the amount of waste heat available from a diesel plant, the diesel plant will show an advantage relative to a Rankine-cycle coal plant with regards to heat recovery. The diesel plant does not incur the penalty of extra fuel consumption for recovered heat. e When the connected heat loads are large and substantially surpass the amount of waste heat available from a diesel plant, a Rankine-cycle coal plant will have an advantage over a diesel plant because of the availability of substantially more low-cost power plant heat. When comparing Rankine-cycle coal plants to diesel plants on the basis of the value of recovered power plant heat, the amount of heat load that can be cost-effectively connected to the power plant is critical. Heat Recovery Issues: Deadfall Syncline Coal Plant The heat recovery issue for the Deadfall Syncline coal plant is the most straight-forward. The plant is remotely sited from the Red Dog mine heat load. The only time that heat recovered from electricity production is used to supply the Red Dog heat load is when the coal plant is down for maintenance and the Red Dog diesel plant is running. Relative 5 - 30 to the all-diesel scenario, the coal scenario receives a 33 million recovered heat penalty. The size of this penalty is directly related to the size of the Red Dog heat load. The information available on the Red Dog heat load is not particu- larly precise, as discussed in section 5.6.3. Heat Recovery Issues: Red Dog Coal Plant The Red Dog coal plant is sited near the Red Dog heat load and can cost-effectively supply that load ($1.3 million capital investment). However, recovered heat from the existing diesel plant currently supplies virtually all of the heat load. As discussed in section 5.6.3, waste heat from the diesel plant supplies heating needs down to an outside temperature of -40°F. We calculate that less than 0.5% of the total heat load is left unserved by diesel waste heat. Thus, issue 2) dominates, the extra fuel consumption associated with recovering heat via steam extraction from the Rankine cycle. The Red Dog coal plant receives a $6 million penalty relative to the diesel plant because of this issue. Heat Recovery Issues: Nome Coal Plant The district heating system included in SFT’s engineering feasibility study for the Nome coal plant is expected to cost $4.8 million to construct and will displace 125,900 gal- lons/year of fuel use. The equivalent heat load served is 12,100 MMBtu/year (125,900 * 0.135 MMBtu/gallon * 71% effi- ciency). If the capital cost of the system is amortized and added together with the annual operation and maintenance costs, the annual cost of the district heating system can be determined. Dividing this figure by the annual heat load served results in a district heating cost per supplied MMBtu of $35/MMBtu, substantially more than the approximate $18/MMBtu cost of supplying heat from a conventional oil-fired Sis= ssi. boiler using retail fuel oil. Thus, the system appears not to be cost-effective. The SFT design was based on the 1990 Fryer/Pressley (FPE) waste heat study for Nome. The FPE study also discusses a larger district heating system (Design Concept 4) that would displace 220,800 gallons/year. We estimate that such a system would cost $6.4 million to construct if connected to the proposed coal plant. However, the cost of delivered heat from the district heating system is still excessive, approximately $26/MMBtu. FPE believes there are economic risks involved with systems larger than this final design concept. In the Base Case for Nome, we assume that no district heating system will be built. Thus, the Recovered Heat Credit is $0 in both diesel and coal scenarios. We do assume that city water is heated with recovered power plant heat in both the diesel and coal scenarios. The amount of diesel waste is significantly larger than the city water heat needs. Since the heat from the coal plant will be recovered from the condenser, no extra fuel cost is incurred, and there is no difference between the coal and diesel scenarios as to the Recovered Heat Credit. One sensitivity test was performed to address the possibility that a district heating system would be built in the diesel scenario but not in the coal scenario, since the diesel system is about $2.2 million cheaper to construct due to the relative location of the diesel and proposed coal plants. Our modeling showed a $1 million net present value benefit for the diesel-based district heating system. This constitutes a $1 million penalty against the coal plant in this sensitivity case. This case is presented in the sensi- tivity chart, Table 5.2. === 32 Finally, a sensitivity test was done that relies on a prior study of the district heating potential in Nome. The 1990 Kotzebue/Nome Coal Study presented a _ substantially different picture of district heating costs and potential size than the 1990 Fryer/Pressley study. The district heating analysis in the 1990 Kotzebue/Nome Coal Study was based on a 1987 study by Polarconsult (see reference list). $/MMBtu, Incremental $30° $25 Kotzebue/Nome Coal Study a $20 Cost of Alternative Heat | Fryer/Pressiey $15 Useable Heat from $10 Diesel Plant $55 $0 0 50 100 150 200 ,000 MMBtu/year of Heat Load Figure 5.5 - Comparison of Two District Heating Studies for Nome The differences between the studies can be summarized by Figure 5.5. The figure shows the extra cost of expanding a district heating system out to a particular level of heat load. The two stair-stepped lines on the figure represent the two different studies. The 1990 Kotzebue/Nome study detailed one concept (named "Nome, without houses") that served about 100,000 MMBtu/year of heat load. When the costs presented in that study are converted to a $/MMBtu basis, the system costs 52—Ss5 approximately $4/MMBtu to be extended out to that level of load. Reaching the next increment of load, 174,000 MMBtu/year (concept "Nome, with houses"), is substantially more expensive, about $23/MMBtu. Even with free waste heat available, this portion of the system would not be cost- effective to build since its cost exceeds the alternative cost of heat from an onsite fuel-fired boiler, $18/MMBtu, the horizontal dotted line on the chart. The Fryer/Pressley district heating cost curve is substantially different. The four concepts presented in the study are shown on the graph. The largest concept only extends out to 21,000 MMBtu/year of heat load, and the expansion costs are substantially more than those implied by the Kotzebue/Nome Coal Study. The vertical hatched line shows approximately the amount of useable waste heat available from in the diesel scenario, after supplying the city water load. The largest Fryer/Pressley system fits within that diesel waste heat availability. Note that this graph appears to imply that the FPE system is cost-effective because the curve is primarily below the $18/MMBtu alternative cost of heat level. However, this curve is based on heat recovery from a diesel plant located within the city of Nome. It does not include the extra costs of reaching the Snake River diesel plant or the proposed coal plant. The incremental costs in the figure are correct, since the costs of reaching these more remote power plants is fixed and unrelated to size of the district heating system. If the Kotzebue/Nome district heating cost curve is more accurate than the Fryer/Pressley curve, a coal plant exhibits a substantial recovered heat advantage over a diesel plant. With a coal plant, substantial net benefit can be had by expanding the district heating system out beyond the 45 5 - 34 MMBtu/year diesel waste heat limit. In the district heating sensitivity case marked "Large/Cheap" in Table 5.2, the coal plant acquires a $13 million present value advantage over the diesel plant in the Credit for Recovered Heat category. Heat Recovery Issues: Kotzebue Coal Plant The heat recovery issues in Kotzebue are somewhat similar to Nome. However, the Fryer/Pressley Kotzebue designs (adopted in the SFT engineering feasibility study for this project) are more cost-effective than the Nome designs. In the base case, we assume that the FPE district heating system is built (out to Concept 3, the 21,000 MMBtu/year level) and city water is heated as well. The system pushes the limits of waste heat availability from the diesel plant in Kotzebue, but our analysis shows a $1 million present value penalty for the coal system because of the extra fuel consumption. Again, the 1990 Kotzebue/Nome Coal Study depicts a different district heating potential in Kotzebue than the Fryer/Pressley study. The studies are compared in Figure 5.6. The structure of the graph is described in the previous section addressing Nome. The Kotzebue/Nome coal study only presents one design concept, and therefore the cost curve consists of only one segment extending out to 64,000 MMBtu/year, the size of the system in the study. A sensitivity test was done that assumes the Kotzebue/Nome Coal Study district heating cost curve is more accurate. Because the extra low-cost recovered heat from the coal plant can be cost-effectively used in this district heating scenario, the coal plant earns an $11 million present value advantage over the diesel plant in terms of recovered heat benefit. 5S - 35 $/MMBtu, Incremental $35 | hy $30 b |Fryer/Pressiey | $25+ $207 AU UT Cost of Alternative Heat $15+ Useable Heat from Diesel| Plant $10F $5 Kotzebue/Nome Coal Study $o° i - - . 1 0 10 20 30 40 50 60 70 ,000 MMBtu/year of Heat Load Figure 5.6 - Comparison of Two District Heating Studies for Kotzebue Further work should be done to reconcile the differences between the two waste heat studies for Nome and Kotzebue. The differences are quite significant in the determination of the economic benefit of coal-fired power plants for those loca- tions. 5.6 Input Assumptions for the Economic Model Table 5.7 summarizes the assumptions that were used in the Base Case run of the coal plant economic model. These assumptions can also be found in more detail in the model output in section 5.7. For example, all years of the load forecast are shown in that section. Also, Low and High forecasts for loads and prices can be found in that section. The methods used to determine the assump- tions are described in the subsections following the table. Ss 6 Table 5.7 - Base Case Input Assumptions. All dollar amounts are 1991 $. ------- Location of Power Plant ------- Deadfall Kotzebue Red Dog Syncline Coal Plant Characteristics Operation Start Date Year Construction Cost w/o District $ million Heating Life of Plant Years Electrical Capacity, Net MW Net Heat Rate, with No Heat Btu/skWh Recovery Non-Labor Operation and Main- miliskWh tenance Expenses Coal Plant Staffing, based on # of per- 2,080 hour/year positions sons Staffing for Standby Operation # of per- of Diesel Plant sons Annual Labor Cost per Position $/year %/year of Property insurance Rate Replace- ment Cost Plant Availability % of Year Transmission Loss at Full Load % Diesel Plant Characteristics Capital Cost for Additional New $kW Capacity Capital Cost for Replacing $kWw Existing Capacity Life of Generator Set Years New 4MWin New 3 MW in Future Generation Capacity MW and 1995, Re- 2003, Repiace- Replacement of Investments needed in Mid Year placement of ment of 3 MW 15 MW in Load Scenario w/o Coal Plant Avoided 3.7 MW in in 2012 2010 2011 Net Heat Rate BtukWh 3 MW: 8,940 3 MW: 9,500 All: 9,350 Rest: 9,500 Rest: 10,500 Non-Labor Operation and Main- miliskWh 5.9 6.9 5.9 tenance Expenses Plant Staffing, based on 2,080 # of per- 9 6 9.1 hour/year positions sons ——— ------- Location of Power Plant ------- Deadfall Variable Unit Nome Kotzebue Red Dog Syncline Annual Labor Cost per Position $/year $78,000 $75,000 $95,000 %/year of Property Insurance Rate Replace- | j= -------- 0.4% -------- ment Cost Heat Recovery Assumptions Total Area Heating Demand Year = 1995: ,000 240 150 1997: MMBtu/yr 247 156 219 ° 2004: 272 179 219 ° 2014: 313 218 219 0 100%, Pro- % of Area Heat Demand that 22%, City cess, Space can be Economically Connected % 4.8%, City Water System and Water to Power Plant Heat Recovery Water System + Some Large Heat Needs of Buildings Red Dog Mine Incremental Cost of Connecting Additional Heat Load (up to $/MMBtu $O/MMBtu $8.40/MMBtu $0/MMBtu above limit) to Power Plant Heat Recovery Losses from Heat Recovery and % 1.3% 7% 1.3% District Heating System For Coal Plant Heat Recovery, Btu of Fuel O, recovery 0.6, extracted 0.6, extracted Extra Fuel Consumed due to per Btu of from steam steam Heat Recovery Heat Load condenser Maximum Amount of Heat Recovery per kWh Generated Diesel Plant: = Btu/kWh 2,700 2,450 2,880 Coal Plant: 9,000 15,150 15,150 Useability of Recovered Heat (Addresses non-coincidence of % 60% 65% 80% Heat Recovered and Heat De- mand) Efficiency of Alternative (On- % 82% 71% 82% site) Heating System Variable O&M Cost for Alterna- $/MMBtu of $0.30 $0.30 $0.30 tive Heating System Fuel Electric Load Forecasts Mid Case 1995: 37,005 8.7 20,370 4.2 1997: MWh, 38,301 9.0 21,503 4.5 105,192 13.8 105,192 13.8 2004: MW peak 40,716 9.6 26,304 5.5 105,192 13.8 105,192 13.8 2014: 46,101 10.8 30,340 6.3 105,192 13.8 105,192 13.8 ------- Location of Power Plant ------- Deadfall Variable Unit Nome Kotzebue Red Dog Syncline Fuel Price Forecasts Coal, Mid Case 1995: $6.02 $6.02 1997: $/MMBtu $3.37 $3.37 $3.37 $2.80 2004: $2.96 $2.96 $2.96 $2.32 2014: $2.49 $2.49 $2.49 $1.91 Utility Oil, Mid Case 1995: $6.42 $7.58 1997: $/MMBtu $6.58 $7.74 $6.34 2004: $7.21 $8.37 $7.00 2014: $8.21 $9.37 $8.02 Retail Oil, Mid Case 1995: $12.44 $12.67 2004: $/MMBtu $13.26 $13.49 2014: $14.29 $14.51 General Assumptions Economic Discount Rate, real Siyeer | tt treet eens 4.5%/year ------------- (inflation-adjusted) 5.6.1 Coal Plant Characteristics Except where noted below, costs and characteristics of the coal plants were primarily obtained from the SFT engineer- ing feasibility study and direct communication with SFT. SFT estimated spare parts and supplies to cost $4 - $5 per ton of coal consumed. This translates to approximately 3.1 mills/kWh. Water consumption figures presented in the SFT report were multiplied by water rates in Nome to Kotzebue to calculate water costs of 1.1 mills/kWh and 2.4 mills/kwWh, Nome water costs per kWh were used for the Red Ash disposal costs respectively. Dog and Deadfall Syncline plants as well. estimated for the proposed 50 MW coal plant at Healy, $5 per ton of ash, were used to calculate disposal costs of 0.2 5 = 39 16, mills/kWh for all four sites. These non-labor O&M components add up to the totals shown in table. Annual labor costs for Nome and Kotzebue were determined from interviews with Nome and Kotzebue utility managers. A NANA executive indicated that Red Dog labor expenses could be estimated by adding a 15% "hardship" bonus to Kotzebue labor rates and including dormitory and catering costs." Discussions with SFT and Mr. Joe Murphy, Nome Joint Utilities general manager, indicated that the extra labor and operation and maintenance costs associated with maintaining a diesel plant in standby mode would be small if a coal plant staff of 22 were available. Some extra cost was accounted for by adding the cost of 0.13 staff positions to the Nome, Kotzebue, and Red Dog plants. Because the Deadfall Syncline plant is 85 miles from the Red Dog diesel plant, a cost equivalent of 2 staff was assumed for operating that diesel plant in standby mode in the scenarios involving the Deadfall Syncline coal plant. Property insurance rates were estimated from discussions with Ms. Karin Acuna of Rollings, Burdick, and Hunter of Alaska. 5.6.2 Diesel Plant Characteristics The cost of installing new diesel capacity used in the model, $740/kW, is based on the cost of Nome’s recently installed (May 1991) 3.7 MW Cat 3616 generator. The cost is relatively close to costs used in the 1990 Juneau Long Term communication with Mr. John Rense, VP Resources, NANA, August 1991. 5 - 40 Energy plan: $660/kW for an EMD 20-645F and $730/kW for a 3 MW Cat 3612. Data from the recent Cat 3616 installation in Nome indicates that replacing existing diesel capacity after it retires would cost about $500/kW, since the power plant building and some other auxiliary components would still be functional after 20 years. This compares well with the $470/kW figure used in a 1990 Least Cost plan for Copper Valley Electric Association. Capacity expansion plans were developed through discus- sions with utility managers and engineers for Nome and Kotzebue, and through assumptions about the lives of recently installed units. Kotzebue is intending to install two new diesel units before the expected 1995 start date of the coal plant and their planning criteria do not allow these capacity additions to be avoided by the proposed coal plant. The net heat rate of the recently installed 3.7 MW Cat 3616 in Nome has averaged an impressive 8,940 Btu/kWh for its first three months of operation. This heat rate is used for Nome’s Baseload unit in the model. However, the baseload unit is modeled as only 3 MW because Nome’s split-bus system reduces the number of kilowatt-hours that are actually provided by the unit. Nome has a separate bus for the city load and the Alaska Gold Company load. The remaining units at the Nome diesel plant and the planned additions are assumed to serve the remaining load with a heat rate of 9,500 Btu/kWh.”® Kotzebue’s upcoming 3 MW addition will be relatively efficient and is modeled as the baseload unit with a net heat Tf the Nome load achieves the level forecasted in the Mid scenario, NJUS intends to install another 4 MW unit in 1995. 5 ~ 41 rate of 9,500 Btu/kWh. Examination of the efficiencies of the other units in the plant led us to model the peak unit as having a 10,500 Btu/kWh heat rate. The Red Dog diesel plant consists of five 5 MW units with net heat rates of about 9,350 Btu/kWh, according to estimates by SFT. Non-labor operation and maintenance expenses for Nome and Kotzebue were acquired for 1990. This data was used to calculate non-labor O&M estimates of 5.9 mills/kWh and 6.9 mills/kWh for Nome and Kotzebue respectively. The Nome figure of 5.9 mills/kWh was used for the Red Dog diesel plant. Diesel plant staffing estimates are based on the actual staffing that was in place at the time of this report. Annual labor costs and property insurance rates were developed as stated in the prior section. 5.6.3 Heat Recovery Assumptions For the heat recovery portion of the model, the starting point is to forecast total heating loads for the areas served by the power plants. This "Total Area Heating Demand" does not consider whether the heat load has economical access to power plant heat recovery. This Total Area Heating Demand forecast is primarily presented for illustrative purposes. The more important heat load estimate is the load that can economically connected to the power plant. The heat load figures in this report are measured on the output side of the heating system, i.e., they represent the actual energy needs of the water, space, or process requiring S42 heat. The figures are less than the fuel consumed to provide the heating (fuel use * efficiency = heat load). For Nome, figures for 1984 heating fuel use were scaled up to 1989 based on population growth.'? Growth from 1989 on was based on projected population growth" minus 0.3%/year, which equals 1.4%/year. Efficiency improvements in housing will probably keep heating fuel demand growing at less than the population growth rate. For Kotzebue, total heating loads were estimated by scaling down Nome’s 1989 heat load by the ratio of electrical customers in Kotzebue to those in Nome. Growth was projected at the residential customer growth rate forecast in the Kotzebue Electric Association 1989 Power Requirements study minus 0.6%, which equals 2.0%/year. Heat usage at Red Dog is not metered, so estimates were made based on statements by power plant staff members. Staff indicated that heat demands can be satisfied by waste heat from the diesel generators down to a temperature of -40°F. With a typical plant load of 12 MW and a heat recovery rate of 2,880 Btu/kWh, a heating demand of 35 MMBtu/hour can be calculated for an outside temperature of -40°F. Staff also indicated that a fairly constant process load amounted to half of their heat demand. From this information we calculated a load of approximately 25 MMBtu/hour at 20°F, the annual average temperature in Kotzebue. Thus, the annual load is 25 MMBtu/hour * 8,766 hours = 219,000 MMBtu/year, and we project- ed no growth in the load. "Kotzebue and Nome Coal Study", prepared by Arctic Slope Consulting Group for Alaska Native Foundation, January 1990, p. 4- 59. “analysis North, Nome Electrical Load Growth, p. 3-11. § = 43 City water heat demands were estimated in the 1990 Fryer/Pressley waste heat reports for Nome and Kotzebue. The additional district heating load assumed to be served in the Kotzebue base case is the load discussed in the SFT engineer- ing feasibility study, and the incremental cost of expanding the system out to that demand level is $8.40/MMBtu, derived from data in the Fryer/Pressley waste heat study. The "Useability of Recovered Heat" addresses the fact that the time-distribution of waste heat from the power plant does not coincide exactly with the time-distribution of heat demand. If there were perfect coincidence between waste heat supply and heat demand the Useability percentage would be 100%. If the annual heat load exceeds the Useability percent- age of the total annual waste heat, supplemental heat will be required. The extra benefits of expanding a district heating system beyond this level are minimal. The value of the extra fuel saved is cancelled to a large degree by the extra capital and operating cost of the expanded system. The Useability figures were derived by analysis performed with a heat coincidence model developed in the Fryer/Pressley waste heat reports. Nome’s useability of waste heat is lower than Kotzebue’s because a significant portion of the Nome load is assumed to be summertime gold mining load. This load has poor coinci- dence with community heating needs. The Useability of the Red Dog waste heat is relatively high because a large portion of the heating demand is due to a constant process load, which matches the fairly constant electrical load well. The "Efficiency of Alternative Heating System" is the efficiency of the heating system that would meet the heat demand if it were not met by recovered power plant heat. The 71% figure for Kotzebue comes from the Fryer/Pressley waste 5 = 44 heat reports for Nome and Kotzebue. Much of the heating load expected to be served from recovered power plant is building space and water heating, having moderate efficiency heating systems. In Nome and Red Dog, the alternative heating system for the city water load and Red Dog mine load would be a larger, high efficiency boiler. 82% efficiency was assumed in these locations. It was assumed that serving heating load with waste heat would also avoid some operation and maintenance cost of the alternative heating system. Those costs were estimated to be $0.30/MMBtu of fuel. 5.6.4 Electric Load Forecasts We previously developed a Nome electrical load forecast for this project, and the results are used in this economic analysis.” Projections of load growth in Kotzebue are available from the KEA 1989 Power Requirements Study. This study only provides one set of projections, and they only extend to the year 1998. After review of the assumptions used, we concluded that it was most appropriate to treat the PRS forecast as the foundation for the high and mid cases.” To create a high case extending through 2014, we extrapolated the PRS results using the 1989-1998 growth rates for each customer class. To create a mid case, we extrapolated the PRS through 2004, then applied "analysis North, Nome Electrical Load. 2The PRS assumes annual growth rates of 4.0% for residential sales, 2.7% for large commercial, and 5.7% for public authorities. There is, however, no forecast of employment, economic activity, or public expenditures to support these estimates. These growth rates are generally higher than the High case growth rates used in our previous Nome load forecast. 5 - 45 growth rates from our Nome mid case, non-mining load forecast. To create a low case, we applied growth rates from our Nome low case, non-mining load forecast beginning in 1990. 5.6.5 Fuel Price Forecasts Coal prices were provided in a July 5, 1991 memo from Mr. Pat Burden of Northern Economics to Kent Grinage, Arctic Slope Consulting Group. The coal price scenario with standard financing was assumed for the base case. A sensitivity test was done with the scenario that assumed the availability of grants and deferred local taxes, and priced the coal so as to eliminate profits. For the Deadfall Syncline coal plant, the coal prices at the port were used in the analysis; i.e. mine costs, infrastructure costs, and non-production costs were included, but the loading structure and transportation costs were excluded. Diesel oil prices are critical in the economic analysis, and we performed substantial work to develop oil price forecasts. The work is described in the following section. Diesel Price Projections Market Structure Assumptions The price of diesel fuel delivered to the study area is ultimately determined by the world price of crude oil. Our model of delivered diesel prices assumes that the value added to crude oil during refining, transport, and storage remains constant in real dollars throughout the study period. With the exception of the interest and insurance costs of carrying inventory, most elements of the cost of transporting and 5 - 46 delivering fuel oil do not depend on its value. We model the delivered price of diesel as: Delivered Diesel Price = Crude Oil Price + Refiner’s Margin + Barge Transport Cost + Offloading Costs + Storage Costs + Distribution Margin We considered each of these cost elements separately in developing projections of the avoidable cost of diesel fuel in the following five markets: Nome utility market Nome retail market Kotzebue utility market Kotzebue retail market Red Dog Mine Both the Nome (NJUS) and Kotzebue (KEA) utilities are part of a buying consortium, known informally as the Western Alaska Fuel Group, which solicits bids each winter for diesel fuel deliveries during the upcoming ice-free season. A base price is bid in the winter and the actual price paid is indexed to the refinery rack price for #2 distillate oil at Anacortes, Washington prevailing at the time the barge is loaded with oil. (The actual loading point is often Anchorage or Nikiski). Retail markets are served by several vendors in both the Nome and Kotzebue markets. The retail price moves with the refinery price in the long run, but in the short term prices are determined by the average cost of inventory on hand, tempered by competitive pressures. Sy 47 Crude Oil Prices Projections of crude oil prices from 1990 through 2010 are taken from the Alaska Energy Authority (1989). These projections are summarized in Table 5.8. Table 5.8: Projected Crude Oil Prices ($1991/bbl) Low Mid High 1990 14.98 18.44 21.90 2000 16.14 23.05 29.97 2010 17.29 28.81 40.34 % growth 0.7% 2.3% 3.1% Saudi Light crude delivered to U.S. Gulf Coast. Converted from 1988 to 1991 dollars using U.S. CPI-U. Source: Alaska Energy Authority 1989. Since the crude price projections are only provided for the three years 1990, 2000, and 2010, we used linear interpo- lation to assign values to both intervening years and to the years 2011-2018. We felt that linear interpolation was appropriate given that the low case is a perfect linear trend and that the mid and high cases exhibit essentially linear growth. Refinery Margin A real ($1991) refinery margin of 20.3 cents/gal is used for all price projections. Current contracts for bulk diesel fuel delivery to Nome and Kotzebue Utilities index the price of diesel to the refinery spot price for #2 distillate oil at Anacortes, Washington. We looked at monthly time series data 5 - 48 for this price from January 1985 through December 1990”! and compared the refinery price to the monthly Saudi Light Crude price.” The data indicate that the real refinery margin was roughly constant during 1985 through 1987 at an average of 15.6 cents/gal and moved® to a new constant level averaging 20.3 cents/gal from August 1987 through December 1990. The 20.3 cents/gal figure is consistent with a previous analysis by ICF (1988) which suggested a refiner’s margin of 20 cents (in 1987 dollars) for an Anchorage refinery. Barge, Wharfage, and Storage Costs for Utility Diesel According to Joe Murphy, Manager of NJUS, current contracts call for a barge markup of 12.0 cents/gal. This figure is adopted as the barge cost for Nome, Kotzebue, and the Red Dog Mine. Wharfage and dockage in Nome costs 3.25 cents/gal, but this payment is a contribution to the fixed cost of the Nome wharf facilities and hence is socially unavoidable and not counted in our analysis. In Kotzebue, however, fuel must be lightered a distance of 11 miles at a cost of 16 cents/gallon™ We assume that this lightering cost is socially avoidable. 4Weekly Anacortes price data obtained from NJUS and averaged to produce monthly values. Several months of missing data were proxied by the Washington refiner’s price for #2 Distillate sales for resale reported in Petroleum Marketing Monthly, Table 36. 2mMonthly average of weekly spot prices reported in Platt’s Oilgram for Saudi Light Delivered to U.S. Gulf Coast. 3A t-test value of 9.0 strongly rejected the hypothesis that the refinery margin was constant over the combined period 85:1 - 90:12. *4anthony Morris, Pacific Alaska Fuel Service, Kotzebue. 5 - 49 Fuel Tank O&M and tank capital costs of 2.2 and 4.6 cents/gal*® are assumed avoidable. We assume that if the Utilities’ storage needs drop dramatically, their unused tank capacity retains value and can be leased at a rate which at least covers costs. The main benefit of this storage may be to exert competitive pressure on existing suppliers. This benefit could be realized without the tanks actually being used by other large customers. Margins for Retail Sales to Larger Customers Because wholesale vendors will not reveal the price at which they buy oil nor their internal costs of transport and storage, we obtained data on current retail fuel prices and compared it to the Anacortes refinery price for July 1991 and to the refinery price at the time of the previous barge delivery which took place in October 1990 during the Kuwait crisis. Several vendors in Nome are still carrying large inventories from these fall 1990 deliveries. This comparison is summarized in Table 5.9. Table 5.9: Retail Diesel Prices and Margins for 1000+ gal/month Refinery Refinery Retail Price A: Price B: Price 7/91 Margin A 9/90 Margin B Nome Vendor 1 1.75 0.54 ted 0.89 0.86 Vendor 2 WaZ/u 0.54 ee 0.89 0.82 Kotzebue Vendor 1 1252 0.54 0.98 Vendor 2 1.50 0.54 0.96 Based on this data, we assume a preliminary margin of $1.00/gal for both Nome and Kotzebue. We then subtract the calculated from cost data provided by NJUS. Inventory interest costs are not included because no such costs are included in delivered coal prices. S50) socially unavoidable wharfage charge of 3 cents/gal for Nome only, yielding final assumed retail margins of $ .97 for Nome and 1.00 for Kotzebue. Sales taxes of 4% are excluded from the avoidable cost. Red Dog Mine Delivered Diesel Prices Cominco Alaska Stores 10 million gallons of diesel fuel at the port end of the DeLong Mountains Transportation Systen. We assume that they can procure and transport fuel for the same price as NJUS. About 7 million gallons per year are burned for electric power generation; substantial amounts are also used for fueling the ore trucks and mining machinery. The State of Alaska owns both the port and the road to the Red Dog Mine. Cominco pays a fixed annual fee to the State for capital recovery and is responsible for complete operation and maintenance expenditures for both the port and road. Because there are no other customers available to take advantage of the diesel storage at the port, we assume that all storage capital costs are unavoidable. Since at least 3 million gallons of fuel would still be stored even if no diesel were used for power generation, we assume that fixed tank O&M is also unavoidable. Some expenses for keeping the fuel warm and for pour point depressant chemicals could be avoided, however. We assume that 1.1 cents/gal falls in this category. This is one half the value of the total (fixed plus variable) Nome O&M cost per gallon. We estimate that it costs Cominco about 3 cents/gal to move diesel by truck from the port to the mine.” However, %Based on a cost of $3.00 per mile to operate a trailer truck hauling 10,000 gallons over the 104 mile round trip. Ls Sasa since this cost is not included in the estimated delivered cost of coal, we have not included it in the avoidable cost of Diesel at Red Dog. The same reasoning holds for the interest cost of inventory. Summary of Avoidable Diesel Price Margins Table 5.10 summarizes the discussion above and displays the constant real dollar margins used to convert projected crude oil prices into avoidable diesel prices. Table 5.10: Summary of Assumed Margins Between Crude Oil Prices and Avoidable Diesel Costs (1991 cents/gal) ---- Utility ---- ---- Retail ---- Nome Kotzebue Nome _ Kotzebue Red Dog Refinery Margin 20.3 20.3 20.3 20.3 20.3 Barge Cost 12.0 12.0 12.0 Lighter/Wharf/Dock 0.0 16.0 Fuel & Tank O&M (1) 2:2, 2:2 v1 Avoidable Storage 4.6 4.6 0.0 Port to Mine (2) 0.0 Refiner to Retail 97.0 100.0 Crude to Delivered Margin 39.2 55.2 723 120.3 33.4 Notes: (1) Red Dog Fuel & Tank O&M assumed only partly avoidable due to necessity to maintain tanks. (2) Red Dog Port to Mine est. at 3 cents/gal but set to zero to be consistent with delivered coal price assumptions. Diesel Price Forecasts Avoidable diesel prices are calculated as the sum of projected crude oil prices and the overall margins discussed above. Table 5.11 summarizes our diesel price projections for the five market areas. S52 Table 5.11: Delivered Diesel Prices: $1991/gal Average Annual Growth 1995 2000 2014 1995-2014 Nome Utility Low 0.76 0.78 0.81 0.3% Mid 0.89 0.94 1.13 1.3% High 1.01 111 1.45 1.9% Kotzebue Utility Low 0.92 0.94 0.97 0.3% Mid 1.05 1.10 1.29 1.1% High 1.17 a7 1.61 1.7% Nome Retail Low 1.54 1.56 1.60 0.2% Mid 1.67 1.72 1.91 0.7% High 1.79 1.89 2.23 1.2% Kotzebue Retail Low 1.57 1.59 1.63 0.2% Mid 1.70 1.75 1.94 0.7% High 1.82 1.92 2.26 1.1% Red Dog Mine Low 0.70 0.72 0.76 0.4% Mid 0.83 0.88 1.08 1.4% High 0.95 1.05 1.39 2.0% 5.6.6 General Assumptions The Economic Discount Rate is the amount by which future costs and benefits are discounted or down-weighted when calculating present value amounts. The discounting process accounts for the time-value of money and is related to interest rates. Because dollar amounts in the analysis are expressed in constant dollars, an inflation-adjusted discount rate ("real discount rate") must be used. 5 = 53 The Base Case discount rate of 4.5%/year is the rate used by the Alaska Energy Authority to evaluate state projects that do not qualify for tax-exempt low-interest financing. For projects that do qualify for tax-exempt financing, the Authority uses a real discount rate of 3%, and sensitivity tests were done with this lower rate. Sensitivity tests were also done with a 6% rate, which is more reflective of the rate used to evaluate private sector projects. 5.7 Model Runs The following pages contain the detailed output from a selected set of economic model runs. The runs are ordered by power plant: Nome, Kotzebue, Red Dog, and Deadfall Syncline. For each power plant the full output from the Base Case run is included. After the Base Case run, the run for the High Load and High Oil Price scenario is presented. In this High/High scenario only the summary sheets of production costs for the coal and diesel alternatives are presented. The plant characteristics for this run are the same as those presented in the Base Case runs. SiS 4: ss-sS Power Plant Production Cost Model Location: Nome Load Forecast: Mid Run Notes: Other Assumptions = Base Case Plant Type: Diesel Fuel Price Forecast: Mid Presert Start 95 Variable Una Value 1005 1906 1907 1908 1908 2000 2001 = 2002, 2003 2004 = 20052008 = 2007 — 2008 = 2008 = 20102011 = 2012 2013 2014 Electric Load MWh 37,005 37,715 36,301 36,612 30,273 30,742 30,763 30,001 40,278 40,716 41,242 41,028 42,068 43,457 43,608 44,137 44.817 45,103 45,508 46.10) Peak Demand uw eco 665 699 911 922 833 833 9389 845 856 8968 984 1002 1020 1030 1038 1047 1050 1070 1082 Baseload Capacity after losses: uw 3.00 300 300 300 300 300 300 300 «6300 300 300 300 300 300 300 300 300 300 300 300 Baseload/Peak Demand * 345% 339% 334% 329% 325% B2Z% 321% 320% 31.7% 314% 31.0% 305% 30.0% 204% 2.1% 290% 286% 283% 280% 277% Load Supplied, by Generation Type Baseload MWh 24,744 24,736 24,719 24,698 24,673 24,643 24,642 24,720 24,720 24,720 24,720 24,720 24,720 24,720 24,720 Peak MWh 12,261 12,060 13,561 14,114 14,599 15,006 15,121 15,271 15,558 15,906 16,522 17,206 17,048 16,737 10,177 * 84.1% 841% 840% 836% 836% B37% GI7T% G4.0% 84.0% 840% 840% O40% B40% B40% 04.0% 24,720 24,720 24,720 24,720 24,720 10,696 20,363 20,678 21,381 840% 840% 840% 840% Fuel Use Basoload ,000 MMBtu 221 221 222s 22d 220 22th 22a eet ttt Peak ,000 MMBtu 1160123128134 138 44H 14S 4B 15217 1831Ts17HsB]BA 189184188203 Fuel Price Baseload smametu 642 650 658 666 674 6682 7Oo1 711) 72) 734 744 751 761 «771)«781) «6701 «801 Bt Bat Peak ‘S/MMBtu 642 650 658 666 674 6682 7.01 mu 721 mM m4 751 761 wm 761 701 601 6«Btt) Blt Fuel Cost Baseload $.000 28,504 1,420 1,437 1,453 1,470 1,486 1,502 1,523 1,550 1,572 1.594 1.616 1.638 1,660 1,682 1,704 1,728 1,748 1,770 1,702 1,814 Peak $000 21,635 748 601 649 692 ou o7e 983 1,018 «1.051 1.006 1.148 1,212 1,261 1,355 1,405 1,441 1405 1,551 1,608 1,667 Variable O&M Baseload $.000 2.548 148) 1460 «1460 «(1460 1461450145 148148148148 141K 11K 1K KKK Peak $ 000 1,800 72 7 80 83 ee 89 so 80 82 24 e702 08 SST 120123128 Electric Production $000 54,775 2,306 2,400 2,528 2,501 2,652 2,714 2,751 2,004 2,061 2.830 3,007 3,087 3,162 3,283 3,368 3,427 3,506 3,567 3,069 3,753 Cost, Variable Total Heat Load ,000 MMBtu 2400 2440 247) 250 254258261 285268272278 280 284 8B ZK 813 Heat Load w/ Access ,000 MMBtu 12 12 12 12 12 12 13 13 13 13 13 13 14 4 “4 14 14 15 15 15 Recoverable Heat Baseload ,000 MMBtu 67 67 67 67 67 67 67 67 67 67 67 67 67 67 67 67 67 87 67 67 Peak ,000 MMBtu 3 35 7 38 38 “a a a 42 a “5 “ “ st 52 82 oy 55 56 58 Total ,000 MMBtu 100 «102-103, 105 108 107, 07, 108 1081101011957 818120122123 Optimal DH Load ,000 MMBtu 60 61 62 63 eB 64 65 65 68 67 68 69 70 ” 72 72 73 74 75 * after losses: 000 MMBtu se 60 61 62 63 o a a4 a 6s oe o 68 68 70 ” ” 72 13 7” Min(Optimal,w/ Access) 000 MMBtu 12 12 12 12 12 12 13 13 13 13 13 13 4 4 1“ 4 “4 15 15 15 Fuel Use for DH ,000 MMBtu o ° o 0 o o ° 0 o ° o ° ° ° o 0 o o 0 ° Onsite Fuel Price S/MMBtu 642 650 658 666 674 G62 681 701 711 «+721 731 741 751 761 771 781 701 BOL et 621 Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 613 622 632 642 651 661 673 685 698 9810 922 934 946 958 970 962 985 1007 1019 1031 Incremental DH Expansion Cost per MMBtu of Load S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per DH MMBtu ‘S/MMBtu 000 000 000 000 000 000 000 000 000 G00 000 000 080 000 G00 000 G00 000 000 000 Recovered Ht Net Benefit S/MMBtu 613) 822) 632) 6842) 851 ei 73 8S 88 810 a2 OSS 70 682 88S 1007: 1018 =1031 Net Benefit from $,000 (2,214) (94) (96) (98) (101) (104) (108) (100) (113) (116) (119) (122) (125) (128) (132) (1398) (140) (143) (147) (154) (158) Recovered Heat Fixed Plant Labor $000 12,258 7o2 702 702 702 702 M2 2 We 2 (%+ M2 i%+we %+We j%+We ij%+.we iijw2 j%+1w2 j$+.w2 j%+17e j%+We 12 Plant Property Insurance $.000 32 4048 tt Total Fixed O8M $000 13,080 730 750 750 750 730 TO 730 750 730 730 150 730 730 750 750 TsO Ts TO 7130 750 New Plant investment $000 4.658 e 228 228 228 228 220 zz zz ze 226 228 228 zz a ze 22 ze 370 370 370 370 TOTAL COSTS 4,200 4,205 4,482 4559 4638 4,717 70,510 3,040 4,041 4,138 oe 3,269 3,342 3.406 3,467 3,525 3,564 3,619 3,068 3,723 3.789 3,862 21-Aug-81 08:18 PM NOTES Present value figures Include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1991 $. SUNY TSPOW SION 9S Power Plant Production Cost Model Location: Nome Load Forecast: Mid Run Notes: Other Assumptions = Base Case Plant Type: Coal Fuel Price Forecast: Mid Preset Start 05 Variable Un Velue 1905) 1906 «= 1997 1998) 1908 =62000 2001 = 2002, 2003) 2004 = 2005S 2008 = 2007_— 2008 = 2008S 2010S 2011 = 2012S 20132014 Electric Load MWh 37,005 37. 36,301 38.812 39,273 39,742 30,763 30,991 40.276 40,716 41,242 41,926 42,668 43,457 43,696 44,137 44,617 45,103 45,506 46,101 Peak Demand uw 669 ees seo eon 922 os on 939 eas 956 968 964 1002 1020 1030 1036 1047 1059 1070 1082 Baseload Capacity after losses: mw 960 960 960 960 960 960 960 960 960 960 960 960 960 960 960 960 960 960 960 960 Baseload/Peak Demand * 110.5% 106 4% 106.6% 105.4% 104 1% 102.9% 102.9% 102.3% 101.5% 1004% OB2% 875% O50% G41% B32% G2TR B1TR BOTKR 897% BB7% Load Supplied, by Generation Type Baseload MWh 34.044 34.6968 35,237 35,707 36,131 36,562 36.562 36.782 37,056 37.459 37,958 36.656 30,370 40,005 40,487 40,699 41,117 41,537 41,060 42,389 Peak MWh 2.960 3.017 3,064 3,105 3,142 3,178 3,181 3,199 3.222 3.257 3,284 3,270 3,208 3,362 3.410 3.438 3,500 3,567 3,638 3,712 Baseload Cap. Fctr. * 405% 412% 419% 424% 429% 434% 435% 43.7% 440% 445% 451% 459% 468% 476% 48.1% 484% 480% 494% 499% 504% Fuel Use Baseload ,000 MMBtu 553 564 573 580 567 594 54 508 602 608 617 628 640 652 658 661 668 675 662 689 Peak 000 MMBtu_ 268 28 268 2 2 wn xn wn » 30 3 2» un un 2 R 3 as u« 6 Fuel Price Baseload ‘S$MMBtu 602 569 337 397 330 206 206 206 206 206 20 260 240 20 20 20 240 24 20 240 Peak ‘SMMBtu 642 650 656 666 67 662 1 701 7 72a ma 7a 751 761 mm 781 781 601 eo” 621 Fuel Cost Baseload $000 33,372 3.332 3.322 1928 1954 1.900 1,760 1,761 1,771 1,764 1603 1539 1,567 1506 1625 1641 1650 1667 1.664 1,701 1,718 Peak $000 4,074 ww 162 167 192 197 202 205 208 213 219 223 225 230 238 245 250 257 266 274 263 Variable O&M Baselosd $000 2,963 150 153 155 157 159 161 161 162 163 165 167 170 173 176 178 178 161 163 185 187 Peak $ 000 ue 7 18 18 18 19 19 19 19 19 19 19 19 19 20 20 2 21 21 21 2 Electric Production $000 40,776 3.676 3.675) 2.288 2,321 2,364 2,141 2.145 2,161 2,178 2.206 1,048 1,082 2,019 2.059 2,084 2,009 2,126 2,153 2,181 2,210 Cost, Variable Total Heat Load ,000 MMBtu- 240 244 247 250 24 258 261 265 268 272 276 260 264 288 282 206 wo we 308 313 Heat Load wi Access ,000 MMBtu 12 12 2 12 12 12 13 13 13 13 13 13 4 4 4 4 4 15 5 15 Recoverable Heat Baseload ,000 MMBtu 306 312 a7 321 325 328 329 a as 37 342 348 354 361 a 366 370 a74 378 381 Peak ,000 MMBtu ° ° ° o 0 o ° ° ° ° ° ° o ° ° o ° ° o °o Total ,000 MMBtu 306 a2 a7 321 325 328 329 331 au 337 342 us as4 31 col 368 370 374 378 361 Optimal DH Load .000 MMBtu 164 167 190 193 195 197 198 199 200 202 205 208 213 av 210 220 222 224 227 229 “after losses ,000 MMBtu- 161 165 168 190 193 105 195 196 196 200 202 206 210 214 216 27 218 221 224 226 Min(Optimal.w/ Access) ,000 MMBtu_ 12 2 12 12 12 12 13 13 13 13 13 13 4 4 “4 14 14 15 15 15 Fuel Use for OH 000 MMBtu ° ° o °o o o o ° o o °o ° ° ° o ° o o ° °o Onsite Fuel Price S/MMBtu 642 650 656 666 674 662 6o1 701 mW 72 m3 ya 751 761 mm 781 781 gor ei e2) Onsite Fuel +O&M per Delivered MMBtu ‘SMMBtu e113 822 632 642 es! eet 673 ees e068 10 922 os e646 ose e70 862 905 1007 1018 1031 Incremental OH Expansion Cost per MMBtu of Load S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per OH MMBtu $/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 0.00 000 Recovered Ht Net Benefit S/MMBtu 813 622 632 642 651 661 673 685 810 822 03% 046 856 970 982 995 1007 1018 1031 Net Beneft from $ 000 (2.214) (94) (96) (98) (101) (104) (108) = (108) (493) (119) (122) (125) (120) (132) (138) (140) (143) (147) (154) (155) Recovered Heat Fixed Plant Labor $000 0,140 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,728 1,728 1,726 1,728 1,726 1,726 1,726 1,726 1,726 1,726 1,726 Plant Property Insurance $000 2,846 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 Total Fixed O&M $ 000 32,067 1,689 1,869 1.8689 1,669 1,689 1,889 1,889 1,689 1.689 1.689 1.689 1,889 1,889 1889 1,088 1609 1,069 1,869 1,689 1,680 New Plant investment $ 000 31,800 31,800 ° ° o ° ° ° o ° ° o o ° o ° o ° ° ° ° ° [ TOTAL COSTS $ ,000 103,348 31,800 5,471 5,468 4079 4,109 4,150 3,923 3,925 937 3,953 3,976 3,715 3,745 3,779 3816 3637 3,848 3,872 3895 3,919 3,044] 21-Aug-91 0625 PM NOTES Present value figures include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1991 $ i" Characteristics ion: Nome ther Assumptions = Base Case Variable onfiguration Name fe: Unit: Rate Fuel Type el Type . Tiable O&M Recoverable Heat pacity ailability Transmission Loss @ Full Load ¢ Units: seat Rate “uel Type el Type ._tiable O&M Jecoverable Heat jystem Loss u of Fuel per OH Btu imental DH Expansion st per MMBtu of Load ‘e#te Heating Plant Effic. te Fuel Type vote Fuel Type site Variable O&M omic Discount Rate tsis Period Nome Model Runs Unit Btu/kWh mills/kWh Btu/kWh MW Btu/kWh mills/kWh Btu/kWh $/MMBtu $/MMBtu %/year years Selected 1 Diesel 8,940 2 Utility Oil 5.9 2,700 3.00 94.0% 0.0% 9,500 2 Utility Oil 5.9 2,700 1.3% 0.00 $0.00 82.0% 2 Utility Oil $0.30 4.5% 35 5 - 57 1 Diesel 8,940 2 Utility Oil 5.9 2,700 3.00 94.0% 0.0% 9,500 2 Utility Oil 5.9 2,700 1.3% 0.00 $0.00 82.0% 2 Utility Oil $0.30 Plant Possibilities 2 Coal 16,250 1 Coal 44 9,000 9.60 92.0% 0.0% 9,300 2 Utility Oil 5.9 0 1.3% 0.00 $0.00 82.0% 2 Utility Oil $0.30 8s New Plant Investments and Fixed O&M Location: Nome ,000 1991$ New Plant Investments Other Assumptions = Base Case Plant Start ID load 1995 1995 1996 1997 1998 1999 2000 2001 2005 2006 2007, — 2008 = 20092010 2011S 2012s 2013's 2014 1 L 171 171 171 171 171 171 313 313 313 313 Diesel M 228 228 228 228 228 228 228 228 228 228 228 370 «3702S 370 370 H 398 398 398 398 398 398 398 398 398 398 398 514 514 514 514 2 C 31,800 Coal M 31,800 H 31,800 3 L M H Fixed Plant Labor Plant Start 1D Load 1995 1995 1996 1997 1998 1999 2005 2006 2007, 2008_=— 2009-2010 2011S 2012, 2013S 2014 1 L 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 Diesel M 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 H 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 2 C 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 Coal M 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 H 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 3 L M H Property Insurance Plant Start ID Load 1995 1995 1996 1997 1998 1999 2005 2006 = 2007, 2008_)=— 2009-2010 2011S 2012s «2013S: 2014 1 L 36 36 36 36 36 45 45 45 45 45 45 45 45 45 45 Diesel M 48 48 48 48 48 48 48 48 48 48 48 48 48 48 48 H 57 57 57 57 57 57 57 57 57 57 57 57 57 57 57 2 L 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 Coal M 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 H 163 163 163 163 163 163 163 163 163 163 163 163 163 163 163 3 L M H 6S Fuel Price Forecast Location: Nome Other Assumptions = Base Case Number of Fuel Types = 3 # FuelT) 1 Coal 2 Utility Oil 3 Retail Oil 4 Fuel Prices, $/MMBtu, 1991 $ Fuel Forecast Type 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Low 1 Coal 6.02 589 337 3.37 339 296 296 296 296 296 249 249 249 249 249 249 249 249 249 249 2 Utility Oil 552 554 556 558 560 562 564 566 568 570 572 574 576 578 580 582 584 586 588 590 3 Retail Oil 14.52 11.54 11.56 11.58 11.60 1162 11.64 1166 11.68 11.70 11.73 11.75 11.77 11.79 11.81 1183 11.85 11.87 11.89 11.91 Mid 1 Coal 602 589 337 337 339 296 296 296 296 296 249 249 249 249 249 249 249 249 249 2.49 2 Utility Oil 642 650 658 666 674 682 691 7.01 7.11 7.21 731 741 751 761 7.71 7.81 791 801 811 821 3 Retail Oil 12.44 1252 12.61 1269 12.77 12.85 12.95 13.06 13.16 13.26 13.36 13.47 13.57 13.67 13.77 13.88 13.98 14.08 14.18 14.29 High 1 Coal 602 569 337 337 339 296 296 296 296 296 249 249 249 249 249 249 249 249 249 2.49 2 Utility Oil 731 745 759 7.73 787 801 819 837 855 872 890 908 926 944 962 980 998 10.16 1034 1051 3 Retail Oil 13.36 13.51 13.65 13.79 13.94 14.08 14.26 14.45 1463 14.82 15.00 15.19 15.37 15.55 15.74 15.92 16.11 16.29 16.48 16.66 SUNY TePpon eTION 09 Electric Load Forecast Location Nome — Formula for % of MWH > X Load — Optimal} MWh-> Min const x x*2 x*3 x*4 "5 Ld/Wast 1985 low 528% 35% 0.069 8357 -48005 91018 -75635 23486 650%] 26.534 Mid 486% 32% 1317 24865 8238 28350 -28912 9941 600% 37,005 High 520% 35% 0069 9357 48095 910168 -75635 23486 550% 56,194 1996 1007 1906 = 1908 = 2000 20012002, 2003 2004 20052008 = 2007_—2008=— 2008 = 2010S 2011S 2012013 4 28,694 28,750 29,064 29,389 29.637 29.668 30.061 30,337 30,701 30,969 31,305 31.655 31,910 32,085 32.316 32.560 32.647 33,117 33,300 37,715 38.301 38,612 39,273 30,742 39.763 30.001 40,2786 40,716 41.242 41,026 42,668 43.457 43,806 44,137 44.617 45.103 45,508 46,101 56.408 56.773 57,143 56,666 60.046 60.668 61.352 61.044 62.975 64.076 65,445 66,972 68.625 60.651 70,364 71,505 72.842 74.127 75.450 Ss T9 Heat Load Forecast Location: Nome Other Assumptions = Base Case % Access| ,000 MMBtu —> 1995 1996 1997 1998 1999 2000 2001 2002. 20032004 200520062007 2008 20092010 2011S 012,013 014 Low 4.8% 230 232 234 235 237 239 240 242 244 245 247 249 251 252 254 256 258 259 261 263 Mid 4.8% 240 244 247 250 254 258 261 265 268 272 276 280 284 288 292 296 300 304 309 313 High 4.8% 253 259 265 271 277 284 290 297 304 311 318 325 333 340 48 356 364 373 381 390 SUNY TSPON SUON 29 Power Plant Production Cost Model + Location: Nome Load Forecast: Hi Run Notes: Other Assumptions = Base Case Plant Type: Diesel Fuel Price Forecast: Hi Presert Start 95 Variable Una Value 1905 1908 = 1887 «1008 = 1908 = 2000 2001 2002, 2003 2004 2005 2008) 2007, 2008 «= 2008) 2010 2011 = 201220132014 Electric Load MWh 56,194 56,408 56,773 57,143 56,666 60,046 60,888 61,352 61,044 62,975 64,076 65,445 68,972 68,625 60,651 70,364 71,505 72,642 74,127 75,450 Peak Demand mw 12120 1216 1224 1232 1269 1295 1313 1323 1336 1358 1362 1411 1444 1480 1502 1518 1544 1571 1590 1627 Baseload Capacity after losses: mw 300 300 300 300 300 300 «300 300 300 300 300 300 300 300 300 300 300 300 300 300 Baseload/Peak Demand * 248% 247% 245% 243% 236% 232% 226% 227% 225% 221% 21.7% 21.3% 2B% 203% 2O% 196% 194% 191% 186% 164% Load Supplied, by Generation Type Baseload MWh 24,720 24,720 24,720 24.720 24720 24720 24.720 24.720 24720 24,720 24,720 24,720 24.720 24,720 24,720 24,720 24,720 24,720 24,720 Poak MWh 31,474 32,053 32.422 34,145 35,326 36,167 36,632 37,223 36.255 30,356 40.725 42,252 43,005 44,931 45,064 46,675 48,122 48,407 50,729 Baseload Cap. Fctr. * 840% 940% 940% 940% 840% 84.0% 840% 940% 840% 840% 940% 840% 840% 040% 04.0% 840% 840% 040% 940% Fuel Use Baseload ,000 MMBtu 221 221 221 221 221 zi 2 zm 221 2 221 221 221 zy zi 221 221 221 zt 221 Peak ,000 MMBtu 209 301 05 we 324 336 “as 48 a4 363 a4 387 “1 ay 427 aM “45 “7 469 482 Fuel Price Baseload SMMBtu mH 74 758 773 787 601 ew ea e55 e72 800 sos oz ou ee2 e680 e908 1016 1034 1051 Peak S/MMBtu ma 745 759 773 7687 sor ew 637 655 672 690 808 o2 ou ee2 9680 eee 1016 1034 1051 Fuel Cost Baseload $000 35,0860 1.616 1,647 1,678 1,708 1,738 1.770 1,608 1,649 1689 1.928 1.968 2.007 2.047 2.006 2,126 2,165 2.205 2.244 2.284 2,324 Peak $000 64.012 2.106 2.243 2.311 2.381 2553 2.668 2613 2.012 3.022 3.171 3328 3.514 3.717 3.036 4.108 4251 4443 4643 4851 5,067 Variable O8M Baseload $000 2,547 146 148 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 Peak $000 4,277 166 187 169 191 201 206 213 216 220 226 232 240 240 20 205 200 277 284 201 200 Electric Production $000 105,696 4534 4,223 4,324 4426 4630 4812 4,962 5,123 5,276 5,470 5.674 5,007 6,158 6.429 6643 6831 7,070 7,317 7,572 7,836 Cost, Variable Total Heat Load ,000 MMBtu 253 259 265 27 277 284 290 207 we au 316 325 a so usB 356 a 373 381 300 Heat Load w/ Access ,000 MMBtu 12 12 3 3 13 4 4 4 5 15 15 16 6 * 7 v7 7 18 18 at Recoverable Heat Baseload ,000 MMBtu e7 67 67 67 e7 67 o7 e7 a7 a7 67 67 67 a7 a7 a7 67 67 e7 e7 Peak ,000 MMBtu 65 cL] eo 68 82 6 96 oo 101 103 106 110 we 108 v20 123 127 130 133 137 Total ,000 MMBtu 152 152 153 1s 1598 162 164 168 167 170 173 w7 161 165 168 190 193 197 200 204 Optimal DH Load ,000 MMBtu a a 64 65 a7 89 80 o 92 a 3 oe ow 102 103 105 106 108 110 12 * after losses ,000 MMBtu 62 63 63 a4 66 68 60 90 o 92 oO 96 oe 101 102 103 105 107 108 wt Min(Optimal,w/ Access) ,000 MMBtu 12 12 13 3 3 4 4 “4 15 5S 5 16 6 16 7 7 7 168 18 18 Fuel Use for OH ,000 MMBtu o o o o °o °o ° o ° o ° °o ° ° ° ° ° o ° o Onsite Fuel Price ‘S/MMBtu 73 745 759 773 787 601 e7 637 655 672 690 808 e268 ou e62 960 906 1016 1034 1051 Onsite Fuel +O&M per Delivered MMBtu SMMBtu 922 939 956 973 990 1007 1026 1050 1072 1004 1116 1136 1150 11961 1203 1225 1247 1269 1280 1312 Incremental DH Expansion Cost per MMBtu of Load ‘$/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per DH MMBtu ‘S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Recovered Ht Net Benefit S/MMBtu 922) 939 956 973 890 1007 10.28 1050 1072 1094 1116 1138 1150 1203 1225 1247 1268 1280 13.12 Net Benefit from ‘000 (3.100) (192) (HIT) (822) (27) (432) (37) (443)__ (150) (158) (163) (170) (178) (18S) (193) (01) (209) (218) (zz7) (238) (248) Recovered Heat Fixed Plant Labor $000 12,258 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 702 Plant Property Insurance $000 967 s7 57 57 57 s7 s7 57 57 57 57 s7 s7 s7 57 57 57 57 57 57 57 Totel Fixed OAM $ ,000 13,245, 7590 759 7598 759 750 738 738 758 738 758 758 759 738 738 750 759 750 7590 738 750 New Plant investment $ 000 7,671 ° 398 308 398 308 308 308 31 38 308 308 398 a1 308 308 1 398 sia si4 514 si4 [ TOTAL COSTS $ 000 123,623 o 5.179 5.263 5,350 5,457 5,664 5,631 5,995 6,130 6,276 6,464 6661 6,806 7,131 7,392 7,598 7,778 8,124 8,362 8,608 8,002] 21-Aug-91 08633 PM NOTES. Present value figures include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1991 $. 9 -S¢ Power Plant Production Cost Model Location: Nome Load Forecast: Hi Run Notes: Other Assumptions = Base Case Plant Type: Coal Fuel Price Forecast: Hi Variable 2001 __2002 2003-2004 20032008 2007_— «2008 2008 201020112012, 20132014 Electric Load 56,773 57,143 58,6668 60,046 60,068 61,352 61,044 62,975 64.076 65,445 66,072 68.625 60,651 70,364 71,505 72,642 74,127 75,450 Peak Demand 1224 1232 1269 1295 1313 13. 1396 1356 1362 1411 1444 1460 1502 15.18 1544 15.71 1599 1627 Baseload Capacity after losses 960 960 960 960 860 960 960 960 960 960 960 960 960 960 960 98 960 96 960 96 Baseload/Peak Demand 702% 780% 784% 778% 756% 741% 73.1% 726% 719% 707% OO5S% GEOR G85% 640% GIGK GIZK E2ZK B11% GOIN 5O0% Load Suppiled, by Generation Type Baseload wwn 51.225 51,414 51,737 52,066 53,613 54,681 55.443 55,664 56,308 57,326 58,307 59,508 60,621 62.197 63,028 63,005 64,537 65,483 66,380 Peak wh 4.969 5.096 5.077 5.253 5.365 5.444 5.488 5,545 5.038 6152 6.428 6.625 6770 7,068 7,378 7,747 Baseload Cap. Fetr. * 60.0% 615% 61.0% 637% 650% 65.9% 664% 67.0% 681% 693% 7OTK 723% 739% 749% 756% 767% 778% 789% Fuel Use Baseload ,000 MMBtu 632 635° B41 8468871 888 OT 08816 32 AT) BF) BBB ,011 1,024 1,034 1,049 1,064 1,078 1,083 Peak ,000 MMBtu “a “68 47 a7 2 8650 St 31 52 a @0 62 o oo 72 76 Fuel Price Baseload snaMetu 602 569 337 337 3309 206 206 206 206 206 249 240 249 240 240 240 240 240 249 240 Peak SMMBtu 731 745 #750 773 767 #801 619 637 655 672 8690 808 826 944 862 960 808 1016 1034 1051 Fuel Cost Baseioad $000 51,126 5.013 4922 2631 2649 2.953 2632 2,669 2689 2,715 2,760 2.363 2412 2,465 2521 2,555 2576 2616 2653 2691 2,727 Poak $,000 @711 3360-346 956 65 A 0415 42T at 58 47H 501 580 S84 DHSS OTH 700 z Variable O&M a Baseload $000 4,505 225 «226228 2282388241244 2482482527282 BBA 277 280284 288 8228 ® Peak $000 ee2 20 220 2.3) 32 a a a | 36 3638 “0 a2“ 48 48 Electric Production $,000 66,004 6,008 5,524 3,443 3,473 3,004 3,903 3,300 3,305 3.437 3,504 3,132 3.210 3.298 3,907 3,404 3516 3508 3082 3,773 3,870 = Cost, Variable ° a Total Heat Load ,000 MMBtu 253° «2590285271277 284 280 287) 04311 318 325 39 KKB KAS 381 300 ® Heat Load wi Access ,000 MMBtu 12 12 13 13 13 4 “4 14 5 15 15 16 18 16 7 7 7 18 18 19 Lo Recoverable Heat w Baseload ,000 MMBtu 461 463466 469 492 499-503 S08, 516 S25 S368 ST 580) 5870572) S81 588) 587) 08 Poak ,000 MMBtu o ° o ° o o o o ° ° o o ° o o 0 0 0 0 § Total .000 MMBtu 461 463 466 469 492 4990 «503 508-516 S25 536 S47 580) 587) 572581 588) 587) = 08 a Optimal DH Load ,000 MMBtu 254 «254256258 2710 2740277) 278284 289 285 01 308 2 31S 318324 328 333 * after losses .000 MMBtu 250 «25125384 267 «2710273 276 280 285 281 87 04 08311315 320 324 329 Min(Optimal,w/ Access) ,000 MMBtu 12 12 13 13 14 4 4 5 15 15 16 16 16 v7 v7 v7 18 18 19 Fuel Use for DH ,000 MMBtu o o oO ° o ° ° o o oO o o ° o o o oO 0 o Onsite Fuel Price S/MMBtu 731 745° «759 «7.73 601 619 637 655 672 890 808 926 944 962 980 996 1016 1034 105) Onsite Fuel +O&M per Delivered MMBtu ‘S/MMBtu 822 939 856 973 890 1007 1026 1050 1072 1094 1116 1136 1158 1161 1203 1225 1247 1268 1290 1312 Incremental DH Expansion Cost per MMBtu of Load = $/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per DH MMBtu ‘S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 00 Recovered Ht Net Benefit S/MBtu 922 939 856 873 990 1007 1028 1050 1072 1094 11.16 11.38 1158 11.61 1203 1225 1247 1269 1200 13.12 Net Benefit from $,000 (3,180) (192) (197) (122) (127) (132) (137) (143) (150) (158) (163) (170) (178) (185) (183) (201) (208) (218) (227) (238) (248) Recovered Heat Fixed Plant Labor $.000 30,140 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,726 1,728 1,726 1,728 1,726 1,726 1,726 1,728 1,726 1,728 Plant Property insurance $,000 2.646 163163 «S163 163 — 163 S163, 163163163169 169169189169 169 18916169163 169 Total Fixed O&M $000 «32,967 1,089 1,609 1,660 1,600 1,000 1,009 1,089 1,000 1,689 1,080 1,009 1,089 1,009 1,809 1,089 1,080 1,089 1,080 1,089 1,689 New Plart investment $,000 31,800 31,800 ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° ° TOTAL COSTS 5.211 5,235 21-Aug-81 06:35PM NOTES Present value figures include the extension of costs in the year 2014 through the year 2029. All dollar values are constant 1901 § v9 Power Plant Production Cost Model Location: Kotzebue Load Forecast: Mid Run Notes: Plant Type: Diesel Fuel Price Forecast: Mid Preset Start 95 Variable Una Vetus 1905 «61906 «61997 §=61908 §=61998 §=8©2000 200i 2002 2003 2004 2005 2006 2007 2008 2008 2010 2011 212 2013 2014 Electric Load MWh 20.370 20.936 21,503 22.112 22.749 23.410 24.095 24.606 25.540 26.304 26.681 27,0864 27,452 27.646 28.247 28.653 29,065 29.464 29,008 30.340 Peak Demand mw 422 4n3 a6 456 an 465 499 S14 520 545 552 560 Sea s77 565 593 602 610 619 «628 Baseload Capacity after losses Mw 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 Baseload/Peak Demand * 711% 692% 674% 655% 637% 619% GOIN 564% SE7% 551% 543% 535% S26% SZ20K% 513% SOGK 408% 491% 464% 476% Load Supplied, by Generation Type Baseload MWh 18.914 19,407 19.684 20,373 20,856 21,323 21,767 22,187 22,576 22,933 23,082 23.243 23,385 23,518 23,643 23,759 23.666 23,065 24,055 24.138 Peak MWh 1.457) 1,528 «1,619 1,738 1693 2,087 2.327 2. 2965 3.371 3568 3,621 4,067 4328 4604 4804 5108 5519 5653 6202 Baseload Cap Fetr * 719% 736% 756% 775% 793% 611% 626% 644% 656% 672% 876% 684% BEO% 694% BOOK GOIKR GOBK 11% GIS 816% Fuel Use Baseload ,000 MMBtu 180 164 169 194 198 203 207 au 214 218 210 221 222 223 225 226 227 228 228 228 Peak ,000 MMBtu 5 16 7 6 20 22 24 27 3 3 « 40 a “a “a s 3s 6 eo 6 Fuel Price Baseload S/MMBtu 7538 766 774 762 790 797 607 e17 627 637 ea? 657 667 677 607 807 ow e27 ea Peak S/MMBtu 758 766 774 762 790 797 e607 ev 627 637 ea es7 6e7 e77 607 907 o7 e27 oa7 Fuel Cost Baseload $000 32,175 1,361 1.412 1.461 1513) 1564 1.615 1670 1,723 1,774 1.624 1658 1693 1.026 1950 1.002 2.024 2056 2087 2116 2.148 Peak $ 000 6449 116 123 ce DT 143 157 75 197 225 256 296 319 “a 370 398 420 461 405 su 570 610 Variable O&M Baseload $000 27 131 m4 137 41 144 147 150 153 156 158 159 160 161 162 163 164 165 165 166 167 Peak $ 000 470 10 uw WwW 12 13 14 16 18 20 23 23 26 2 x» xz x J « “ “a Electric Production $000 41,705 1,618 1,679 1.741 1,808 1,052 2.033 2,118 2.208 2.302 2,362 2,423 2,406 2,550 2.616 2,683 2,752 2.822 2,804 2,967 Cost, Variable Total Heat Load 000 MMBtu: 150 153 156 159 162 165 169 172 175 179 1863 166 190 194 196 202 206 210 2u4 216 Heat Load w/ Access ,000 MMBtu x u“ u“ 6 % xs v7 “s 3 3 4 a 42 a a “4 “a “6 a 468 Recoverable Heat Baseload ,000 MMBtu 46 “8 48 sO st 52 s “ 5s 36 7 Ere Ls se se 36 se se ss 5e Peak 000 MMBtu 4 4 4 4 5 5 6 6 7 6 8 ° 10 Ww "W 12 13 “4 “4 15 Total 000 MMBtu sO st 53 54 6 v7 se 61 63 a4 es e 67 6s eo 70 ” 72 73 4 Optimal OH Load 000 MMBtu 322 33 u“ 35 x wv x 40 a 42 42 a “ “4 “6 “6 “8 a7 “8 “8 * after losses ,000 MMBtu 3 a 32 a3 “ 3s %« uv % 39 40 40 a a a2 a2 a “ “4 “ Min(Optimal.w/ Access) 000 MMBtu wn au 32 3 u“ 35 « a 3% 39 40 “0 at at 42 42 a “4 “ “ Fuel Use for DH ,000 MMBtu ° o o ° o o oO o o o 0 ° o ° ° ° ° 0 o o Onsite Fuel Price ‘SMMBtu 1267 1275 12863 1291 1299 1308 13186 1328 1338 1349 1358 1368 1379 13868 1400 1410 1420 1430 1441 1451 Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 1814 1825 1637 1649 18660 1872 1866 1900 1915 1929 1944 1958 1973 18967 2001 2016 2030 2045 258 2074 Incremental DH Expansion Cost per MMBtu of Load S/MMBtu 640 640 640 640 640 640 640 640 640 640 e640 640 600 640 640 640 640 640 640 640 Fuel Cost per OH MMBtu SMMBtu 000 6000 000 6000 000 000 000 000 000 000 6000 6000) 6000) 6000 «6000 000 6000) «6000 000 6000 Recovered Ht Net Benefit SMMBtu 974 9685 907 1008 1020 1032 1046 1060 1075 1069 1104 11.16 1933 1147 1161 11.76 1190 1205 1219 12% Net Benefit from $,000 (7,720) (294) (308) (318) (330) (344) (958) (973) (90) (407) (424) (498) (448) (400) (473) (400) (409) (512) (526) (540) (354) Recovered Heat Fixed Plant Labor $000 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 Plant Insurance $ 000 a 3 as 3 3 3 33 33 42 42 42 42 42 42 42 42 42 42 42 42 Total Fixed OAM $000 48) 483 “3 483 “83 483 “3 483 492 492 492 402 a 492 402 482 482 402 402 402 New Plant investment $ 000 2.518 ° o o ° ° ° ° o o 7 1 wm 171 wm m1 m1 wt wm 206 206 206 [ TOTAL COSTS $ 000 45,040 o 1,008 1.657 1.907 1.061 2.018 2.078 2143 2.213 2.465 2541 2569 2638 2689 2,740 2,793 2847 2,002 3.074 3,132) 3,191 23-Aug-91 04:16PM NOTES Present value figures include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1991 $ s9 Power Plant Production Cost Model Location: Kotzebue Load Forecast: Mid Run Notes: Plant Type: Coal Fuel Price Forecast: Mid Present Start 05 Variable Una Vetue 1905 = 1906 = 1087 1088 = 1988 = 2000 2001 ~— 2002S 2003 |= 2004 = 2005S 2008 = 2007 = 2008 «= 200839 2010S 2011 2012 2013 2014 Electric Load MWh 20,370 20,836 21,503 22,112 22,748 23.410 24,095 24,806 25,540 26,304 26,681 27,064 27,452 27,646 28,247 28,653 29,085 20,484 29,008 30.340 Peak Demand uw 422 4u 465 458 a7 405 490 «514 520 545 552 5se0 S68 S77 585 503 4602 610 19° 86626 Baseload Capacity after losses: Mw 520 520 520 520 520 520 520 520 $20 520 520 520 520 520 520 520 S20 520 520 520 Baseload/Peak Demand * 123.3% 120.0% 116.6% 113.6% 110.4% 107.3% 104.2% 101.3% B63% 855% 041% 926% 915% BOZK% BBB% GB7.7% BE4% B5SZ% 640% 826% Load Supplied, by Generation Type Baseload MWh 16,741 19.261 19,763 20,343 20.029 21,537 22.167 22.622 23.578 24.324 24660 24.988 25,311 25.695 25,062 26,294 26,633 26,961 27,338 27,704 Peak MWh 1,630 1,675 1,720 1,769 1,620 1,673 1,928 1,064 1,962 1,960 2,021 2076 2141 2211 2285 2350 2432 2503 2571 2635 Baseload Cap Fetr * 41.1% 423% 434% 446% 459% 472% 466% SO1% SI7% 534% 541% 546% 555% SE2% S7O% S7.7% SE4% SO2% BOOK GOBK Fuel Use . ( Baseload 000 MMBtu Z e ws ° 313 321 331 340 350 360 am 363 395 401 406 ai a7 422 427 433 a8 444 450 Peak ,000 MMBtu ’ 16 ed Ww v7 2 18 2 12 20 20 20 20 2 2 2 23 = 24 2 26 26 Fuel Price Baseload SMMBtu e02 seo 337 327 339 206 206 29 206 296 249 260 20 20 20 240 240 24 249 240 Peak SMMBtU 738 766 774 762 790 797 607 ew 627 637 ea os7 ec7 677) «668687 607 07 ow e27 e377 Fuet Cost Baseload $000 20,497 ae 1,634 7 1644 «$1,062 1.113 1,153 1.036 1.067 1,089 1.135 1.171 1000 1013 1,026 1.030 1052 1.066 1060 1.094 1106 1,123 Peak $000 3.285 123 128 133 138 144 148 56 162 162 166 71 78 166 194 203 212 zai ze 2 27 Variable O&M Baseload $ 000 2412 107 110 m3 116 118 123 126 130 144 138 V4 142 144 146 148 150 152 154 156 156 Peak $ 000 261 uw 12 12 12 13 13 13 14 ic] in) at) “4 3 15 16 1 17 7 16 18 Electric Production $ 000 26,455 2,076 2,004 1,340 1,378 1,428 1,322 1,362 1,405 1,445 1,489 1,325 1,348 1,371 1,384 1,41 1,444 1,468 1,484 1,520 1,546 Cost, Variable Total Heat Load ,000 MMBtu 150 153 156 159 162 165 169 W72 175 178 163 166 190 194 106 202 206 210 214 216 Heat Load w/ Access ,000 MMBtu as xu u s xs s v7 3 ce) 3 a a 2 a a “ “a “a a7 “a Recoverable Heat Baseload 000 MMBtu 264 292 300 308 a7 326 36 ue 357 369 374 378 33 (368 303 396 403 408 aia 420 Peak 000 MMBtu_ 0 o o o o ° ° ° ° o ° o ° 0 0 o ° ° o o Total ,000 MMBtu 264 292 300 308 a7 326 336 346 357 369 374 379 3483 368 383 396 403 409 aia 420 Optimal OH Load ,000 MMBtu 1865 190 185 200 206 212 20 225 232 240 243 246 248 252 256 250 262 266 268 273 * after losses: 000 MMBtu- 172 176 161 166 192 197 203 2098 20 223 226 220 232 235 23% at 244 247 250 254 Min(Optimal,w/ Access) ,000 MMBtu as a“ xu 3 % xs av a 3 39 4 a a2 a a 44 “a “6 a7 48 Fuel Use for DH 000 MMBtu 2 2 22 23 23 23 a 24 2 23 26 26 a 2 2 2 2 so wo au Onsite Fuel Price SMMBtu 1267 #1275 1263 1291 1299 1308 1316 1328 1336 1349 1359 1368 1378 13868 1400 1410 1420 1430 1441 451 Onsite Fuel +O&M per Delivered MMBtu ‘S/MMBtu 1614 1625 1637 1649 1860 1672 1666 1900 1915 1929 1944 19586 1873 1887 2001 2016 2030 2045 2058 2074 Incremental DH Expansion Cost per MMBtu of Load SMMBtU e400 640 a4 640 640 640 640 640 640 «0 640 640 640 640 840 640 640 840 840 640 Fuel Cost per DH MMBtu S/MMBtu 369 360 27 27 210 ie to 181 o 1 161 161 161 161 161 161 161 161 161 161 Recovered Hi Net Benefit SMMBtU 585 605 780 791 601 ea 655 669 664 696 oa 957 972 986 1000 1015 1028 1044 1058 1073 Net Benefit from $000 (6,752) (193) (203) (267)(277)_—(206)_—(308) (317) (328) (341) (954) (378) (302) (408) (420) (435) (450) (408) (402) (408) (515) Recovered Heat Fixed Plant Labor $000 26,981 1,660 1,660 1,660 1660 1,660 1,660 1660 1,660 1660 1660 1660 1660 1,660 1,660 1660 1660 1660 1660 1660 1660 Plant Property insurance $000 2,547 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 46 Total Fixed O&M $ 000 31,528 1,006 1,006 1,806 1,606 1,008 1,806 1,806 1,806 1,006 1,806 1,006 1,006 1,006 1,006 1,806 1,806 1,806 1,006 1,806 1,606 New Plant investment $ 000 28,100 28,100 e ° o ° ° ° ° ° ° ° ° ° ° ° ° oO ° ° o o 2,081 2.041 2,752 2,761 2,770 2,760 2,780 2,799 2809 2,818 2,827 2,837 28,100 3,688 2,008 2,048 2.621 2,851 23-Aug-81 0431 PM NOTES: Present value figures include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1891 s suny Tepow enqezzoy Plant Characteristics Location: Kotzebue Selected Plant Possibilities Variable Unit 2 i 2 3 Sry T LTT SENT DT ATP TDTDL) NPTNTaT TTDI TAL PETTITT CIEL NNTTTNITIT TTDI THT Configuration Name Coal Diesel Coal Baseload Unit: Heat Rate Btu/kWh 16,250 9,500 16,250 Fuel Type 1 2 1 7 Fuel Type Coal Utility Oil Coal Variable O&M mills/kWh §.7 6.9 5.7 Recoverable Heat Btu/kWh 15,150 2,450 15,150 Capacity MW 5.20 3.00 5.20 Availability 92.0% 94.0% 92.0% Transmission Loss @ Full Load 0.0% 0.0% 0.0% Peak Units: Heat Rate Btu/kWh 10,000 10,500 10,000 Fuel Type 2 2 2 Fuel Type Utility Oil Utility Oil Utility Oil Variable O&M mills/kWh 6.9 6.9 6.9 Recoverable Heat Btu/kWh 0 2,450 0 DH System Loss 7.0% 7.0% 7.0% Btu of Fuel per OH Btu 0.60 0.00 0.60 Incremental DH Expansion Cost per MMBtu of Load $/MMBtu $8.40 $8.40 $8.40 Onsite Heating Plant Effic. 71.0% 71.0% 71.0% Onsite Fuel Type 3 3 3 Onsite Fuel Type Retail Oil Retail Oil Retail Oil Onsite Variable O&M $/MMBtu $0.30 $0.30 $0.30 Economic Discount Rate %/year 4.5% Analysis Period years 35 5 - 66 wes Lo zebu ,000 1991 $ New Plant investments Plant Start 1D Load 1995 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1 ff 115 115 115 Diesel M 171 171 171 171 171 171 171 171 171 286 286 286 H 71 171 171 171 171 171 171 171 171 286 286 286 2 L 28,100 Coal M 28,100 H 28,100 3 t M H Fixed Plant Labor Plant Start ID Load 1995 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1 L 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 Diesel M 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 H 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 2 [e 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1.660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 Coal M 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1660 1660 1,660 1,660 1,660 1,660 1,660 H 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1,660 1660 1,660 1,660 1,660 3 Cc M H Property insurance Plant Start {0 Load 1995 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 1 u 33 33 33 33 33 33 33 33 33 33 33 33 33 33 3 33 33 33 33 33 Diesel M 33 33 33 33 33 33 33 33 42 42 42 42 42 42 42 42 42 42 42 42 H 33 33 33 33 33 33 33 33 42 42 42 42 42 42 42 42 42 42 42 42 2 i 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 Coal M 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 H 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 146 3 L M . H suny Tepon enqezz0oy% 89 Fuel Price Forecast Location: Kotzebue Number of Fuel Types = 3 # Fuel Type 1 Coal 2 Utility Oil 3 Retail Oil 4 Fuel Prices, $/MMBtu, 1991 $ Fuel Forecast Type 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Low 1 Coal 602 589 337 337 339 296 296 296 296 296 249 249 249 249 249 249 249 249 249 2.49 2 Utility Oil 668 670 672 674 676 678 680 682 684 686 688 690 692 694 696 698 700 702 7.04 7.06 3 Retail Oil 11.74 11.76 11.79 1161 11.63 11.65 1187 11.69 11.91 1193 11.95 1197 11.99 12.01 1203 12.05 12.07 12.09 12.11 12.13 Mid 1 Coal 602 589 337 337 339 296 296 296 296 296 249 249 249 249 249 249 249 249 249 249 2 Utility Oil 758 766 7.74 782 790 7.97 807 817 827 837 847 857 867 877 887 897 907 917 927 937 3 Retail Oil 12.67 12.75 1283 1291 12.99 13.08 13.18 13.28 13.38 13.49 1359 1369 13.79 13.89 14.00 14.10 14.20 1430 14.41 1451 High 1 Coal 602 589 337 337 339 296 296 296 296 296 249 249 249 249 249 249 249 249 249 249 2 Utility Oil 847 6861 875 889 903 917 935 953 9.70 9.88 1006 10.24 10.42 10.60 10.78 10.96 11.14 11.32 11.49 11.67 3 Retail Oil 13.59 13.73 13.87 14.02 14.16 14.30 14.49 1467 1486 1504 1523 1541 15.59 15.78 15.96 16.15 16.33 1652 1670 16.88 Ss 69 Electric Load Forecast Location Kotzebue — Formula for % of MWH > X Load — Optimal] MWh-> Min const x n°? x*3 x*4 «*5 Ld/Wast 1995 1906 1087 1998 = 1908 = 2000 2001_— 20022003 2004 2005 2008S 2007_— 2008 = 2008S 2010S 2011, S24 Lo 55.1% 36% -1.234 19378 -76.481 128.119 -100.427 29.644 65.0% 16,153 18,265 16,379 16.493 16,600 16,726 16.643 16,062 19,082 19,202 10,324 10,447 10,571 10.607 10,623 10,050 20.078 20,200 20,340 Mid 551% 36% -1234 19379 -76481 129119 -100427 29644 650%] 20.370 20.936 21,503 22,112 22,749 23.410 24,085 24.606 25,540 26.304 26.681 27,064 27,452 27.646 26.247 28.653 20.065 20.484 29.008 30,340 Hig 55.1% = 36% -1234 10378 -76481 120119 -100427 20644 650% | 20.370 20.936 21.503 22.112 22.749 23.410 24.095 24.604 25,540 26.304 27,005 27,017 26,760 20,653 30,571 31,524 32,514 33,542 34609 35,716 suny Tepown enqezzoy% ol Low High Access} ,000 MMBtu —> to DH 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 22.0% 139 140 141 142 143 144 145 146 147 148 149 150 151 22.0% 150 153 156 159 162 165 169 172 175 179 183 186 190 22.0% 156 160 165 169 174 178 183 188 193 198 204 209 215 2008 2009 2010 152 194 221 153 154 2011 155 198 202 206 227 233 239 2012 156 210 245 2013 157 214 252 2014 158 218 259 TL Power Plant Production Cost Model Location: Kotzebue Load Forecast: Hi Run Notes: Plant Type: Diesel Fuel Price Forecast: Hi Presert Start 05 Variable Unk Velue 1905 1908 =1007 1908 §=1908 «©2000 2001 = 2002S 2003S 2004 = 2005S 2008 = 2007 ~=—«2008 = 2008 = 2010S 2011 = 2012S 2013 2014 Electric Load MWh 370 20,936 21,503 22,112 22,748 23,410 24,085 24,804 25,540 26,304 27,005 27,917 28,760 20,653 30.571 31,524 32,514 33,542 34,600 35,7168 Peak Demand uw 422 4n 46 #458 an 40650 «(408 su S28 5465 «6561 576 See 614 6s 653 673 604 717) «7.40 Baseload Capacity after losses Mw 300 3200 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 Baseload/Peak Demand * 71.1% 682% 67.4% 655% 637K G1G% GOIN SO4% SETH SS1N 535% SIGH SO4% 480% 47.4% 460% 446% 432% 419% 406% Load Supplied, by Generation Type Baseload MWh 16.914 19,407 19.884 20,373 20,656 21,323 21,767 22,186 22,576 22,033 23.255 23,541 23,780 24,002 24,178 24,321 24.432 24.515 24.574 24.615 Peak MWh 1,457 1,528 f 1,736 1883 2087 2.327 2.065 3,371 3,641 4376 4,978 5.651 6303 7.203 6.082 8.027 10.035 11.104 Baseload Cap. Fctr. * 71.9% 73.6% 756% 77.5% 793% 61.1% 626% 64.4% 65.6% 672% 684% 69.5% 90.5% 01.3% 01.8% 825% 620% G32% 834% 036% Fuel Use Baseload ,000 MMBtu 180 164 189 194 196 203 207 au 24 216 221 224 228 228 20 aa 232 2a 233 24 Peak ,000 MMBtu 5 18 7 16 20 2 a 27 au 3s 40 4 52 se 7 76 635 s 105 wy Fuel Price Basetoad S/MMBtU ea7 661 e75 660 e03 ov 035 os 970 oes 1006 1024 1042 1060 1076 1006 1114 1132 1140 1167 Peak ‘S/MMBtU oa ea 675 6689 903 817 935 953 970 9868 1006 1024 1042 1060 1078 1006 1114 1132 1140 1167 ” Fuet Cost Baseload $ 000 30,035 1.522 1,586 1.653 1.721 1,769 1.657 1833 2,008 2061 2153 2223 2200 2355 2417 2476 2532 2565 2635 2683 2,730 o) Peak $ 000 11,637 130 138 149 162 178 201 226 282 ed 350 406 am 5 620 724 620 945 1,073 1.211 1,361 N Variable O&M @ Baseload $000 2741 131 44 137 wt 144 147 150 153 156 158 160 162 164 166 167 166 168 169 170 170 vo Peak $000 (x) 10 W WW 12 13 14 16 18 20 23 26 20 x 2 “4 so EJ e J 7 c Electric Production $ 000 54,106 1,792 1,870 1,950 2.035 2,125 2,220 2,328 2,441 2,560 2,685 2.816 2,054 3,098 3.250 3,410 3,578 3.754 3,839 4133 4,337 ® Cost, Variable 4 Total Heat Load ,000 MMBtu_ 156 160 165 169 74 176 1863 168 193 196 204 208 215 221 227 233 238 245 252 2508 2 Heat Load w/ Access ,000 MMBtu cd 3s x wv a 2 “« “a a2 “ “as “a a a so 5 3s Ly 3s 57 @ Recoverable Heat - Baseload ,000 MMBtu “6 “a 48 50 St 52 ss “ 55 56 7 58 3 5e se 60 60 60 60 60 Peak ,000 MMBtu 4 4 4 4 5 5 6 6 7 6 i) WwW 12 “ 1” 6 20 2 235 27 w Total ,000 MMBtu x» St 5s 4 56 7 se a1 a a cS) 68 70 73 7 7 80 a2 65 668 5 Optimal DH Load ,000 MMBtu 2 3 u« 5 % a « “0 a 2 a “ “a a7 “0 so 52 s 55 s7 * after losses 000 MMBtu » au 32 a3 u“ 3s se au % 398 40 “a a Aa “ a7 “a ss» st s3 a Min(Optimal,w/ Access) 000 MMBtu » u 2 3 u“ 6 xs av xs 3 4 at a “4 “ a7 “a sx st s3 Fuel Use for OH ,000 MMBtu o ° o o o ° ° o ° o oO o o ° o o o o o o Onsite Fuel Price S/MMBtu 1359 1373 1387 1402 1416 1430 1448 1467 1466 1504 1523 1541 1558 1576 1586 1615 1633 1652 1670 1688 Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 1944 1964 1964 2004 2024 2045 2071 2087 2123 2148 2174 2200 2228 2252 2278 2304 2330 2356 2362 2408 Incremental DH Expansion Cost per MMBtu of Load SMMBtU 640 640 640 840 640 640 e640 640 640 640 640 60 60 640 640 640 640 640 60 640 Fuel Cost per OH MMBtu SMMBtu Recovered Hit Net Benefit S/MMBtu 1104 (11.26 1144 1164 11.64 1205 1231 1257 1263 1308 1334 1360 1386 1412 1438 1464 1400 15.16 1542 15.68 Net Benet from $,000 (10,285) (333) (348) (364) (381) (309) (418) (439) (462) (485) (510) (538) (562) (501) (620) (651) (884) (718) (753) (790) (830) Recovered Heat Fixed Plant Labor $ 000 7,657 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 450 Plant Property Insurance $000 681 3 xs 3x3 x 3 3 33 x 42 42 42 42 42 a2 42 42 42 42 42 42 Total Fixed O&M $ 000 6,538 483 483 483 483 “a 483 483 a “2 4e2 402 a 492 492 4a2 a2 42 492 492 492 New Plant investment $ 000 2.518 ° oe o ° 0 ° o 0 o m1 m1 171 1 m1 71 1 1 1 zee 2e6 2e6 TOTAL COSTS O38 2.043 3.054 3,171 3,283 23-Aug-91 0452 PM NOTES: Present value figures Include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1991 $. (als Power Plant Production Cost Model Location: Kotzebue Load Forecast: Hi Run Notes: Plant Type: Coal Fuel Price Forecast: Hi Preset Start 05 Variable Una Valve 1905) = 1906) §=61987) = 1908 = 1988 §=62000 | 2001 = 2002, 2003) 2004 = 2005, 2008 = 2007S 2008) 2008S 2010 2011 = 2012 201320 Electric Load MWh 20,370 20,836 21,503 22,112 22,749 23,410 24.085 24.604 25,540 26.304 27,095 27.017 28,769 20,653 30,571 31,524 32,514 33,542 34,608 35,716 Peak Demand Mw 422 433 445 456 an 465 409 si 529 545 se 576 596 ow 633 653 673 604 77 740 Baseload Capacity after losses Mw 520 520 520 520 5.20 520 5.20 520 520 520 520 520 520 520 520 520 520 520 520 520 Baseload/Peak Demand * 123.3% 1200% 1166% 113.6% 110.4% 107.3% 104 2% 101.3% BB3I% B55% B27% BOOK 673% B47H% B22% 7TOTR 772% 748% 726% 703% Load Supplied, by Generation Type Baseload MWh 16.741 19.261 19,783 20,343 20,829 21,537 22.167 22,8620 23,578 24.324 25.014 25,693 26.389 27,123 27,003 28,734 29.612 30.529 31.475 32.430 Peak MWh 1630 1,675 1,720 1,768 1,620 1,673 1,926 1,964 1962 1960 2061 2224 2380 2,531 008 2,700 2002 3,013 3.134 3,278 Baseload Cap Fctr * 411% 423% 434% 446% 459% 472% 486% SOIN% SI7% 534% 549% 564% 578% SO5% 612% GIO% 650% 670% B9IN 712% Fuel Use Baseload ,000 MMBtu 305 313 321 a 340 350 360 am 33 305 406 aie 428 a 453 467 48) 496 si 527 Peak .000 MMBtu 16 wv 7 16 18 19 19 20 20 20 21 22 24 23 27 2 2 nw au a3 Fuel Price Baseload ‘SMMBtU 602 ses 337 a7 330 296 206 296 206 296 260 24 26 240 20 240 24 24 20 24 Peak S/MMBtu e47 e61 675 ee9 903 o17 935 953 970 868 1006 1024 1042 1060 1076 1006 1114 1132 1148 1167 Fuel Cost Baseload $ 000 21,790 1634 1644 1062 1,113 1,153) 1,036 1,067 1.099 1,135 1,171 1,014 1,041 1.070 1,008 1,131 1,165 1,200 1,237 1.276 1,315 Peak $ 000 4.486 138 144 151 157 164 172 180 169 190 196 209 226 248 268 268 68 323 ui 360 383 Variable O&M Baseload $000 2,585 107 110 Ww3 116 119 123 126 130 M4 138 143 146 150 155 158 164 169 174 178 165 Peak $ 000 293 uw 12 12 12 13 13 13 “4 14 “4 4 15 16 v7 18 1” 20 21 z2 a2 Electric Production $ 000 20,173 2,000 2,110 1.358 1,398 1,449 1,344 1,367 1,431 1,473 1,518 1,380 1,431 1,484 1540 1,506 1,653 1,712 1,773 1,637 1,905 Cost, Variable Total Heat Load .000 MMBtu 156 160 165 169 74 178 1863 188 193 196 204 208 25 2 227 23 238 245 252 2598 Heat Load w/ Access ,000 MMBtu_ uu“ 3s s« a7 «3 32 4 a 42 “4 “a 468 aT “0 sO s ss “ 55 57 Recoverable Heat Baseload .000 MMBtu 264 292 300 we a7 326 336 346 357 368 373 389 400 at 423 as 449 463 477 491 Peak .000 MMBtu o o o ° o o o °o o o o o o ° ° o o ° 0 o Total .000 MMBtu 264 292 300 8 anv 326 336 46 357 369 378 389 400 au 423 as 448 463 477 4e1 Optimal OH Load .000 MMBtu 165 190 195 200 206 212 216 225 232 240 246 253 260 267 275 283 282 wi 310 319 * after losses .000 MMBtu 72 176 181 166 182 197 203 209 216 223 229 235 242 248 256 263 271 280 268 207 Min(Optimal,w/ Access) ,000 MMBtu u“ 35 « a 3% 39 4 a 42 “4 “a “a a7 40 sO Ss 53 a 55 s7 Fuel Use for OH 000 MMBtu_ 22 23 23 24 23 2 26 27 27 26 2 nw» 30 un 32 a u“ 35 « v7 Onsite Fuel Price SMMBtu 1359 1373 1387 1402 1416 1430 1449 1467 1466 1504 1523 1541 1559 1578 1596 1615 1633 1652 1670 1668 Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 1944 1964 1984 2004 2024 2045 2071 2097 2123 2148 2174 2200 2226 2252 2278 2304 2330 2356 2382 2408 incremental DH Expansion Cost per MMBtu of Load S™MMBtu 640 e40 640 640 640 640 640 640 640 640 840 640 640 640 640 640 640 640 640 640 Fuel Cost per DH MMBtu S/MMBtu 369 #300 217) 217 218 191 1.01 101 1981 191 161 161 161 161 161 161 «1.61 1.61 161 161 Recovered Ht Net Benefit SMMBtU 715 744 927 47 966 1014 1040 1065 1091 1117 1174 1200 1225 1251 1277 1303 13.29 1355 1361 1407 Wet Benet from $000 (0.768) (248) (262) (336) (352) (968) (308) (419) (441) (484) (408) (526) (552) (879) (607) (637) (087) (609) (732) (708) (801) Recovered Heat Fixed Plant Labor $000 26,061 1,660 1.660 1,660 1,660 1660 1,660 1.660 1,660 1660 1,660 1660 1,660 1,660 1660 1660 1,660 1660 1660 1,660 1,660 Plant Insurance $ 000 2.547 148 1486 146 146 146 148 146 146 148 146 146 146 146 146 146 146 146 146 146 146 Total Fixed O&M $000 31,528 1,806 1,606 1,606 1,806 1,806 1,806 1,806 1,606 1606 1,806 1,806 1,806 1,806 1606 1806 1,806 1,806 1,806 1,806 1,606 New Plant investment $ 000 26,100 28,100 ° o ° ° o o ° o ° ° ° ° ° ° ° ° ° ° ° ° [ TOTAL COSTS $ 000 79,032 28,100 3,650 3,653 2.827 2,852 2,886 2.752 2,774 2,796 2,815 2837 2660 2685 2,711 2,738 2,765 2,782 2819 2847 2877 2,009 23Aug-81 0452PM NOTES Present value figures include the extension of costs in the year 2014 through the year 2029 All dollar values are constant 1991 $ eL-S§ Power Plant Production Cost Model Location: Red Dog Load Forecast: Mid Run Notes: Plant Type: Diesel Fuel Price Forecast: Mid Presert Start 07 Variable Unk Value 1907 1998 = 1998 = 2000 2001 ~=— 2002, 2003 2004 = 2005S 2008 = 2007 = 2008 §= 2008 )3= 2010S 201i §= 2012) 2013 2014 «= 2015 2018 Electric Load MWh 1051982 105192 105192 105182 105192 105182 105182 105162 105182 105192 105192 105182 105192 105192 105192 105192 105192 105162 105192 105102 Peak Demand uw 1379 13.79 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 13798 Baseload Capacity after losses mw 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 Baseload/Peak Demand * 33% WI WIR 33% 363% WIR WIR WIR WIR BIR 363% 363% 363% 363% BIN WIR 33% BIR 363% 363% Load Suppiled, by Generation Type Baseload MWh 41,200 41,200 41,200 41,200 41,200 41,200 41,200 41,200 41,200 41.200 41,200 41,200 41,200 41,200 41,200 41.200 41,200 41.200 41,200 41,200 Peak MWh 63,082 63.992 63.992 63.992 63,092 63,092 63,082 63,992 63,092 63.992 63,092 63,002 63,082 63,002 63.002 63,902 63.902 63.992 63,992 63,992 Baseload Cap Fetr * 840% 840% 840% 940% 840% 840% 840% O40% 840% B40% 940% 040% 840% B40% B40% 840% 840% 840% B40% 940% Fuel Use Baseload ,000 MMBtu 385 365 385 365 365 385 385 385 385 385 385 385 385 385 385 385 335 385 365 385 Peak 000 MMBtu 5ee 5068 596 598 596 ‘Se8 506 508 506 506 506 see 506 506 see see Ses see see 506 Fuel Price Baseload S$/MMBtu eu 643 651 659 668 680 690 700 710 720 ma 7a 751 761 772 762 792 802 613 623 Peak S/MMBtU ou 643 651 659 660 690 7.00 710 720 73 7a 751 761 772 782 7e2 602 613 623 Fuel Cost Baseload $000 40,776 2.444 2,476 2507 2539 2578 2616 2657 2697 2736 2775 2615 2654 2694 2033 3,052 3,081 3,130 3,170 Peak $000 77,315 3.706 3645 3694 3943 4005 4066 4127 4188 4250 4311 4372 4433 4485 4556 4740 4801 4662 4923 Variable O&M Baseload $000 4244 243 243 243 243 243 243 243 2403 243 243 243 23 243 243 243 243 243 243 243 249 Peak $000 6.592 376 378 378 376 376 378 378 378 3768 3768 378 376 3276 376 376 376 376 378 376 378 Electric Production $000 137,830 6,061 6942 7,022 7,103 7,203 7,304 7,405 7,508 7,606 7,707 7,808 7,008 6,008 6,110 6210 6311 8.412 6513 8613 8,714 Cost, Variable Total Heat Load ,000 MMBtu- 219 219 218 219 219 219 20 219 210 210 219 200 216 20 20 210 218 210 218 210 Heat Load w/ Access ,000 MMBtu 219 219 219 219 210 20 20 210 20 200 219 20 20 20 20 20 216 210 210 210 Recoverable Heat Baseload ,000 MMBtu 119 119 119 v9 1198 119 me 1198 1198 198 119 19 1198 108 1108 108 119 118 118 Peak ,000 MMBtu 164 164 184 164 164 164 164 164 164 164 164 164 164 104 104 164 164 184 164 Total ,000 MMBtu 303 303 33 303 303 303 3 33 w~3 303 33 3 «3 303 ws 303 303 3~3 303 Optimal DH Load ,000 MMBtu 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 * after losses .000 MMBtu 239 239 239 239 239 230 238 239 239 239 239 239 239 230 238 238 238 239 238 Min(Optimal,w/ Access) 000 MMBtu 219 219 219 219 2100 209 20 219 219 20 219 219 210 200 200 216 210 219 218 Fuel Use for DH 000 MMBtu o ° o o ° o ° o o 0 ° o o ° ° ° ° o ° Onsite Fuet Price ‘SMMBtu 6 643 651 659 669 660 690 700 7.10 720 ma 74 751 761 7.72 782 602 613 623 Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 804 B14 e624 6x4 46 659 eo” 684 606 809 921 ou 046 e500 e711 oe4 e068 1009 1021 1034 Incremental OH Expansion Cost per MMBtu of Load S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per OH MMBtu ‘$MMBtU 000 0.00 000 000 000 000 6000 0.00 000 000 000 000 000 000 000 «6000 «(000 000 6000) «6000 Recovered Ht Net Benefit SMMBtU 804 ei 624 834 846 659 6871 e846 896 909 62) ou eee 6858) 6a7t eee 906 1009 1021 1034 Net Benefit from $,000 (35,658) (1,760) (1,782) (1,604) (1,626) (1,853) (1,681) (1,008) (1,035) (1,063) (1,000) (2,017) (2,045) (2,072) (2,000) (2,127) (2,154) (2,181) (2,209) (2,236) (2.263) Recovered Heat Fixed Plant Labor $000 15,095 665 665 665 665 665 665 665 665 665 665 665 665 665 865 665 665 665 665 665 665 Plant Insurance $000 1,292 74 4 74 74 74 74 74 74 74 74 74 4 74 ™ 4 74 74 74 74 74 Total Fixed OAM $ 000 16,387 939 939 939 939 939 939 938 930 939 939 930 939 9398 930 0 939 939 939 939 939 New Plant Investment $000 4,485 ° o ° o o ° ° ° ° ° ° o o ° s77 s77 s77 s77 377 377 377 ( TOTAL COSTS $ 000 123,143 o 6,030 6,000 6157 6.215 6,200 6,362 6435 6509 6562 6656 6720 6802 6876 7,526 7,590 7,672 7,746 71819 7,802 7,966 } 26-Aug-81 09:22 AM NOTES: Present value figures include the extension of costs in the year 2016 through the year 2031 All dollar values are constant 1891 $ sUNY Tepon eUTTOUAS TTesPeed pue boa pex vl Power Plant Production Cost Model Location: Red Dog Load Forecast: Mid Run Notes: Plant Type: Coal Fuel Price Forecast: Mid Presert Start 07 Variable Una Valve 1907 1908 §=61908 ©2000 = 2001S 2002, 2003 20042005 2008 )=— 2007S 2008 = 2008 = 2010S 2011 = 2012S 20132014 = 20152018 Electric Load MWh 105182 105182 105182 1051982 105192 105182 1051982 105192 105192 105182 105182 105182 105182 105192 105192 105162 105192 105162 105162 105192 Peak Demand mw 1378 1378 1378 1378 13.78 1378 1378 1378 1379 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1379 Baseload Capacity after losses mw 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 15.00 1500 1500 1500 Baseload/Peak Demand * 108.6% 108 6% 108 6% 106.8% 106.6% 108 6% 106.6% 106.6% 108.6% 108.6% 106.8% 108.6% 106.8% 1086% 108.8% 108.8% 108.8% 1066% 106.8% 106.8% Load Supplied, by Generation Type Baseload MWh 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96,777 96.777 96,777 96,777 96,777 Peak MWh 6415 6415 6.415 6415 6415 6415 6.415 6.415 6.415 6415 6415 6415 6415 6415 6415 6415 6415 6.415 Baseload Cap. Fctr. % 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 73.6% 736% 736% 736% 736% 736% 736% 736% 736% Fuel Use Baseload ,000 MMBtu 1,573 1,573 1,573) 1,573 1,573 1.573. 1,573. 1,573. 1,573. 1.573 1.573 1.573. 1,573. 1,573° 1,573 1,573 1.573 1,573 1,573. 1,573 Peak ,000 MMBtu 79 73 79 73 78 79 78 78 79 73 73 79 78 79 78 78 78 78 73 79 Fuel Price Baseload S/™MMBtu 337 307 339 206 206 296 206 206 20 240 249 24 24 20 20 240 24 240 240 240 Peak S/MMBtu ou 643 651 659 669 680 690 700 710 720 m3 74 751 761 772 762 7982 802 613 623 Fuel Cost Baseload $000 75,128 5.285 5.295 5330 4657 4659 4659 4659 4659 3.923 3923 3,923 3.923 3,923 3.923 3,923 3.923 3.923 3923 3.923 3.923 Peak $000 10,167 499 506 512 519 527 535 543 551 550 567 575 583 Set 508 607 615 623 631 639 e47 Variable O&M Baseload $000 7.435 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 426 Peak $ 000 ee7 so 50 50 so 50 50 so 50 so 50 sO so so so so sx so so so so Electric Production $ 000 93,597 6.269 6.276 6.317 5651 5,661 5.669 5677 5.685 4,957 4.965 4.973 4,061 4,969 4.097 5,005 5,013 5,021 5,030 5,038 5,046 Cost, Variable Total Heat Load ,000 MMBtu 219 219 219 219 20 2100 20 210 2100 219 219 210 219 210 219 218 210 219 218 218 Heat Load w/ Access ,000 MMBtu 219 219 210 219 219 219 219 210 219 219 219 200 210 210 219 219 219 210 219 210 Recoverable Heat Baseload ,000 MMBtu 1.466 1466 1.466 1.466 1466 1466 1466 1466 1,466 1466 1.466 1466 1466 1466 1466 1466 1,466 1466 1,466 1,466 Peak ,000 MMBtu 24 24 24 24 24 24 2 2 24 24 24 2 2 24 24 24 24 24 24 24 Total ,000 MMBtu 1,490 1490 1490 1490 1490 1.490 1.490 1490 1.490 1490 1490 1.480 1490 1400 1,400 1490 1490 1.490 1,490 1,490 Optimal DH Load ,000 MMBtu 1,182 1.192 1,192 1.192 1.192 1,182 1,192 1.192 1.1982 1,192 1,182 1,192 1,192 1,192 1,182 1.192 1.192 1,192 1,192 1,192 “after losses: ,000 MMBtu AATT OAATT OAATT NATE NATE NATE ANTE ATT ANT AATT NATE OAATT NATE NATE ONATT OAATT NTT ATT ATT ATT Min(Optimal.w/ Access) ,000 MMBtu 219 219 219 219 219 219 219 219 219 219 219 210 210 20 219 219 218 ral) 210 218 Fuel Use for DH ,000 MMBtu 133 133 133 133 133 133 133 133 133 133 133 133 133 133 133 133 133 133 133 133 Onsite Fuel Price ‘S/MMBtu ou 643 651 659 669 660 690 700 710 720 mH 74 751 761 772 762 702 602 613 623 Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 804 e14 824 634 646 659 e711 ees eo6 809 e21 ou e468 950 oo” 964 oo 1008 1021 1034 Incremental DH Expansion Cost per MMBtu of Load SMMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per OH MMBtu ‘S/MMBtu 205 205 206 180 160 160 «160 160 152 152 152 152 152 152 1.52 152 152 152 152 152 Recovered Ht Net Benefit S/MMBtU 599 609 616 654 666 679 7.04 745 7.57 7.69 782, 704 «©6607 6618 6632) 644 B57) 868 2 Net Benefit from $,000 (29,298) (9,392) (1,334) (1,953) (1,432) (1,450) (1,486) (1,513) (1,541) (1,630) (1,658) (1,685) (1,713) (1,740) (1,767) (1,795) (1,022) (1,849) (1,877) (1,004) (1,031) Recovered Hest Fixed Plant Labor $000 36,708 2.102 2.102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2.102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 Plant Insurance $000 5,308 4 we we we we we we m4 m4 4 4 4 we we ws 04 04 304 304 4 Total Fixed O&M $ 000 42,017 2,406 2,406 2,406 2,406 2,406 2,406 2,408 2,406 2,406 2,406 2,406 2,406 2,406 2,406 2,406 2,406 2,406 2,406 2,406 2,406 New Plant investment $000 57,500 57,500 ° o ° ° ° o ° o o o o o o o ° o ° ° o o [ TOTAL COSTS $ ,000 163,816 57,500 7,364 7,348 7,371 6,626 6,008 6560 6570 6551 5,733 5,714 5604 5.675 5.656 5,636 5,617 5,508 5,579 5,559 5,540 5,521] 26-Aug-81 09:24 AM NOTES: Present value figures include the extension of costs in the year 2016 through the year 2031. All dollar values ave constant 1991 $. SLs Power Plant Production Cost Model Location: Red Dog Load Forecast: Mid Run Note: Plant Type: Minemouth Coal Fuel Price Forecast: Mid Present Start 97 Variable Unt Vetue 1907 jose =—1908 =62000 = 2001 = 2002, 2003 2004 = 2005 2008 = 2007_—S 2008 = 2008 «3S 2010S 2081 = 2012S 2013) 2014 «= 2015 2018 Electric Load MWh 105182 105182 105192 105192 105162 105182 105192 105192 105162 105192 105182 105192 105182 105182 105192 105182 105102 105192 105192 105182 Peak Demand Mw 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 1378 13.78 1378 1378 1378 1378 1378 1378 1370 Baseload Capacity after losses mw 15.00 1500 1500 1500 1500 1500 15.00 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 Baseload/Peak Demand * 108.6% 108.6% 106.6% 106.6% 106.6% 106.6% 108.6% 108.6% 1086% 108.6% 10866% 1066% 1086% 108.6% 108.6% 1086% 1086% 1086% 1068% 106.6% Load Supplied, by Generation Type Baseload MWh 06,777 86,777 86,777 86.777 86.777 86.777 96.777 06.777 96.777 96.777 86.777 96,777 06.777 06,777 96.777 96,777 06.777 96,777 96777 Peak MWh 6415 6415 6415 6415 6415 6415 6.415 6415 6415 6.415 6415 6415 6415 6415 6415 6415 6415 6415 6.415 Baseload Cap. Fetr * 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% 736% Fuel Use Baseload ,000 MMBtu 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 1615 Peak ,000 MMBtu_ 78 739 79 79 79 79 7 79 78 7 73 73 78 7 7 78 7 7 7 73 Fuel Price Baseload SMMBtu 280 280 262 231 232 232 232 232 101 191 ier 101 191 1981 191 101 101 101 191 igor Peak S/MMBu 6% 86643 «6651 659 669 660 690 700 710 720 m3 Ta 751 761 772 782 702 602 613 623 Fuel Cost Baseload $000 60,300 4516 4516 4552 3.736 3.738 3.738 3.738 3.738 3,061 3.081 3,081 3.081 3,061 3.081 3.061 3,081 3,081 3081 3081 3081 Peak $000 10,167 4e0 506 512 519 527 535 “ 351 558 567 575 563 sot see 7 e115 623 631 639 647 Variable O&M Bascload $ 000 437 437 aay 47 a7 a7 a7 a7 437 a7 437 437 a7 a7 a7 a7 ar a7 47 437 Peak $000 50 50 50 so so 50 50 so 50 50 50 sO 50 50 50 sO 3 so so 5o Electric Production $ 000 5,502 5,509 5,551 4,741 4,752 4,760 4,768 4,776 4,127 4,135 4,143 4,151 4,159 4167 4175 4,163 4191 4199 4207 4215 Cost, Variable Total Heat Load 000 MMBtu 219 219 219 210 2100 210 219 210 210 219 210 210 219 218 216 218 216 218 218 218 Heat Load w/ Access ,000 MMBtu 219 219 219 219 219 210 2 210 20 210 210 219 20 20 20 20 210 2 216 219 Recoverable Heat Baseload ,000 MMBtu ° ° o o o o ° o ° o o 0 o o o o o o o 0 Peak 000 MMBtu 24 24 24 a4 2 2 a 24 24 2 a a a a a 2 2 24 24 24 Total ,000 MMBtu 24 24 24 24 24 24 2 2 24 24 24 2 24 24 24 24 24 24 24 24 Optimal DH Load 000 MMBtu 19 19 19 19 19 19 19 9 19 19 19 19 1° 1° 19 1° 19 19 19 18 * after losses: 000 MMBtu 19 19 19 18 19 19 19 19 19 19 19 19 19 18 18 ty 18 19 19 19 Min(Optimal,w/ Access) 000 MMBtu 19 19 19 19 19 19 19 19 19 19 19 1° 18 19 19 1° aL] 19 19 19 Fuel Use tor OH 000 MMBtu 0 o o o o o o o o o o o ° o o o o o ° o Onsite Fuel Price SMMBtu 634 64a 651 659 669 660 690 700 710 720 ma 741 751 761 772 762 782 602 613 623 Onsite Fuel +O&M per Delivered MMBtu ‘SMMBtu 604 e4 624 634 646 659 e711 ees 896 909 e21 o34 946 ose e711 oe4 906 1008 1021 1034 Incremental OH Expansion Cost per MMBtu of Load ‘S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per OH MMBtu ‘S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 6000) «6000 Recovered Ht Net Benefit SMMBtU 604 614 624 834 646 6659) 6671 eee 6806 809 9821 934 946 8950 O71 oes 1008 1021 103% Net Benefit from $000 3.116) (154) (156) (158) (160) (162) (164) (167) (160) (171) (174) (76) (178) (181) (83) (188) (Ve8) (193) (198) (198) Recovered Heat Fixed Plant Labor $000 30.611 2.280 2,280 2280 2.280 2,260 2,260 2,280 2,260 2260 2.260 2280 2,280 2.280 2,280 2,280 2,280 2,260 2,280 2280 2,260 Plant Property Insurance $000 332 332 332 332 332 a2 332 332 332 332 332 332, 332 32 a2 332 332 2 332 332 Total Fixed ORM $000 45,615 2ei2 2,612 2612 2,612 2612 2,612 2,612 2612 2612 2,612 2,612 2,612 2612 2612 2612 2612 2,612 2,612 2612 2,612 New Plant Investment $ 000 64,600 64,600 ° oO ° ° o ° ° ° ° o ° ° ° oe ° ° ° ° o ° { TOTAL COSTS $ 000 186,067 64,600 17,061 7,006 6,006 7,104 7,202 7,208 7,213 7,219 0,567 6,573 6,579 6,585 6500 6596 6,602 6,607 6.624 26-Aug-91 0927AM NOTES: Present value figures include the extension of costs in the year 2016 through the year 2031. All dollar values are constant 1991 s suny Tepon eutTouds TTespeed pue bod per Plant Characteristics Location: Red Dog jee | | ie ree Serena SSEEeeD Base Case Selected Plant Possibilities Variable Unit 2 1 2 3 ee Configuration Name Coal Diesel Coal Minemouth Coal Baseload Unit: Heat Rate Btu/kWh 16,250 9,350 16,250 16,250 Fuel Type 1 2 1 3 Fuel Type Coal Utility Oil Coal Minemouth Coal Variable O&M mills/kWh 4.4 5.9 4.4 44 Recoverable Heat Btu/kWh 15,150 2,880 15,150 0 Capacity MW 15.00 5.00 15.00 15.50 Availability 92.0% 94.0% 92.0% 92.0% Transmission Loss @ Full Load 0.0% 0.0% 0.0% 3.2% Peak Units: Heat Rate Btu/kWh 9,350 9,350 9,350 9,350 Fuel Type 2 2 2 2 Fuel Type Utility Oil Utility Oil Utility Oil Utility Oil Variable O&M mills/kWh 5.9 5.9 5.9 5.9 Recoverable Heat Btu/kWh 2,880 2,880 2,880 2,880 DH System Loss 1.3% 1.3% 1.3% 1.3% Btu of Fuel per DH Btu 0.60 0.00 0.60 0.00 Incremental DH Expansion Cost per MMBtu of Load $/MMBtu $0.00 $0.00 $0.00 $0.00 Onsite Heating Plant Effic. 82.0% 82.0% 82.0% 82.0% Onsite Fuel Type 2 2 2 2 Onsite Fuel Type Utility Oil Utility Oil Utility Oil Utility Oil Onsite Variable O&M $/MMBtu $0.30 $0.30 $0.30 $0.30 Economic Discount Rate %lyear 4.5% Analysis Period years 35 S| 76 LL New Plant Investments and Fixed O&M Location: Red Dog ,000 1991 $ New Plant Investments Plant Start iD Load 1997 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 #2008 2009 2010 2011 2012 2013 2014 2015 2016 1 Ct 577 577 577 577 577 577 577 Diesel M 577 577 577 577 S77 S77 S77 H 577 577 577 577 S77 577 577 z2 L 57,500 Coal M 57,500 H 57,500 3 L 64,600 Minemout M 64,600 H 64,600 Fixed Plant Labor Plant Start ID Load 1997 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 1 L 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 Diesel M 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 H 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 865 2 L 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 Coal M 2,102 2,102 2,102 2,102 2,102 2,102 2102 2,102 2,102 2102 2,102 2,102 2,102 2,102 21402 2,102 2102 2102 2,102 2,102 H 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2,102 2102 2,102 2,102 2,102 2,102 2102 2,102 2,102 2,102 3 t 2.280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,260 2,280 2,280 2,280 2,280 2,280 Minemout M 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2.280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 H 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,280 2,260 2,280 2,280 2,280 2,280 2.280 Property Insurance Plant Start ID Load 1997 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 1 e 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 Diesel M 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 H 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 74 2 & 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 Coal M 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 H 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 304 3 E 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 Minemout M 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 H 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 332 82 Fuel Price Forecast 2002 2003 2004 2005 2006 2007 Location: Red Dog Base Case Number of Fuel Types = 3 # Fuel Type 1 Coal 2 Utility Oil 3 > Minemouth Coal 4 Fuel Prices, $/MMBtu, 1991 $ Fuel Forecast Type 1997 1998 1999 2000 2001 Low 1 Coal 3.37 337 339 296 296 296 296 296 2 Utility Oil 5.30 532 534 536 538 540 542 5.44 3 Minemouth Coal 280 280 2862 231 232 232 232 232 Mid 1 Coal 3.37 3.37 339 296 296 296 296 296 2 Utility Oil 634 643 651 659 669 680 690 7.00 3 Minemouth Coal 280 280 282 231 232 232 232 2.32 High 1 Coal 3.37 3.37 339 296 296 296 296 296 2 Utility Oil 7.39 753 7.68 782 800 819 837 856 3 Minemouth Coal 280 280 282 231 232 232 232 2.32 2.49 5.46 1.91 2.49 7.10 1.91 2.49 8.74 1.91 2.49 5.48 1.91 2.49 7.20 1.91 2.49 8.93 1.91 2.49 5.51 1.91 2.49 7H 1.91 2.49 9.11 1.91 2008 2009 2010 2.49 5.53 1.91 2.49 7.41 1.91 2.49 9.29 1.91 2.49 5.55 1.91 2.49 7.51 1.91 2.49 9.48 1.91 2.49 5.57 1.91 2.49 7.61 1.91 2.49 9.66 1.91 2011 2.49 5.59 1.91 2.49 7.72 1.91 2.49 9.85 1.91 2012 2.49 5.61 1.91 2.49 7.82 1.91 2.49 10.03 1.91 2013 2.49 5.63 1.91 2.49 7.92 1.91 2.49 2014 2.49 5.65 1.91 2.49 8.02 1.91 2.49 10.22 10.40 1.91 1.91 2015 2.49 5.67 1.91 2.49 8.13 1.91 2.49 2016 2.49 5.69 1.91 2.49 8.23 1.91 2.49 10.58 10.77 1.91 1.91 6L Electric Load Forecast Location: Red Dog Base Case Load ~~ Formula tor % of MWH > X Load — Optimal) MWh--> Factor Min const x x*2 x*3 x74 x75 ULdWast] 1997 lo 87.0% 76% -3149 153 -27086 207.342 -56.542 -1.446 600%] 89.413 76% -3149 153 -27086 207342 -56542 -1446 600% 76% 3148 153 27086 207342 -56542 -1446 800% 1996 = 1988 = 2000 2001 — 2002, 2003 2004 20052008 2007 200s = 20082010 201i 012 013 4 20152016 69.413 689. 13 80,413 60,413 60,413 69.413 80,413 69,413 69,413 69,413 69,413 69,413 80,413 69,413 60,413 3 80,413 69.413 60,413 105182 105182 105192 105182 105182 105192 105182 105192 105192 105192 105182 105182 105182 105192 105192 105192 105192 105192 105192 120871 120871 120971 120971 120871 1209871 120971 120971 120971 120971 120971 120871 120871 120871 120871 120871 120971 120071 120971 Gam ——-- wweceen ——— sins Tanay arvranra 08 Heat Load Forecast Location: Red Dog Base Case % Access} ,000 MMBtu —> to DH 1997 1998 1999 2000 2001 +2002 2003 2004 2005 2006 ~=2007 ~=2008 =: 2009 2010 2011 = 2012, 2013, 2014S 2015s 2016 Low 100.0% 197 197 197 197 197 197 197 197 197 197 197 197 197 197 197 197 197 197 197 197 Mid 100.0% 219 219 219 219 219 219 219 219 219 219 219 219 219 219 219 219 219 219 219 219 High 100.0% 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 sung Tepon euttouds TTezpeeda pue boa vex te - Ss Power Plant Production Cost Model Location: Red Dog Load Forecast: Hi Run Notes: Plant Type: Diesel Fuel Price Forecast: Hi Present Start 97 Variable Unk _ Value 1997 1908 1908 2000 2001_—«2002_—-2003 20042005 2008 2007-2008 = 200820102011 = 2012, 2013-2014 «201520 Electric Load MWh 120871 120871 120971 120971 120971 120971 120871 120871 120071 120971 120971 120071 120871 120071 120071 120071 120071 “Saari Peak Demand uw 1566 1566 1566 1586 1586 1586 1586 1586 1566 1566 1566 1586 1586 1586 1586 1586 1586 “A Baseload Capacity after losses Mw 500 500 500 500 500 500 5.00 5.00 500 500 500 500 500 500 500 500 500 500 500 500 Baseload/Peak Demand * 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% 315% Load Supplied. by Generation Type Baseload MWh 41,200 41,200 41,200 41,200 41,200 41.200 41.200 41,200 41,200 41.200 41.200 41.200 41,200 41,200 41.200 41,200 41,200 41,200 41.200 41.200 Peak MWh 78,771 79,771 79,771 79,771 70.771 79.77% 79.771 79,771 79.771 79.771 79.771 79,771 79,771 70.771 70.771 70,771 79.771 79.771 79.771 Baseload Cap. Ft * 840% 840% 840% 840% 940% 840% B40% 840% 840% B40% B40% 40% B40% B40% 040% B40% 40% 840% 840% 840% Fuel Use Baseload ,000 MMBtu_ 365 385 385 385 385 385 385 385 385 385 385 385 385 385 385 385 385 385 385 385 Peak ,000 MMBtu 748 748 748 746 146 746 71468 748 748 748 748 748 748 7468 748 7468 746 7468 7146 748 Fuel Price Baseload S/™MMBtu 739 753 768 762 800 619 e- ana em 693 ei e208 o48 966 965 1003 1022 1040 1058 1077 Peak ‘S/MMBtU 739 753 768 762 800 eis 637 ese em 693 on o2 e408 eee 865 1003 1022 1040 1058 1077 Fuel Cost Baseload $000 62,410 2.646 2.957 3.012 3063 3154 3225 3206 3367 3438 3509 3560 3651 3722 3783 3664 38935 4006 4077 4146 Peak $000 120,637 5.511 5.725 5632 5968 6107 6244 6362 6519 6657 6784 6832 7068 7207 7344 7482 7619 7,757 7,604 6031 Variable O&M Baseload $000 4244 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 243 Peak $ 000 6216 am a7 am 4am am ami 47 am am am am amt am ami avi am am am am an Electric Production $000 195,708 9,071 9,234 9,396 9,558 9,766 9,975 10,183 10,392 10,600 10,008 11,017 11.226 11,434 11,643 11,851 12,059 12,268 12,476 12,685 12,093 Cost, Variable Total Heat Load ,000 MMBtu 241 241 241 2at aan 24 2at aan 241 241 241 241 2at 2a 241 241 241 241 241 24t Heat Load w/ Access 000 MMBtu 2at 241 24 241 24t 2a 2a 241 2at 241 241 241 241 aat 24 24) 241 2at 2a 24t Recoverable Heat Baseload 000 MMBtu 119 119 119 19 9 119 119 1108 1108 108 19 1108 108 118 1108 110 108 118 1108 119 Peak ,000 MMBtu 230 230 230 2300 230 230 2300 200 230 230 230 20 230 280 230 230 230 230 230 230 Total 000 MMBtu 348 48 348 348 48 M6 “Bs ue 148 348 348 8 8 348 8 48 348 48 348 348 Optimal DH Load .000 MMBtu 279 279 279 279 279 278 278 278 279 279 278 278 278 270 270 270 279 278 278 278 * after losses .000 MMBtu 275 275 275 275 275 275 275 275 275 275 275 275 275 275 275 275 275 275 275 275 Min(Optimal,w/ Access) 000 MMBtu 241 241 241 241 24t 241 241 241 241 2a 241 2a 241 2at 2at 241 24t 241 241 241 Fuel Use for Dti ,000 MMBtu_ o o o ° o o 0 o ° o o o ° o o o ° o o 0 Onsite Fuel Price ‘S/MMBtu 739 753 768 762 800 e19 637 ese em 693 gi e290 948 066 ees 1003 1022 1040 10586 1077 Onsite Fue! +O&M per Delivered MMBtu S/MMBtU on 949 966 964 1006 1029 1051 1073 1006 1116 #1141 #1163 11966 1208 1231 1253 1276 1298 1321 1343 Incremental DH Expansion Cost per MMBtu of Load S/MMBtU 000 000 000 000 000 000 0.00 000 000 000 000 000 000 000 000 000 000 000 000 000 Fuel Cost per DH MMBtu ‘$/MBtu ooo 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Recovered Ht Net Benefit S/MMBtu 931 949 966 984 1006 1029 1051 1073 1096 1116 11.41 1163 1186 1208 1231 1253 1276 1208 1321 1943 Net Benefit from $000 (48,658) (2.243) (2,205) (2,327) (2,360) (2,424) (2,478) (2,592) (2,588) (2,640) (2,604) (2,748) (2,003) (2,057) (2,011) (2,005) (3,010) (3,073) (3,127) (3,182) (3.230) Recovered Heat Fixed Plant Labor $000 15,095 665 665 665 665 665 665 865 865 665 665 665 665 665 665° 665 665 665 665 66s 865 Plant Property Insurance $000 1,292 4 74 74 4 4 74 74 74 4 74 4 74 74 4 74 74 4 4 4 74 Total Fixed O&M $,000 16,387 039 +030 +030 030 +090 030 030 030 030 030 000 039 039 030 0309 030 930 039 030 ©6030 New Plant Investment $000 4,485 ° o o ° o o o ° o ° oO o o ° s77 s77 377 s77 s77 77 s77 (Torat costs $,000 167,724 o 7,167 7,007 0,007 0,127 0,201 0,436 0,500 0,744 6.009 0,053 0,207 0,362 0,516 10,247 10.401 10,555 10,710 10,864 11,018 11,173) 26-Aug-91 0929AM NOTES: Present value figures include the extension of costs in the year 2016 through the year 2031 All dollar values are constant 1991 $ a ermyw Tranetr anecanI an oe een z8 Power Plant Production Cost Model Location: Red Dog Load Forecast: Hi Run Notes: Plant Type: Coal Fuel Price Forecast: Hi Presert Start 67 Variable Una Vetus 1907 1908 1909 2000 2001 2002 2003 2004 2005 2008 2007 2008 2008 2010 2011 2012 2013 2014 2015 2016 Electric Load wh 120871 120071 120071 120871 120071 120071 120071 120871 120071 120871 120871 120871 120871 120071 120071 120071 120071 120071 120071 120071 Peak Demand mw 1566 15866 1566 1566 1566 1566 1566 1566 1566 1566 1566 1566 1566 1586 1566 1566 15866 1586 1586 1566 Baseload Capacity after loeses mw 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 Baseload/Peak Demand * 946% GB46% O46% GB46% 046% 046% B46% B46% GB46% 046% 846% 046% O46% O46% B46% B46% B46% B46% B46% O46% Load Supplied, by Generation Type Baseload MWh 110929 110828 110829 110628 110829 110828 110029 110628 110829 110829 110028 110628 110628 110829 110829 110829 110828 110828 110629 110020 Peak MWh 10,041 10.041 10.041 10,041 10,041 10,041 10.041 10,041 10.041 10,041 10.041 10,041 10,041 10,041 10,041 10,041 10,041 10,041 10,041 10.041 Baseload Cap. Fctr * 844% 844% 644% 644% 644% 844% 644% 844% 644% 644% 644% 844% 644% 644% 844% 844% 844% 844% 844% 844% Fuel Use Baseload ,000 MMBtu 1,603 1603 1803 1603 1603 1603 1603 1603 1.603 1603 1603 1603 1603 1603 1603 1803 1603 1603 1603 1603 Peak 000 MMBtu J o a4 J o oo oo oo o o La “ oo “ Lat “ o~ “ - o Fuel Price Baseload SMMBtU 337 337 339 206 206 206 206 296 20 20 24 20 20 20 20 20 20 24 20 24 Peak SMMBtu 730 7533 768 762 600 619 637 ese er 693 ow o2 o4 ses oes 1003 1022 1040 1058 1077 Fuel Cost Baseload $000 66.114 6.069 6069 6109 5339 5340 5340 5340 5.340 4496 4496 4496 4496 4406 4496 4496 4496 4406 4496 4406 4406 Peak $000 15,211 604 7107 721 734 751 769 766 603 621 63 655 673 680 907 24 42 oe 976 904 ton Variable O&M Baseload $000 6523 488 488 488 488 488 4868 468 488 488 488 4668 488 Peak $000 1,034 se 5e se se se se se se se se se se Electric Production $000 110,682 7,310 7,324 5.082 5,009 ie 5.051 5,068 5.985 6003 6020 6037 6,055 Cost, Variable Total Heat Load ,000 MMBtu 241 241 24) 241 24t a4t 241 241 24) 24t 241 aan 2a 241 2a4t 241 2a4t 241 24i 241 Heat Load w/ Access ,000 MMBtu 241 2at 241 241 241 241 241 241 241 241 241 241 241 241 24t 241 2at 241 241 241 Recoverable Heat Baseload ,000 MMBtu 1.661 «1.661 1.661 1661 1661 1661 1681 1661 1661 1681 1681 1681 1661 1661 1661 1681 1681 1,681 1.681 1,681 Peak 000 MMBtu 2 2 2 2 2 2 2 2 2 2 2 2 2 a 2 2 2 2 2 2 Total ,000 MMBtu 1,708 1,708 1.709 1,708 1.708 1,708 1,708 1,708 1.708 1,708 1.708 1.708 1,708 1,708 1,708 1,708 1,709 1,708 1,709 1.700 Optimal DH Load ,000 MMBtu 1,368 1,368 1.368 1,368 1,368 1,968 1,368 1,368 1.366 1,368 1368 1,366 1,368 1.368 1,368 1,368 1,368 1368 1,368 1,368 * after losses 000 MMBtu 1,350 1,350 1350 1,350 1,350 1350 1350 1,350 1,350 1,%0 1,350 1,350 1,350 1,350 1,350 1350 1,350 1350 1350 Min(Optimal.w/ Access) .000 MMBtu 241 241 241 241 241 2at 241 241 241 241 aan 241 2a 241 aat 24 241 241 241 241 Fuel Use for Ott 000 MMBtu 146 146 146 146 146 1468 146 146 146 146 146 146 146 146 146 146 146 146 146 146 Onsite Fuet Price shametu 730 733 768 762 600 619 637 ese eM e93 ew o2 o4 966 oes 1003 1022 1040 1056 1077 Onsite Fuel +O&M per Delivered MMBtu SMMBIU ea 949 966 oa4 1006 1028 1051 1073 1006 1116 1141 1963) 1166 «#1208 1231 1253 1276 1206 1321 1343 Incremental DH Expansion Cost per MMBtu of Load S/MMBtu ooo 000 000 000 000 000 000 000 000 000 000 ooo 000 000 000 000 ooo 000 000 000 Fuel Cost per DH MMBtu SMMBtU 205 205 206 160 160 160 160 160 152 152 152 152 152 152 152 1.52 152 152 152 152 Recovered Hi Net Benefit SMMBtU 72 744 760 604 628 648 em 603 ou 967 989 1012 103% 1057 1078 1102 1124 #1147 1168 1162 Net Beneft from $000 (41,642) (1,750) (1,792) (1,831) (1,036) (1,090) (2,044) (2,008) (2,152) (2,275) (2,329) (2,383) (2,437) (2,401) (2,548) (2,000) (2,654) (2,708) (2,762) (2,816) (2,870) Recovered Heat Fixed Plant Labor $000 36,708 2,102 2,102 2,102 2,102 2.4102 2,102 2.102 2,102 2.102 2,102 2,102 2,102 2,102 2,102 2,102 2102 2,102 2102 2,102 2,102 Plant Property Insurance $000 5,306 304 4 304 304 204 304 304 304 04 we 304 304 304 El 304 4 304 we 4 304 Total Fixed OAM $ 000 42,017 2,406 2,406 2.406 2,406 2,408 2,408 2,408 2408 2,408 2,406 2,408 2,408 2,408 2,408 2,408 2,408 2,406 2,406 2,406 2,406 New Piart investment $ 000 57,500 ° ° o ° ° ° ° ° o ° ° ° ° ° ° ° ° o ° ° (Cforac costs $ ,000 166,538 7,067 7,038 7,953 7,091 7,056 7,019 6,062 6,945 5,006 5,959 5,022 5,085 5,648 5,812 5,775 5.738 5,701 5,664 5.627 5. 26-Aug 81 08:29 AM NOTES. Present valve figures include the extension of costs in the year 2016 through the year 2031 All dollar values are constant 1001 $ £8 Power Plant Production Cost Model Location: Red Dog Load Forecast: Hi Run Notes: Plant Type: Minemouth Coal Fuel Price Forecast: Hi Present Start 07 Variable Una Value 1907 = 1908 §=1988 §=2000 0 2001 = 2002, 2003 2004 = 2005S 2006 = 2007 = 2008 = 2008 3=— 2010S 2018 §= 2012S 2013) 2014 «= 2015 2018 Electric Load MWh 120871 120971 120871 120871 120871 120871 120871 120871 120871 120971 120971 120871 120971 120871 120071 120971 120971 120971 120971 120971 Peak Demand mw 1566 1566 1566 1566 1566 1566 1566 15.66 1566 1566 1566 1586 15866 15866 1586 1586 1566 15866 1566 1566 Baseload Capacity after losses Mw 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 1500 Baseload/Peak Demand * 946% 946% 946% 846% 946% 846% G46% 046% 046% 046% B46% O46% 046% G46% O46% 946% 46% 046% 046% 046% Load Supplied, by Generation Type Baseload MWh 110931 110931 110931 110831 110931 110931 110931 110931 110831 110831 110931 110831 110831 110831 110831 110031 110931 110931 110931 110031 Peak MWh 10,039 10,039 10,039 10,039 10,038 10,039 10,039 10,039 10,039 10.039 10,039 10,039 10,039 10,038 10,039 10,039 10,039 10,039 10,039 10,030 Baseload Cap Fctr * 843% 643% 643% 643% 643% 643% 643% 843% 643% 643% 643% 843% 843% 843% 843% 843% 643% 643% 843% 843% Fuel Use Baseload ,000 MMBtu 1656 1656 1656 1.656 1656 1656 1656 1656 1656 1656 1656 1656 1856 1656 1656 1656 1656 1656 1656 1656 Peak ,000 MMBtu ad Co) 94 94 4 o4 4 4 o4 o4 oo cy a4 a a a a 4 o4 o4 Fuel Price Baseload S/MMBtu 260 260 262 231 232 232 232 232 191 191 191 181 191 191 191 101 181 181 191 191 Peak SMMBtu 739 753 768 782 600 ew 677 ese em 603 ew 920 oa eee e685 1003 1022 #1040 1058 10.77 Fuet Cost Baseload $000 69,307 5,191 5.191 5.232 4204 4296 4296 4296 4206 3541 3541 3541 3541 3541 3541 3541 3541 3541 3541 3541 3541 Peak $000 15,206 694 707 721 TH 751 769 766 603 620 ee ess 872 680 oo7 e246 42 958 976 993 1,011 Variable O&M Baseload $000 6,774 503 503 503 503 503 503 503 503 503 503 503 503 S03 503 503 503 503 503 503 503 Peak $000 1,034 590 59 59 se 59 59 59 se se 50 5e se se se 58 se 5e se 58 se Electric Production $000 04,324 6.446 6460 6515 5500 5.610 5.627 5644 5,661 4923 4941 4,956 4975 4993 5,010 5027 5,044 5,062 5,079 5,096 5,114 Cost, Variable Total Heat Load ,000 MMBtu 241 241 241 241 241 241 241 241 241 241 241 241 241 241 241 24i 24) 24) 241 24at Heat Load w/ Access ,000 MMBtu 241 241 241 241 241 2a 241 241 241 241 241 241 241 aa 2a 241 241 241 24t 241 Recoverable Heat Baseload ,000 MMBtu o oO oO o o ° °o o o o o o ° ° o 0 o o o 0 Peak ,000 MMBtu 2 2 28 2 2 2 28 28 28 2 28 28 2 2 2 2 28 2 29 28 Total .000 MMBtu 2 29 28 2 2 2 2 2 2 2 2 2 2 2 2 2 2 29 20 20 Optimal OH Load ,000 MMBtu 23 23 2 2 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 * after losses ,000 MMBtu 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 Min(Optimal.w/ Access) 000 MMBtu_ 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 23 Fuel Use for OH ,000 MMBtu 0 oO o oO oO o o oO o o oO o o o o oO oO oO o 0 Onsite Fuel Price ‘S/MMBtu 739 753 768 762 600 619 637 ese e74 ee3 gn 820 e486 866 ees 1003 1022 1040 1058 10.7/ Onsite Fuel +O&M per Delivered MMBtu S/MMBtu 931 949 966 864 1006 1029 1051 1073 1096 1116 1141 1163 1166 1208 1231 1253 1276 1208 1321 1343 Incremental DH Expansion Cost per MMBtu of Load ‘$/MMBtu 000 000 000 000 000 000 000 000 000 G00 000 000 000 000 000 000 000 000 000 000 Fuel Cost per DH MMBtu S/MMBtu 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 000 Recovered Ht Net Benefit S/MMBtu 931 949 966 984 1006 1028 1051 1073 1096 1116 1141 1163 1186 1208 1231 1253 1276 1296 1321 1343 Net Benefit from $,000 (4,630) (213)_(217)_(221)_—-(225)_—(230) (238) (240) (245) (280) (288) (260) (266) (271) (276) (281) (208) (201) (208) (302) (307) Recovered Heat Fixed Plant Labor $000 39,811 2.280 2.260 2.260 2,260 2.260 2.260 2,280 2.260 2.2860 2260 2260 2.280 2,260 22860 2.260 2280 2.2800 2260 2.260 2200 Plant Insurance $ 000 5,604 332 332 332 332 332 332 332 332 332 332 332 332 x2 332 332 332 32 332 332 332 Total Fixed OAM $000 45,615 2,612 2,612 2,612 2,612 2,612 2,612 2,612 2,612 2,612 2,612 2,612 2.612 2,612 2,612 2612 2,612 2,612 2,612 2,612 2,612 New Plant investment $000 64,600 64,600 ° o ° o o o oO o ° o ° o o o ° ° ° o o o C TOTAL COSTS $ 000 199.009 64,600 6,046 6,856 0,006 7,978 7,002 8,004 6.017 8,020 7,206 7,208 7,310 7,322 7,334 7,346 7.350 7.371 7,383 7,305 7,407 7,419 J 26-Aug-91 0931AM NOTES Present value figures include the extension of costs in the year 2016 through the year 2031. Ali dollar values are constant 1991 $ 5.8 References Alaska Energy Authority. 1989. Update of Oil Price Forecast Assumptions. Memorandum from Richard Emerman to Robert LeResche. September 27. Arctic Slope Consulting Group. January 1990. Kotzebue and Nome Coal Study. Prepared for Alaska Native Foundation. CH2M Hill. August 1990. Juneau 20-Year Power Supply Plan Update. Prepared for Alaska Electric Light and Power Company, Alaska Energy Authority, Alaska Power Administration, Juneau Energy Advisory Committee. Frank Moolin & Associates an R.W. Beck. March 30, 1990. Healy Coal Project Financial Plan and Feasibility Study. Prepared for Alaska Industrial Development and Export Authority. Fryer/Pressley Engineering, Inc. May 1, 1990. Nome Waste Heat Recovery Report and Concept Design. Prepared for Alaska Energy Authority. Fryer/Pressley Engineering, Inc. March 30, 1990. Kotzebue Waste Heat Recovery Report and Concept Design. Prepared for Alaska Energy Authority. ICF/Lewin, Inc. 1988. Fuel Price Outlook for the Alaska Railbelt Region: Oil and Natural Gas. Prepared for Alaska Energy Authority. August. Jabbour, Salim J. et al. June 1989. Railbelt Intertie Reconnais- sance Study. Prepared for Alaska Power Authority by Decision Focus, Inc. Kotzebue Electric Association, Inc. March 1989. Power Require- ments Study, Alaska 13 Kotzebue. Mitchell, Alan and Colt, Steve. October 26, 1990. Nome Electrical Load Forecast. Prepared for Arctic Slope Consulting Group by Analysis North and EMI Consulting. Polarconsult Alaska, Inc. November 1987. Nome Waste Heat Feasi- bility Study. Prepared for Nome Joint Utility Board. SFT, Inc. 1991. Technical Memorandum on Power Plant Evaluation for Northwest Alaska Coal Project. Prepared for Arctic Slope Consulting Group. 5 - 84 Stone and Webster. November 1988. Estimated Costs and Environmen- tal Impacts of Coal-Fired Power Plants in the Alaska Railbelt Region. Prepared for Alaska Power Authority. Stone and Webster Management Consultants, Inc. November 1990. Draft Report on Least-Cost Utility Planning Demonstration Study. Prepared for Copper Valley Electric Association Inc. 5 - 85 Technical Paper Micronized Coal Reburning for NOx Control on a 175 MWe Unit Dale T. Bradshaw Tennessee Valley Authority Chattanooga, Tennessee 37402 James U. Watts Department of Energy Pittsburgh Energy Technology Center Pittsburgh, Pennsylvania 15236 Thomas F. Butler Tennessee Valley Authority Chattanooga, Tennessee 37402 Allen C. Wiley MicroFuel Corporation Ely, lowa 52227 Robert E. Sommerlad Research-Cottrell Companies Branchburg, New Jersey 08876 £ P/4) FULLER:MPD ™ MINERALS PROCESSING DIVISION ‘A member of the F | Smacth-Fuler Enaneenna Grou FULLER COMPANY 2040 Ave. C, LVIP * Bethlehem, PA 18017-2188 Telephone: (215) 264-6900 FAX: (215) 264-6441 + Telex: 173189 Mc FUEL POWER-GEN 91 Tampa, Florida December 4-6, 1991 Presented at Power-Gen ‘91 ABSTRACT The Tennessee Valley Authority (TVA) along with MicroFuel Corporation, Research-Cottrell Research & Development, and Duke/Fluor Daniel have been selected for the Department of Energy’s (DOE's) Clean Coal Technology IV program to demonstrate Micronized Coal Rebum technology for control of nitrogen oxide (NOx) emissions on a 175 MWe wail- fired steam generator at its Shawnee Fossil Plant. This retrofit demonstration is expected to decrease NOx emissions by 50 to 60 percent. Up to 30 per- cent of the total fuel fired in the furnace will be micronized coal injected in the upper fumace creat- ing a fuel-rich rebum zone. Overfire air will be in- jected at high velocity for good furnace gas mixing above the rebum zone to ensure complete combus- tion. Shawnee Station is indicative of a large por- tion of boilers in TVA’s and the nation’s utility operating base. Micronized Coal Rebum technology compares favorably with other NOx control tech- nologies and yet offers additional performance benefits. This paper will focus on Micronized Coal Rebum technology and the plans for a full-scale demonstration at Shawnee. INTRODUCTION According to recent industry studies, 44 percent of the nation’s coal-fired plants will have seen their 30th birthday by the turn of the century. Older fossil plants typically have the following operating characteristics and many of these conditions lead to high NOx production: * Higher excess air * Deteriorating coal fineness * Poor control of secondary air * Mill limited from coal switching * Poor turn-down ratio * Cyclic duty operation TVA has a high boiler population that falls into this category, yet demand upon this existing fossil generating capacity continues. Therefore, TVA has investigated methods of reducing NOx while improving overall boiler performance. A substantial data base has been developed in the reduction of nitrogen oxides (NOx) by various combustion modifications both here and abroad. Accurate control of coal particle fineness and air fuel ratios are essential ingredients in their success. NOx reduction in existing coal-fired boilers has Page 1 been demonstrated with either low NOx burners, or reburning with natural gas representing up to 20 percent of the total furnace fuel. Accurate control of the combustion process is common in both NOx reduction methods. The purpose of this project is to demonstrate the effectiveness of micronized coal (80 percent less than 325 mesh) combined with an advanced coal reburning technology for decreasing NOx emis- sions by 50 to 60 percent in a 175 MWe pulverized coal wall-fired boiler. Up to 30 percent of the total fuel fired in the fur- nace will be micronized coal. This fuel will be in- jected into the upper furnace creating a fuel-rich zone, at a stoichiometry of 0.8 to 0.9. Overfire air will be injected at high velocity, for good furnace gas mixing, above the reburn zone ensuring an oxidizing zone for an overall furnace stoichiometry of 1.15 (excess air of 15 percent). Micronized Coal Reburn technology reduces NOx emissions with minimal furnace modifications and enhances boiler performance with the improved burning characteristics of micronized coal. The availability of the reburn fuel, as an additional fuel to the furnace, solves several problems con- currently. Units that are mill limited from fuel switching now have sufficient fuel capacity to reach their maximum continuous rating (MCR). Res- toration of lost capacity, as a benefit to NOx reduction, becomes a very economical source of power generation. Reburn burners can also serve as low-load burners and units can achieve a turndown of 8:1 without consuming expensive auxiliary fuels. The combination of micronized coal reburn fuel and better pulverizer performance will increase overall pulverized fuel surface area for better carbon burnout. Micronized Coal Reburn Characteristics and Benefits are high- lighted in Figure 1. Micronized Coal Reburn technology can be ap- plied to cyclone-fired, wall-fired, and tangentially fired pulverized coal units. The overfire air system can also be easily adapted to incorporate in-fur- nace sorbent injection for SO2 control. Presented at Power-Gen ‘91 ([) - generits CO - Cherecteristics Burnout Zone —————= Reburn Zone ————= 4) MF 3018 Mcrofuel Systens Figure 1 Restore Lost Capacity Maintain Pient Outout Increased Load Corrying Cooopmty Micronized Coal Reburn Characteristics and Benefits A baseline test profile of the furnace along with furnace flow and computer modeling will be con- ducted prior to the design and installation of the MicroMill Systems and micronized coal injec- tor/burners. An extensive test program will docu- ment performance during a three-year operational period. DOE CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM The Clean Coal Technology Demonstration (CCT) Program is a multi-billion-dollar national commit- ment, cost-shared by the government and the private sector, to demonstrate economic and en- vironmentally sound methods for using our nation’s most abundant energy resource, coal. The program will foster the energy-efficient use of the nation’s vast coal resource base. The program will contribute significantly to the long-term energy security of the United States, further the nation’s objectives for a cleaner environment, and improve its competitive standing in the international energy market. Page 2 The objective of the CCT is to demonstrate a new generation of innovative coal utilization processes in a series of “showcase” facilities built across the country. The program takes the most promising of the advanced coal-based technologies and, over the next decade, moves them into the commercial marketplace through demonstration. These demonstrations are on a scale large enough to generate all the data, from design, construction, and operation, that are necessary for the private sector to judge their commercial potential and make informed, confident decisions on commercial readiness. The goal of the program is to furnish the U.S. energy marketplace with a number of advanced, more efficient, and cnvironmentally responsive coal-using technologies. The Clean Coal Program is intended to demonstrate innovative technologies that utilize coal in an environmentally superior manner. Candidate technologies must be capable of cither retrofitting, repowering or replacing existing facilities and/or providing for future energy needs Presented at Power-Gen '91 in an environmentally acceptable manner. Such existing facilities include coal-fired power genera- tion and industrial processes that utilize coal. The demonstration projects, however, can be at new facilities provided the commercial application of the technology is capable of retrofitting, repower- ing or replacing applications and/or providing for future energy needs. When the projects are completed, the sponsors and participants will be in a position to use the in- formation and experience gained during demonstrations to promote and market the tech- nologies in commercial applications. The detailed data and experience will be vital to firms deciding to build retrofit or repower plants using clean coal technologies. As a part of CCT IV, DOE selected as one of the nine projects to be demonstrated under round IV, TVA’s Micronized Coal Reburning at Shawnee. Since NOx, as well as SO2, has been designated by the 1990 Clean Air Amendments passed by the U.S. Congress as precursors of Acid Rain precipitation, controlling NOx has presented chal- lenging problems in achieving a low-cost retrofit control system. To date, there have been several methods used to reduce NOx, however, each with some disadvantages. Low NOx burners have been fairly successful but may not provide sufficient reduction by themselves. Gas reburning also has been successful, but it requires a steady supply of gas at a reasonable cost. Coal reburning shows promise in providing a NOx control system which can be readily retrofitted and operated at low cost. Coal reburning does not require external modifica- tions to the flue gas duct system nor does it re- quire major modifications to the boiler or a separate type of reburn fuel. In fact, coal reburn- ing may help some power producers who have had to derate their unit due to coal switching to meet SO2 reduction requirements. PROJECT TEAM Successful projects are a result of innovative tech- nology with superior and skilled management. An integral part of this combination are the DOE and TVA project team members. The Department of Energy/Pittsburgh Energy Technology Center (DOE/PETC) will be a co- funder of the project and will work with all the other team members by recommending work em- phasis and line of inquiry to accomplish the stated Page 3 objectives of the project. Also, DOE/PETC will assist in publishing reports and technical informa- tion necessary to achieve a commercial success for the project. The Tennessee Valley Authority (TVA) has as- sembled a uniquely talented team for this project, including: * MicroFuel Corporation, Ely, lowa (MFC), Prime Contractor, Micronized coal tech- nology ° Research-Cottrell Research & Develop- ment, Somerville, NJ (R-C), Furnace modeling, reburn technology ° Duke/Fluor Daniel, Charlotte, NC (D/FD), Engineering and construction contractor TVA and each team member bring a unique ex- pertise and experience to the project. Each will provide complementary functions to insure the success of the project. TVA will be the participant and provide the host site, Shawnee Fossil Plant near Paducah, Kentucky. Shawnee Station is cur- rently the site for a DOE CCT III project and was also the host site for a 160 MWe atmospheric fluidized bed combustion demonstration plant. The TVA management staff is well versed and ex- perienced in full-scale technology demonstrations. A Project Organization Chart is shown in Figure 2. ee me U.S. GOVERNMENT DEPARTMENT OF ENERGY (00€} PITTSBURGH ENERGY TENNESSEE VALLEY TECHNOLOGY CENTER = }-—— AUTHORITY (PETC) (TVA) TVA RESOURCE DEVELOPMENT NCROFUEL CORPORATION (MFC) RESEARCH-COTTRELL. OUKE/FLUOR DANIEL NC. (0/FO! R-C1 Figure 2 Project Management Team Presented at Power-Gen '91 MicroFuel Corporation (MFC) is the developer of the MicroMill system and has eight years of ex- perience with micronized coal technology. In 1988 MFC installed a 5-ton/hour micronized coal com- bustion system at Duke Power’s Cliffside Station, Unit 5, a 600 MWe unit. The micronized coal combustion system replaced the main oil guns in corners 2 and 4 and has demonstrated the stability of a 100 percent micronized coal flame in a cold furnace. Research-Cottrell Research & Development (R-C) has been a pioneer in NOx control and a leader in the development of advanced reburn technology. R-C will provide engineering and R&D support, including computer and cold flow boiler modeling, and emissions monitoring and laboratory analysis. Developing NOx control methods for major utilities nationwide has provided R-C with exten- sive knowledge and experience in both combustion and post-combustion NOx reduction techniques. At their Western Research Facility (formerly KVB), low NOx burners have been designed and test-fired correlating fuel burnout, ignition be- havior, and NOx emissions as a function of burner geometry and swirl levels. In addition, R-C is familiar with the TVA Shawnee test facility, having conducted a study of flue gas desulfurization by spray dryer and electron beam in 1983-84. Trials were performed with both fabric filter and an electrostatic precipitator as the par- ticulate control device. Duke/Fluor Daniel (D/FD) will provide architec- tural and engineering services to facilitate con- struction and integration of the boiler systems. As the engineer constructor, D/FD combines Duke Power’s 65 years of experience and the resources and experience of Fluor Daniel in coal power plant design, construction and operation. In addi- tion, D/FD was the engineer construction manager on TVA’s 160 MWe atmospheric fluid bed demonstration project at Shawnee. SITE Site Description The host site will be one of units 1-9 at TVA’s Shawnee Fossil Plant which was built to help meet the huge electric power requirements of a nearby DOE facility. Construction began in January 1951 and commercial operation commenced in April 1953. By October 1956 all 10 of the plant’s identi- Page 4 cal pulverized coal-burning units were generating power. Although Shawnee is approaching 40 years of operation, it still has the capacity to generate ap- proximately 11 billion kilowatt-hours of electricity each year. Despite its age, the plant has a lifetime generation availability of greater than 91 percent. The Shawnee facilities have also been a testing center for the development of pollution control technology. Over the years limestone furnace in- jection and a variety of wet scrubbers have been demonstrated for SO2 removal. Fluidized bed combustion has been demonstrated first with an atmospheric fluidized bed combustion (AFBC) 20 MWe pilot plant since 1982 and more recently with a 160 MWe commercial scale unit (unit 10). Presently emission control for the conventional pulverized coal-fired units (units 1 through 9) con- sist of low sulfur coal (1.195 Ib $O2/10° Btu), and fabric filters for particulate control. Each boiler is a 175 MWe (gross) front wall-fired dry-bottom furnace burning East Appalachian low- sulfur coal. A cross sectional general arrangement of a typical unit with Micronized Coal Reburn sys- tem in place is shown in Figure 3. The plant was originally designed to burn high-sulfur coal, but in the 1970s, the plant was modified to burn low-sul- fur coal in order to meet an emission limit of 1.2 Ibs SO2/10° Btu of heat input without the use of any sulfur dioxide control technology. Each unit has been equipped with a baghouse to control par- ticulate emissions. Flue gas from each unit dis- charges to one of two 800-foot stacks also con- structed in the 1970s. The original electrostatic precipitator short-stack system has been removed from service. The nine existing pulverized coal units are representative of a large number of wall- fired units in the industry which will be required to reduce NOx emissions in response to the 1990 Clean Air Act Amendments. Ash Handling In the past, fly ash and bottom ash from all 10 units at the Shawnee Fossil Plant were sluiced to an ash pond for disposal. The ash pond was peri- odically dredged to dry storage in order to prolong the useful life of the pond. Plant facilities recently have been modified to allow dry handling and dis- posal of fly ash from the pulverized coal units and spent bed material from the AFBC unit. If the demonstration achieves a secondary goal of reduc- ing carbon in the ash when combined with dry handling, market potential in the ash will increase. ven aro 00 > scarce Gum Sine ALRATING CATER Seen teas meron s1810 owe QuscevA tie ba cone sence Feo Pes é & s > ; 9 ie = comoensee Tennessee Valley Authority OWG. No. 25-0008 (Ref. SHF47213) 0.0.€. PON DE-PSO1-91FE62271 TVA Shawnee Station Unit 6 Micronized Coal Reburn Demonstration NOx Control-175 MW Wall Fired Unit Mechanical Equipment Traverse Section Presented at Power-Gen 91 Coal Acquisition TVA has contracts in place to supply Shawnee with low-sulfur bituminous coals from Kentucky and West Virginia. These coals will be used as the primary fuels for the project. TVA has test burned western coals such as Powder River Basin (PRB) at a number of sites, including Shawnee, since the late 1970s. PRB coal will be obtained for testing for this demonstration. Installing four 5- ton/hour MicroMills will offset the furnace derat- ing effect of PRB coal with its lower heating value. The Shawnee units typically cycle between mini- mum and maximum load daily. This will provide opportunities for data collection under varying conditions and demonstration of the capabilities of the MicroMill Systems and burners to allow opera- tion at very large turndown ratios without sup- plemental firing. REBURN CONCEPT History of Technology Reburning is a combustion modification technol- ogy that removes NOx from combustion products by using a hydrocarbon fuel as the reducing agent. This technology, which is alternately referred to as “in-furnace NOx reduction” or “staged fuel injec- tion,” has been found to involve kinetic processes similar to those in staged combustion. The con- cept was originally developed by the John Zink Company and Wendt, et al., based on the principle of Myerson, et al., that CH fragments can react with NO. More recently several investigators have conducted detailed investigations of the process and demonstrated its potential for large-scale ap- plications. See list of references in Attachment A. Process Chemistry Reburning is a process where a fraction of the fuel is injected downstream of the main combustion zone to form a fuel-rich zone. Additional air is needed further downstream to complete combus- tion. The reburning process consists of three main zones: the primary or main burner zone, the reburn zone, and the burnout zone, as shown schematically in Figure 4. Details of the process in the various zones are as follows: FUEL NO HCN NH BURNOUT AIR +XN ZONE REBURNING ZONE FUEL (CHN) HzO . SO2 AIR bm PRIMARY ZONE Figure 4 Chemistry of Reburn Process Primary Zone This is the zone where the main fuel normally enters the furnace through one or multiple burners. These burners may be mounted on the front or rear walls, or both walls, or in the corners (tangential firing). In utility-sized furnaces the fuel enters in a horizontal direction, combus- tion occurs, and the products of combustion then turn and move upward in a vertical direction. Normally the fuel burns with an excess amount of air (fuel-lean) to assure good combustion perfor- mance. The fuels used in this type of furnace are gaseous, liquid, or solid (pulverized coal, normally 70 percent through 200 mesh or nominally 60 microns). This is the zone where NOx is formed from fuel nitrogen and air fixation mechanisms. Under reburning the amount of fuel entering this zone is reduced to approximately 70 to 80 percent of the total heat input to the system. The fuel is combusted under a fuel-lean condition but the amount of excess air can be reduced without im- pact on combustion efficiency because of the other zones of the reburn process. Reburning fuel is injected in a horizontal direction downstream of the primary zone to form a fuel- rich mixture. The reburn fuel may be gaseous, liq- uid or solid. In this reburn process the reburn fuel is micronized coal, 80 percent through 325 mesh or nominally 20 microns. The three major reactions occurring in the reburning zone are: NO on XN (NH3* HCN + NO) XN *NO — Np CH + NO — XN NO . COg. Q . ASH Presented at Power-Gen ‘91 1. NO reacts with hydrocarbon radicals in reac- tions such as: NO + CH > N + CHO > HCN+0O which increases the nitrogen radical pool. nN Interconversion of nitrogen specics among different fixed nitrogen compounds (NO, HCN, or NH3) occurs. (In this paper, the ex- pression XN is used to refer generically to any of these three fixed nitrogen species.) 3. The formation of molecular nitrogen by the reaction of nitrogen radicals with NO. The reaction, NO +N > N2+0 sometimes referred to as the “back-Zcldovich” reaction mechanism, is the most probable path, al- though reactions with NH2 species are possible. Consequently, the nitrogen oxide formed in the primary zone cither is converted to N2, NH3, HCN, or retained as NO. When the rcburning fuel contains nitrogen (e.g., if the reburning fucl is coal), coal nitrogen could remain with the char or form NO, HCN, and NH3. Thus, the products of this zone contain nitrogen species which can be converted to NO, (namely char nitrogen) NH3, and HCN, as well as NO. The sum of these gas- phase species is referred to as total fixed nitrogen (TFN). Burnout Zone In this zone air is added to produce an overall air-rich (fuel-lean) condition to complete the combustion of all the remaining fucl. The TFN or char nitrogen is converted to NO or N2. This zone is analogous to the second stage of a staged-combustion process. The resultant NOx leaving this zone is substantially less than the NOx formed in the primary zone and also less than formed in a conventional furnace. Typically the stoichiometry in the primary zone is between 1.0 and 1.1 (0 and 10 percent excess air) to minimize NOx while not producing a zone that may result in slagging or corrosion and also com- bustible burnout problems. The reburn zone would normally be operated at a stoichiometry be- tween 0.8 and 0.9. The air used for dispersion of the micronized coal through the coal injector would be preheated air (secondary air) from the windbox. The coal injector will require that the micronized coal be distributed across the furnace to mix with the furnace gas in the reburn zone and then with the overfire air in the burnout zonc. Page 7 Concept Operation Micronized coal reburning for NOx control will operate in the same manner as natural gas reburn- ing on coal-fired boilers. In effect, the entire fur- nace operates as a low NOx burner. The existing burners shall be operated slightly oxidizing with accurate fuel/air control. Microfine coal, with a surface area of 31 m*/gm is fired substoichiometri- cally in a reburn zone above the top row of the existing burners. Combustion of the high-surface- area micronized coal consumes oxygen very rapidly converting NOx to molecular nitrogen. NOx con- version occurs with a residence time of 0.5 to 0.6 seconds. Above the reburn zone high velocity overfire air will uniformly mix with the sub- stoichiometric furnace gas to complete combus- tion, giving a total excess air ratio of 1.15. This concept should reduce NOx emissions 50 to 60 percent from current levels of 0.82 to 0.95 Ibs/10°Btu to an emission level of 0.33 to 0.48 Ibs/10°Btu. The proposed project will demonstrate the effec- tiveness of reducing nitrogen oxide emissions with an advanced coal reburning technology utilizing micronized coal. This technology can be applied in new as well as existing pulverized coal-fired fur- naces. The coal used in reburning can be the same coal as used in the main fuel burners. A schematic of this system is shown in Figure 5. In addition, this reburn technology can be combined with various sulfur dioxide (SO2) control technologies such as fucl switching, dry sorbent injection, or other post combustion technologies. Overtire Ar System — Injector/ Burners ————————_ ~ MicroFuel System — Exsting Pulverizers Figure 5 Schematic of Reburn Process Presented at Power-Gen ‘91 The original design coal for Shawnee had a Hardgrove Index (HGI) of 50. By converting to east Appalachia low sulfur coal with an HGI of 36 to 44, the units are mill limited to 154 MWe when coal moisture is high. The reburn system provid- ing 20 ton/hour of micronized coal milling capacity would maintain boiler maximum continuing rating (MCR). Other advantages would include im- proved opacity on start-up, a much higher turndown ratio (8:1), and improved LOI. (Loss on Ignition) Levet 2 With the furnace operating at an MCR of 154 MWe, the coal/air flows for each burner level are shown in Figure 6. The heat input for each level is shown along with the percentage of the total heat input, the air flow by level, and the stoichiometry. fen 24.230 46.5 25.0 | 351920 | 351.920 420 2 Eastern Kentucky Coot - 12.264 81U/® Figure 6 [— += Con Feed J ae Five Gos PC Block-flow Diagram - Eastern Kentucky Coal, 154 MWe Gross Unit Operating Capacity Page 8 Presented at Power-Gen ‘91 Figure 7 shows the Micronized Coal Reburn Sys- tem with reburn fuel at level 5 and overfire air at level 6. The total heat input has been increased, and thus the operating capacity is shown at a gross MCR of 175 MWe. The units at Shawnee have ex- cess turbine generator capability but may be limited by boiler feed water flow and permitted heat input limits. These issues will be addressed during the operational phase and the benefits of additional capacity will be weighed against current operating criteria. (4) Microf et Systeme (4) Gisting 1-70 Puwenters ie Preneoter FD Fon GROSS UNIT OPERATING CAPACITY 175 MWe furnace Levet lever Level 2 Level 3 Level 4 Level $ Lever 6 Totet Coat, &a/h 25,000 25,000 22,000 21,000 (35.000 128,000 ‘MMBTU be (306.6 306.6 2698 (257.8 429.2 1,570 | Percent of Totot 198 195 72 16.4 a 100 hie, s/he 270.300 270,300 237,900 227,100 48.600 461,800 1,316,000 eam tab l Stoichiometry 1.05 105 105 105 80 11s 11s —e— Aa /tee Gos.PC Eostern Kentucky Cool - 12.264 BTU/ib Figure 7 Block-flow Diagram - Eastern Kentucky Coal, 175 MWe Gross Unit Operating Capacity Page 9 Presented at Power-Gen ‘91 The addition of MicroMill systems will increase total heat input and will allow classifier settings on existing pulverizers to be adjusted for improved fineness relating directly to combustion efficiency and lower LOI. Stoichiometry in the lower fur- nace is maintained at 1.05 (5.0 percent excess air) to assure an oxidizing zone and minimize slagging and corrosion. The stoichiometry at burner level 5, the reburn level, is 0.8 to 0.9 and with the addi- tion of overfire air at level 6, the furnace will have an exiting stoichiometry of 1.15 (15 percent excess air), compared to the current operating condition of 1.21 (21 percent cxcess air). Thus, the micronized coal reburn system not only reduces NOx emissions but also improves boiler efficiency and increases boiler capacity. Process Advantages The following advantages of micronized coal reburning for NOx control compare favorably with other NOx control technologies. * Economical Fuel - Reburning is a recog- nized cffective technology for controlling NOx emissions in a pulverized coal-fired boiler. Most of the reburning activily to date has been with natural gas or oil as the reburn fuel. Although both fuels have demonstrated effectiveness, they are sub- ject to one or more of the following disad- vantages: ¢ Availability, especially in winter ° Unstable/escalating fuel cost ° Operational problems firing dual fucls ° Reduced boiler hydrogen in fuel efficiency due to * Flexibility - The technology is flexible enough to combine with other NOx control micronized coal reburn technologies and reduce NOx emissions to required lower levels. ° Site Specific Benefits ° Reduced energy replacement costs due to improved ability to operate at a rated load even with wet coals and/or equip- ment problems (mills, feeders). ° Reduced capacity costs due to increased power generation. ° Increased fuel flexibility allowing use of lower quality coals while mitigating Page 10 deratings caused by fuel handling limita- tions. ° The ability to operate existing pul- verizers at reduced throughput without loss in capacity will improve coal fine- ness and possibly reduce unburned com- bustible in ash, thus increasing value of the ash as a marketable commodity. ° Improved turndown and stability at low loads without firing supplemental fuels; and maintaining superheater outlet temperatures at low loads. ° Knowledge gained from this demonstra- tion can be used to scale up the Micronized Coal Reburn technology for installation on TVA’s Allen Fossil Plant (330 MWe cyclone fired). NOx Control Strategy A majority of the 300,000 MWe generated by coal- fired utility units will be impacted by the 1990 Clean Air Act Amendments requiring reduction of NOx emissions. It is unlikely that one NOx control method will meet the needs of this diverse boiler population. NOx control strategies fall into two major categories: Combustion modification and post combustion technologies. Combustion modification includes low NOx burners, reburning and fuel air staging. The post combustion options are selective noncatalytic reduction (SNCR) using reagents such as ammonia or urea and selective catalytic reduction (SCR) using both reagent injections and catalysts. In selecting an NOx control strategy for a given unit, utility engineers must weigh many factors in- cluding the type of unit, operating requirements and unit design ratings versus current operating capabilities. Most utilities will probably select some form of combustion modification as their preferred NOx control method. Many utilities, al- ready familiar with pulverized coal burners and burner management systems, will elect to install low NOx burners as the method of controlling the combustion process. There is, however, a large population of utility boilers for which reburning is an attractive option. Wet bottom furnaces such as cyclones and some wall-fired furnaces that operate in a slagging mode are obvious choices for reburning, and the addition of a micronized coal reburn system can be utilized in such diverse applications as start-up, low load Presented at Power-Gen ‘91 operation and restoring lost capacity. Units that operate at very low loads for long periods of time, units that are relegated to cyclic duty, and units that have pulverizer load limitations resulting from fuel switching are all very good candidates for reburning as a primary NOx control method. SUPPORTING ACTIVITIES While the Micronized Coal Reburn system is in a state of technical readiness for full-scale demonstration, there will be several supporting ac- tivities to ensure a high degree of success for the demonstration. Among these activities are furnace cold-flow and computer modeling. The modeling will be conducted in the first phase and will pro- vide even further evidence of adequacy, availability, suitability, and quality of the data and analysis to support the full-scale demonstration. Diagnostic tests will be conducted to determine temperature and velocity patterns in the furnace, supplementing similar previous tests in another unit at the plant with different burner registers. Boiler performance tests will also be conducted providing flue gas flow rate, gas composition, and unburned combustibles. These tests will be used to initiate preliminary design of the rcburn injec- tor/burners and overfire air nozzles. A 1:8 scale cold-flow model will be built to simulate the exist- ing burner windbox assembly, burners and air registers as well as the furnace flow regime, includ- ing the lower and upper furnace past the furnace nose and into the convection section. This flow model will permit determination of the number and location of both the reburn injector/burners and overfire air nozzles. The flow model will com- pare front versus rear-wall locations and also a combination of both. The cold-flow model will be designed, fabricated and tested at R-C’s Fluid Dynamic Laboratory. With the cold-flow model existing windbox, burner and furnace flow patterns can be observed. In addition, the model will pro- vide an easy, convenient model to vary the number and location of the reburn injector/burners, over- fire air windbox, and nozzlcs to assure dispersion and mixing of the micronized coal in the reburn zone and the overfire air in the burnout zone. The cold flow model will also be available during Phase 3 of the test program in the event any fine tuning of the reburn system is required. The computer modeling of the furnace will provide not only screening for the cold-flow model but also predict reburn system performance on the furnace and Page 11 boiler as well as the effect of heat release and mixing in the reburn zone. Once the flow and mixing characteristics have been determined from the modeling activities, the reburn injector/reburner will be designed. The design will accommodate these flow characteristics while achieving local mixing of the micronized coal-air stream from the injector to achieve com- bustion at a prescribed fuel-rich condition (0.8 stoichiometry) as well as a micronized coal burner at normal fuel-lean condition. The latter condition is desired to achieve a high turndown ratio or as a conventional burner in the event that the conven- tional pulverizers are out of service. A single micronized coal injector/burner will be tested in R-C’s Test Simulator. These supporting activities will then be utilized for the overall system design for the full-scale demonstration. MICRONIZED COAL TECHNOLOGY Technology Description The technology described in this paper is a com- bination of a technology that produces micro-fine coal reliably and economically, with a known NOx control technology (fuel reburning). | When micronized coal is fired at a stoichiometry of 0.8 to 1.2, devolatilization and carbon conversion occur rapidly. Micronized coal is defined as coal ground to a particle size of 43 microns or smaller. The Micro- Fuel System, consisting of the MicroMill and an external classifier, micronizes coal to a particle range of 10 to 20 microns. Figure 8 displays a typi- cal particle distribution curve. Finished Particle Size Field Data 8 9,800 Ib/hr - 132 kw 8 &8 8 Percent Less Than 2 3 i 55 Micron Size 176 135 8 2 H Duke Power Cliffside Staton Parncle Anaivsis - l’enn State University Mictotrac (SRA - Model) Figure 8 39 28 19 14 Presented at Power-Gen ‘91 For a given volume of material, the surface area doubles for every three (3) micron reduction in mean particle diameter. Figure 9 shows the relationship between particle diameter/particle The combined surface area of just one gram of micronized coal particles is 31 square meters, con- trasted to a surface area of 2.5 square meters per gram for pulverized coal. count versus a given volume. i / The heart of the MicroFuel System is a patented centrifugal-pneumatic MicroMill, with only one moving part, the replaceable rotating impeller. Size reduction is accomplished, not by pressure crushing or hammer impacting, but by the particles themselves striking against one another as they \verage Pulverized Coal Particle Size Average Micronized Coal Particle Size 60 um 20um h whirl in a tornado-like column of air inside the ClO O1Ol@ Mi ; ; : eat icroMill. Centrifugal force retains material in O0000 | the rotational impact zone (RIZ) as the particles OO0000 reduce in size prior to being conveyed by the air O0000 | stream entering the center of the rotating impeller. OO0000 {Figure 10 is a sectional view of the MicroMill and OO : Figure 11 is a cut-away view of the MF-3018 | particle, 600 um diameter 27 particles, each 20 um diameter MicroMill. Volume = 0.90x10* cu. in Volume = 0.90x10* cu. in | Area = |.75x10° sq. in. (one particle) Area = 5.26x10° sq. in. (27 particles) j Figure 8 Micronized and Pulverized Coal Particle Size Comparisons Wey MMi Motor Impeller Rack plate Cerame Lined Scroll Replaceable Blade BELT DRIVEN SHAFT ——_ UPPER BEARING SET Discharge to Classifier LOVER RADIAL BEARING Pivot Point ACEABLE BLADES BACKPLATE CERAMIC TILE ° Coal and Primary Air inlet pact fina CONE CASTING MILL INLET Discharge Figure 10 Figure 11 Sectional View of MicroMill Cut-Away View of MicroMill Page 12 Presented at Power-Gen ‘91 Material entering the impeller is swept out of the MicroMill to the classifier, which separates par- ticles by size. Micronized coal particles below 43 microns are discharged directly to the burners, and larger particles are returned to the MicroMill for further size reduction. Figure 12 is a dimensional elevation of a complete MicroMill system. TEMPERING AiR C> iD CLASSIFIER iSO HP MF = 3018 MICROMILL TRAMPIRON N) GATE L Taunt Because of its simple design, the MicroMill is easy to operate and maintain. For a given amount of energy, it produces significantly more surface area for combustion than conventional coal pulverizers. The micronizing process produces a dramatic in- crease in the surface area per weight of coal, resulting in a more stable, controllable combustion reaction. All chemical reactions, including com- bustion, require that the surfaces of different sub- stances come in direct contact. The rate of any chemical reaction varies predictably, based on the nature of the substances involved and the condi- tions, such as temperature and pressure, under which the reaction takes place. But in any case, it is directly proportional to the size of the contact area between the substances involved in the reac- tion. In combustion, these substances are the fuel and the combustion air. pls Ma le’ 1 578° HATE Figure 12 Dimensional Elevation, General Arrangement, MF-3018 MicroMill System Page 13 Presented at Power-Gen '91 o : i = z = xy 4 5 200+ < | & 2 | z | 6 3 | ¢ } 4 g oh Fett 6085 spew 325 mes Font 215% rs 325 mean 12 3 4 STOICHIOMETRIC RATIO Figure 13 Effect of Excess Air and Coal Size on NOx Emissions The net result of this reaction is a uniform com- pact combustion envelope allowing for complete combustion of the coal/air mixture in a smaller fur- nace volume than conventional pulverized coal. Heat rate, heat flux, carbon loss, and NOx forma- tion are all impacted by coal fineness. ENVIRONMENTAL ASPECTS With the exception of significant reductions in NOx emissions, the environmental impact of the proposed project is inconsequential. As a result, no new permits or licenses will be necessary to im- plement the proposal. Application of the Micronized Coal Reburn system is projected to reduce NOx emissions by 50 to 60 percent on a mass basis, from 1,943 tons/year to 874 tons/year, based on a capacity factor of 40 percent. Shawnee currently burns low-sulfur Appalachian coal (1.195 Ib $02/10° Btu). Lower-sulfur western coal (0.35 Ib $O2/10° Btu) will be burned briefly as part of the demonstration. During that period, SO2 emissions will be further reduced. The use of eastern low-sulfur coals with reduced grindability has made the existing pulverizers marginal. Equip- ment problems or wet coal will result in further derating of the unit. The introduction of Micronized Coal Reburning as an additional fuel will allow Shawnee to overcome mill limitations and operate at somewhat higher capacity factors. This may result in a slight increase in total emis- Page 14 3155 | Zone sf Zone 4+ 34125 | = Zone 3+ 7 95 3 3726 = 57 6 Zone 2+ 2 = as § Zone 1 = ——— Test 1 — 60% thru 325 Mesh 10 —— Test 2 — 75% thru 325 Mesn , 40 Heat Flux (kKBTU/HR-FT.) 30 50 60 70 80 Figure 14 Effect of Coal Size on Furnace Icat Flux sions on a mass basis, but emissions concentration will remain unchanged. Reduction/Control of Greenhouse Gases and Air Toxics No significant changes in the emissions of green- house gases or air toxics are projected. A minor increase in the emissions of CO and hydrocarbons may occur at times during the demonstration as parametric testing may occasionally result in slight- ly less than complete combustion. However, exist- ing pollution control equipment should be able to maintain emission levels within regulatory limits. Emissions monitoring will be performed to ensure continued compliance. No new waste products will be generated by the Micronized Coal Reburn process, as no reagents are utilized. Existing requirements for fly ash and bottom ash disposal are expected to remain con- stant. Current water usage by the unit averages 3.1 million gallons per day for ash sluicing, and no change is projected for the purposes of the demonstration. Average fly ash particle size will decrease slightly, but existing baghouses will effi- ciently collect fly ash. EHSS Compliance/Risk and Impact Since this demonstration will cause no significant increases in emissions, TVA has applied for and Presented at Power-Gen "91 expects to receive a categorical exclusion. Emis- sions will remain within permitted limits. No risks or adverse impacts to human and animal health and safety or to geographic features are an- ticipated. It is predicted that the objective of this demonstration, reduction of NOx emissions, will be the only significant environmental effect. No im- pacts on land or water quality are anticipated ex- cept as a modest reduction in precursors to acid rain formation. The primary socioeconomic effect of this project is expected to be favorable: the demonstration of a high degree of NOx reduction at relatively low costs. No significant changes in personnel require- ments or operating inputs at the plant are projected. PREOPERATIONAL AND TESTING OPERATIONAL Pre-operational testing will be conducted to in- clude characterization of various aspects of the system, particularly the newly designed com- ponents. Parametric testing will document the ef- fect of the following reburn system variables: * Primary burner zone stoichiometry * Reburn zone stoichiometry * Final (burnout zone) stoichiometry * Reburn zone momentum * Micronized coal consumption in main burners * Reburn fuel particle size * Reburn zone injection with flue gas recir- culation Load * Coal composition . This data will permit the determination of optimal conditions for achieving various levels of NOx reduction, boiler efficiency, operating and main- tenance requirements. Long-Term Testing Boiler performance with the reburn system will be documented over a three-year period to identify long-term trends in emissions and boiler behavior. Monitoring of flue gas will be by a Continuous Emissions Monitor (CEM). The objective of all monitoring functions will be to assess: Page 15 * NO, NO2, O2, CO, CO2, and SO2 emis- sions * Particulate emissions * Emissions during transients * Unburned carbon in flue gas and fly ash * Pulverizer/mill performance * Coal flow rate and size distribution * Air preheater performance * Boiler slagging and fouling * Waterwall and convective pass corrosion * Furnace temperature profile * Boiler thermal efficiency * Combustion system reliability * Boiler load response All CEM and boiler operation signals which can be efficiently monitored in real time will be direct- ly stored on disk. The database will permit ready and efficient reduction and analysis of the data, both during execution of the program and during final analysis and evaluation. Information from the long-term test will permit evaluation of system ef- ficiency and reliability under real conditions. Also, the extended operating period will provide data for projecting economic impacts. CONCLUSIONS TVA has a strong history of leadership in the development of new and emerging technologies and the performance of successful R&D programs. TVA believes that this nitrogen oxide emission control technology shows sufficient benefit to its own system as well as the utility industry in general to take the leadership position in sponsoring a Micronized Coal Reburn Demonstration. The combination of micronized coal supplying up to 30 percent of the total furnace requirements and reburning for NOx control will provide flexibility for significant environmental improve- ment without adding higher operating costs or fur- nace performance deratings normally associated with environmental controls. By meeting the objectives of this important coal reburning project, coal will be shown to be its own best friend in controlling NOx emissions and providing economical power to the public well into the future. Presented at Power-Gen ‘91 Attachment A Reburn Technology for Boiler NOx Control by R.W. Borio of Combustion Engineering, Inc., R.E. Hall of U.S. Environmental Protection Agency, R.A. Lott of Gas Research Institute. A. Kokkinos of Electric Power Research Institute, and S. Durrani of Ohio Edison. Presented at the 6th Annual Coal Preparation, Utilization and Environmental Control Contractors Conference. An Evaluation of Naturai Gas Cofiring for Emissions Control on a Coal-Fired Boiler by P.K. Vitta. S.M. Wilson, M.T. New- ton, M.D. Conner of Souther Company Services, Inc. Presented at the ASME International Joint Power Generation Conference 1990. Preliminary Study of the Effects of Natural Gas Co-Firing on Coal Particle Combustion by A.R. Schroeder, D.A. Thompson, H. Krier, J.E. Peters and R.O. Buckius of the Department of Mechanical and Industrial Engineering, University of Illinois. Results of Combustion Modification for the Reduction of NOx Emission by K.R.G. Hein and G. Jager of RWE Energie AG. Germany, Presented at the Joint ASME/IEEE Joint Power Generation Conference, 1990. New Steam Generators with Low NOx Pulverized-Coal Firing by K. Straub and F. Thelen, of Steag AG, Germany, Presented at the Joint ASME/IEEE Power Generation Conference, 1990. Review of Research Activities on Pulverized Coal Firing Systems by F. Adrian of L&C Steinmuller GmbH, West Germany. Presented at the Joint ASME/IEEE Power Generation Conference, 1990. Pilot Scale Process Evaluation of Reburning for In-Furnace NOx Reduction by J.M. McCarthy, B.J. Overmoe, S.L. Chen, W.R. Seeker and D.W. Pershing of Energy and Environmental Research Corporation, Irvine, California, Presented at the Joint ASME/IEEE Power Generation Conference, 1990. Micronized Coal Technology: Process & Potential Applications by Allen C. Wiley of MicroFucl Corporation. Ely, lowa. presented at the 4th Annual Pittsburgh Coal Conference, 1987. Micronized Coal for Boiler Upgrade/Retrofit. Duke Power Coal Start-up Tests by A.C. Wiley of MicroFuel Corporation. T. Rogers and M. Beam of Duke Power Company, and L. Berry of Peabody Engineering Company, Presented at Gen-Upgrade 90. Micronized Coal for Boiler Upgrade/Retrofit. Duke Power Coal Start-up Tests, Update and Results by A.C. Wiley of Micro- Fuel Corporation, T. Rogers and M. Beam of Duke Power Company, and L. Berry of Peabody Engineering Company, Presented at Power Gen Conference, 1990. Technical and Economic Feasibility for the Application of Micronized Coal as a Replacement for Number 2 Oil for Start-up and Low-Load Operation at Illinois Power Havana #6 Cycling Unit by F. Rosenberger of Illinois Power Company, C.J. Guil- foyle of Sargent & Lundy, and W.O. Parker, Jr. of MicroFuel Corporation, presented at American Power Conference, 1991. Bench and Pilot Scale Process Evaluation of Reburning for In-Furnace NOx Reduction by S.L. Chen, J.M. McCarthy, W.D. Clark, M.P. Heap, W.R. Seekez, D.W. Pershing, Twenty-First Symposium (International) on Combustion, The Combustion In- Stitute, 1986, p.1159-1169. Process for the Disposal of Nitrogen Oxide by R.D. Reed of John Zink Company, U.S. Patent 1,274,637, 1969. Fourteenth Symposium (International) on Combustion, p. 897, by J.O. Wendt, C.V. Sternling and M.A. Matovich, The Combus- tion Institute, 1973. Sixth Symposium (International) on Combustion, p. 154. by A.L. Myerson, F.R. Taylor and B. Faunce, The Combustion In- stitute, 1957. Development of Mitsubishi “MACT” In-Furnace NOx Removal Process by Y. Takahashi, et al., presented at U.S.-Japan NOx Information Exchange, Tokyo, Japan, May, 1981. Evaluation of In-Furnace NOx Reduction by S. Miyamae, H. Ikebe and K. Makino, Proceedings of the 1985 Joint Symposium on Stationary Combustion NOx Control, 1986. Three-Stage Pulverized Coal Combustion System for In-Furnace NOx Reduction by N. Okigami, Y. Sekiguchi, Y. Miura. K. Sasaki and B. Tamaru, Proceedings of the 1985 Joint Symposium on Stationary Combustion NOx Control, 1986. Three Stage Combustion (Reburning) on a Full Scale Operating Boiler in the USSR by R.C. LaFlesh, R.D. Lewis and D.K. Anderson of Combustion Engineering, Robert E. Hall of US EPA, and V.R. Kotler of All Union Heat Engineering Institute (VTI), Moscow, USSR, Presented at the Joint EPA/EPRI Symposium on Stationary Combustion NOX Control, 1991. Comparisons of Micronized Coal, Pulverized Coal and No. 6 Oil for Gas/Oil Utility and Industrial Boiler Firing by E.T. Robinson of Advanced Fuels Technology Company, Oliver G. Briggs, Jr. of Riley Stoker Corporation, and Robert Bessette of IES, presented at the American Power Conference, 1988. Reburn Technology for NOx Control on a Cyclone-Fired Boiler by RC. Booth of Energy Systems Associates, R.E. Hall of US EPA, R.A. Lott of GRI, A. Kokkinos of EPRI, D.F. Gyorke of DOE-PETC, S. Durrani of Ohio Edison, HJ. Johnson of OCDO, J.J. Kienle of East Ohio Gas; R.W. Borio, R.D. Lewis, M.B. Keough of ABB Combustion Engineering, Presented at the Joint EPA/EPRI Symposium on Stationary Combustion NOx Control, 1991. Page 16 Technical Paper Technical and Economic Feasibility for the Application of Micronized Coal as a Replacement for Number 2 Oil for Start-up and Low-Load Operation at Illinois Power Havana #6 Cycling Unit Frank Rosenberger Illinois Power Company Havana Station Havana, Illinois 62644 Charles J. Guilfoyle Sargent & Lundy 55 East Monroe Street Chicago, Illinois 60603 William O. Parker, Jr. MicroFuel Corporation 1205 State Street Ely, lowa 52227 P/4) FULLER:MPD “ MINERALS PROCESSING DIVISION ‘A member of the F.L_Smidth-Fuller Engineering Grou FULLER COMPANY 2040 Ave. C, LVIP * Bethlehem, PA 18017-2188 Telephone: (215) 264-6900 FAX: (215) 264-6441 © Telex: 173189 AMERICAN POWER CONFERENCE Chicago, Illinois April 29 - May 1, 1991 Proceedings or ABSTRACT Uncertainty regarding oil availability and long- term price stability make it difficult for a utility to predict annual ignition costs for a cycling unit. Illinois Power Company, Sargent & Lundy Engineering and MicroFuel Corpora- tion have produced a feasibility study on the application of micronized coal as a replace- ment fuel for start-up and low-load operation for Havana No. 6. This unit is a B&W op- posed-fired boiler which is rated at 410 MWe (summer net). This paper presents a technical and economic analysis, including the uncer- tainties of the application of this technology. INTRODUCTION Objective The objective is to determine economic benefit, application of the technology and potential technological risks associated with the application of micronized coal as a re- placement fuel for no. 2 oil utilization at Havana Power Station, Unit No. 6. Motivation and Background The development of micronized coal tech- nology began about 10 years ago with a test firing at Gulf States Utilities to fire micronized coal in a boiler designed for gas firing.’ This is the period when coal-oil and coal-water mixtures were being developed for the conversion of gas and oil boilers. This was significant because at that time it was believed that coal with a particle size of < 98% passing a 325 mesh screen was needed to burn coal directly in gas/oil boilers. Since then, it has been shown the particle size needed for conversion of oil and gas units need only be, on the order of 80% to 90% < 325 mesh.” Micronized coal is nor- mally defined as any coal pulverized to a the American Power Conference minimum fineness of 80% passing 325 mesh (43 microns). New pulverizers like the MicroFuel System have been developed to produce this size range product economical- ly. Combustion testing in test furnaces and full-scale power plants have proven the validity of 80% passing 325 mesh to be a very acceptable particle size for combustion of micronized coal.2>* A major motivation for the consideration of coal as a source for start-up and low-load operation is the rapid escalation of oil prices in 1990 and the instability of the oil market due to world-wide pressures. With no. 2 oil costs delivered to Havana at $7.60/MMBtu and delivered coal cost of $1.46/MMBtu, it was prudent to consider the long-term savings possibilities which may be generated by using less expensive coal as a replacement for no. 2 oil. To date, there has not been a technology which has shown the potential for success that the MicroMill system has shown. HAVANA NO.6 GENERATING STATION - Equipment Havana No. 6 Power Station consists of a B&W, pulverized coal, opposed-fired balanced-draft furnace. The unit is designed for constant and variable throttle pressure operation and a bypass system to permit cyclic operation. The furnace is designed with a full division wall and 40 dual register burners located in compartmented windboxes in the front and rear walls. Each burner compartment contains a 13 MMBtu/hr air atomized no. 2 oil igniter. Figure 1 is a side elevation drawing of the Havana No. 6 unit. Five B&W MPS-89 pulverizers are included for grinding the Illinois Basin design coal or alternative western subbituminous coal and eastern bituminous coal. Four pulverizers Page 1 ILLINOIS POWER COMPANY HAVANA POWER STATION— UNIT NO 6 HAVANA, ILLINOIS B&W CONTRACT NO RB-540 Figure 1 are sufficient to carry full load on either the Illinois Basin or eastern coals; however, all five are needed when western coal is used. Each of the five pulverizers supplies eight burners. Except for the bottom row of burners, all eight burners are in a common compartmented windbox on one wall. The fifth pulverizer is split with four burners in each of two compartmented windboxes on the front and rear walls. All eight burners are usually fired together; however, for start- up and emergency reasons it is possible to fire only four burners. Each compartmented windbox and pulverizer entrance is equipped with meters and dampers to measure and control air flow to minimize excess air at most loads. Power Conrerence Maximum continuous rated capacity (MCR) of the unit is 3,243,000 pounds of steam per hour at 1965 psi superheat outlet pressure and 1005/100S°F superheat/reheat terminal temperatures. Steam temperature control is primarily accomplished by the use of excess air distributed through the burners. The boiler supplies an Allis-Chalmers steam tur- bine rated at 447 MWe at 1000°F, 1800 psi throttle conditions. System Operation Havana Unit No. 6 is operated to take full advantage of the design flexibilities built into the systems. The unit is operated in the cy- cling mode with over 1770 starts since 1978. This unit is capable of operating at a low load of approximately 72 MWe, ap- proximately 20% MCR on coal, without oil. This allows for rapid starts and minimizes the amount of no. 2 oil consumed during starts. As a result, this unit operates over its full capacity range from 72 MWe to 447 MWe gross generation on a regular basis. Actual maximum net capacity is limited to 410 MWe and 420 MWe summer and winter genera- tion, respectively, due to mechanical cooling tower limitations. The flexibility of unit no. 6 to generate from 72 MWe to 420 MWe (net) is a definite benefit for system load balancing with low cost coal. During the last full load heat rate test, unit 6 operated at a unit heat rate ranging between 10,500 and 10,600 Btu/Kwh. The last low- load test at a load of 90 MWe (72 MWe net) indicated the heat rate of the unit was 14,181 Btu/Kwh. During the low load test with the burner arrangement as is, it was possible to maintain an excess air level of about 12.9%. However, when the unit is operated at lower loads and during start-up, 20% total air is re- quired to maintain unit operation. As a result, the unit operates with excess air levels on the order of 200% to 300% until the coal burners can be brought on line. During Page 2 Proceedings or the American Power Conrerence these times much of the Btu input to the unit is used to heat air and unit heat rates can be well above 15,000 to 16,000 Btu/Kwh. This has been taken into consideration with the evaluation of the application costs of the oil and coal. Fuel Utilization The Havana No. 6 unit currently burns either eastern or western compliance type coal (1.2 Ibs S02/MMBtu) to meet emission regula- tions. Both coals have been evaluated; how- ever, for purposes of this presentation only the eastern coal will be discussed. Table 1 shows a brief description of the eastern coal and no. 2 oil used for the evaluation. In- cluded are some basic parameters used in the performance calculations, a calculated ef- ficiency and the simple application cost com- parison used for determining the relative cost of the two fuels. For purposes of this evalua- tion, coal and oil storage, handling and in- ventory costs have been considered as ap- proximately equal and have not been con- sidered. Sootblowing costs also have not been considered due to insignificant amounts of flyash and its very small particle size char- acteristics. Although there should be no need for sootblowing during start-up on micronized coal, it is required that air prehea‘ers be blown continuously whenever oil is used for start-up or ignition. This has not been included as an oil use cost. ILLINOIS POWER MICRONIZED COAL/#2 OIL COMPARATIVE SUMMARY COMPARISON MICRONIZED COAL # 2 OIL FUEL CHARACTERISTICS MOI. 6.86 0.0 ASH 8.43 0.0 VOL. 37.00 100.00 BTU/# 12.708 19,680 BTU/GAL os 140,000 OPERATING CONDITIONS EXCESS AIR 236% 241% CARBON LOSS 0.3% 0.0% AH EXIT TEMP. COMBUSTION EFF. 230 F 62.90% 230 F 81.39% APPLICATION COSTS $_/ MMBTU $_/ MMBTU FUEL COST DEL. $1.460 $7.600 APPLICATION COSTS: COMB. EFF. $0.301 $1.738 STOR, HAND & INV 0.000 0.000 ASH HAND & DESP 0.010 0.000 AIR/FLUE GAS HAND 0.264 0.265 MICRONIZATION 0.081 0.000 SOOTBLOWING 0.000 0.000 SUBTOTAL $0.656 $2.903 TOT. APPLICATION COST $2.116 $9.603 Table 1 Other than combustion efficiency (based on heat loss method of calculation), the highest application cost factor for the fuels is the cost of air and flue gas handling. These numbers are based on the horsepower per 1000 CFM of air and flue gas at ambient air temperatures and the flue gas exit tempera- ture used for calculating boiler efficiency. Decreases in fan efficiency for low-load operation were not considered. As can be seen from Table 1, this difference between coal and oil turned out to be small, but was included since it is such a large factor in the total cost. The only other factors having a significant impact on the coal/oil differential are coal micronization and ash disposal. Coal micronization costs are based on the ac- tual horsepower per ton experienced at Duke Power’s Cliffside Station. Ash handling and disposal costs are based on $2.50 per ton ash for the plant. Based on these numbers, the cost of using no. 2 oil at the Havana No. 6 Unit is about $9.60/MMBtu, whereas the cost for using micronized coal is projected to be about $2.12/MMBtu — a. savings of $7.48/MMBtu. Start-Up Operations Table 2 is a summary of the no. 2 oil utiliza- tion at the Havana No. 6 Unit over the last 13 years. Illinois Power separates the num- ber of starts into two categories: the cold start (when the unit is off line for more than Page 3 Proceedings of the American Power Conrerence 24 hours), and the hot start (when the unit is off line for less than 24 hours). Different procedures are used for both start-ups. During a cold start, two different burner compartments with 16 burners are used and the total start takes about 2.5 hours. During a hot start, only eight burners are used and the start takes only about 1.5 hours. Each oil burner has a heat input capability of 13 MMBtv/hr. Plant records indicate there were 440 cold starts and 1337 hot starts over the period from January 1978 through September 1990. The average number of starts was looked at over the last 10 years and the last five years to see what changes may have occurred in unit operation. As a result, the average of 33 cold starts and 124 hot starts per year over the last five years was selected as typical of what might be expected in the future. The average start-up time was 2.8 hours for cold starts, and 1.5 hours for hot starts. Utiliza- tion of 16 burners during cold starts was ap- parent from the oil utilization rate (average gallons per hour) for the different starts — 1540.6 for cold and 773.4 for hot. Estimating the amount of time a MicroMill could operate, it was determined there could be a total of 270 hours per year operation at 108 to 110 MMBtu/hr heat input rate. Of the total hours possible, 90 would be cold starts at a 50% firing rate on coal, and 180 would be hot starts at 100% of the needed firing rate. During these starts, the only oil used would be that for ignition of the micronized coal. Following ignition, oil is turned off and no pilot is maintained. With the MicroMill capable of 5 tons per hour coal capacity, there would be an additional 12% micronized capacity usable during the start-up process to decrease the start-up time, if needed. This has not been con- sidered further herein. ILLINOIS POWER HAVANA NO. 6 OIL UTILIZATION COLD STARTS HOT STARTS TOTAL NO. STARTS 440 1337 1/78-9/90 AVG NO./YR. (10 YRS) 35 105 AVG NO./YR. (5 YRS) 33 124 AVG HRS./START 2.8 1.5 AVG TOT.HRS./YR. 90 180 AVG GAL./HR. 1540.6 773.4 AVG MMBTU/HR. 215.7 108.3 Table 2 Based on the amount of oil consumed and the relative costs of application, an annual savings of about $161,000 per year is projected if micronized coal is used as a re- placement fuel for no. 2 oil delivered to the plant at $7.60/MMBtu (about $1.06 to $1.10 per gallon). Table 3 provides a simple sum- mary of the costs and benefits obtained from the information contained within Table 1 and Table 2. ILLINOIS POWER ECONOMIC EVALUATION SUMMARY 1 MICRONIZER OPERATING AT APPROX 110 MMBTU/HR MICRONIZED COAL No. 2 OIL ANNUAL FUEL USAGE: 829 TONS/yr. 150.813 Gal/yr. START-UP OPER 4.30 T/hr. 773.4 Gal/hr. ANNUAL OPERATING HRS 195 hrs/yr. 270 hrs/yr. @ 110 MMBTU/HR TOT. ANNUAL COST: $62,500 $285.000 FUEL & OPER ANNUAL DIFFERENTIAL: ($222.500) =0 Table 3 MICROFUEL MICROMILL Figure 2, the MicroFuel MicroMill, is a general arrangement drawing of the com- plete mill system, including: © Turbo blower for delivering air and moving coal through the system to the burners ¢ MicroMill, a pneumatic/centrifugal microniza- tion unit with only one moving part not directly impacted by the coal © Centrifugal classifier with no moving parts. Page 4 Proceedings of the American Power Conference Figure 2 The operation of the MicroMill is based on particle-to-particle attrition generated by a rotating impeller producing air flow patterns within the mill inducing particle-to-particle collisions. There are no conventional grind- ing hammers or rollers to wear out in the mill. Coal particle size is maintained at the desired fineness by the external classifier. There is no deterioration of fineness as parts wear. Although not required for operation of the system, there are benefits from both a combustion and mill capacity standpoint if hot primary air is supplied to the MicroMill. System operation may best be described through a brief summary of the Duke Power operations test. Duke Power Tests During the last year, over 3000 tons of coal have been micronized at the Duke Power Cliffside Generating Station Unit No. 5. This coal has been used as replacement fuel for two of the four oil start-up guns in a CE tangential-fired 600 MWe boiler, both during Start-ups and load operation in order to gain operating time and coal throughput for operating information. The micronized coal system has proven useful. Following one outage, the unit was brought on line with only micronized coal and the side pilot ig- niters. (In this case, the auxiliary boiler needed to supply atomizing steam was not available.) Although longer than usual, the start was successful. Over the micronizer operating hours logged, an average capacity of approximately 4.5 tons/hr was maintained. An average system energy consumption of approximately 28 KW/ton of coal was achieved. Micronized coal fineness was confirmed at 90% passing 325 mesh with an average particle size < 22 microns. After 3000+ tons of coal through- put and over 670 hours of operation, erosion on the impeller blades indicated the poten- tial for another 2000 to 3000 tons microniz- ing capability — the total equivalent of five or six years start-up operation at the Havana Station. Improved impeller blades have been installed. These will significantly improve impeller life. MICRONIZED COAL BURNERS AND APPLICATION The application of the MicroFuel MicroMill to Havana No. 6 is in many respects similar to the Duke Power installation. The only major difference is the burner design and ar- rangement. At Duke, Peabody Engineering designed a burner to fit in the existing CE tangential burner oil gun bucket. For pur- poses of this evaluation, it was assumed that a small diameter coal gun could be developed to replace the 13 MMBtu/hr B&W oil guns at the “D” level. Operation of the burner would require ignition by the current igniters. However, once the boiler flame safety system indicates ignition, the oil igniters would be turned off and the remainder of the start carried out on coal. The most difficult or uncertain aspect of ac- tual unit conversion may be the burner. To minimize cost, complete new burners were not considered in this study. Before any decision to actually convert the unit to micronized coal would be made, burner Page 5 Proceedings or design would be completed and tested. All indications from the Duke Power operation and previous combustion testing point toward probable success. Currently there is no direct micronized coal igniter available in the industry. MicroFuel Corporation is working to develop a dilute phase micronized coal igniter technology which will expand and simplify the applica- tion of micronized coal to the utility and in- dustrial markets. These igniters would be small in diameter, capable of fitting within existing igniter ports for conventional burners, and provide zero oil operating capability for any unit. In addition to start- up and warm-up service, these _ ig- niter/burners could also provide for con- tinuous operation for load stabilization and capacity recovery due to coal quality or con- ventional pulverizer performance deteriora- tion. Test work will begin within the next six months at the MicroFuel Corporation Ely test facility. Ely Test Facility MICROMILL SYSTEM DESCRIPTION AND CAPITAL REQUIREMENTS Figure 3, MicroMill system sketch, is a simple layout diagram of the addition of one MicroMill located adjacent to one of the stock feeders and under the coal silo. Coal is fed from a bunker side opening above the stock feeder to a screw conveyor to the MicroMill system. Hot primary air is ducted the American Power Conrerence from windbox to the high-temperature inlet of the turbo blower supplying primary air for the MicroMill and classifier. Two splitters are installed on the classifier outlet lines. Four separate streams of micronized coal are generated from each splitter and piped to each of the four burners on each of the two levels in the compartmented windbox — a total of eight burners. Table 4 is a summary of the capital costs for the Havana No. 6 addition. Total capital costs for the complete system installed at the feeder floor elevation and supplying eight burners on the “D” level are projected to be approximately $900,000. There are no major uncertainties or problems which could create undue cost overruns for the application. COST SUMMARY REPORT DESCRIPTION EQUIPMENT MATERIAL LABOR TOTAL MECHANICAL 480,000 -—=«*92,200 73,700 646,600 STRUCTURAL 1,500 5,700 7,200 ELECTRICAL 69,300 $5,600 125,100 ~"""qotaL—~«480.000-—=—«*163,700 135,200 778.900 INDIRECT, OTHER & CONTINGENCY 121,100 TOTAL ESTIMATED CONSTRUCTION COST $ 900,000 Table 4 As mentioned previously, the only unproven system component is the micronized coal burner. However, based on experiences at Duke Power and the MicroFuel test facility in Ely, Iowa, application of similar burners to Page 6 Proceedings or the american Power Conference the Havana unit should be successtul. No other technical uncertainties are seen which could result in a major change in the above cost estimate. ECONOMIC FEASIBILITY With an installed capital cost of approximate- ly $900,000 and an annual savings of ap- proximately $161,000 per year, a simple payback of about 5.6 years can be projected. Detailed financial evaluations were carried out, and the following is a brief summary of those evaluations: Evaluation Assumptions The following is a listing of the primary evaluation assumptions used to calculate the economic value of this project: Capital Costs $900,000 Start-up Heat Rate (Btu/Kwh) 15,000 Annual Start-up Hours 270 Oil Displacement (MMBtu/hr) 110 Annual Maint. Cost (% Capital) 1.50 Maint. Cost Escalation (%/yr) 4.50 Applied Coal Cost ($/MMBtu) 2.12 Coal Escalation (%/yr) 5.30 Applied Oil Cost ($/MMBtu) 9.60 Oil Escalation (%/yr) 8.40 After Tax Discount Rate (%) 10.12 30 yr Levelized Fixed Chg Rate (%) 15.90 Using these parameters, the present value net rate of return was calculated over a 30- year period. A cumulative present value of net rate of return was also calculated to determine the projected discounted payback period. As a limited sensitivity analysis, these evaluations were run for three different cases where the applied oil cost was varied by +/- $1/MMBtu. This would be equivalent to approximately +/- $.14/gallon on a dollar- per-gallon basis for 140,000 Btu/gal no. 2 oil. Economic Results The economic evaluations for the base case indicate a discounted payback period of ap- proximately five years and a net present value over the life of the evaluation of $4,700,000. Although there are many uncer- tainties which could affect these values, there are two which could have a significant im- pact. The first is the actual delivered price of no. 2 oil to the Havana facility. The second is the number of start-up/warm-up cycles the no. 6 unit will experience each year and how long oil will be used during these start-ups. ILLINOIS POWER MICROFUEL Vs. OIL -- OIL COST SENSITIVTY OCF PAYBACK ( YRS) 8 — 86 76 86 96 106 Ts 12.6 APPLICATION COST OF NO. 2 OIL 5.16 5.91 6.78 7.6 8.41 9.22 10.03 *DELIVERED COST OF NO. 2 OlLe Figure 4 The uncertainty regarding the delivered oil price at the Havana Station was addressed. Using the costs from Table 1, the total ap- plication cost of the no. 2 oil was varied +/- $1/MMBtu from $9.60 to $10.60 and $8.60. From this information a trend line was plotted to identify the project discounted cash flow payback sensitivity to the applica- tion cost of no. 2 oil at the plant. Figure 4 is a graph representing the discounted payback years over the application cost range con- sidered. The respective delivered oil cost figures are also included to provide a better understanding in normal terms. Table 5 gives a comparison of the oil cost at Havana in terms of $/gallon, $/MMBtu and applied cost $/MMBtu for oil with a heating value of 140,000 Btu/gal. Page 7 ILLINOIS POWER OIL PRICE COMPARISON $/GalDe) $/MMBTUDej $/Mi Al 0.61 4.35 5.60 0.72 5.16 6.60 0.83 5.91 7.60 0.95 6.78 8.60 1.06 7.60 9.60 117 8.41 10.60 1.29 9.22 11.60 1.41 10.03 12.60 S/gal delivered based on 140,000 btu/gal ILLINOIS POWER Oil: $/MMBTU, $/Gal & Appl, $/MMBTU Ou (s/muMeTUD $/Galion j “ | 428 11.16 — \2 | — js 9.16 - - _——_ _ 1 7.16 os 6.16 a 0 616 666 616 666 7.16 816 866 916 966 Delivered Co: jo. 2 OW —— APPLICATION COST — EQUIVALENT $/GAL Table 5 Based on past experience, it is believed the number of starts should remain fairly stable over the next 5 to 10 years. It is possible, with lower cost start-ups, it may be ad- vantageous to increase the number of times the unit is cycled during the course of a year; however, this was not taken into considera- tion. The possibility of operation at load levels down to station demand (i.e., zero net output) was considered; however, the cycling capabilities of unit 6 virtually eliminated any benefit and further consideration. Lower load operation was not pursued. With the expected stability of operation scheduling, a sensitivity to operating hours was not run. Increased operating time would increase the MicroMill operating benefits. SUMMARY AND CONCLUSIONS Under the current economic environment, Il- linois Power is generally limiting investments to those which will show a discounted payback of three years or less. From this evaluation, the discounted payback was shown to be 4.95 years. Under a “normal” economic environment where a 10-year dis- counted payback is the typical criteria for Proceedings of the American Power Conrerence making investment decisions, this project would show significant merit. From Figure 4, all indications are when the price of oil rises to a level on the order of $10/MMBtu ($1.40/gal) delivered, a 3-year discounted payback may be reached. Future oil price uncertainty and availability could change how this project is viewed. The overall technology application is simple and has a very high probability of success. Fur- ther investigations into the burner design and application are under way along with a re- evaluation of the price of no. 2 oil over the long term. Pending the outcome of these evaluations, a decision to install the Micro- Mill System could come in the near future. For installations where turndown capabilities are not as flexible as those of the Havana No. 6 Unit, or where there could be a greater demand for oil, the MicroMill tech- nology should be of definite benefit. In other instances, recapture of lost capacity due to grindability, Btu content, and slagging and fouling with changes in coal purchases to meet acid rain legislation, this technology may provide a definite benefit to the user. However, with current financial constraints, this is not the case with Illinois Power’s Havana No. 6 Unit. REFERENCES 1. Hartness, J.L. and M.M. Koeroghlian, “Dry Micronzied Coal Application on Utility Gas-Fired Boiler.” Presented at the 7th International Coal & Lignite Conference and Exhibition, 1984. 2. Robinson, E.T., O.G. Briggs and RD. Bessette, “Comparisons of Micronized Coal, Pulverized Coal and No. 6 Oil for Gas/Oil Utility and Industrial Boiler Firing.” In the proceedsings of the American Power Conference, 50th Annual Meeting, May 1988, Chicago, Illinois. 3. Batyko, B., M. Savone, R. Gallup, T. Lanager and R. Sheahan, “Micronized Coal Firing: Commercial Operating Experience.” 4. Wiley, A.C., T. Rogers, L. Berry, M. Beam, “Micronized Coal for Boiler Upgrade/Retrofit. Duke Power Coal Start-Up Tests,” presented at Gen-Upgrade 90 International Symposium on Performance Improvement, Retrofitting, and Re: ring of Fossil Fuel Power Plants, Washington, D.C., March 6-9, 1990. 5. Wiley, A.C., T. Rogers, L. Berry, M. Beam, “Micronized Coal for Boiler Upgrade/Retrofit. Duke Power Coal Start-Up Tests, Update and Results,” presented at Power Gen, The In- ternational Exhibition and Conference for the Power Genera- tion Industries, Orlando, Florida, December 4-6, 1990. Page & Technical Paper Micronized Coal For tnortetaporater Boiler Upgrade/Retrofit Ely, lowa 52227 M. Beam Duke Power Coal Start-up Tests Duke Power Company Update and Results Cliffside Station Cliffside, North Carolina 28024 T. Rogers Duke Power Company 500 South Church Street Charlotte, North Carolina 28242 L. Berry Peabody Engineering Corporation 39 Maple Tree Avenue Stamford, Connecticut 06906 POWER GEN The International Exhibition & Conterence for the Power Generation Industries Orlando, Florida December 4-6, 1990 fl FULLER:MPD" MINERALS PROCESSING DIVISION ‘A member of the FL Smidth-Fuller Engineering Group Micronized Coal for Boiler UpGrade/Retrotit In 1987 Duke Power Company made a commit- ment to implement a direct-fired micronized coal system as a replacement for no. 2 oil. A previous paper, “Micronized Coal For Boiler Upgrade/Ret- rofit, Duke Power Coal Start-up Tests”, presented at Gen-Upgrade 90, March 6-9, 1990, Washington, D.C., discussed the motivation behind micronized coal and its current status as an applicable fuel for utility boiler performance improvement. It also spe- cifically addressed the results of performance test- ing and operating experience to date for the MicroFuel™ System as applied to the Duke Power Cliffside No. 5, 600 MWe generating station. This paper summarizes the findings of this ongoing test and discusses current modifications to the system. When this paper is presented at the Power Gen Conference in December 1990, the MicroFuel™ System will have processed in ex- cess of 3000 tons of coal (approximately six times the annual coal requirement for a one-mill system at 20 starts per year). The MicroFuel™ System's present performance, limitations, forecast of future activities and assessment of economic impact are also included in this paper. Introduction The primary objective for undertaking the Duke Power start-up test was to investigate the cost benefits using micronized coal as a replacement fuel for no. 2 oil during start-up. The next phase of the test pro- gram will include direct micronized coal-fired low- load operation. The 600 MWe fossil unit is currently capable of operating on one mill at 60 MWe. Recent increases in oil prices have added an in- centive to the test program. Duke Power Company and other utilities have curtailed the use of oil unless absolutely necessary, and micronized coal has demonstrated the ability to decrease the amount of oil needed during start-up and low-load operation. The MicroFuel™ System has been successfully tested this year in a very difficult application. There are four main factors contributing to this level of difficulty. + Aminimum of 30% total air flow at any load. * A single furnace with only four firing corners. + Asingle MicroFuel™ System capable of firing only two of the four corners. + Afire safety system (FSSS) which will not allow coal firing without having either the “A” or “B” mill at = > 40% capacity or having the sustain- ing side plate igniters in service. Other locations for the MicroFuel™ System were considered, and in fact, there were other units within the Duke Power system where a single MicroFuel™ System could have had a greater impact on the overall operation. However, for many years Cliffside No. 5 has been run at a high level of performance, within the top 10 best units in the United States, and the unit has achieved operating levels previously thought impossible. This consistent operation greatly improves the validity of any tests performed. The Duke Power test has shown what some of the limitations of the micronizing system are. In the following paragraphs these limitations will be discussed, as well as what can be done to address them. Also, recent modifications to the system will be explained and how they affect the present performance of the Duke unit. Finally, a forecast of future activities and their economic impact is presented. System Modifications The original system installed at the Cliffside plant (a paper presented at Gen-Upgrade 90) was a negative draft system (see figure 1) which used the draft induced by the impeller and two boost fans (mill exhausters) to move coal through the system to the burners. Erosion on the mill impeller (operating at 3600 rpm) and boost fan impellers (operating at 2800 rpm) was a primary motivation to redesign the system to forced draft. (See figure 2.) The heart of the forced draft system is anew mill MF-3018 with areplaceable- blade impeller. Impeller speed was decreased from 3600 rpm to 2860 rpm by changing from direct drive to belt drive. The replaceable-blade design generates better internal dynamics as well as improved erosion resistance. High chrome cast white iron blade sections are mounted on a dynamically balanced T1 steel backplate. The entire impeller assembly is then dynamically balanced prior to installation. The current impeller has as-cast blades rated at 550 Brinell hardness. At the end of approximately 500 hours of operation, there was some indi- cation of minor erosion at the outlet end of each blade. After 3000 tons of coal are processed with this impeller, a new impeller will be installed with blades heat treated to 700 Brinell hardness. Replaceable-blade impeller weight (660 pounds) is approximately 300 pounds greater than the original tungsten carbide coated cast steel impel- ler. As a result of increased impeller weight and side pull of the belt drive, there have been some new problems associated with the bearing frame. Weare currently in the design phase of selecting a proper top and bottom bearing combination that will handle the thrust load of the heavier impeller, the radial load of the belt drives and vibration due to imbalance as erosion occurs. Power Gen international Exhibition & Conference Micronizea Coal for Boiler UpGrade/Retrofit MicroFuel™ System Performance Since implementation of the new impeller design and a change to a forced draft system, there have been a total of over 3000 tons of coal processed by the system. The average coal throughput has been approximately 4 tons per hour at 80% minus 44 microns (see figure 3) during the testing phase, with over 5 tons per hour obtained during maximum load conditions. System energy use during normal operation (4 ton/hour) is 29 KW/ton. This includes all energy associated with raw coal feed, coal micronization, and pneumatic delivery through two 8-inch schedule 40 burner lines approximately 125 feet in length. The 50 hp turbo blower is utilized to overcome 22 inches w.c. back pressure in the burner lines. Shorter burner lines could potentially reduce system energy consumption to a low of 22 KW/ton. When the system is operating at 5 tons/ hour, system energy is 26 KW/ton. (See table 1) For the MicroFuel™ System to be turned on, the FSSS logic must be satisfied. (“A” or “B” mill = > 40% or side plate igniters in operation.) This has limited mill operation to 10 to 16 hours per day. Although we would prefer to run the system 24 hours per day, to more quickly establish mainte- nance and wear guidelines, a sufficient number of hours have been run (approximately 1000 by the date of this conference) to determine those areas where modifications or improvements are required. Availability During the test period, the MicroFuel™ System has been unavailable for the following reasons. + Bearing frame modification and bearing failure. * Installation of ceramic tiles in high wear areas of the classifier. + Installation of walkways for operator accessibility. + Aburned relay on the programmable controller output card. (Probably caused by welding) + Screw feeder jamming due to foreign material in the coal which was large enough to have affected normal pulverizer or feeder operation. + Rotary air lock jamming due to pieces of wood, wire cable and belt material which made it through the mill and into the classifier. Only the air lock outages have been due to extra- neous material in the raw coal which would not have interrupted normal operation of the Raymond bowl mills. An access panel has been installed in the classifier above the rotary air lock and these outages are now limited to 30 minutes in length. Modifications to the classifier are being tested at the MicroFuel R&D facility to eliminate these out- ages and provide a means of rejecting this material before it enters the air lock. System Limitations As of this point it has not been practical to operate the MicroFuel™ System without side plate igniters or the “A” or “B” puiverizers oper- ating at 40% or more capacity due to FSSS logic limitations. Continuous operation of unit no. 5 has prevented installation of venturis on the Peabody burners. At present there is no control of secondary air. As a result, extremely high air flows have required a minimum 4 MMBtu/hour oil ignition for flame stability. Manual control of secondary air dampers have demonstrated im- proved flame stability; however, the FSSS continues to be the main limiting factor in prov- ing the overall application. Work with ABB Combustion Engineering and Peabody Engineering is underway to eliminate this limitation; and during the scheduled annual outage in December, venturis will be installed on both Peabody burners. (See Burner Con- siderations and figures 4, 5a, 5b and 5c.) Recent tests at the MicroFuel R&D facility have dem- onstrated the ability of this burner to operate as low as 10 MMBtu/hour without support fuel. This type of turndown would not be required at Cliffside No. 5. However, with minimum air flow set at 400% excess air, flame stability without support fuel must be demonstrated while maintaining these high air flows with the micronizer in operation. The original four primary oil guns were sized for 900 gallons of no. 2 oil per hour (approximately 125 MMBtu/hour). Orifices have reduced the firing rate to 90 MMBtu/hour each, or a total of 360 MMBtu/hour from the four oil guns. With one MicroFuel™ System replacing two oil guns and firing at 62 MMBtu/hour per burner, the total firing rate has been decreased 30%. Each Peabody burner has a center-fired oil gun ca- pable of firing at 60 MMBtu/hour concurrently with micronized coal firing. This would increase two burner capability to 120 MMBtu/hour each. During start-up it is imperative that a maximum amount of Btus are delivered to the bottom of the furnace as rapidly as possible to replace losses from 400% excess air and the overall size of the furnace. Other than price differential, there are advan- tages in burning coal in lieu of oil in the lower furnace during start-ups. The lower heat loss due to hydrogen and moisture and the higher emissivity of coal generate a higher absorption rate in the lower furnace walls. With only one MicroFuel™ System involved, however, the maximum heat input from micronized coal Power Gen international Exhibition & Conference Page 2 Micronized Coal for Boiler UpGrade/Retrotit during the test period has limited the actual benefit. The installation of an additional MicroFuel™ System would increase total Btu input from coal to 250 MMBtu/hour; and if the center-fired oil guns were used concurrently with coal firing, a total of 396 MMBtu/hour would be available for start-up. For a furnace of this size, one MicroFuel™ System dedicated to each corner (a total of four) would have the firing equivalency, on micronized coal, of the original 900-gallon-per-hour oil guns. From a low-load operating standpoint, two MicroFuel™ Systems would allow the unit to oper- ate at a minimum of 14 MWe (assuming 16,000 Btu/KW at 400% excess air). Four MicroFuel™ Systems would provide 30 MWe. Recent studies indicate that the unit would have sufficient capacity to maintain total plant auxiliaries at 14 MWe elimi- nating the need for unit shut-down. This would also eliminate any oil requirements during low-load operation. At a level of 14 to 30 MWe, the unit would disconnect from the grid and simply maintain house power while keeping the turbine spinning. Burner Considerations The CE corner-fired unit utilizes the fireball con- cept for the main pulverized coal to achieve com- bustion. The CE burners (commonly referred to as nozzles or buckets) are designed to inject pulver- ized coal from all four corners at tangents to an imaginary circle in the center of the furnace. The combustion process is initiated at the nozzle tip but is dependent upon the fireball in the middle of the furnace to assure complete combustion. As one can suspect, these coal buckets are not designed to provide the individual, stable coal flames required during start-up or low-load conditions. Because of its extremely small particle size, a micronized coal particle exhibits similar charac- teristics to atomized fuel oil. The small particle size creates greater surface area per unit weight of coal, resulting in better air/fuel mixing to yield a shorter flame envelope (less residence time) and lower excess air levels. In addition, the air/fuel mixing tends to minimize the chilling effect of acold furnace such that micronized coal, like oil, can be used for start-up and warm-up of a cold furnace. The CE unit at Cliffside was set up with one level of no. 2 oil warm-up guns (total of four) located between the bottom two coal levels. Each warm-up guncompartmentconsisted of an oil bucket located between two larger air buckets. Each oil unit was designed to fire 90 MMBtu/hour with the ignition source coming from an ignitor located in the side or eddy plate. As is inherent in the CE tangential design, the oil and air buckets were capable of tilting plus or minus 30°. Before Duke would consider retrofitting the boiler with micronized coal warm-up guns, assurance was given that the micronized coal burner would provide the same function as the oil burners, namely: + Becapable of ignition and stabilization of the main coal. * Be capable of at least 60 MMBtu/hour each to provide warm-up and standby capability. + Provide an independent stable flame on micron- ized coal without the need for support fuel. + Provide a burner that would fit into the exist- ing windbox without modifications to tubes, windbox or air supply. The only feature that wasn’t required of the test burner was the ability to tilt, since the existing oil units had to be brought to the horizontal position to be ignited anyway. In addition, oil firing ca- Pability was provided in the test burner to pro- vide flexibility in fuel selection for warm-up. The items above would not be a problem in a front-fired boiler which utilizes conventional burners. Those conventional burners utilize air registers, diffusers, and throat tile as important features in developing stable flame envelopes and complete combustion. However, putting a conventional style register in a CE tangential windbox with no modifications to tubes, windbox or air supply is virtually impossible because: * The compartment for the oil bucket is not wide enough or high enough to permit proper combustion air entrance and distribution into the 360 degrees of an air register. + Proper diffusers and throat tile for the desired heat input could not be employed due to the relatively narrow distance between tubes. * Scroll type coal burners usually applied in pulverized coal burners also could not be used due to the small compartment area. Initially, the only modification permitted was the removal of the oil bucket from its compartment. Thus, other burner firing techniques had to be investigated. With the similarities to fuel oil in mind, the design of the burner for the Cliffside project included elements of not only a (pulverized) coal burner, but an oil burner as well. In addition to giving the micronized coal rotation, the capability of an adjustable spray angle (like that of the oil tip) was implemented. The conical stabilizer (figure 4) was employed to increase or decrease the spray angle of the coal stream as it left the coal tube. This permitted the coal to be fired at a Power Gen International Exhibition & Conference Micronized Coai for Boiler UpGrade/Retrofit wider angle than a conventional pulverized coal burner so as to achieve better heat distribution to the sidewail tubes. This is particularly desirable in a Start-up or warm-up condition. A venturi was used for secondary air control and flame stabilization. The air pressure recovery concept of the venturi has been used for the past 15 years in low excess air burners with tremendous success. The conversion of velocity pressure to static pressure in the diverging section of the venturi provides the energy for good air/fuel mixing without the requirement of the spin turbulence of an air register. The venturi combined with the adjustable stabilizer provides sufficient flame shaping so the need for a throat tile is eliminated. Also, the stabilizer acts like a heat-sink which also tends to keep the flame back at the burner tip. A conical tertiary air guide vane following the contour of the venturi diverging section will be installed to permit compartment combustion air to enter the furnace without disturbing the coal igniter stability or flame pattern so essential to stable generation. (See figures 5a, 5b and 5c.) Economic Considerations As indicated earlier, it is not possible to displace 100% of the oil on start-up with one or two MicroFuel™ Systems. It would require a minimum of four MicroFuel™ Systems to equal the output of the four primary oil guns. However, to establish an economic assessment that would displace a high percentage of annual oil use, we have based an application cost of coal over the displaced no. 2 oil with two MicroFuel™ Systems operating at maxi- mum capacity for approximately 18 starts averaging 5 hours per start (87.6 hours), or 1% of the annual potential operating time. (See table 2) (The savings generated from the micronizer currently in service would be one-half of the projected savings for two MicroFuel™ Systems.) A prime factor for the in- stallation of a second MicroFuel™ System would depend upon the ability to maintain plant auxilia- ties at 14MWe under low-load operation. The economic evaluation was conducted by /es, Lexington, Kentucky, based on actual coal analy- sis, typical no. 2 oil analysis, plant operating data, and the delivered price of coal. For the base case evaluation, oil cost was assumed to be $1 per gallon delivered to the plant. The overall evaluation included: * The direct costs of fuel utilization. * Combustion efficiency at 400% excess air re- quired for low-load operation. + Fuel storage and handling costs. Inventory costs. Ash handling and disposal costs. Air and flue gas handling costs. Coal micronization costs and soot blowing costs. (At low-load operation, soot blowing would be a minimum requirement.) Maintenance costs were not included but were expected to be no more than those associated with conventional pulverizer equipment. With a delivered coal price of $1.80 per MMBtu versus no. 2 oil at $7.14 per MMBtu, there are signifi- cant savings achievable with the displacement of any amount of oil. In this case, displacing approximately 250 MMBtu/hour of oil, 87.6 hours per year results in a savings of $163,000. Be- cause this is a testing and demonstration in- stallation, we have not considered the payback or cash flow evaluations which would normally accompany a complete plant feasibility evalu- ation. (See figures 6 and 7) Evaluations of low-load operations, where over- all system needs must be considered, have not been performed. This would include heat rate comparisons, cost of supporting power to the down plant, start-up costs on coal or oil, de- creased response time for demand systems maintenance savings by keeping the turbine running, et cetera. These will be evaluations specific to the site and system, and at this time we are only considering economics based upon oil displacement. A more detailed evaluation will be completed as the test progresses. Future Direction Overall results of the test to date are very positive. Burner feed, particle distribution and system energy consumption have remained consistent throughout the test period. Nagging problems such as foreign material, jamming feeders and proper bearing selection continue to be designed and modified. All other aspects of the MicroFuel™ System are now operating under what might be called a normal operating mode with general O&M guidelines. Immediate goals: * Complete burner modifications during sched- uled outage and fire both Peabody burners in a start-up condition without support fuel. + Operate the modified burners over the load range of the furnace for an extended period of time. + Operate the burners in acold furnace through a minimum of five starts. Power Gen International Exhibition & Conference Page 4 Micronized Coal for Boiler UpGrade/Retrofit A logistical, operational and economic evaluation will be conducted in detail selecting the number of MicroFuel™ Systems ideally suited for start-up and low-load operation. There are several other fossil units within the Duke Power system that have expressed an interest in the MicroFuel™ technology, and future activities will include an investigation of various applications at other Duke fossil units. In 1991 MicroFuel Corporation will be designing a 12-1/2 to 15-ton-per-hour MicroFuel™ Reference: System. Two units of this size may be more appropriate for a 600 MWe single furnace. Micronized coal has demonstrated many uses as a direct oil replacement. Ignition of coal-fired utility boilers is a good proving ground for this fuel. As testing continues, a data base will be available for interested parties in the industry. Wiley, A.C., Rogers, T., Berry, L.,and Beam, M., “Micronized Coal For Boiler Upgrade/Retrofit, Duke Power Coal Start-up Tests.” Presented at the Gen-Upgrade 90 International Symposium, Washington, D.C., March 1990. Power Gen International Exhibition & Conference Page 5 E-COAL NOTE : BUNKER FLOWS FOR THE MICROFUEL SYSTEM. ACTUAL PHYSCAL LAYOUT 1S NOT SHOWN. PROCESS FLOW DIAGRAM ae = U —— st aro Eom a Figure 1 Process Flow Diagram E BUNKER ANNEX BIN mit. PREHEAT AiR s00"F > PREHEAT AIR ) TEMPERATURE POSITION V. DC-ORIVE Figure 2 Percent Passing 100 == 10 Particle Size Distribution Coal - Cliffside #5 (9/90) | lat \ a | HI '\ i a 1 i 0.1 aoe nl _ ee Janeth edt _—— +-———. — = a St —— —— — Ba a 1.3 Poy SS ted ie : = | a ofc eammna pf tt +} -- 0.1 10 Particle Size In Microns Figure 3 1000 Operating Data Summary MicroFuel System Duke Power - Cliffside Station Date Tons Hours Ton/hr KW KW/Ton Aug 24 19.35 4.2 4.61 528 27.29 Aug 29 29.97 Nt 4.22 672 22.42 Aug 30 51.06 12.8 3.99 1488 29.14 Aug 31 51.95 12.0 4.33 1440 27.72 Sept 2 54.77 12.5 4.38 1536 28.04 Sept 3 34.85 9.6 3.63 1104 31.68 Sept 5-7 118.90 28.0 4.25 3936 33.10 Sept 20 47.85 11.6 4.13 1440 30.09 Sept 21 67.22 16.7 4.03 2016 29.99 Sept 22 29.21 7.8 3.74 1008 34.51 Sept 27 34.35 8.1 4.24 1008 29.34 Sept 29 26.99 6.7 4.03 864 32.01 Oct 3 13.04 35 3.78 384 29.45 Total 579.51 140.55 17,424 Average 4.10 29.60 Table 1 Coal-Fired Ignitor For CE Tangential Furnace ELEVATON (FROM FURNACE) SIDE ELEVATION FRONT ELEVATION Figure 4 Peabody Burner Modification Venturi Air Flow Air Volume Lbs/hr (Thousands) 80 70 60 50 40 30 20 10 0 0.5 1.0 15 20 25 30 35 40 45 #£5.0 Windbox Pressure « 70°F -« 200°F -= 350°F -+ 500°F -— Ign. Stoich. Air Figure 5a 180 160 140 120 100 80 60 40 20 0 Peabody Burner Modification Tertiary Air Flow Air Volume Lbs/hr (Thousands) «= 70°F To.” 20: 25 < 200° F = 350° F Figure 5b 3.0 Windbox Pressure 3.5 ~~ 500° F Peabody Burner Modification Total Air Flow Air Volume Lbs/hr (Thousands) 250 200 150 100 50 0 7 T T T aromas T 7 1 i a 0.5 1.0 15 2.0 2°90) 3.5 4.0 4.5 5.0 Windbox Pressure « 70°F -« 200°F w= 350°F -+ 500°F | Figure 5c Table 2 Cliffside Oil Utilization 1985 Through 1989 Gal/Yr Starts/Yr Gal/Start 540,000 26 20,769 365,000 25 14,600 280,000 14 20,000 372,000 19 19,579 306,000 20_ 15,300 372,600 18.4 18,050 (Average) Normal start-up is approximately 5 hours. Duke Cliffside Economic Evaluation Summary Base Case Micronized Coal No. 2 Oil Fuel Cost Delivered $1.80/MMBtu $7.14/MMBtu Application Costs: (Based on heat loss from 400% excess air) Comb. Eff. $0.525 $2.395 Stor., Hand. & Inv. 0.003 0.008 Ash Hand. & Desp. 0.001 0.000 Air/Flue Gas Hand. 0.466 0.508 Micronization 0.119 0.000 Sootblowing 0.020 0.000 Total Application Cost $2.90/MMBtu $10.07/MMBtu Combustion Efficiency 77.42% 74.89% Annual Btu (106) 21,824 MMBtu 22,562 MMBtu Annual Fuel Usage 862 Tons/yr 161,157 Gal/yr 9.84 Tons/hr 1,840 Gal/hr Effective Fuel Cost $75.41/Ton $1.41 Gal Total Annual Cost $65,000 $227,000 Annual Differential $162,000 0 Under this case, two MicroFuel micronizers would supply approximately 50% of the total Btu needed at maximum stat-up rates using four 900 gai/hr guns for 5 hours. 140,000 Btu/Gal-19,680 Btu/# oil; 12,657 Btu/# coal 2 Micronizers @ MCR; 88 hr/yr; $1.00/gal #2 oil Annual Fuel Cost Savings Coal vs Oil @ 1% Operating Annual Fuel Cost Savings (Thousands) 400 350 300 250 200 150 100 4— 50 0 ——— 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 No. 2 Oil Delivered Price ($/gal) | « One Mill5-Ton/hr -& Two Mills - 10 Ton/hr | Figure 6 Annual Fuel Savings (Coal vs Oil) Sensitivity To Operating Hours Savings/yr - In Thousands 4500 4000 3500 3000 2500 2000 1500 1000 500 0 5 10 15 20 25 Percent Annual Operating Hours «+ One Mill-5 Ton/hr -& TwoMills - 10 Tonvhr | Figure 7 J FULLER SeoeIvED ‘= Amember of the FL.Smidth-Fuller Engineering Group ASCG, Inc. SCIENCE DIVISION 301 Arctic Slope Ave- Mr. Dale Letourneau Suite 200 ASCG Incorporated AK 99518 301 Arctic Slope Avenue, Suite 200 Anchorage, Alaska 99518-3035 12 January 1993 Dear Dale: Subject: Modularized Micronized Coal-Fired Boiler Systems Thank you for your letter regarding your project and interest in the MicroMill™. After reviewing the information, we see no problem in micronizing and burning the coals you have available. I have taken the liberty of contacting Roger Swanson, president of Nebraska Boiler, to solicit his interest in this project. We are interested in putting together a team which would be capable of providing the boiler island. However, before committing fully to support this project, we need a definition of partnering agreement. Our decision was made on the basis that partnering agreement meant we would provide you with technical support to pursue the project in exchange for exclusive rights to provide the boiler island equipment. As I stated, we are interested under these conditions; however, neither of our companies is currently interested in providing equity investment or participating in the ownership of IPP or cogeneration projects. I believe as a team MicroFuel® and Nebraska Boiler can provide you with the modular micronized coal-fired boiler islands your project will require. If our understanding of your project is correct, we are looking forward to working with you to develop this project. Sincerely, FULLER POWER CORPORATION Gb C Lek, John C. Welling (at-/ General Manager, MicroFuel Minerals Processing Division JCW:sb cc: R. Swanson/Nebraska Boiler FULLER POWER CORPORATION 2040 Avenue C e Bethlehem, Pennsylvania 18017-2188 Telephone: 215-264-6011 ¢ FAX: 215-264-6170 Telex: 173189 FULLERCO CAQA e Cable: COLFULLER Micronized Coal: Its Use in Package Boilers Peter G. Kasik MicroFuel Corporation Ely, Iowa 52227 Lee Pohlenz Nebraska Boiler Company Lincoln, Nebraska 68507 Nicholas C. Francoviglia, P.E. Bibb and Associates, Inc. Shawnee Mission, Kansas 66204 /fl FULLER:MPD" MINERALS PROCESSING DIVISION ‘A member of the F. Smictth-Fuller Engineering Group MICRONIZED COAL: ITS USE IN PACKAGE BOILERS Peter G. Kasik MicroFuel Corporation Ely, Iowa Lee Pohlenz Nebraska Boiler Company Lincoln, Nebraska Nicholas C. Francoviglia, P.E. Bibb and Associates, Inc. Shawnee Mission, Kansas Abstract Most industrial boilers are fired by natural gas or fuel oil. These are, of course, the fuels of choice, if the supplies are adequate, stable and cost competitive. This has been the case for several years. However, prudent utility managers must continue to evaluate fuel options and make contingent plans to respond to fuel interruptions or take advantage of fuel price changes. This presentation is a technical and economic overview of the application of micronized coal firing to package industrial boilers, including site considerations, fuel handling and storage, micronizing system requirements, boiler/furnace design considerations and air pollution equipment and requirements. Introduction Small and medium-sized industrial steam users have relied primarily on packaged boilers as their source of steam generation. Package boilers have historically been fired by either gas or oil, which is certainly the preferred fuels for most industrial package boiler applications. The price and availability of oil and gas have been fairly stable for the past several years. All industrial utility managers realize the advantage of having complete fuel flexibility allowing them to use the most economic fuel. Almost all industrial package boiler installations are designed solely for gas and oil and until the introduction of micronized coal, did not have the flexibility to use coal as an alternate fuel source. The intent of this paper is to define and evaluate the requirements for a micronized coal-fired package boiler installation. The intent would be to give the end user the fuel flexibility to utilize either oil or micronized coal. It is realized that the installed cost of a plant to burn both oil and micronized coal will be greater, but the operator will have the flexibility to use the most economical fuel. There will also be other advantages such as having an industrial plant permitted to burn coal which will become increasingly more difficult in the future should oil not be available for firing. This paper addresses the technical, economic, permitting, and operating advantages of a micronized coal/oil-fired industrial package boiler installation. Obiectiv The major objective of this paper is to define the technical requirements, economic feasibility, equipment availability, permitting requirements, and operating requirements of a micronized coal-fired industrial packaged steam generator. Although this paper is based on a grass-roots new site, the possibility of retrofitting existing package boilers is also covered. It is the intent of the presenters of this paper to give the industrial boiler user a broad brush picture of the options available to them when considering additional or new steam generation. It is also ' intended to give the industrial boiler operator insight as to the options of converting existing package industrial boilers to fire micronized coal as a second or primary fuel. System Description and Design Assumptions The micronized coal-fired boiler plant evaluated in this paper consists of an 80,000 lb/hr A-Type package boiler generating steam at 150 psig saturated designed for micronized coal firing with No. 2 fuel oil firing capability as well. The coal is a low sulfur eastern bituminous. Coal will be pulverized to an average mean particle size of 15-20 microns by means of a micromill. Figure 1 presents the system flow diagram. The following are assumptions and basic design conditions forming the basis of the boiler system evaluated in this paper. 1. Boiler Capacity: 80,000 lb/hr 2. Steam Pressure/Temperature: 150 psig/saturated 3: Boiler Design Pressure: 250 psig 4. Boiler Heat Input: 92.3 MMBtu/hr 5: Feedwater Temperature: 220°F 6. Exit Fluegas Temperature: (Coal) 320°F, (Oil) 300°F ae Blowdown Rate: 3% 8. Fuel Analysis: Coal No. 2 Oil Carbon, % 71.89 86.4 Hydrogen, % 2.41 MET Nitrogen, % 0.89 0.2 Sulfur, % 1.61 0.4 Oxygen, % 3.84 0.3 Ash, % 10.70 Trace Moisture, % 8.66 Trace HHYV, Btu/Ib 12,715 19,567 9. Coal Delivery: End or bottom dump truck 10. Soil Bearing Capacity: 2,000 psf 11. SO, Reduction: 90% 12. Calcium to Sulfur Ratio: 1.5:1 13. Particulate Matter Emissions: 0.05 lb/MMBtu 14. NO, Emissions: Coal (0.7 lb/MMBtu), Oil (0.2 lb/MMBtu) 15. Lime Purity: 90% 16. Site Elevation: 800 ft MSL Fuel Options Package boilers in the past have used natural gas or oil as the predominate fuels. These fuels are more convenient from a user stand point because of various problems associated with coal and the issue of stack emission controls. For 1991 the U.S. imported almost 40% of its oil from overseas, with a large share of this coming from the Mideast. Because of the volatile nature of oil supplies around the world, they are not insured. The Gulf war of 1991 is good proof of this issue. To compound this predicament is the fact that oil prices are driven by the world market place, not domestic, and are currently at artificially low prices. It is a certainty that oil and gas prices in the future will rise, but to what levels? With air pollution concerns becoming greater and the fact that more federal and state legislation regarding this matter is increasing, permitting of new boilers becomes a larger issue. In the future permits allowing the combustion of coal will be increasingly more difficult to obtain. Coal reserves in the U.S. are abundant, and the cost is and will be stable in the future. The boiler plant owner looking to add a boiler to a plant must be cognizant to all the concerns listed above. Having the flexibility of being able to use either coal and oil in a package boiler gives them advantages from both a cost and fuel availability standpoint. This allows the plant the ability not be tied to the price and availability concerns but also not to political problems around the world. Micronized Coal Micronized coal is defined by the "INDUSTRY" as coal that has been ground so that 99% is less than 177 microns (99% < 80 mesh), 80% less than 44 microns (80% <325 mesh) with the average particle size being approximately 20 microns. Pulverized coal on the other hand has 99% less than 297 microns (99% <50 mesh), 70% less than 74 microns (70% < 200 mesh) with an average particle size of approximately 60 microns. Top size is another important comparison to be made between pulverized and micronized coal. The largest particle produced by a pulverizer is almost 1.7 times larger than that attained in micronized coal. Various tests have been performed and it has been found that there are no real benefits to produce coal beyond 80%<44 micron”. To produce a finer product than this requires additional energy and increases transport problems. Combustion tests that were performed during this test indicated minimal gains in either combustion, tube slagging and erosion or boiler efficiency. Adv: Mi The benefits of producing micronized coal have been understood for a long time®. Many studies have been performed and papers written on this subject and the conclusions drawn from each one is the same, micronized coal is superior to pulverized coal in most performance aspects. Even though the benefits of micronized coal have been realized, in the past there was a large drawback to producing it. Until recently there has not been a cost effective method to produce it. But, through technological advances in milling the economics to produce micronized coal have become more competitive with pulverized coal and alternate fuels. Looking at Figure 2 it can be seen that micronized coal particles have approximately 300% more surface area per unit volume than pulverized coal particles for that of an average pulverized particle size of coal. Because of this significant increase in surface area two things can be accomplished. In looking at Figure 3, for any given percentage of excess air the percent of unburned carbon goes down as particle fineness goes up. Also, micronized coal gives the added benefit of reducing the amount of excess air to achieve the same amount of unbumed carbon in the fly ash. This allows for more heat to be liberated to the furnace than for heating a larger mass of air. Another important aspect of micronized coal is its improvement in boiler efficiency. Referring to Figure 4, it can be seen that for combustion at 15% excess air, there is at least a 1.25% increase in the efficiency of the boiler. Another attribute of micronized coal is its similarity for flame size and shape to No. 6 fuel oil, and also the fact that with micronized coal the flame became shorter (approx. 35 inches long) versus a pulverized coal flame (approx. 55 inches long). These flame geometries can be seen in Figure 5. When comparing boiler tube slagging and fouling it has been found that due to the smaller particle size of micronized coal these problems are reduced. The ash deposition of the tubes can be easily handled by the soot blowers, and due to the fast burn out of the particles, the incidence of slagging is diminished because of the quicker heat release of the flame. Because of this the particle is able to radiate its heat content earlier, and be below its fusion temperature. MicroMill The MicroMill is centrifugal-pneumatic mill that works on the principle of particle to particle attrition. Coal is conveyed pneumatically with a hot air stream into the cone area, creating a vortex of air and coal particles. As the diameter of the cone enlarges, the air/coal velocity decreases allowing for the coal to achieve a position in the cone based on its weight. (Refer to Figure 6) If across section were made through the cone and Rotational Impact Zone (RIZ) you would see a segregation of particles with the larger ones at the bottom with the diameters getting smaller as you go towards the (RIZ). As this “tornado like" or vortex of material is moving, the smaller particles move through the paths of the larger ones and collide. These collisions 4 coupled with the collisions of "like" particles causes attrition in size. The RIZ area acts as an orifice keeping material in the cone/RIZ area until it reaches a certain minimal size at which time it is discharged out of the mill into the classifier. The classifier is an horizontal centrifugal type, and only allows particles of a given size distribution to be discharged to the burner, oversized ones pass through an airlock to be re-entrained back in the air stream that is going back to the mill. This air stream serves two purposes, it is used for both conveying the coal and to drive moisture from the raw feed. ' Retrofit Potential This project was approached from a "grass roots" perspective, thus allowing for an optimal design of the whole system. This gave the most flexibility for coal handling and delivery, plant layout and the most economical method for pollution control and ancillary equipment. In any retrofit job, the cost to do so is based on many factors that are plant and site specific. Some of these factors are coal handling and storage, available floor space for installation of the milling system, burner(s) and coal transport piping, ash handling and particulate control. But, for an oil fired boiler, it should be pointed out that when using micronized coal as a fuel there are things that probably will not have to be changed or the changes would be minimal. These include: 1) Existing soot blowers (if applicable) 2) Coal Handling 3) Ash Handling 4) Pollution Control Equipment 5) Boilér Tubes 6) Controls For this "grass Roots” boiler plant, plant arrangement and systems can be ideally designed. However, in the case of a retrofit, certain items may be less than ideal. The boiler bottom ash collection hopper is a good example of this. For an existing oil fired boiler, it would be impractical to add a bottom ash collection hopper. This should not be viewed as a major problem. The quantity of ash collected by the bottom ash hopper is perhaps 10-20% of the total ash. Much, if at all, of this ash may be re-entrained in the flue gas by means of “puff” blowers. For a “grass roots" plant, the cost of the bottom ash hopper is not significant and adds conservatism to the design. Envi L Considerati It is no secret that environmental rules and regulations are becoming, and will continue to become, more and more stringent. Who would have believed only a few years ago that a scrubber would be required on a small boiler firing a fuel oil with a sulfur content greater than 0.5 percent? We producers of steam and we consumers of the products for which boiler plants exist, must pay the price of these regulations. We should do so with the positive attitude that it can only benefit our civilization in the long run. But, we must comply with the regulations in the most economical way possible. Discussed below is a synopsis of the air pollution regulations that pertain to the 80,000 lb/hr micronized coal fired plant considered in this paper. New Source Performance Standards Part 60 of the Code of Federal Regulations contain the "Standards of Performance for New Stationary Sources." These are referred to as the New Source Performance Standards (NSPS). Subpart De of the NSPS contains the "Standards of Performance for Small Industrial - Commercial - Institutional Steam Generating Units," which are defined as units with a maximum design heat input of 100 MMBtv/hr or less. The micronized coal fired boiler plant studied in this paper fall under these regulations. As such, SO, reduction will be required at a removal rate of 90% and limit the outlet emission rate to 1.2 lb/MMBtu. An emerging SO, control technology need only remove 50% of the SO, with an outlet SO, emission limit of 0.6 Ib/MMBtu. While this appears to be an ominous disadvantage for coal firing in an industrial boiler, it need not be. SO, removal systems are a proven technology. They have been in use for the past twenty years. They do add another significant cost to the operation of a coal fired boiler, but that cost is far outweighed by the potential savings of coal over fuel oil. For the boiler plant evaluated in this paper, a dry flue gas desulfurization system using pebble quick lime as the reagent was selected. Other systems using limestone or other reagents are available. For a small application, it is desirable to obtain a dry product that can be handled with the fly ash. It is also desirable to avoid such other complications as disposing of a wet sludge, reheating of the flue gas and adding additional operating staff. Subpart De also requires that particulate matter be controlled to an emission rate of 0.05 lb/MMBtu. This level is routinely achieved by a fabric filter baghouse. Subpart De does not contain a standard for nitrogen oxides (NOx) emission. However, it is expected that the emission limit for NOx would be comparable to that for boilers above 100 MMBtv/hr heat input. Subpart Db of the NSPS currently has a standard of 0.7 lb/MMBtu for pulverized coal fired boilers. For No. 2 fuel oil, the limits are 0.1 Ib/MMBtu for boilers with heat release rate of 70,000 Btu/hr-ft* or less and 0.2 Ib/MMBtu for heat releases of greater than 70,000 Btu/hr-ft*. Prevention of Signifi ‘oration Permi Any stationary source which has the potential to emit 250 tons per year or more of any regulated air pollutant would more than likely be required to obtain a PSD permit. For most coal fired boilers, the applicable pollutants are sulfur dioxide, nitrogen oxides, particulates, and carbon monoxide. The PSD regulations are very complex and would require significant discussion not appropriate for this paper. ' However, there are three major aspects of the PSD regulations that merit mention. The first is that up to one year of ambient air monitoring may be required prior to submittal of the permit. There are options to avoid this requirement, but they are specific to the environmental situations of the site and facility. The second requirement is that an extensive air quality analysis be conducted predicting the highest estimated ground level impacts of the emissions from the facility. The third major aspect of PSD is that Best Available Control Technology (BACT) be applied. The determination of BACT is a case by case review taking into account energy, environmental and economic impacts. ir Pollution Emissi Based on the current rules and regulations, the following emission rates are expected to pertain to a dual fuel micronized coal and No. 2 fuel oil boiler. For SO, under micronized coal firing 90% removal is assumed. The annual potential emissions are based on full load operation for 8760 hours per year. Micronized Coal No. 2 Fuel Oil Ib/MMBtu lb/hr tons/yr =~ —Ss IO/MMBtu = Ib/hr_-—tons/yr NO, 0.7 64.61 283 0.2 18.46 81 co 0.1 9:23 40 0.1 9723 40 so, 0.14 12.92 57 0.4 36.92 162 Particulates 0.05 4.62 20 Nil Nil Nil Boil iB Desien Considersti The boiler is a Nebraska Boiler Company, open bottom, "A" type water tube fully shop assembled with welded wall construction. A trough hopper is attached to the bottom for the collection of ash which falls out in the combustion zone. The micronized coal burner is an Atlas low - NOx system consisting of dual flow air registers, low - NOx adjustable burner, adjustable tilting angle air injection system, and control system for air flow, temperature monitoring and damper control. Balance of Plant Coal Handling System As shown on Figure 7, the coal handling system consists of a 50 ton truck unloading hopper with a structural grizzley designed for both end dump and bottom dump trucks, a vibrating pan feeder, 50 ton per hour belt conveyor and bucket elevator to a 90 ton day bin. A wet dust suppression system, fixed magnet and bin vent filter are also provided. Coal will normally be ' conveyed directly into the day bin as the trucks are unloaded. When the silo is filled, a stock- out chute and flop gate will direct the coal to a stockpile adjacent to the bucket elevator. A two- side concrete push wall will allow for some short-term storage, and the coal can be reclaimed back to the truck unloading hopper by means of a small front-end loader. Ash Handling System Micronized coal firing results in a very fine ash product with the majority (80-90%) collected by the particulate removal device. The ash that drops out within the boiler will fall into a trough type hopper under the boiler. While the total quantity of ash is relatively small, only about 7.5 tons per day, it is considered too great to be removed by mechanical conveyors to portable dumpsters. Dust considerations would also be negative factor in this type of operation. A vacuum pneumatic ash handling system was therefore selected. A screw conveyor designed for high temperature duty will convey the ash from the boiler’s bottom ash hopper to a surge bin and pneumatic valve. The two baghouse hoppers will each be provided with a pneumatic valve. Ash will be conveyed at the rate of approximately 5 tons per hour to a 40 ton ash storage bin. The bin will allow 3.3 days of storage capacity, adequate for a long weekend. To minimize fugitive dust emissions, a 25 ton per hour ash rotary dustless ash conditioner will wet the ash prior to unloading into dump trucks. A flow diagram of the ash handing system is depicted on Figure 1. Air Pollution Control System The air pollution control system consists of a spray dryer for flue gas desulfurization and fabric filter baghouse for particulate control. The spray dryer is a dual fluid nozzle type using compressed air as the atomizing media. Pebble quick lime will be received via pneumatic truck and blown into a packaged storage bin and slaker system. The equipment will be largely shop assembled and insulated to minimize field erection. Upon contact with the SO, in the flue gas by the slaked lime, calcium sulfate and sulfate will be formed and collected by the baghouse. The pulse jet fabric filter baghouse is selected with Ryton bags and a 3.5:1 gross air to cloth ratio. The inlet fluegas flow is 34,000 ACFM at 160°F which includes about 10% design margin. A full complement of accessory equipment is provided with the baghouse including support steel, caged access ladders, inlet butterfly dampers, pneumatic outlet dampers, bypass damper, ash level detectors, and shop insulation and lagging. The bypass damper would be used during No. 2 fuel oil firing. Water Treatm: ipm The water treatment equipment is identical to an industrial boiler plant firing No. 2 fuel oil. The deaerator operates at 5 psig with make-up water softened by a sodium zeolite water treatment system. Two 100% capacity electric motor driven boiler feedwater pumps are used. Drum level is controlled by a two element level control device. Feedwater Preheater To maintain suitable stack exit gas temperature to prevent corrosion of the economizer, I.D. fan and stack, a feedwater preheater is provided taking steam from the main steam header with condensate going to the deaerator. The feedwater preheater will also maintain adequate temperature to the dry scrubber. Controls Each system of the boiler plant will be controlled with individual control panels with single loop controllers and PLC’s for analog logic. The panels which will consist of those for the coal handling, micromill, boiler and burner, spray dryer and baghouse, and ash handling systems, will be located in a control room within the boiler building. Power Power will be fed to motors through a 480 volt motor control center (MCC). A lighting panel will be fed by a dry transformer from the MCC. The following are the estimated motor horsepowers for both a coal fired and oil fired boiler plant. Estimated Motor Horsepower Coal Fired Qil Fired Air Compressor 25 10 Boiler Feed Pumps 30 30 Boiler F.D. Fan 40 40 Fuel Oil Pump NA 10 Pan Feeder 5 NA Bucket Elevator 10 NA I.D. Fan 80 NA 292 KW Micro Mill System 200 NA Lime Slaker 10 NA Ash Exhauster 25 NA Screw Conveyor 5 NA Misc. 20 10 Total Connected Horsepower Load 450 100 Operating Load (80% Connected) 360 80 Kilowatt Load (92% Motor Eff.) 290 65 The above motor list is the connected power load. The operating power was obtained by multiplying the connected load by 80%. An average motor efficiency of 92% was used to calculate the kilowatt load. Therefore, the economic analysis is based on an electrical power consumption of 227 kw for the micronized coal case and 65 kw for the No. 2 fuel oil case. Si { Buildi The boiler plant is anticipated to be constructed at an existing facility with access to potable " water, sanitary and industrial waste, and electrical power. It is further assumed that the site is suitable for carrying equipment and building loads with spread footing foundations. The building is of structural steel construction with insulated metal siding. It is estimated that the overall building dimensions will be 75 feet by 40 feet by 35 feet tall. A combination office and control room will be within the building. A partial basement area will be provided under the boiler for the boiler hopper and ash handling equipment. Figure 8 is a Typical General Arrangement Drawing of the entire facility. Not shown is the 220,000 gallons (14 day capacity) fuel oil storage tank. Redundancy Philosophy Because of the back-up fuel oil firing capability, certain balance of plant systems relating to coal firing are not essential to plant operation when firing fuel oil and therefore have not been provided with redundance that would be typical for a plant firing only coal. The pulse jet baghouse used for the control of particulate emissions is a two module design with a gross air to cloth ratio of 3.5:1. It will not be possible, therefore, for off-line cleaning of the baghouse without a potentially high differential pressure. The ash handling system will be equipped with a single mechanical exhauster and ash conditioner. An outage of these items may require the use of the alternate fuel until repairs are made. This design philosophy should not result in major additional operating costs. E ic A ti i Evaluati As with all business decisions most of us are required to make, the determination as to whether or not micronized coal should be considered as a secondary or primary fuel for an industrial steam generator, it all boils down to economics. If it is not competitive, it probably will not be salable. Therefore, in evaluating the use of micronized coal, some basic economic assumptions need to be made. The only exception to economics is availability; and if oil and natural gas are Not available due to boycotts, shortages or other political situations which impact the availability of these fuels, economics becomes secondary and the primary driving factor is product production and delivery. Therefore, in evaluating the potential, we have made the assumptions regarding fuel price and escalation of the base fuels as shown in Table 1. Based on the project 10 plant cost in Table 2 and the operating costs in Table 3, the additional cost of adding micronized coal as the primary fuel would realize paybacks in 1 to 2 years as shown in Table 4 depending on the capacity factor of the installation. There are other economic advantages that are not measurable, and they are just the ability to produce your product if fuel availability is cut off completely and the potential that your competitors are in a fuel market outside of your area that gives them a distinct competitive advantage. In looking at retrofit potentials, the competitive advantage varies significantly depending on the availability of existing coal handling facilities, or other plant equipment that would not have to be added on a grass-roots facility. There is also going to be the long-term advantage of having a plant permitted for solid fuel should liquid and gaseous fuels become unavailable in that the conversion time and permitting time to convert to a solid fuel may be prohibitive or in some cases impossible, depending on the plant location and the permitting requirements at the time. Conclusions The technology and equipment are currently available to provide micronized coal-firing packaged industrial boilers and the advantage to an industrial user to have the fuel flexibility to fire either coal or oil is well defined and documented. Therefore, the decisions that industrial steam generators must consider are the economics of providing a facility with dual fuel capabilities. This must be weighed over the life of the unit, and prudent business people will require normally at least one alternate energy source to support a facility that has a useful life of greater than five years. Industrial steam users who are considering expansion at a facility that currently have some coal burning facilities should certainly look at micronized coal firing as a primary or secondary fuel, and manufacturers who are building a facility that has a life of greater than 10 years should seriously consider optional solid fuel firing for their energy needs. This is not only based on the assumption that there will be interruptions in oil supplies as well as increases in the cost, but that the permitting and licensing of future solid fuel units will only become more time consuming and costly, and in some areas may not even be achievable in five to ten years. Therefore, prudent managers who are responsible for the energy supply should seriously consider micronized coal as an option for primary fuel on all new and retrofit applications that require large energy inputs and very high capacity factors. The decision to utilize coal as a primary or alternate fuel today may mean the difference between your product being economically competitive in the future. 11 BIBLIOGRAPHY "Comparisons of Micronized Coal, Pulverized Coal and No. 6 Oil for Gas/Oil Utility and Industrial Boiler Firing," Robinson, Briggs and Bessette, American Power Conference, April 18-20, 1988. "Combustion Characteristics of Fine-Ground Coal," Briceland, Khinkis and Waibel, International Symposium on Combustion Diagnostics From Fuel Bunker to Stack, October 3-6, 1983. "Analysis of the Effects of Coal Fineness, Excess Air and Exit Gas Temperature on the Heat Rate of a Coal Fired Power Plant," Levy, Munukutla, Jibilian, Crim, Cogoli, Kwasnik and Wong, The American Society of Mechanical Engineers, Paper No. 84- JPGC-Pwr-1. 12 TABLE 1 ECONOMIC ASSUMPTIONS Operating Cost Coal Cost $2.50/MMBtu, Escalation 4-5 %/year' Fuel Oil Cost $6.90/MMBtu, Escalation 8-10%/year* Power Cost $.06/Kwh Incremental Maintenance Cost $10.50/ton coal processed’ Ash Disposal Cost $8.00/ton ash disposed of* Operating Cost 49 weeks/year, 7 days/week, 24 hours/day = 8,232 hours/year Capacity Factor - Ave 80% of MCR Additional Plant Operator - $50,000/year ' Escalation will be approximately equal to general inflation. 2 Escalation will be at a rate greater than general inflation and will likely run at a rate of 1.2 to 2.0 times the rate of general inflation. 3 Includes MicroMill, burner, boiler, scrubber, coal and ash system. ‘ Assumes 100% of the ash in the coal and dry scrubber sorbent must be disposed of. 13 TABLE 2 MICRONIZED COAL - ITS USE IN PACKAGED BOILERS MICRONIZED COAL FIRED BOILER PLANT CAPITAL COST ESTIMATE Coal Fired No.2 Oil Fi Boiler with Oil Burner and Pump Set 537,000 350,000 Coal Burner Additional Cost 43,000 NA Micromill 210,000 NA Coal Handling System 350,000 NA Baghouse and Dry Scrubber 550,000 NA I.D. Fan 25,000 NA Stack 40,000 20,000 Ash Handling System 225,000 NA Deaerator and Boiler Feedwater Pumps 100,000 100,000 Blowdown Tank/Heat Recovery 10,000 10,500 Water Softener 10,000 10,000 Chemical Feed Equipment 10,000 10,000 Feedwater Preheater 15,000 15,000 Continuous Emissions Monitor 75,000 75,000 Air Compressor & Dryer 15,000 10,000 Fuel Oil Tank 100,000 100,000 Site Work 100,000 75,000 Foundations 300,000 150,000 Building Structure and Siding 225,000 200,000 © Mechanical Installation, Piping and Valves 700,000 400,000 Electrical Wiring and Equipment 300,000 150,000 Environmental Permitting 100,000 100,000 Engineering 250,000 150,000 TOTAL 4,290,000 1,925,500 14 TABLE 3 INCREASED OPERATING COST (Coal vs. Oil) Energy (Electricity) Incremental HP Increase = 280 HP 280 HP x .7457 Kw/HP x 1 hr x $.06/Kwh = $15.66/hr Maintenance Cost @ 80% MCR = 2.9 ton coal/hr 2.9 ton/hr x $10.50/ton = $30.45/hr Ash Disposal @ 80% MCR = .31 ton ash/hr Dry Scrubber Sorbent @ 80% MCR = .08 ton sorbent/hr Operating Cost @ $8.00/ton = .39 = $3.12/hour SO, Removal Sorbent -08 tons/hr @ $75.00/ton = $6.00 hr Plant Operators and Maintenance Personnel 2 additional required at $50,000/yr each = $100,000/yr $100,000/yr + 8,232 hrs/yr = $12.13/hr Total Incremental Operating Cost = $64.25/hr Total Fuel Savings = $324.47/hr Net Fuel Savings = $260.22/hr TABLE 4 PROJECTED COST RECOVERY Incremental Micronized Capital Cost $2,364,500 Annual Projected Savings (approximate) $2,000,000 Simple Payback 1 to 2 years 15 ECONOWIZER UME STORAGE/SLAKER SYSTEM COAL FEED FROM FO Fan MICRO MILL wa 2 FUEL OW BURNER FEEDWATER LY 40 TON | | mae) | WATER SOFTNER i ej ? Onn FEEOWATER PUMPS eae ASH CONDITIONER 25 TPH MECHANICAL EXHAUSTER TO QuuP TRUCK AvSates Inc. MICRONIZED COAL Engineers - Architects » Consultants ee SYSTEM FLOW DIAGRAM Shawnee Mission, KS 66204-1260 FIGURE 2 Average Pulverized Coai Particle Size Average ore Coal Particle Size 20um 60 um c | particle. 60 um diameter 27 particles, each 20 um diameter Volume ® 6.90x10° cu. in. Volume = 6.90x10* cu. in. Area = 1.75x10°* sq. in. (one particle) Area = 5.26x10° sq. in. (27 particles) FIGURE 3 60 COAL FINENESS (PERCENT THRU 200 MESH) PERCENT UNBURNED CARBON SO: i 20 ws SO EXCESS AIR (PERCENT) COMPUTED VARIATION OF UNBURNED CARBON WITH EXCESS AIR BOILER EFFICIENCY FIGURE 4 91.0 90.0 89.0 88.0 60 COAL FINENESS (PERCENT THRU 200 MESH) 5 10 i} 20 2s 30 EXCESS AIR (PERCENT) BOILER EFFICIENCY AS A FUNCTION OF EXCESS AIR AND COAL FINENESS FIGURE 5 Micronized 40-60" Coal ee ee ee ee eee 9 (inches) FIGURE 6 Mill Motor Impeller Backplate Replaceable Blade Rotational Impact Zone with Abrasion Discharge to Resistant Lining Classifier Pivot Point —— Inlet Cone Coal and Primary Alr inlet “~ Tramp iron Discharge Bin Vent Filter Variable Speed Belt Feeder ion My, Pen ales inc. COAL HANDLING SYSTEM Engineers « Architects - Coneultants 6700 Antioch Roed FLOW DIAGRAM Shawnee Mission, KS 66204-1260 UNLOADING HOPPER onaly Flssociates Inc. Engineer + Architects + 6760 Antioch Road Shawnee Mission, KS 66204-1260 | OF FICE/ | CONTROL ROOM WATER CHEMICAL AIR ® SOFTNER Ff, COMPR. v SYSTEM — ECONOMIZER ASH HOPPER AREA BELOW STORAGE SILO IN MICRONIZED COAL TYPICAL GENERAL ARRANGEMENT